A key objective of EPRI’s research into distribution system practices is to identify, document and provide practice summary descriptions to research participants in a format that facilitates comparison and aids decision-makers in identifying those practices in place at other utilities that can be applied to their utility to improve performance. In order to facilitate comparisons, EPRI has issued practice results in an online repository, which places like practices employed by multiple companies one against the other. By organizing practices in this fashion, a funding company representative can use the EPRI Practice Repositories to compare and contrast practices used by peer companies to address like challenges.

Background

Underground systems are a crucial part of the electric utility industry infrastructure, delivering high levels of reliability to customers. Underground systems also present challenges to industry leaders, such as aging infrastructure and high construction and maintenance costs. Moreover, the loss of experienced staff to mergers and attrition has left many utilities with a gap in experience needed for optimal planning, design and engineering, construction, operations, and maintenance of underground systems. In 2007, EPRI embarked upon a multiyear effort to identify and illustrate noteworthy practices in managing urban underground systems. Originally focused on secondary network systems, EPRI expanded the scope of its practices research (at the request of participant utilities) to include practices employed in non-network designs such as radial ducted manhole systems, and non-network dual feeds to major urban customers. While some of the challenges faced by utilities with network systems are unique to network systems (e.g., network protector maintenance), many of the challenges operators of network systems face are similar to those faced by operators of non-network designs. For this reason, EPRI has expanded its research to identify noteworthy practices it believes valuable to utilities of both network and non-network systems. Beginning in 2012, EPRI expanded its research scope to include urban underground system practices employed by international (non-U.S.) utilities; specifically, ESB Networks in Dublin Ireland, and Energex in Brisbane, Australia. Research into international company practices presents an opportunity to identify unique practices and alternate ways of conducting business. A significant finding from EPRI’s review of these companies is that the fundamental design of the urban underground infrastructure serving their central business districts is significantly different than the urban design approach used by most U.S. utilities. Most U.S. utilities utilize a low-voltage meshed secondary underground network to serve urban customers. In this design, the meshed secondary system is supplied from multiple primary feeders. Because the secondary system is meshed, if one (or more) of the primary feeders go out of service, the secondary network continues to be supplied from the remaining primary feeders, ensuring uninterrupted customer service. The international approach is similar in that it utilizes an expansive secondary system to serve customers. However, the secondary system is not meshed, but radially designed, with multiple normally open tie points that can be used to facilitate restoration in an outage. Beginning in 2020, EPRI expanded the repository to include survey and practice information associated with underground residential and commercial distribution (URD and UCD). The ultimate research goals are deliverables that can aid utilities in managing underground distribution systems by identifying noteworthy industry practices information that can reduce time, cost, and uncertainty of dealing with these systems, and improve safety and reliability.

Approach

Successful management of underground distribution systems requires a confluence of people, processes, and technology practices. For example, performing a distribution feeder load flow analysis requires people with the appropriate educational background and training, and standards that define when and why such an analysis should be performed. Performing a feeder load flow analysis also requires a defined process, or set of activities that describe how such an analysis should be performed, and positions that set of activities within a larger process (e.g., overall capacity planning). Performing load flow analysis also entails the application of technology, such as load flow software and automated mapping systems. For this reason the EPRI research team focused on identifying People practices, Process practices, and Technology practices:

• People practices include things such as organizational designs, educational requirements, training, management controls such as policies, standards and audits, and performance management practices. These practices are descriptions of “who does things” and “how people are prepared.” • Process practices focus on the structure and performance of the activities involved in executing business processes in each key functional area. These practices summaries are descriptions of “how things are done.” • Technology practices focus on the application of tools, equipment, and information technology to support the execution of the processes. These practices summaries are descriptions of the “tools used to get things done.”

Summaries of practices in this repository are presented in a “People”, “Process”, and “Technology” format. In addition, the EPRI project team has also gathered practices information using surveys. Results from surveys are used to help members better understand common and contrasting practices among utility peers for managing underground systems. Survey results have been summarized and are included in the data repository.

Acknowledgements

EPRI wishes to acknowledge the high levels of cooperation, openness, and information sharing by all of the study participants from the companies who have participated in the practices immersions thus far and whose practices are represented in this repository, including: Seattle City Light (SCL), Con Edison, FirstEnergy (The Illuminating Company - CEI), Hawaiian Electric Company (HECO), CenterPoint Energy, Duke Energy, Pacific Gas & Electric (PG&E), National Grid, Ameren, ESB Networks, Energex, Georgia Power, and AEP.

In particular, EPRI wishes to acknowledge the following individuals for their leadership in helping to create and shape this practices repository:


Mr. Hamed Zadehgol	SCL
Mr. Frank Doherty	Con Edison
Mr. Matt Slagle	FirstEnergy
Mr. Roger Savako	FirstEnergy
Ms. Charlyne Nakamura	HECO
Mr. Lance Miyahara	HECO
Mr. Larry Neal	CenterPoint
Mr. Mark Mitchell	CenterPoint
Mr. Jeff Hesse	Duke Energy
Mr. Jerry Ivey	Duke Energy
Ms. Tuyet La	Duke Energy
Mr. Bob Malahowski	PG&E
Mr. Robert Sheridan	National Grid
Mr. Robert Schwarting	National Grid
Mr. Greg Ringkamp	Ameren
Mr. Ken Worland	Ameren
Ms. Theresa Fallon	ESB Networks
Mr. Michael Moran	ESB Networks
Mr. Paul Rainbird	Energex
Mr. Lee Welch	Georgia Power
Mr. Perry Pettigrew	Georgia Power
Mr. Roy Middleton	AEP
Mr. Tom Weaver	AEP

Find more information on participating utilities here.

EPRI Contact Information

John Tripolitis
JTripolitis@EPRI.com
(610) 385-0884

Josh Perkel
JPerkel@EPRI.com
(704) 595-2568

2 - Company Summaries

2.1 - AEP - Ohio

2015

Name	AEP Ohio
Utility Type	Investor Owned: American Electric Power
Web Site	https://www.aepohio.com/
Contact	Roy Middleton
Number of Electric Customers	Approx. 1.5 million customers
Location Description	Networks in metropolitan Columbus and Canton, Ohio
Network Organization	The network group is an operating unit within the AEP parent company.
Workers Represented by Collective Bargaining?	Yes: Network Mechanics.
Job Progression	Advancement within Network Mechanic job family based on attainment of training objectives and testing. There are expected times to advance to next level, but not an “up or out” program.
Number of Field Network Electrical Workers	Approximately 30 field resources, 6 Network Crew Supervisors, 2 support positions and 1 Supervisor for support of the Columbus networks.
Number of Distinct Secondary Networks Served	Four networks in Columbus, supplied by three stations. All serve combination of grid load and spot load. Two networks in Canton, OH
Network Primary Operating Voltage(s)	Columbus networks operated at 13.8 kV Canton network operated at 23 kV
Network Secondary Voltages	125/216-V secondary grid; 480-V spot networks
Number of Primary Feeders Supplying each Network	Six feeders
Design Contingency	N-2 in Columbus, N-1 in Canton
Number of Network Distribution Transformers	Metro Columbus –320 Canton – 50 Total - 370
Network Transformer Sizes	500/750/1000 kVA at 208 V; 500/750/1000/1500/2000/2500 kVA at 480 V
Network Protector Sizes	1600A/1875A/2000A/2250A/2825A/3000A/3500A/4500A
Primary Cable Sizes	1/0 TR-XPLE (URD) 4/0 TR-XPLE 500 copper flat strap EPR with thin jacket to fit 3” to 31/2” ducts. Use compact stranding and reduced wall. 750 Cu and Al used for station exits
Secondary Cable Sizes	All secondary cable is being replaced with 750 EAM (ethylene-alkene copolymer) copper and aluminum.
Civil Construction	17 crew members, including equipment operators
Peak Network Load	120 MVA in Columbus and 20 MVA in Canton
Annual Network Load Growth	1%
Preventive Maintenance Programs
Network Protector Inspection, Maintenance and Testing	1-year cycle for inspections; 4-year cycle for complete maintenance
Network Transformer Inspection, Maintenance and Oil Testing	1-year cycle for inspections; 4-year cycle for complete maintenance
Vault Inspections	1-year cycle
Vault Environmental Cleanup	Utilize vacuum trucks, as required.
Manhole Inspections	Four year cycle

2.2 - Ameren Missouri

2011

Name	Ameren Missouri
Utility Type	Investor Owned
Website	www.ameran.com
EPRI Contact	Ken Worland
Number of Electric Customers	2.4 million electric customers in Missouri and Illinois (Ameren) St. Louis network - 5100 meters St. Louis downtown radial – 1400 meters
Location Description	Ameren Missouri network system serves portions of the City of St. Louis, MO.
Network Organization	Part of the Distribution Services. UG network design and construction performed by Underground Division. Network equipment maintenance and operations performed by Distribution Operations.
Workers Represented by Collective Bargaining?	Yes, field workers and Energy Service Consultants (Estimators) represented by IBEW.
Automatic Mode of Progression?	No journeyman program in UG Construction Distribution Service testers advance to journeyman after aggressive 20 week training program,
Number of Field Electrical workers	10 Dist Serv Techs 12 Cable Splicers
Number of Distinct Secondary Networks Served	4 networks, each sourced by separate substation
Network Primary Operating Voltage(s)	13.8kV
Network Secondary Voltages	125/ 216 V Grid and spots 277/480 V spot networks
Number of Primary Feeders Supplying Each Network	2 networks are fed by 8 dedicated feeders 1 network is fed by 7 dedicated feeders 1 network is fed by 6 dedicated feeders
Design Contingency	N-1, including planning for a substation bus outage.
Number of Network Distribution Transformers	265 network units in St. Louis
Network Transformer Sizes	Most common size – 500 and 750 kVA on the Grid. 1000 kVA spots.
Network Protector Sizes	Current Standard: 1875, 2000, 2250, 2825, 3000 Amps
Primary Cable Types	13.8kV – PILC, EPR EPR used as primary sections are replaced
Primary Cable Sizes	15kV - 750 cu, 500 cu, 350 cu, 4/0 Al 35 kV - 750 cu, 350 cu, 1/0 Al
Secondary Cable Sizes	500 cu for mains
Civil Construction	Have poured in place, brick and mortar, and precast construction in the network. Current standard - precast construction
Peak Network Load	St Louis – 207 MVA
Annual Network Load Growth	Flat, some residential growth, as downtown buildings are converted to lofts.
Preventive Maintenance Programs
Network Protector Inspection	Annual
Network Protector Maintenance And Testing	2 year cycle
Network Transformer Inspection, Maintenance And Oil Testing	2 year cycle, part of vault inspection. Separate programs for sampling oil from transformer and from primary termination compartment.
Vault Inspections	Visual inspection annually. More detailed inspection of equipment on a 2 Year cycle
Vault Environmental Cleanup	Number of cleanups based on findings from annual vault inspection
Manhole Inspections	Detailed inspection on every 4 years.

2.3 - BC Hydro

2022

Name	Company Name
Utility Type	BC Hydro
Web Site	www.bchydro.com
Contact	Stefano Ghirardello, stefano.ghirardello@bchydro.com
Number of Electric Customers	Approximately 1.9M customers. The urban underground network in Victoria serves ~2700 customers
Location Description	Networks in downtown Victoria, serving a geographic area of about 124 acres, or 50 hectares
Network Organization	Electric utility (crown corporation) which handles G, T & D
Workers Represented by Collective Bargaining?	Field workers and Design, yes. Engineering and Planning, no
Job Progression	4-year apprenticeship
Number of Field Network Electrical Workers	Total crew 3-4 + flagging
Number of Planners and Designers	1 Planner and typically 1 Designer (neither are dedicated to the network)
Annual Network Load Growth	~750kVA
Number of Distinct Secondary Networks Served	1
Number of Spot Networks	6
Miles of MV UG cable in networks
Miles of LV UG cable in networks
Network Primary Operating Voltages	12.47kV
Network Secondary Voltages	120/208V, SPOT networks are 347/600V
Number of Primary Feeders Supplying each Network	7
Design Contingency	N-2
Number of Network Distribution Transformers	108 (12 of which are for SPOT networks)
Network Transformer Sizes	Area networks – 500kVA Spot networks – 1500kVA
Network Protector Sizes	1600A -2000A(SPOTS)
Primary Cable Types	PILC and XLPE
Primary Cable Sizes	#2 KCM, 400kCM-600kCM Cu PILC and 500 kCM Cu XLPE
Secondary Cable Types	Cu
Secondary Cable Sizes	4c 500kCM Cu and 7c (6x4/0 and 1x450kCM neutral) Cu
Civil Construction	All civil work on the Network is performed by our contractor. All work is constructed in place (no pre-cast).
Preventive Maintenance Programs
Network Protector Inspection, Maintenance and Testing	5 year frequency
Network Transformer Inspection and Maintenance	5 year frequency
Transformer Oil Testing	5 year frequency
Vault Inspections	5 year max
Vault Environmental Cleanup	5 year max
Manhole Inspections	5 years max

2.4 - CEI - The Illuminating Company

2008

Name	The Illuminating Company
Utility Type	Investor Owned
Website	https://www.firstenergycorp.com/The_Illuminating_Company/index.html
EPRI Contact	Matt Slagle (216) 479-1100 mfslagle@firstenergycorp.com
Number of Customers	745,000
Location Description	The City of Cleveland, Ohio and surrounding areas
Network Organization	Dedicated organization for underground construction , operation and maintenance, including network and non – network underground systems. Dedicated section within regional Engineering Services for underground systems design, including network and non-network systems.
Workers represented by collective bargaining?	Yes, Field Force is represented by UWUA, Local 270. Engineers are not represented by collective bargaining.
Automatic Mode of Progression?	Employees are not mandated to advance to a journeyman position within a given period of time, but can achieve the journeyman level in six years with time in grade, formal and on-the-job training, and testing. Management determines the number of positions at each classification.
Number of Field Electrical workers	48, work with network and non-network distribution
Number Of Network Planners And Designers	2
Number of Network Customers Served	Total – 600. Most downtown load in Cleveland is not served by the secondary network system.
Number of Distinct Secondary Networks Served	Total – 1 network 2 spot networks with 120/208 V secondary
Miles of Underground Cable	16,000 ft of network primary cable 37,000 ft of network secondary cable
Network Primary Operating Voltage(s)	11 kV
Network Secondary Voltages	120/ 208 V, with cable limiters
Number of Primary Feeders Supplying Each Network	5 primary feeders supply the network. All network feeders are sourced from the same area substation.
Design Contingency	N-1
Number of Network Distribution Transformers	Total - 61
Network Transformer Sizes	500-1000 kVA
Network Protector Sizes	1600 and 2000 amps @ 120 V
Primary Cable Types	PILC EPR (current standard - used for new construction) XLP (used in substation getaways – non – network feeders)
Primary Cable Sizes	Typically, 600 Kcmil cu, 3 conductor PILC; 500 Kcmil cu, 1- conductor EPR
Secondary Cable Sizes	Standard – 500 Kcmil cu
Civil Construction	Pre-cast vaults
Peak Network Load	12 MVA
Total Company Peak Load
Annual Network Load Growth	0 %, load is declining.
Preventive Maintenance Programs
Manhole Inspection	5-year cycle
Network Vault Inspection	Every 6 months
Network Protector Maintenance	6-year cycle
Network Relay Maintenance	6- year cycle
Network Transformer Oil Sampling	2-year cycle
Network Protector Operational Test	Annual

2.5 - CenterPoint Energy

2009

Name	CenterPoint Energy
Utility Type	Investor Owned
Website	http://www.centerpointenergy.com/home/
EPRI Contact	Larry Neal (713) 207-4530 larry.neal@centerpointenergy.com
Number of Electric Customers	2 Million
Location Description	The City of Houston, Texas and surrounding metropolitan area (5000 Sq mile territory)
Network Organization	Dedicated organization for major underground design, construction, operation and maintenance, including network and non – network underground systems.
Workers represented by collective bargaining?	Yes, Field Force is represented by IBEW. Local 66. Engineers are not represented by collective bargaining.
Job Progression	Advancement through the Network Tester and Cable Splicer job families involves a three year apprenticeship program that includes a combination of training, job skills demonstration, and testing. Workers must complete the required training and testing to remain in the program and advance to a journeyman level.
Number of Field Electrical workers	110, work with network and non-network distribution
Number of Planners And Designers	30, work with network and non-network distribution design.
Number of Distinct Secondary Networks Served	5 networks, served by from 6 to 10 feeders each. Feeders are sourced out of three different substations.
Miles of Underground Cable (Major Underground, excluding URD)	624 miles of 12kV 233 miles of 35kV 28 Miles of UG Network Secondary
Underground Primary Operating Voltage(s)	12.47 kV and 34.5 kV
Network Secondary Voltages	120/ 208 V, grid and spot networks 277/480 V spot networks 2400/4160 V spot networks
Number of Primary Feeders Supplying Each Network	From 6 – 10, depending on the network. All network feeders supplying a given network are sourced from the same substation. CenterPoint has three different subs that supply its Houston networks
Design Contingency	N-1
Number of Network Distribution Transformers	148
Network Transformer Sizes	480Y/277V to 208Y/120V – 300kVA 208Y/120V – 600kVA and 750kVA 480Y/277V – 1000kVA, 1500kVA, 2500kVA
Number of Network Protectors	278
Network Protector Sizes	800, 1600, 2000 and 2500 amps @ 208 V 800, 1200, 1600, 2500 amps @ 480V
Primary Cable Types (Major Underground)	PILC (existing, not used currently) Butyl Cable (existing, not used currently) EPR (current power cable standard for Major Underground, installed in conduit) TR-XLPE – used in Direct Buried URD applications
Primary Cable Sizes	750 and 1000 MCM AA EPR at 12kV 2/0, 500, and 1000 MCM Cu EPR at 12 KV 1250 MCM AA at 35 kV 2/0 and 350 MCM Cu EPR at 35 kV 1/0 AL TR XLPE at 12 kV and 35 kV
Civil Construction	CenterPoint ‘Pours in place” to build new manholes. Precast units are usually the choice of customers who are providing manholes.
Preventive Maintenance Programs
Manhole Inspection	1 year, 5 year, or 10 year cycle depending on the manhole criticality
Vault Inspection	1 year cycle, though some critical vaults inspected more often
Network Protector Maintenance	5 year testing, 1 year inspection
Three phase pad-mounted transformer Inspection	1 year cycle

2.6 - Central Hudson Gas & Electric

2022

Name	Central Hudson Gas & Electric
Utility Type	Investor Owned
Web Site	https://www.cenhud.com/
Contact	Taryn Black, tblack@cenhud.com
Number of Electric Customers	Approximately 309,000 customers throughout the service territory. In total, the three individual urban underground network systems serve approximately 1,500 customers.
Location Description	The entire service territory spans the Mid-Hudson Valley region of NY. In total, serving a geographic area of about 2,700 sq miles. Networks service portions of the City of Poughkeepsie, City of Newburgh, and City of Kingston.
Network Organization	There is no dedicated section for UG construction, it’s all a part of Distribution Engineering and Operations. UG network design and planning is performed by Engineers in the Distribution Engineering Division. Network equipment construction and maintenance performed by Splicing and Substation Technician crews who work on both network and non-network systems.
Workers Represented by Collective Bargaining?	Operation field forces are represented by the IBEW Local 320. Engineers are not represented by collective bargaining.
Job Progression	Field forces start as 3^rd Class and are in that role for 24 months before testing into 2^nd Class. The 2^nd Class timeline is approximately 36 months before testing into 1^st Class. After approximately 36 months in the 1^st Class role, they are eligible to sit for a Working Foreman test. It’s a similar progression for all field forces.
Number of Field Network Electrical Workers	9 Splicers (not dedicate) 12 Substation (Relay) Technicians (not dedicated) 8 Equipment Operators (Rigging) (not dedicated)
Number of Planners and Designers	1-2 Engineers
Annual Network Load Growth	This is not tracked but the network load has always represented less than 1% of the total system load.
Number of Distinct Secondary Networks Served	3 separate networks. (1) the City of Poughkeepsie, (1) the City of Newburgh, (1) the City of Kingston
Number of Spot Networks	None
Miles of MV UG cable in networks	Approximately 12 miles
Miles of LV UG cable in networks	Approximately 203 miles
Network Primary Operating Voltages	4.16/2.4 kV and 14.4 kV
Network Secondary Voltages	125/216V grid networks
Number of Primary Feeders Supplying each Network	3 non-dedicated feeders per area network
Design Contingency	N-1
Number of Network Distribution Transformers	40 total (29-3Ø network units, 11-banks of 3x1Ø units)
Network Transformer Sizes	167kVA(x3), 500kVA, 750kVA, and 1000kVA
Network Protector Sizes	1600amp, 2500amp, 3000amp
Primary Cable Types	PILC and EPR with flat strap concentric neutrals, PILC is being replaced by EPR.
Primary Cable Sizes	4/0 Cu is the standard
Secondary Cable Types	EPR is the standard but old VCL and old Rubber Braid still exist.
Secondary Cable Sizes	500 Cu mains, 500 Cu, 350 Cu, 4/0 Cu, and 1/0 Cu for services.
Civil Construction	Civil construction is contracted out to local companies. The contractor builds forms pours the duct banks in place. The manhole and pullbox structures are precast by another company and delivered to the site.
Preventive Maintenance Programs
Network Protector Inspection, Maintenance and Testing	Visual inspections completed on a 5 year cycle, electrical and mechanical testing on a 6 year cycle.
Network Transformer Inspection and Maintenance	Completed on a 5 year cycle.
Transformer Oil Testing	None
Vault Inspections	Completed on a 5 year cycle.
Vault Environmental Cleanup	No cyclic programs but vaults are thoroughly vacuumed if work is occurring in them.
Manhole/Pullbox Inspections	Completed on a 5 year cycle.

2.7 - Con Edison - Consolidated Edison

2008

Name	Consolidated Edison (Con Edison)
Utility Type	Investor Owned
Website	http://www.coned.com
EPRI Contact	Frank Doherty 212-460-3342 dohertyf@coned.com
Number of Customers	3.2 million
Population Service	9.1 million
Location Description	The five boroughs of the city of New York, and Westchester County; Orange and Rockland Counties in New Jersey. Focus of EPRI was the boroughs of Manhattan and Brooklyn.
Network Organization	Dedicated network resources for network planning, design, construction, and maintenance.
Workers represented by collective bargaining?	Yes, Field Force is represented by IBEW. Manhattan – Local 12 Engineers are not represented by collective bargaining.
Automatic Mode of Progression?	Employees are not mandated to advance to a journeyman position within a given period of time. Employees can advance with time in grade, formal and on-the-job training, and testing.
Number of Network Customers Served	Manhattan – 699,831 Total – 2,364,000
Number of Distinct Secondary Networks Served	Manhattan – 35 networks Brooklyn/Queens – 18 Bronx – 6 Staten Island / Westchester – (some small networks) Total – 59 networks
Miles of Underground Cable	94,000 miles, Manhattan 20,408 miles
Network Primary Operating Voltage(s)	13.8 kV, 26.4 kV
Network Secondary Voltages	125/ 216 V, with cable limiters 480Y/277, with cable limiters
Number of Primary Feeders Supplying Each Network	From 8 to 29 primary feeders supply each network. (Average 16 feeders per network) All network feeders for a given network sourced from the same area substation.
Peak Load per Feeder	Peak load ranges from 60 to 400 MW
Design Contingency	N-2 in Manhattan, parts of Brooklyn and Queens, N-1 elsewhere
Number of Network Distribution Transformers	Manhattan 9,593 Brooklyn/Queens 11,654 Bronx/Westchester 4,643 Staten Island 263 Total 26,153
Network Transformer Sizes	500-2500 kVA
Network Protector Sizes	2250 and 4500 amps @ 120 V; 5100 amp @ 265 V
Primary Cable Types	PILC (22%) XLP EPR (current standard - used for new construction)
Primary Cable Sizes	Various, typically 750 or 1000 Kcmil for main lines at 13.8, with 2/0 to the transformers; 500 or 750 Kcmil for main lines at 27 kV with 2/0 taps to the transformers
Secondary Cable Sizes	Standard – 500 Kcmil
Civil Construction	Pre-cast and poured in place vaults
Total Company Peak Load	13,141 MW, Summer 2006, 5404 MW - Manhattan
Annual Network Load Growth	3-4% Manhattan
Preventive Maintenance Programs
Network Distribution Equipment Inspection Includes inspection and maintenance of vault or manhole, and all equipment including network transformers, and network protectors	Routine Inspection of 208 V vault with RMS (remote monitoring system) – 5 year cycle. Routine Inspection of 208 V vault without RMS (remote monitoring system) – from 18 month to 3 year cycle depending on equipment age. (>25 years old, 18 month cycle) Routine Inspection of 460 V vault with RMS – 18 month cycle. Routine Inspection of 460 V vault without RMS – 18 month cycle – with test box. Non “routine” inspections performed more frequently depending on vault classification based on vault location, nature of customer, and equipment type, age, and condition. Non-routine inspection locations are predefined.
Network Protector Maintenance—with Test Box	Routine test box inspection of 208 V with RMS – not performed cyclically, inspection driven by other factors Routine test box inspection of 208 V without RMS – 6 year cycle Routine test box inspection of 460 V with RMS – 4.5 year cycle Routine test box inspection of 460 V without RMS – 18 months. Non “routine” inspections performed more frequently depending on vault classification based on vault location, nature of customer, and equipment type, age, and condition. Non-routine inspection locations are predefined.

2.8 - Duke Energy Florida

2016

Name	Duke Energy Florida – Clearwater	Duke Energy Florida – St. Petersburg
Utility Type	Investor Owned: Duke Energy Florida	Investor Owned: Duke Energy Florida
Web Site	https://www.duke-energy.com/	https://www.duke-energy.com/
Contact	Glenn Hilditch	Glenn Hilditch
Number of Electric Customers Total Number of Electric Customers - Networks	1,715,771 –Total in Florida 500
Location Description	Clearwater, FL	St. Petersburg, FL
Network Organization	3	5
Workers Represented by Collective Bargaining?	3	5
Job Progression	Electric Apprentice (EA) to Network Specialist (NS)	Electric Apprentice (EA) to Network Specialist (NS)
Number of Field Network Electrical Workers	3	5
Number of Civil Construction workers	Normally Contracted	Normally Contracted (5 Contractor Crews at time of immersion)
Number of Distinct Secondary Grid Networks Served	1 True Network	8 Spot Networks
Number of Spot Networks Service	0	8
Network Primary Operating Voltage(s)	7200/12470	7200/12470
Network Secondary Voltage(s)	125/216	125/216 277/480
Number of Primary Feeders Supplying each Network (Grids and Spots)	3	7 feeders that supply downtown St Pete. All spot network locations fed by two feeders.
Design Contingency	N-1	N-1
Number of Network Distribution Transformers	20	34
Network Transformer Sizes	500	500, 750
Network Protector Sizes	1600 & 1875	1600, 2500, 3500 & 1200
Primary Cable Sizes	4/0	4/0 and 1000mcm
Secondary Cable Sizes	500 CU	500 CU & 4/0
Peak Network Load
Annual Network Load Growth	<1%	<1%
Preventive Inspection & Maintenance Programs
Network Protector Inspection	Done in conjunction with Vault Inspections 3 x per year to 6 x per year depending on vault criticality	Done in conjunction with Vault Inspections 1 x per year
Network Protector Maintenance and Testing	Every 2 years	As needed based on inspection findings
Vault Inspections	3 x per year to 6 x per year depending on vault criticality	1 x per year
Network Transformer Inspection and Maintenance	Done in conjunction with Vault Inspections 3 x per year to 6 x per year depending on vault criticality	Done in conjunction with Vault Inspections 1 x per year
Network Transformer Oil Testing	N/A Piloting dissolved gas monitoring sensor technology	N/A
Vault Environmental Cleanup	3 x per year to 6 x per year depending on vault criticality	1 x per year
Manhole Inspections	Every 5 years	Every 5 years
Network Feeder Sectionalizing Switches (RAs) – inspection and exercise	3 x per year	N/A

2.9 - Duke Energy Ohio

2009

Name	Duke Energy
Utility Type	Investor Owned
Website	https://www.duke-energy.com/
EPRI Contact	Jerry Ivey
Number of Electric Customers	Duke Energy Ohio – 685,000
Location Description	Duke Energy Ohio network system serves the City of Cincinnati, Ohio and surrounding metropolitan area
Network Organization	Centralized, part of the Dana Avenue Construction and Maintenance Organization.
Workers represented by collective bargaining?	Yes
Automatic Mode of Progression?	Yes, a 4 year mode of progression to a Journey worker position
Number of Field Electrical workers	46
Number of Planners And Designers	4
Number of Distinct Secondary Networks Served	4 distinct network systems, 120/208V
Network Primary Operating Voltage(s)	13.2kV
Network Secondary Voltages	120/ 208 V 277/480 V spot networks
Number of Primary Feeders Supplying Each Network	Three of the four networks in downtown Cincinnati are supplied by eight feeders, each, and the fourth network, by four feeders.
Design Contingency	N-1
Number of Network Distribution Transformers	Total 414
Network Transformer Sizes	Most common is size – 600 kVA Also use 750 kVA units
Network Protector Sizes	Most common, 2000A, 2825A
Primary Cable Types	PILC EPR (network feeders)
Primary Cable Sizes	750 cu EPR flat strapped neutral cable 4/0 cu EPR cable (without flap strapped neutral) 400 and 600 MCM PILC cables Duke Energy Ohio will pull three conductors bundled together through a single duct.
Secondary Cable Sizes	500 cu EPR
Civil Construction	Use both precast and poured in place, depending on application
Peak Network Load	170 MVA (1989 – 1990) 2009 Peak: 136 MVA
Annual Network Load Growth	In the network, load growth has been declining, driven by the implementation of a chiller system (by Duke) and end use efficiency.
Preventive Maintenance Programs
Network protector drop tests	Weekly
Manhole inspections	Six year cycle
Vault inspections	Four times per year (quarterly)
Network transformer oil sampling	Four year cycle

2.10 - Energex

2014

Name	Energex
Utility Type	State-owned
Website	https://www.energex.com.au
EPRI Contact	Paul Rainbird, paulrainbird@energex.com.au
Number of Electric Customers	1.3 million residential, industrial, and commercial customers across a population base of around 3.1 million
Location Description	City of Brisbane
Organization	Energex has a Service Delivery organization that is organized geographically. Field resources assigned to the center(s) with responsibility for downtown Brisbane support the Central Business District.
Job Progression (Electrical Jointer)	3 ½ Year jointer apprenticeship program, including formal training, testing, on the job training, and time in grade. In the first 18 months after completing the apprenticeship, participants must complete a "basket of skills" required by the electrical office.
Selected Job Classifications	Substation Technicians (work with sub breakers / relay protection) Substation Fitter Mechanics (work with relay operated switchgear, and serve as rapid responders) Power Workers (Civil Work) Electrical Jointers (Cable work, splicing) Diagnostic Testing technicians Electrical Fitter Mechanics (Fully qualified electricians and “fitters¹”)
Primary Operating Voltage(s)	11 kV – Medium-voltage primary serving Brisbane
Secondary Voltages	230/400 V, 50 Hz Single Phase delivery range of 207 V to 253 V
Number of Primary Feeders Supplying Each Network	Normally three-feeder mesh
Design Contingency	N-1, including planning for a substation bus outage.
Number of Distribution Transformers	Approximately 40,000 system-wide
MV Transformer Sizes	Most common size – 60 or 80 mVA
Cable Population	Varied: PILC, XPLE, others
Primary Cable Sizes	The standard XLPE is a triplex cable, using stranded aluminum conductors (400 mm²). In areas of restricted conduit diameter, Energex uses XLPE insulated copper conductors (240 mm²).
Secondary Cable Sizes	4 conductor bundled, jacketed, stranded sector H68 Aluminum, with XLPE insulation
Civil Construction	Primarily through contractors
Peak Network Load	Approximately 4000 MW
Preventive Maintenance Programs	Network circuit breaker Network transformer Work depot inspections Substation inspections Customer substation inspections Vegetation management

The term “Fitter”, refers to the mechanical aspects of a journey worker lineman, such as line construction.↩︎

2.11 - ESB Networks

2015

Name	ESB Networks
Utility Type	Regulated monopoly
Website	http://www.esb.ie/esbnetworks/en/home/index.jsp
EPRI Contact	Michael Moran
Number of Electric Customers	2.3 million electric customers in the Republic of Ireland
Location Description	ESB Networks UG Networks serves City of Dublin.
Network Organization	Meshed network in Dublin, radial distribution.
Workers Represented by Collective Bargaining?	Six separate unions.
Automatic Mode of Progression?	Through training and certification. Active recruitment internally and externally.
Primary Operating Voltage(s)	10 kV – MV primary serving Dublin 20 kV – MV primary serving much or Ireland
Secondary Voltages	230/400 V, 50 Hz Single-phase delivery range of 207 V to 253 V in accordance with European Standard EN50160
Design Contingency	N-1, including planning for a substation bus outage. N-2 in Dublin.
Number of Distribution Transformers	253,000
MV Transformer Sizes	Most common size – 400, 630, and 1000 kVA
Cable Population	400 kV: 2 km 220 kV: 135 km 110 kV: 290 km 38 kV: 915 km MV (10/20 kV): 8000 km/1300 km (Note – Primary distribution system serving Dublin is 10 kV LV Mains : 10250 km
Primary Cable Sizes	XPLE, PILC in some locations
Secondary Cable Sizes	4 x 185 sq mm Al LV mains cable for all new developments 35/25sq mm Al service cable standard
Civil Construction	Have poured in place, brick and mortar, and precast construction in the network. Current standard precast construction
Peak Network Load	5100 MW (Ireland)
Annual Network Load Growth	The UG system across ESB Networks has expanded by 100% in the past 10 years.
Preventive Maintenance Programs
Cable inspection	Quarterly. Looking at remotely monitoring sheathing.
MV substations	Once every four years

2.12 - Georgia Power

2013

Name	Georgia Power
Utility Type	Investor Owned
Web Site	www.georgiapower.com
EPRI Contact	Lee Welch
Number of Electric Customers	More than 2.4 million
Location Description	Metro Atlanta, Savannah, Athens, Columbus, Augusta, Valdosta, and Macon, Georgia
Network Organization	Network Group is self-contained operating unit within Georgia Power
Workers Represented by Collective Bargaining?	Yes. Some field workers, including Cable Splicers, Duct Line Mechanics, Winch Truck Operators (WTO), Journeymen
Automatic Mode of Job Progression?	Yes, with training objectives and testing: three-year progressions for WTO, Cable Splicers, and Duct Line Mechanics; training and progression for Senior Engineers
Number of Field Electrical Workers	Total Union – 72 workers Cable Splicers – 28 in Atlanta, 3 in Augusta, 6 in Savannah Duct Line Mechanics – 12
Number of Distinct Secondary Networks Served	35 networks in Atlanta
Network Primary Operating Voltage(s)	19.8 kV, 13.8 kV, 12.47 kV
Network Secondary Voltages	120/208 V secondary grid; 277/480 V spot networks
Number of Primary Feeders Supplying Each Network	5, sometimes 6 feeders (about 40 mVA per network)
Design Contingency	N-1
Number of Network Distribution Transformers	Metro Atlanta – 1533 Other (Outside Atlanta) – 506 Total - 2039
Network Transformer Sizes	500/1000 kVA at 208v; 500/1000/2000 kVA at 480v; C57.12.40 with some modifications
Network Protector Sizes	1600/1875 Amp; 3000 Amp
Primary Cable Sizes	300 MCM 3-conductor copper/paper/lead compact sector;350 MCM copper/EPR in some cases, but not aggressively replacing lead 1000 MCM copp/EPR 1000 MCM alum/XLPE
Secondary Cable Sizes	2000 MCM copper, 600 V on secondary collector buses 500 MCM copper, 600v EPR on street mains 350 MCM copper, 600v EPR on street mains #4/0 copper, 600v EPR on street mains
Civil Construction	17 crew members, including equipment operators
Peak Network Load	approx 700 MW
Annual Network Load Growth	New network in Buckhead area; downtown Atlanta flat; some new projects in Savannah (Note: new business has increased in all areas after this immersion visit)
Preventive Maintenance Programs
Network Protector Inspection, Maintenance And Testing	5-year cycle, separate program from vault inspections
Network Transformer Inspection, Maintenance And Oil Testing	5-year, performed as part of vault inspections
Vault Inspections	5-year cycle
Vault Environmental Cleanup	Cleaning trucks with oil socks; vacuum trucks with hazmat disposal
Manhole Inspections	6-year cycle

2.13 - HECO - The Hawaiian Electric Company

2009

Name	The Hawaiian Electric Company
Utility Type	Investor Owned
Website	https://www.HECO.com
EPRI Contacts	Charlyne Nakamura (808) 543 - 7984 Charlyne.Nakamura@HECO.com
Number of Customers	293,740
Population Served	905,034
Location Description	The Island of O’ahu, Hawaii, including the City of Honolulu
Network Organization	Dedicated organization for underground construction, operation and maintenance, including network and non – network underground systems. Underground Group does all network cable work, all work with lead cable in or out of the network, all fault locating. Substation group maintains network transformers and network protectors. (Note – HECO also has an “Overhead” group that works with poly cables in the 12 kV system, including cable pulling and splicing.) No dedicated section within Engineering for underground systems design or for network design.
Workers represented by collective bargaining?	Yes, Field Force is represented by IBEW, Local 1260 Engineers are not represented by collective bargaining. Load and Trouble Dispatchers are represented by IBEW.
Automatic Mode of Progression?	Yes, 3 years to Lineman First Year, 4 years to Journeyman. In UG Group, the Cable Splicer position filled from Journeyman Lineman position. After one year as a Cable Splicer, with OJT, a person moves to a Senior Cable Splicer. Mode includes time in grade, formal and on-the-job training, and testing.
Number of Field Electrical workers	20, work with network and non-network distribution. (Not including a percentage of the “Overhead” workforce that works with non lead underground cables, and substation workers who manage network equipment) Approximately 3 field electrical workers focus on the network
Number Of Network Planners And Designers	1 Planning engineer works on Network Planning. This individual has non-network responsibility as well.
Number of Planners and Designers focused on Underground	HECO has 7 total distribution planning engineers that do all of the Overhead and underground planning.
Number of Network Customers Served	1594. Most of downtown load in Honolulu is not served by the secondary network system. HECO uses a dual feed non-network service, with a throwover switch, to serve large customers
Number of Distinct Secondary Networks Served	Total – 7 networks, 208y/120 V secondary 27 spot networks with 480y/277 V secondary
Primary Distribution Operating Voltage(s)	11.5 kV – Network Non – Network 11.5 kV 12.47 kV 24.94 kV
Network Secondary Voltages	120/ 208 V, with cable limiters 277 / 480 V Spot networks
Number of Primary Feeders Supplying Each Network	From 4 through 13 feeders supply the 7 HECO network areas. The secondary grid networks in these areas are each fed by four circuits. All network feeders are sourced from the same area substation.
Design Contingency	N-1 including network and non network distribution.
Number of Network Distribution Transformers	Total – 140.
Network Transformer Sizes	500-2000 kVA
Network Protector Sizes	125/216V – 1200A -3000A 277.480V spots - 800A - 3000A
Primary Cable Types	PILC (installed plant, but no longer standard) XLPE (Standard for new construction for non-network distribution. Not used in the network because of conduit size constraints) EPR (used in areas where a smaller cable diameter is required)
Primary Cable Sizes	Typically, 1000 Kcmil Al, 3-1/c (three singles, parallel wound) conductor XLPE for main runs For network feeders, most installed cable is 3-1/c 750MCM PILC, and 301/c 4/0 PILC. Upon failure, the feeders are replaced with the 3-1/c cu EPR equivalent.
Secondary Cable Sizes	Network secondary cables are 3-1/c 500KCM 600V EPR with 1/c 4/0 BC neutral. Non-network secondary cables are 2-1/c 350KCM Al 600V XLPE with 1/c 4/0 neutral triplexed for the secondary mains.
Civil Construction	Pre-cast vaults
Peak Network Load	46MW
Preventive Maintenance Programs
Manhole Inspection	Planned annual inspection and Amp readings of secondary limiters for network manholes Non – network inspection frequency is being developed by C&M
Network Vault Inspection	Transformer vaults inspected as part of transformer and NP service and testing, every 2-3 years.
Network Protector Maintenance	Network Protector Service performed every 2 - 3 years
Network Transformer Inspection	Network Transformer Inspection performed every 2 - 3 years

2.14 - National Grid (Albany)

2011

Name	National Grid
Utility Type	Investor Owned
Website	https://www.nationalgridus.com/niagaramohawk/
EPRI Contact	Rob Sheridan
Number of Electric Customers	The Albany network serves about 2786 customers. There are 10 customers fed by 11 spot networks and 1 dual fed customer through a padmounted switchgear on the 13.2kV general network feeders. There are 14 customers fed by spot networks and 2 dual fed primary customers on the 34.5 kV primary feeders.
Location Description	The National Grid Albany network system serves portions of the downtown Albany NY,
Network Organization	Part of the NY Underground Lines East, serving eastern NY state, including Albany.
Workers represented by collective bargaining?	Yes, IBEW in Albany. (National Grid also has resources represented by UWUA).
Automatic Mode of Progression?	Yes, 42 month year mode of progression to a Journey worker position. (C Cable Splicer, or C Maintenance Mechanic)
Number of Field Electrical workers – NY Eastern Division	23 Cable Splicers 6 Maintenance Mechanics
Number of Field Non-Electrical workers – NY Eastern Division	13 Mechanics 5 Equipment Operators 1 Machinist 1 Welder 3 Haz Mat Mechanics
Number of Distinct Secondary Networks Served	The UG group located in Albany (The NY Eastern Region) is responsible for networks in Albany (2786 custs), Troy (1583 custs), Schenectady (1,120 custs) and Glens Falls. (220 custs) Albany has one grid network system and one spot network system
Network Primary Operating Voltage(s)	Albany Grid System (and some spot networks) 13.2kV Spot Network system 34.5kV
Network Secondary Voltages	125/ 216 V grid and spots. 277/480 V spot networks
Number of Primary Feeders Supplying Each Network	Albany network fed by 10 dedicated 13.2 network feeders. Spot networks fed by 5 34.5 kV feeders. (34.5 system feeds 277/480V spot networks only)
Design Contingency	N-2
Number of Network Distribution Transformers	251
Network Transformer Sizes	500 to 1000 kVA on the Grid; 500 to 2500 kVA on the spots.
Network Protector Sizes	Current Standard: 1200, 1875, 2825, 3500 Amps at 216Y/125V , 800, 1200, 1875, 2825, 3500 and 4500 Amps at 480Y/277V
Primary Cable Types	13.2kV – PILC and EPR , concentric and flat strapped 34..5kV – PILC and EPR, concentric and flat strapped. EPR used as primary sections are replaced
Primary Cable Sizes	1000 Cu, 750 cu, 500 cu, 350 cu (replaced with 500 cu as fails)
Secondary Cable Sizes	500 Cu mains; 500 Cu, 4/0 Cu, and #2 Cu services Lead and EPR with a Hypalon Jacket (Current standard)
Civil Construction	Use primarily pre cast construction
Annual Network Load Growth	Flat
Preventive Maintenance Programs
Network Protector Maintenance And Testing	Five Years (Except for CMD protectors which are maintained on a two year cycle)
Network Protector Operational (Drop) testing	Annual
Vault Inspections	Annual
Manhole Inspections	Five Years

2.15 - PG&E

2010

Name	PG&E
Utility Type	Investor Owned
Website	www.pge.com
EPRI Contact	Bob Malahowski
Number of Electric Customers	685,000
Location Description	PG&E network system serves portions of the Cities of San Francisco and Oakland, California.
Network Organization	Part of the Maintenance and Construction (M&C) Electrical Network group, with resources in San Francisco and Oakland.
Workers Represented by Collective Bargaining?	Yes, IBEW.
Automatic Mode of Progression?	Yes, 30 month year mode of progression to a Journey worker position. (Cable splicer)
Number of Field Electrical workers	17 , San Francisco (Cable Splicers) 3, Oakland
Number of Distinct Secondary Networks Served	12 networks 10 networks in San Francisco, 2 in Oakland
Network Primary Operating Voltage(s)	12kV and 34.5kV
Network Secondary Voltages	120/ 208 V Grid and spots. 277/480 V spot networks
Number of Primary Feeders Supplying Each Network	10 are 12kV. Each individual networks fed by 6 dedicated network feeders. 2 are 34.5 kV- one fed by 4 feeders and one by 5 feeders. (34.5 system feeds 277/480V spot networks only)
Design Contingency	N-1
Number of Network Distribution Transformers	221 network units in Oakland. 1128 network units in San Fran.
Network Transformer Sizes	Most common is size – 500 and 750 kVA on the Grid. 1000 kVA spots.
Network Protector Sizes	Current Standard: 1875, 2825, 3500 Amps
Primary Cable Types	12kV – PILC 35kV – XLPE, EPR (more recent standard) EPR used as primary sections are replaced
Primary Cable Sizes	12kV - 750 cu, 500 cu, 250 cu, #2 cu 35 kV - 1100 Al, 700 Al, 350 Al, 1/0 Al
Secondary Cable Sizes	1000 cu for transformer ties; 250 or 500 cu for the street mains.
Civil Construction	Use primarily poured in place construction in the network because of varying field conditions. Will use precast construction in other locations.
Peak Network Load	San Francisco – 300 mVA Oakland - 68 mVA
Annual Network Load Growth	Flat since 2007.
Preventive Maintenance Programs
Network Protector Inspection	Annual
Network Protector Maintenance And Testing	Three years
Network Transformer Inspection, Maintenance And Oil Testing	Annual
Vault Inspections	Annual
Vault Environmental Cleanup	Number of cleanups based on findings from annual vault inspection
Manhole Inspections	Three years

2.16 - Portland General Electric

2022

The term CORE is used to describe the group that is responsible for the central Portland underground infrastructure, including the network. The term stems from this infrastructure being at the core of their downtown.↩︎

Name	Portland General Electric
Utility Type	Public utility
Web Site	http://portlandgeneral.com/
Contact	John Watkins; John.Watkins@pgn.com Kenneth Atagabe; Kenneth.Atagabe@pgn.com
Number of Electric Customers	Approximately 1.9 million customers. The urban underground network in Portland, OR serves 2200 customers
Location Description	Networks in downtown Portland, serving a geographic area of about 1.5 mi² (3.9 km²)
Network Organization	The network group operates as part of the Portland Service Center in the Eastern Region. This is referred to as the CORE ¹.
Workers Represented by Collective Bargaining?	Yes, IBEW.
Job Progression	Journeyman Linemen enter the underground group as a Cable Splicer Assistant and advance to Cable Splicer after one year. The apprenticeship to become a journeyman lineman is a 3 ½ year mandatory progression with testing and training.
Number of Field Network Electrical Workers	There are currently 16 people working in CORE, including 4 non-journeymen, 11 journeymen (assistant cable splicers, cable splicers, foremen), and a Special Tester.
Number of Distinct Secondary Networks Served	Two substations serve five networks. Our 11kV networks were cutover to a 12.4 substation in 2019. One substation (Canyon. Open bus) supplies three area networks, and the other substation (Marquam. GIS ring bus built in 2019) supplies two area networks and has the capacity to source 5 total area networks.
Network Primary Operating Voltages	Both substations operate at 12.4 kV.
Network Secondary Voltages	125 kV/216 kV and 27 kV/480 kV (all spots) volt systems
Number of Primary Feeders Supplying each Network	Four
Design Contingency	N-1 (in some locations, can provide N-2)
Number of Network Distribution Transformers	280
Network Transformer Sizes	500 kVA, 750 KVA or 1000kVA. For spot networks, transformers can be 500, 750, 1000, or 1500 kVA
Network Protector Sizes	1875 A, 2825 A and 3500 A
Primary Cable Sizes	PGE has a combination of in-service PILC and EPR insulated cable. The company’s current standard is to use EPR, and the company has a proactive lead cable replacement program underway. Standard size is 500 cu, with a flat strap neutral. The EPR cable is designed to fit conduits of less than 4 in. (10.2 cm) in diameter. (PGE installs three tri-plexed conductors.) PGE has 3.5 in. (8.9 cm) in clay tile ducts in many locations.
Secondary Cable Sizes	500 MCM diameter copper cables, and a reduced insulation 750 MCM
Civil Construction	Mostly external contractors
Annual Network Load Growth	Load growth in the network has been moderate. Most of the load gains are from load that was lost in 2020 when COVID forced most workers to work from home or businesses closing their doors.
Preventive Maintenance Programs
Network Protector Inspection, Maintenance and Testing	Testing is annual for 480-V units and every two years for 216-V units. Maintenance is performed with the primary feeder energized and is accompanied by complete vault inspection
Network Transformer Inspection and Maintenance	An informal cycle is used, and is usually performed in conjunction with NP maintenance. We are currently working on a comprehensive maintenance plan for the UG Core. The project starts with taking an audit of all our Vaults and MHs. Then create a cycle for inspections and/or maintenance based on what is in the vault of MH.
Transformer Oil Testing	A four-year cycle is used, and is accompanied by complete vault inspection.
Vault Inspections	An informal cycle is used, and is usually performed in conjunction with equipment maintenance and testing. We are currently working on a comprehensive maintenance plan for the UG Core. The project starts with taking an audit of all our Vaults and MHs. Then create a cycle for inspections and/or maintenance based on what is in the vault of MH.
Vault Environmental Cleanup	Clean vaults as part of inspection. We are currently working on a comprehensive maintenance plan for the UG Core. The project starts with taking an audit of all our Vaults and MHs. Then create a cycle for inspections and/or maintenance based on what is in the vault of MH.
Manhole Inspections	An informal cycle is used, and is generally inspected every year. We are currently working on a comprehensive maintenance plan for the UG Core. The project starts with taking an audit of all our Vaults and MHs. Then create a cycle for inspections and/or maintenance based on what is in the vault of MH.

The term CORE is used to describe the group that is responsible for the central Portland underground infrastructure, including the network. The term stems from this infrastructure being at the core of their downtown.↩︎

2.17 - SCL - Seattle City Light

2007

Name	Seattle City Light
Utility Type	Municipal
Website	http://www.ci.seattle.wa.us/light/
EPRI Contact	Hamed Zagehgol, P.E. 206 233 2186 Hamed.zagehgol@seattle.gov
Number of Customers	375,000
Population Service	738,000
Location Description	The city of Seattle, WA, and surrounding area.
Network Organization	Dedicated network resources for network planning, design, construction and maintenance.
Workers represented by collective bargaining?	Yes, Field Force is represented by IBEW, Local 77, and Engineers are represented by IFPTE, Local 17.
Automatic Mode of Progression?	Yes, transition from apprentice to journeyman Cable Splicer in three years.
Number of field electrical	87
Number of field Civil	36
Number of network planners and Designers	23, (8 System, 8 Service Engineers, and 7 IT support individuals for their NetGIS system)
Total Network Employees	146
PHYSICAL / GENERAL INFORMATION
Number of Network Customers Served	22917 meters
Number of distinct secondary networks served	15 “Sub – networks” (a sub-network is an isolated secondary network usually sourced by six primary feeders)
Network primary operating voltage(s)	13.8kV, 26.4kV Downtown networks (12 subnets) supplied at 13.8 kV First Hill and University District networks supplied at 26.4 kV
Network Secondary voltages	208Y/120, with cable limiters 480Y/277, with cable limiters
Number of primary feeders supplying each network	6 primary feeders per each sub network. (3 sub networks are sourced by less than 6 feeders) All network feeders for a given network sourced from the same substation.
Design Contingency	N-1
Number of Network distribution Transformers	Approx 1200
Network Transformer sizes	500-2500 kVA
Network Protector Sizes	1875 – 4500 Amp
Primary Cable Types	PILC ( 8 %) XLP (majority of the installed cable) EPR (Used for new construction at 13kV)
Primary Cable Sizes	Various, from AWG #4 to 1000 kcmil cu
Secondary Cable Sizes	Various, from AWG #2 to 750 kcmil cu
Civil Construction	Precast vaults (for new vaults other than locations where it is not possible – in these, use concrete poured in place)
Total Company Peak Load	2025 MW
Peak Network Load	339 MVA
Annual Network Load Growth	.9% Company load growth 2-2.5% Local Network Growth
Preventive Maintenance Programs
Feeder Maintenance	4 year cycle, includes manhole inspection, switch maintenance, transformer maintenance
Network Protector Maintenance	4 year cycle, performed independently of the feeder maintenance program, primary feeder remains energized

2.18 - Tampa Electric

2022

Name	Tampa Electric
Utility Type	Investor-Owned Utility
Web Site	www.tampaelectric.com
Contact	Scott Hartlage / Travis Ammann
Number of Electric Customers	Approximately 700K customers. The urban underground network in Tampa serves 50 buildings / vaults
Location Description	Networks in downtown Tampa, FL, serving a geographic area of about 0.45 mi²
Network Organization	CSA Network Operations Installs, Troubleshoots, Locates Faults, Repairs, and Maintains Network Txs, Network Protectors, Primary & Secondary Cable, PILC Splices, Switches/Switchgears, Transition Modules, and Viso Blocks.
Workers Represented by Collective Bargaining?	19
Job Progression	4 ½ year apprenticeship to become a Network Specialist.
Number of Field Network Electrical Workers	9 Network Specialists and 9 Apprentice Network Specialists
Number of Planners and Designers	4
Annual Network Load Growth	0
Number of Distinct Secondary Networks Served	5 Distinct Secondary Networks
Number of Spot Networks	22
Miles of MV UG cable in networks
Miles of LV UG cable in networks
Network Primary Operating Voltages	13.2 kV
Network Secondary Voltages	480Y/277 Spot, 208Y/120 Spot, 216Y/125 Grid
Number of Primary Feeders Supplying each Network	6
Design Contingency	N-1, N-2
Number of Network Distribution Transformers	93
Network Transformer Sizes	500 kVA, 750 kVA, & 1000 kVA for 216V Grid 1000 kVA for 208V Spot,750,1000,1500,2000,2500 kVA for 480V Spot
Network Protector Sizes	1200A,1600A,1875A,2000A,2500A,3000A,3500A
Primary Cable Types	PILC / TR-XLPE / EPR
Primary Cable Sizes	#2 PILC,350,500,&750 MCM PILC,4/0 ALJCN TR-XLPE & 500 MCM EPR
Secondary Cable Types	TR-XLPE
Secondary Cable Sizes	500 MCM CU
Civil Construction	Indicate whether civil construction is performed by in house or contractor resources. Developer or Contractor Also indicate whether UG structures are typically precast, or poured in place. Poured in Place
Preventive Maintenance Programs
Network Protector Inspection, Maintenance and Testing	Yes, annually.
Network Transformer Inspection and Maintenance	Yes, annually.
Transformer Oil Testing	No.
Vault Inspections	Yes, annually and infrared just before entering a vault.
Vault Environmental Cleanup	Yes, when needed.
Manhole Inspections	Yes, annually and infrared just before entering a manhole.
List any other preventive maintenance programs

3 - Construction

3.1 - Account Management-Scheduling

3.1.1 - Portland General Electric

Construction & Contracting

Account Management - Scheduling

People

The Planning and Scheduling Department is responsible for assigning work to crews, scheduling projects, and ensuring efficient usage of human resources.

Process

Scheduling: PGE moved from an all-paper system to a work management system using Maximo. All the work provided to the crews is scheduled in Maximo and sent to the field through electronic field devices. Early in the adoption of this system, PGE experienced a learning curve. Some work orders became lost, and workers struggling to utilize the new system. An intensive information technology (IT) training program targeted to field workers rectified these challenges.

Until about two years ago, the CORE area was “siloed” in that the CORE group management made scheduling decisions without involving other organizations. CORE work now passes through the Planning and Scheduling Department, which looks at resourcing and scheduling across the company. PGE tracks work using metrics.

One unique restriction on work scheduling in the CORE is that during the Portland Rose Festival, the city limits the number of permitted road closures and PGE’s access to network infrastructure.

Technology

PGE uses IBM’s Maximo for Utilities 7.5 system for work management, and the system supports all work types. The system allows users to create detailed work estimates and manage field crews. Maximo can integrate with a number of systems, including fixed-asset accounting, mobile workforce management solutions, and graphical design systems. The Maximo Spatial system is compatible with map-based interfaces, such as ESRI ArcGIS, and follows J2EE standards [1].

Maximo for Utilities supports estimating compatible units (CUs) and managing field crews. With the support of a CU library, planners and designers can estimate CUs when creating a project, and users can manage crews and track crew type and composition [2].

[1] T. Saunders, J. Souto Maior, and V. Garmatz. “IBM Maximo for Utilities.” IBM, 2012.
ftp://ftp.software.ibm.com/software/tivoli_support/misc/STE/2012_09_11_STE_Maximo_for_Utilities_Upgrade_Series_v4.pdf
(accessed November 28, 2017).
[2] IBM. “IBM Maximo for Utilities, Version 7.5.” IBM.com. https://www.ibm.com/support/knowledgecenter/en/SSLLAM_7.5.0/com.ibm.utl.doc/c_prod_overview.html (accessed November 28, 2017).

3.2 - Cable Installation and Replacement

3.2.1 - AEP - Ohio

Construction & Contracting

Cable Installation / Cable Replacement

People

Electrical work with network infrastructure at AEP Ohio, including cable replacement, is performed by Network Mechanics, which is a bargaining unit position responsible for performing all network construction and maintenance activity, including cable pulling, cable splicing, and network equipment construction and maintenance. Organizationally, network field resources are centralized, with the field resources who work with the Columbus networks reporting out of one service center, and resources who work with Canton networks reporting out of another. These service centers are led by a supervisor, and consist of Network Crew Supervisors, the front line leadership position, and the Network Mechanics. Organizationally, the service centers are part of Regional Operation reporting ultimately to the Vice President of Distribution Regional Operations.

Project work orders, repairs, and maintenance are scheduled and dispatched from the Service Centers. Some replacement is outsourced to contractors, working alongside AEP Ohio field crews.

At the time of the practices immersion, AEP had embarked upon a system-wide effort to replace selected secondary network cables to improve the reliability of the network infrastructure, with each operating company deciding what parts of the network infrastructure should be targeted for replacement. This work is being performed primarily by contractor resources.

In addition, AEP Ohio is proactively replacing selected primary network cables primary cables in high risk and congested areas.

Process

After a number of incidents involving fire in manholes caused by faulty secondary cables, AEP Ohio performed a risk assessment of its secondary network infrastructure to identify what part of the cable fleet should be considered for replacement. The comprehensive assessment of the secondary cable system included the following:

On-the-ground inspection of cables s by camera during cable fire investigations
Scientific modeling of the existing secondary cable and its loads
Load flow models to identify cables that are overloaded or nearly fully loaded
Examination of failed secondary cable at AEP Ohio, as well as outside testing by a third party consultant.

As a result of these studies, AEP Network Engineers found that existing styrene butyl cable was primarily responsible for the incidents that had occurred in the system. Analysis found that its insulation breaks down due to overheating and may produce combustible gases. These gases may contribute to manhole fires.

AEP has decided to replace the entire butyl cable fleet, prioritizing the effort based on various factors including visual inspection and load analyses performed by Network Engineering.

In addition, AEP Ohio has found that while secondary lead cables fail infrequently, when they do fail, they can result in a hot fire, which can potentially threaten other cables in the duct lines. Therefore, lead cables are also scheduled for replacement under this revitalization and refurbishment project.

AEP Ohio had initially prioritized the secondary cable replacement according to conditions and loads as shown on Figure 1. Subsequent to the EPRI practices immersion, AEP has since updated the risk model for mitigation of secondary network cable failures to a 12 step model.

Figure 1: AEP Ohio mitigation and prioritization strategy for secondary cable replacement

The cable replacement project, totaling $300 million, will ultimately replace nearly 60,000 feet of secondary cable at AEP Ohio. The Network Engineering Supervisor meets weekly with service center leadership to review the progress of the secondary cable replacement effort in Columbus and Canton. AEP has a protocol in which if any area becomes more than 20% behind schedule, the rationale for the schedule must be shared with an officer of the company who becomes involved in developing a solution. At the time of the immersion, the project was ahead of schedule at AEP Ohio (see Figure 2).

Figure 2: Target and actual secondary cable replacement curves for AEP Ohio

From its experience, some of the potential challenges have been:

Identifying and assuring adequate crew leadership for both company and contractor crews.
Weather can adversely impact schedules.
Choice of crab and size of crab support, based on limited manhole size and desired mounting orientation.

Secondary butyl and other cable types are being replaced with 750 cu EAM insulated cables. The 750 EAM cable was chosen by the engineers because it is the largest sized cable that will fit in the current duct lines (3 ½ inch) and has the capacity and thermal rating required by the network. The older butyl cable was rated at 70 degrees C, whereas the 750 EAM is rated at 90 degrees C (see Figure 3). AEP seeks to maximize the use of duct space, including keeping open ducts available for communications. Figure 4 shows new secondary cables being installed.

Figure 3: 750 cu EAM secondary replacement cable rated"

Figure 4: New secondary cables being installed

For network primary cables, AEP Ohio design criteria specify that there cannot be more than two circuits supplying any one network in the same manhole. For distribution (non-network) circuits, the company limits the number of circuits in any one manhole to three. AEP engineers reviewed circuit maps to identify congested locations in the network and initiated targeted projects to modify construction to adhere with the criteria.

Technology

AEP Ohio uses cable ratings and load flow analysis in CYMECAP and CYME SNA to identify overloaded cables and cable designs that are due for replacement. The AEP Ohio NEED database is used to record and track all serialized assets and cables, including on-site inspection of cables that are deemed in need of replacement. Once cable is replaced it is updated in the AEP mapping systems and in the Smallworld GIS system for company-wide access.

AEP has sent cable samples for testing (to both internal and external laboratories) to better understand the condition of selected cable populations. Figure 5 shows an AEP Ohio cable pulling truck.

Figure 5: AEP Ohio cable pulling truck

3.2.2 - Duke Energy Florida

Construction

Cable Installation / Cable Replacement

People

Duke Energy Florida has a formal primary cable replacement program in place, which includes replacement of cables for both network and non-network feeders. The St. Petersburg and Clearwater replacement program is a two-year program, with a goal to replace 60,000 feet of older cable per year in the South Coastal Region.

The cable replacement is being performed by contractor crews (six people), who are performing the complete installation, including cable pulling and cable splicing. The crew is on a two-year contract, working on 35-40 cable pulling locations that involve network infrastructure. The contractors provide all equipment, such as cable pulling gear, heavy trucks, etc. The crews start the workday at a remote mustering point, and report to a Duke Energy Network Specialist who has been temporarily appointed to provide contractor oversight. Because of the size of the project, it is also being managed by the Resource Management group, who meets twice per month with the contractor for progress updates.

In addition to the cable replacement program, Duke Energy Florida network crews are replacing secondary mole connections throughout the Clearwater and St. Petersburg network system for network hardening. Duke Energy Florida has proactively targeted replacement for older mole connections in manholes prone to long periods of time underwater. Duke Energy Florida has found that these secondary cable mole connections are subject to bloating and cracking over time.

Process

One driver for the cable replacement program was that the company had experienced a high amount of faults on older cables due to a deterioration of the metal type center plug used at T-body connections. The standards group decided to replace the metal type body center plugs and cable to harden the underground network system. Figure 1 shows a typical center plug with a metal ring used on the Duke Energy Florida network system.

Figure 1: Center plug with metal ring

Historically, Duke Energy Florida’s cable design called for the use of T-bodies (600A separable connectors) for both straight as well as Y and H splices, so that cables could be easily separated for fault locating, maintenance and for future system enhancements. Historically, the center plugs used in the T-bodies were designed with an exposed metal ring which was prone to deterioration / corrosion with age and with prolonged submersion in water. Figure 2 shows a crack on a failed center plug with a metal ring.

Figure 2: Crack in failed center plug

Recognizing they had a high concentration of cables with the T-bodies with the suspect center plug component in downtown St. Petersburg, and that the cables were of an older vintage (early 1980s) nearing the end of the cable life, Duke Energy Florida elected to perform a targeted cable replacement, rather than solely replace the center plugs associated with T bodies. Figure 3 shows the replacement center plugs currently being installed. Figure 4 shows a close up of the Elastimold center plug without an exposed metal body.

Figure 3: Replacement center plugs

Figure 4: Close-up, replaced plug, no metal exposed

Duke Energy Florida noted that it is virtually impossible to just replace the center plugs, because before unbolting and parting the cable, their process calls for spiking the cable to confirm that it is de-energized, thus damaging additional infrastructure that must be replaced. When they encounter a vault or manhole that contain T-bodies with the older center plugs, they will not enter the hole while the cable is energized. They will schedule for replacement, sectionalizing to de energize and isolate the section, before performing replacement with new components.

Duke Energy Florida has already identified approximately 43 locations with T-body connections with the older style center plugs to be replaced. At most of these locations, the T-bodies are submerged. Their experience has shown failures often occur after the water is removed. The primary reason for the failure is because the water serves to pass the electrical stresses across the center plug. After the water is removed, the plugs tend to fail because of additional electrical stress on the plug.

Duke Energy Florida is also performing a further assessment in the other portions of its service territory to identify other cable populations that may also be built with T-bodies with the metal ringed center plug component, in order to determine whether to expand the replacement program.

Technology

Duke Energy Florida is installing Elastimold K651CP connecting plugs as replacements for the older metal body T plugs previously used. The Elastimold K651CP is a deadbreak connector that can be removed when the cable is energized to facilitate work on the connected cable.

3.2.3 - ESB Networks

Construction & Contracting

Cable Installation / Cable Replacement

People

Cable installation at ESB Networks is performed by Network Technicians, the journey worker position. The Network Technician is a mutli-faceted position, performing both line work, such as building pole lines, and electrical work, such as making connections at a transformer. Network Technicians work on all voltages from LV through transmission voltages (110 kV). Note that ESB Networks created the Network Technician position in the 1990s by combining a former Line Worker position and Electrician position.

Work specialization for Network Technicians is by assignment. In Dublin, where the majority of the distribution infrastructure is underground, Network Technicians work mainly as cable jointers, installing underground cables and accessories. ESB Networks rotates Network Technician work assignments as business needs require.

Much of the cable installation and replacement in the ESB Networks underground network is performed by contractors. In the past, graduate student engineers were used on line work, but this has become far less frequent in recent years. Otherwise, cable replacement and installation is performed by Network Technicians, who work on all cable voltages.

ESB Networks has a four-year apprentice training program for attaining the journeyman Network Technician position. Network Technicians who worked as cable jointers work closely with both the Training group and the Asset Management groups at ESB Networks. Network Technicians readily bring information about problems with particular cable joints back to these groups.

The Training and Underground Networks group within the Assets & Procurement organization share the process of performing forensic analysis of failed joints and in preparing the failed component summary reports. Within both groups, ESB Networks has significant cable/cable accessory expertise. Both groups work closely with Network Technicians to ensure that they understand the science of cable joints and have an appreciation for the importance to long-term joint reliability of performing the proper steps associated with cable joint preparation.

Process

ESB Networks has installed significant amounts of MV (10-kV and 20-kV) cables over the past 10 years. Thirty-four percent of the total in-service MV cable has been installed in the past few years. Most of this installation has been outside of Dublin, in both rural and urban areas. Figure 1 shows the total amount of installed MV cable from 2000 to 2012.

Figure 1: Installed MV cable

ESB Networks has also installed significant amounts of LV cables – used for their LV network mains. Thirty-seven percent of the total in-service LV network cables have been installed within the past seven years (statistic includes replacement of cables). Figure 2 shows the total amount of installed LV cable from 2000 to 2012.

Figure 2: Installed LV cables

Technology

ESB Networks has embarked on a five-year cable replacement program and is spending €11.4M on replacing oil filled cables and terminations due to higher than acceptable failure rates in recent years. The company is also replacing lead cable by retrofitting 38 kV PILC cables with XLPE, especially within the business district.

ESB Networks’ approach in developing its replacement plan includes determining ESB Networks’ overall risk profile, comparing age versus performance of cables older than 65 years. In all, ESB Networks will replace 18 km of cables that are the critical feeds for the city. ESB Networks estimates this replacement will reduce the risk of failures by approximately 50 percent. As part of its replacement program, ESB Networks is also targeting older (pre-1982) XLP insulated cables, as this cable had been experiencing an average of eight faults per 100 km.

3.2.4 - Georgia Power

Construction & Contracting

Cable Installation / Cable Replacement

People

Georgia Power utilizes a combination of PILC cable and EPR insulated cable in its Atlanta network. They continue to use lead cable in some locations where they may be limited by conduit size, or locations where they may require a Y splice in a limited space. However, the company is increasing its use of EPR cable for new installations where practical.

Note: in Savannah, Georgia Power has replaced its lead secondary cable with EPR insulated cable.

Cable replacement is supervised by a senior engineer in the Network Underground group. Senior Cable Splicers within the group perform any needed cable replacement.

The Georgia Power Network Underground group has not historically performed routine diagnostic testing of network cables other than fault location testing and some proof testing after cable repair. Therefore, cable is replaced on an as-needed basis as determined by inspection, cable failure, or on recommendation of the supervising engineer.

Process

Because of its durability and space constraints in older duct lines Georgia Power is maintaining the use of lead cables in its four-inch duct lines and wherever it is currently performing well (See Figures 1 through 3.). If a lead cable fails in a larger duct or a manhole with room to accommodate newer EPR cable splicing, the group will replace the lead with EPR insulated cables and accessories. (Georgia Power engineers noted that an EPR-type Y-splice at 20kV takes up virtually all the wall space in the manhole at most locations, and thus reduces their flexibility for future expansion. A lead Y splice is far more compact.)

Figure 1: Lead cable joints

Figure 2: Lead cable joint preparation

Figure 3: Lead secondary cables - Atlanta

The Network Underground group is concerned that there is only one domestic source for its lead cable, and thus may become more aggressive in the future in replacing lead, particularly if a smaller form-factor EPR proves reliable (See figure 4.).

Figure 4: EPR secondary cables - ring bus, Savannah

Technology

Georgia Power‘s lead cable system is extremely reliable. They establish performance goals for cable in terms of cable failures per year. For example, the goal for 2013 was to have no more than 23 cable failures. Cable failure performance is tied in with the overall performance management process at Georgia Power.

The utility industry is moving away from the use of lead-covered cables because of limited availability, environmental concerns, and complex splicing and terminating requirements. GPC’s Network Underground group is actively researching and testing other cable types as a replacement for lead. They are using more solid-dielectric cable at medium and low voltage. New and improved cold-shrink splices and terminations are being evaluated and will accelerate the move toward solid-dielectric cable

3.2.5 - Portland General Electric

Construction & Contracting

Cable Installation / Cable Replacement

People

PGE has a proactive cable replacement program aimed at replacing PILC primary network cables with EPR insulated cables.

Three Distribution Engineers focus on both the networks and non-network infrastructure in the CORE. The engineers provide technical data and perform risk assessments used for the Strategic Asset Management Program, which evaluates the economic benefits of programs, such as cable replacement.

The CORE underground falls within the Portland Service Center (PSC). The resources focused on the CORE are responsible for both non-network (radial) underground and network systems. The CORE resources perform cable replacement.

Process

The PILC network cable replacement program is part of an initiative called the Performance Improvement Assessment (PIA), which utilizes detailed root-cause analyses performed by the Network Engineers to drive actions to improve performance. The scope of the program is to replace all current lead primary feeders with EPR insulated cables. PGE is focusing on replacing primary cables before moving towards a proactive secondary lead cable replacement program planned for the future. PGE often performs lead cable replacement at night because of city restrictions on closing the streets during the day.

As part of its Strategic Asset Management Program, in 2013, PGE developed an economic lifecycle model to evaluate cable, using data gathered by crews over the past 40 years. This supported a model that used the correlation between age and insulation type, which recommended a program of replacement and/or injecting XLPE cable.

PGE assessed that targeted cable replacement would improve reliability by removing a significant risk posed by aging cable. As part of a strategic asset management program, PGE’s model evaluated approximately 11,300 conductor miles (18,185 km) of cable and determined which sections were most likely to experience failure. After this, the model determined which areas would cause the most disruption according to loading and/or customer numbers. In total, PGE has replaced 203 conductor miles (327 km) of cable [1].

Note that the use of the economic lifecycle model described above has not yet been applied to network cables. Because the replacement of lead cables in the network was already occurring from the PIA, the Strategic Asset Management Group deferred inclusion of an analysis of network cables in the economic lifecycle model though it still plans to include it in the program.

PGE does not presently perform any routine diagnostic cable testing on the network. In the past, they have performed some diagnostic testing on primary network cables crossing the river. Before commissioning new cable or returning a de-energized primary circuit to service, crews perform a direct current (DC) high potential (hipot) test. Very low frequency (VLF) testing is performed on the getaway cables at substations. PGE is not performing a tan delta test.

Technology

For connecting lead cable to EPR, PGE uses Raychem Transition Splices. Although the company prefers pulling EPR all the way, that is, fully replacing the lead cable with EPR insulated cable, the Raychem splices are used if this is not possible.

Before cutting a cable, crews test it using a device called a hummer to verify its de-energized state. If the cable is energized, the device will “hum” significantly [2]. Note that use of the hummer is not foolproof. PGE relies on a combination of maps, tags, and the hummer device to identify de-energized cables. The standard work practice is to cut a cable remotely by placing a “guillotine” cutter on the cable and activating it from outside the vault.

Figure 1: A “hummer” to verify the de-energized state of a cable

Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).
D. Johnson, BIS Consulting, “A stepwise approach to building a cable program.” Presented at the WEI Operations Conference, Newport Beach, CA (April 19, 2017). https://uploads.westernenergy.org/2017/05/05103408/EAM_Thu_1000_1of2_Johnson_WEI-2017-Underground-cable-program-draft-032617.pdf (accessed November 28, 2017).

3.2.6 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 7.6 - Cable Pulling

3.3 - Cable Pulling

3.3.1 - Ameren Missouri

Construction & Contracting

Cable Pulling

People

Cable pulling at Ameren Missouri is normally performed by underground construction resources within the Underground Construction group, led by a Construction Superintendent. The Underground Construction group is part of the Underground Operations Center.

The Underground Construction group is comprised of Cable Splicers, Construction Mechanics, and Assistant Journeymen, a new position at Ameren Missouri that combines the duties of Construction Mechanics and Cable Splicers. The group also has a Utility Worker classification, an entry level position from which Cable Splicer and Construction Mechanic positions are filled. Cable Pulling can be performed by any of these classifications, and is sometimes contracted.

Cable pulling design, including calculation of pulling tensions, is performed by Estimators (Energy Services Consultants) or engineers, part of the Division Engineering group. Note that most cable runs in downtown St. Louis are relatively short; thus, the calculation of cable pulling tensions is not required.

Process

Ameren Missouri estimators perform cable pull calculations using in-house cable pulling software based on Excel. Most cable runs in downtown St. Louis are so short, that the calculation of cable pulling tensions is not required. However, estimators noted that they periodically must perform pulling calculations for installations where services are being pulled from the street grid into a building, as these services utilize 600 V secondary network cable with a rubber jacket that tends to create more friction, and increases sidewall bearing pressure. In these situations, installation crews must work at a low enough winch speed to prevent damage to cable or conduit.

Figure 1: Cable trailer

Technology

Ameren Missouri is using an in - house, Excel based software to perform cable pulling calculations. This in – house software is based upon the Ameren Missouri engineering design standards, and allows the estimator to enter known variables to calculate safe tolerances for cable pulling. For example, the Excel spreadsheet allows the user to select the cable and conduit types, the number and severity of bends, and the coefficient of friction estimates for the pulls. Note that Ameren Missouri is considering acquiring the DSTAR (Distribution Systems Testing, Application and Research program) Cable Pulling Assistant.

Ameren Missouri is using a reduced wall cable design so that they can utilize older, narrower ducts for cable replacement, avoiding the cost of installing bigger conduits to handle thicker conventional diameter insulated cables. See Cable Design

Ameren Missouri is using the OK Champion Cable Scrapper truck to remove, and cut abandoned cable.

Figure 2: OK Champion Cable Scrapper

3.3.2 - CEI - The Illuminating Company

Construction & Contracting

Cable Pulling

People

Cable pulling is performed by the UG Electricians who work in the Underground Network Services Department.

Process

In most cases, CEI is not performing any cable pulling calculations to determine pulling tensions, nor using a dynamometer to monitor the tension of a pull. They design their pulls so that they are well within the tolerances of the cable and “pull the cable not to break it”, using their experience. They will only use a dynamometer to monitor tension very large cable pulls.

Technology

When CEI does calculate pulling tensions, they do so manually. CEI corporate Design Standards is currently evaluating a piece of software for performing cable pulling calculations, sidewall pressure, etc.

CEI uses specialized cable pulling trucks to facilitate cable installation.

Figure 1 and 2: Cable pulling truck

3.3.3 - CenterPoint Energy

Construction & Contracting

Cable Pulling

People

Cable pulling at CenterPoint is performed by the Cable Splicers who work in the Cable Group of the Major Underground department.

Process

In most cases, CenterPoint is not performing any cable pulling calculations to determine pulling tensions, nor using a dynamometer to monitor the tension of a pull. Years ago they used to calculate pulls and use the dynamometer and found that their pull designs are well within the tolerances of the cable. They will only use a dynamometer to monitor tension on very large cable pulls.

CenterPoint typically uses a partitioned reel for a standard three phase installation. They will pull the cable off of a master reel onto the partitioned reel. For a new installation, they will typically pull three conductors through a six inch pipe.

A typical cable pull involves a five man crew. At one end, three men are stationed with the cable reel which is loaded onto a trailer. During the typical pull, one man is located outside the hole controlling the pay out of the cable, one man is in the hole directing the cable into the conduit, and the third man is applying a lubricant to the cable. At the other end, there is a two man crew with the cable pulling truck; one man controlling the winch line and monitoring the tension, and the other, the crew leader.

Figure 1: Cable Pulling Truck

Figure 2: Cable Pull

Figure 3: Cable Reel Trailer Note Partitioned Reel

Figure 4: Cable Reel Trailer Job site

Figure 5: Bucket of cable lubricant, from American Polywater© Corporation

At the end of the pull, because of the length of the pulling apparatus attached to the grips, the cable may not be in position to be put on the cable racks. Therefore, just before the end of the pull, the Cable Splicer will lash a nylon flat strap, around the cable in order to pull the cables into final position.

Figure 6: Cable Splicer applying nylon straps for final pull

Figure 7: Final pull before racking cable

Figure 8: Pulled in cables, racked (top)

3.3.4 - Con Edison - Consolidated Edison

Construction & Contracting

Cable Pulling

People

Construction Group

Con Edison’s service territory consists of four regions: Manhattan, Brooklyn/Queens, Staten Island, and Bronx/Westchester. The Manhattan Region is made up of three districts, including one headquartered at the W 28th St. Work Out Center. The term Work Out Center refers to a main office facility to which field construction and maintenance resources report.

The construction department consists of several groups, including the Cable Group, responsible for pulling and retiring cable.

Process

Conduit Size Restriction

One challenge that Con Edison faces is trying to expand capacity given the space limitations of and damage to existing duct bank systems. In some locations, spare ducts might be crushed or blocked. In others, the size of the spares is not adequate to pull through the necessary cable to meet loading. For example, in a design where 750 MCM cable is called for, Con Edison might have to consider running double 500s because the 750 cannot fit in the 10.16-cm (4-in.) spare conduit. The Brooklyn Operation Center noted that about 10% of their ducts are crushed. In Manhattan, the number of crushed ducts is significantly higher, at 45 – 50%.

In some cases, Con Edison bifurcates the feeders; that is, breaks the feeder into two sections outside the station in order to adjust to the limited space considerations and add reliability. In this design, Con Edison installs SF6 switches with fault indication outside the station, protecting each leg of the bifurcated feeder. In a feeder lockout, this enables them to isolate the faulted section and pick up the rest of the load. (See the pictures below for a photograph of a Con Edison 600-A, 27-kV Rated, SF6 gas-insulated submersible sectionalizing switch.)

Cable-Pulling Duct Preparation

One big challenge that Con Edison faces is obstructions in the ground. Crews often find that ducts have collapsed or are obstructed. These obstructions can be due to foreign utilities or vibrations from the subway that over the years cause ducts to collapse. In Manhattan, crews encounter obstructions in 45 – 50% of their projects.

Prior to installing cables in conduits, Con Edison has a defined set of operations that are performed on the conduit systems.

These operations include:

Rodding the ducts to establish that a clear passage exists through the conduit between structures and to provide a means of installing various lines to perform subsequent cleaning, mandreling, and cable-pulling operations.
Brush duct to remove any soil or debris that might have entered the duct since it was installed.
Clean duct if soil or debris prevents the rodding device from passing from one structure to another.
Perform mandrel operation to establish that a specific size passageway exists from one end of the duct to the other, and to establish that the duct is aligned so that horizontal and vertical bends meet the specified minimum radii requirements.
Install 1.27-cm (1/2-in.) steel rope, 1.42-cm (9/16-in.) steel rope, or 0.64-cm (1/4-in.) polypropylene rope (depending on the timing and type of pull).

Technology

Con Edison provides its employees with the specialized tools and equipment that they need to do their jobs, including trucks outfitted for the different types of work that they perform. Employees stated that they believed Con Edison provides them with good quality trucks, appointed with the equipment they need to perform their work. People demonstrated a sense of pride in their trucks and associated equipment.

An example of a specialized vehicle is a heavy-duty tandem axle flatbed underground cable-puller truck that is used by cable pullers to pull and remove cable.

See Attachment G for the Dejana Hub Drive Cable Puller Brochure.

3.3.5 - Duke Energy Florida

Construction

Cable Pulling

People

Organizationally, the Duke Energy Florida resources that construct and maintain the urban underground and network infrastructure fall within the Network Group which is part of the Construction and Maintenance Organization. More broadly, Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager. The region consists of various Operation Centers, organized either geographically or functionally throughout the Region.

The Network Group is organized functionally, and has responsibility for construction, maintain and operating all urban underground infrastructure (ducted manhole systems), both network and non-network, in both Clearwater and St. Petersburg. The Network Group is led by a supervisor who reports to the Region General Manager. The group consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position), all part of the Network Specialist job family.

The Network Specialist is a jack-of-all trades, position, responsible for all facets of UG work, including pulling cable. Network Specialists also work with the installation and maintenance of automation associated with the equipment they manage.

The Network Group at Duke Energy Florida has close ties with peers within Duke Energy sister companies throughout the country, and regularly shares information, lessons learned, and network standards with them.

While Network Specialists do pull cable, for new installations and for large replacement programs, the network group at Duke Energy Florida primarily relies on contractor resources to pull cable. These contracted employees work under the guidance and oversight of a designated Network Specialist.

Process

Contracted employees pull cable under the guidance of a Network Specialist who has been designated as oversight for the contract crews during cable pulling projects. Network Specialists with oversight of the cable pulling projects will inspect cable installation, take pictures, maintain a safe work zone, and make certain the contractors observe construction standards.

For the cable replacement project underway at Duke Energy Florida, the contractors also perform the associated cable splicing.

Technology

The Network Group supervisor has focused on identifying processes and tools that can improve the safety of cable pulling. At the time of the immersion, the Duke Energy Florida network team was assessing new cable rigging and pulling tools, such as the cable guide depicted below in figure 1

Figure 1: Cable Guide

3.3.6 - Duke Energy Ohio

Construction & Contracting

Cable Pulling

People

Cable pulling Duke Energy Ohio is normally performed by the Cable Splicers who work in the Dana Avenue department. Duke will also intermingle other resources on cable pulling crews, including overhead lineman, and network specialists. Contractor resources are often used in cable pulls.

Cable pulling design, including the calculation of pulling tensions, is performed by the Network Project Engineer, part of the Distribution Design organization.

Process

Duke Energy Ohio does design cable pulls, including performing cable pulling calculations on longer or more complicated pulls. Note that while the software Duke is using to perform cable pulling calculations can factor in the use of cable pulling lubricant, the Network Project Engineer typically calculates pulls without lubricants to more conservatively estimate pulling tensions.

Figure 1: Crewman in hole applying lubricant

Figure 2: Crewman at other end of pull with remote controller

Duke crews will monitor pulling tensions using the dynamometer on the truck during the pull, as some pulling tensions day encounter are rather high.

Duke Energy Ohio will use various combinations of trucks and trailers to perform the cable pull depending on the job. For example, they will use the rod truck as a cable puller in some instances. They will typically use reel trailers, with three conductors on the reel. Their trailers are equipped with an automated cable payout feature.

Figure 3: Cable Reel Trailer

Figure 4: Cable Reel, three conductor

Duke crews will pull the cable by conductor, attaching the pulling grips directly to the conductor itself to do the pull.

They use a non crimp, reusable cable pulling system by Condux ^[1] .

Figure 5: Cables being pulled into hole. Note non-crimp reusable pulling eyes attached to cable

Figure 6: Cables being pulled into hole. Note flat straps ('Cow tail') attached to cable to pull into final position

Crews noted that because of the age of their infrastructure, setting up the rigging to before cable pulls can sometimes be difficult. At the time of the immersion, Duke Energy Ohio noted that they were investigating the purchase of a new truck to facilitate the removal of retired cables in difficult or deteriorated installations (OK Champion Cable Scrapper).

At the end of the pull, because of the length of the pulling apparatus attached to the grips, the cable may not be in position to be put on the cable racks. Therefore, just before the end of the pull, the Cable Splicer will lash flat straps around the cable in order to pull the cables into final position.

Technology

Duke Energy Ohio is using a software product called Pull Planner 2000, to perform cable pulling calculations. See above figures.

^[1] www.condux.com

3.3.7 - Energex

Construction & Contracting

Cable Pulling

People

The Journeyman position for working with cable systems at Energex, including cable splicing and cable pulling is the cable jointer position. Employees move through the jointer apprenticeship program in about three and one half years. The apprenticeship includes formal training, testing, on the job training, and time in grade. At the conclusion of the apprenticeship, persons in the program must still must complete a “basket of skills” required by the electrical office. These skills are over and above the skills that are taught as part of the apprenticeship, but necessary for the employee to be a fully qualified jointer. Employees complete this basket of skills in the first 18 months after apprenticeship. Consequently, it takes 5-6 years in total before an employee is a fully qualified to run a job.

All jointers within the underground group are trained for CBD cable joining, operating in confined spaces, safe work practices in pits, and both high-voltage and low-voltage cabling. Jointers are trained in both Australian Qualifications Framework (AQF) and network-specific tasks before working on CBD underground splicing.

( See the Training section in this report. )

Process

Jointers work with cable and cable accessory installation and maintenance, including cable pulling, splice preparation, and cable replacement.

Technology

Energex utilizes a shear bolt connection, rather than a compression type connection for splicing, when preparing an 11 kV cable joint. They implemented the use of shear bolt technology for improved reliability.

3.3.8 - ESB Networks

Construction & Contracting

Cable Installation

People

Cable installation at ESB Networks is performed by Network Technicians, the journey worker position. The Network Technician is a mutli-faceted position, performing both line work, such as building pole lines, and electrical work, such as making connections at a transformer. Network Technicians work on all voltages from LV through transmission voltages (110 kV). Note that ESB Networks created the Network Technician position in the 1990s by combining a former Line Worker position and Electrician position.

Work specialization for Network Technicians is by assignment. In Dublin, where the majority of the distribution infrastructure is underground, Network Technicians work mainly as cable jointers, installing underground cables and accessories. ESB Networks rotates Network Technician work assignments as business needs require.

Much of the cable installation and replacement in the ESB Networks underground network is performed by contractors. In the past, graduate student engineers were used on line work, but this has become far less frequent in recent years. Otherwise, cable replacement and installation is performed by Network Technicians, who work on all cable voltages.

ESB Networks has a four-year apprentice training program for attaining the journeyman Network Technician position. Network Technicians who worked as cable jointers work closely with both the Training group and the Asset Management groups at ESB Networks. Network Technicians readily bring information about problems with particular cable joints back to these groups.

The Training and Underground Networks group within the Assets & Procurement organization share the process of performing forensic analysis of failed joints and in preparing the failed component summary reports. Within both groups, ESB Networks has significant cable/cable accessory expertise. Both groups work closely with Network Technicians to ensure that they understand the science of cable joints and have an appreciation for the importance to long-term joint reliability of performing the proper steps associated with cable joint preparation.

Process

ESB Networks has installed significant amounts of MV (10-kV and 20-kV) cables over the past 10 years. Thirty-four percent of the total in-service MV cable has been installed in the past few years. Most of this installation has been outside of Dublin, in both rural and urban areas. Figure 1 shows the total amount of installed MV cable from 2000 to 2012.

Figure1: Figure 1 - Installed MV cable

ESB Networks has also installed significant amounts of LV cables – used for their LV network mains. Thirty-seven percent of the total in-service LV network cables have been installed within the past seven years (statistic includes replacement of cables). Figure 2 shows the total amount of installed LV cable from 2000 to 2012.

Figure 2: Figure 2 - Installed LV cables

Technology

ESB Networks has embarked on a five-year cable replacement program and is spending €11.4M on replacing oil filled cables and terminations due to higher than acceptable failure rates in recent years. The company is also replacing lead cable by retrofitting 38 kV PILC cables with XLPE, especially within the business district.

ESB Networks’ approach in developing its replacement plan includes determining ESB Networks’ overall risk profile, comparing age versus performance of cables older than 65 years. In all, ESB Networks will replace 18 km of cables that are the critical feeds for the city. ESB Networks estimates this replacement will reduce the risk of failures by approximately 50 percent. As part of its replacement program, ESB Networks is also targeting older (pre-1982) XLP insulated cables, as this cable had been experiencing an average of eight faults per 100 km.

3.3.9 - Georgia Power

Construction & Contracting

Cable Pulling

People

Cable Pulling, including electrical cable and fiber, is performed primarily by Cable Splicers, although Duct Line Mechanics may also pull cable. Georgia Power enjoys good cooperation among the Cable Splicers and Duct Line Mechanics. They cite the fact that both positions are filled from the WTO position and thus have a common background as a reason for this good cooperation (See Job Progression in this report).

Cable pulling for larger projects may be given to a contractor.

The Cable Splicing crews report directly to distribution supervisors within the Network Underground Construction group at Georgia Power. The Network Construction group, led by a manager, performs all network construction activity, and is comprised of Cable Splicers, Duct Line Mechanics and Test Technicians. The Network Construction group is part of the Network Underground group.

Process

For new projects, the work package that goes to the construction crews includes several drawing types that provide the design and construction details.

Duct Line Mechanic crews receive duct line drawings that include plan and profile views.

Cable Splicers will receive cable racking drawings that specify the use of racks mounted on the vault or manhole walls and include specific cable racking instructions (which cables go where). See Attachment D.

Cable Splicing crews are provided with a detailed cable pulling sketch, also developed by engineering, which provides specifications on cable type, length, pulling tensions, etc. (See Attachment E ). Georgia Power underground network facilities are fairly close to one another, so that cable pulls are usually very short – no more than 500 feet in most cases. For very short pulls, the design may exclude pulling tension information.

Additional construction drawings include a one line diagram showing transformer locations, fuse location, wire sizes, etc.; permit drawings; easement drawings; and a transmittal document, which is signed off by the engineer and formally transfers the project to construction.

One notable practice at Georgia Power is the use of what is called the Peachtree racking system for positioning cables in manholes and vaults. Primary feeders are racked on the bottom, secondary feeders are racked on the top, and the neutral is on the very top (See Figure 1.). Each cable and splice is assigned a specific vertical and horizontal position on each rack. The racking approach is designed with future expansion in mind, with specific locations for joints. Feeders are numbered, from 1-6, also to more easily accommodate expansion and maintenance (See Figure 2.).

Figure 1: GA Power employee explaining benefits of Peachtree racking within a training manhole

Figure 2: Desktop training aid showing Peachtree racking approach

Technology

The Georgia Power Network Underground engineering group performs cable pulling calculations using both an in house Microsoft Access based tool and the Pull Planner software from Polywater. Most pulls within the Atlanta network are very short, less than 500 feet, and so pulling tensions are often not calculated.

Manholes are designed with bay forms built into the corners to minimize the required bends in the cable. Therefore, the cables can maintain the appropriate bending radius and still be positioned close to the wall. Georgia Power utilizes a duct camera system (Pearpoint Flexiprobe) to inspect duct integrity before pulling cable (See Figure 3 and Figure 4.).

Figure 3: Duct Rodder

Figure 4: Duct camera system

3.3.10 - HECO - The Hawaiian Electric Company

Construction & Contracting

Cable Pulling

People

Cable pulling is performed by both the Cable Splicers who work in the Underground Group, and Lineman who work in the Overhead C&M groups. Underground and Overhead crews will often collaborate on larger cable pulls. EPRI researchers noted high levels of cooperation between these two working groups.

Process

In most cases, HECO designs pulls such that they are well within the safe pulling tension limits of the cable itself. HECO will only calculate pulling tensions and use a dynamometer to monitor tension during very large or complicated cable pulls.

Technology

When HECO does calculate pulling tensions, they use Pull Planner software.

HECO uses specialized cable pulling trucks to facilitate cable installation, including a Rod trucked equipped to pull cable (See figure below left).

See Attachment H.

Figure 1: Rod Truck with Cable Pulling Feature

Figure 2: cable reel

3.3.11 - National Grid

Construction & Contracting

Cable Pulling

People

Cable pulling at National Grid Albany is normally performed by the field resources responsible for the underground system in eastern New York, called Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The group is comprised of Cable Splicers, Maintenance Mechanics and Mechanics, and is led by three supervisors. Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. Maintenance Mechanics perform network switching, fault location, minor vault maintenance, and inspection and maintenance of network equipment such as transformers and network protectors. Mechanics perform minor civil work.

Both the Mechanic and Cable Splicer classifications participate in cable pulling projects.

The Cable Standards contain guidelines for calculating pulling tensions. Cable pulling design, including the calculation of pulling tensions if required, is performed by the designers who support the Albany network, part of the Distribution Design organization, and physically located at the NYE building in Albany.

Process

National Grid designers perform cable pull calculation if required either using hand calculations (most often) or cable pulling software. Most designs are such that the calculation of pulling tensions is not required.

Technology

National Grid uses Pull Planner software, and hand calculations to determine pulling tensions.

3.3.12 - PG&E

Construction & Contracting

Cable Pulling

People

Cable pulling at PG&E is normally performed by the General Construction group. The General Construction Group serves as an internal contractor, supporting the M&C Electric Network group with services such as cable pulling and cable splicing. The General Construction group is comprised of cable splicers.

Cable pulling design, including calculation of pulling tensions, is performed by project estimators (Estimator and Estimator Senior) that work within the Service Planning group. These estimators are involved with new service projects and develop cost estimates, perform field checks and prepare the job packets for construction. The project estimators that work on network design projects are located in the San Francisco division.

Process

PG&E project estimators perform cable pull calculations using in house cable pulling software. Planning engineers will sometimes perform cable pulling calculations as well.

Technology

PG&E uses in house software to perform cable pulling calculations.

3.3.13 - Portland General Electric

Construction & Contracting

Cable Pulling

People

Cable pulling is the responsibility of the Underground Group, also known as the CORE group.

Organizationally, this group is part of the Portland Service Center (PSC) and is responsible for the underground CORE, which includes both radial underground and network underground infrastructure in downtown Portland. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen (also cable splicers) typically perform the work inside the manhole or vault, while the helper usually stays above ground, carrying material and watching the barricades and street for potential hazards.

The cable splicer position is a “jack-of-all-trades” position, whose responsibility includes cable pulling. A crew may include an equipment operator to operate the cable puller.

The group may use overhead crews for cable pulling when needed. They do not give additional training, and the CORE cable splicer oversees them.

Field Inspectors ensure that newly-built facilities have the required equipment for cable pulling.

Process

PGE is replacing all of its PILC network primary feeders with EPR insulated cables, and works primarily at night because the city has restricted street closings during the day. Although the company prefers to replace feeders in their entirety, pulling EPR all the way, PGE will use Raychem transition joints if this is not possible.

To support cable pulling, PGE standards for vaults and new cable from manufacturers include specifications for pulling hardware, such as pulling eyes. For example, newly built conduits are specified to include a non-conductive pull line, rated 500 lb (227 kg), with 6 ft (2 m) of line left extending from each end of the conduit. The vault specification includes requirements for pulling eyes.

For customer vaults, PGE Field Inspectors check that the vault meets the PGE specifications, including the correct hardware for cable pulling [1]. Pulling eyes should be installed on the wall opposite primary and secondary cable conduits, or in the ceiling if cable conduits emerge vertically from the floor. Pulling irons should be installed opposite of cable conduits for pulling, with a minimum working strength of at least 10,000 lb (4535.9 kg). Other pulling irons, ceiling anchors, and Burke clutches, if required, should be installed as specified by PGE for installing transformers.

New cable reels are specified to include factory-installed pulling eyes, which act as a common eye for all three phases of a triplexed cable set. New cable reels have a maximum working strength equal to the sum of the maximum allowable strengths for each of the center conductors of the triplexed cable set. The pulling eye also provides a waterproof seal for the cable end [2].

Portland General Electric, LD51030m Portland Core & Waterfront Districts Underground Core Standards, internal document.
Portland General Electric. From L20506 15-kV EPR Jacketed Concentric Neutral Cable, internal document.

3.3.14 - SCL - Seattle City Light

Construction & Contracting

Cable Pulling

People

At Seattle City Light, all network electrical workers are part of the Cable Splicer family; that is, the journeyworker Cable Splicer performs all of the tasks associated with building, maintaining, and operating a network system including cable pulling, splicing, construction, equipment inspection, and maintenance.

Technology

Diagnostic Camera

SCL has a camera device that they use for ascertaining the condition of conduit sections. The device is basically a camera head (maybe 5.08 cm [2 in.] in diameter) that fits on the end of a fish tape. The camera is connected to a display monitor that is usually viewed above the ground. A cable splicer pushes the fish tape with the camera on its head through a conduit, and the camera displays a 360-degree view of the inside of the conduit, revealing any cracks, debris, and so on.

SCL uses this tool primarily as a troubleshooting device. For example, they use this device when they have had a dig-in to ascertain the condition of the conduit. They also use the device in situations where they need to pull cable through a small duct. They run the camera through in advance to identify any deficiencies that could affect the pull.

Note: SCL is not presently using the tool as a preventive maintenance device.

3.3.15 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 7.6 - Cable Pulling

3.4 - Cable Quality Control

3.4.1 - AEP - Ohio

Construction & Contracting

Cable Quality Control

(Cable Inventory)

People

The specification for cable used in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineers in collaboration with the Network Engineering Supervisor. These personnel are geographically based in downtown Columbus at AEP Ohio’s Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is part of the Distribution services group at AEP, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Distribution Services group, including the Network Engineering Supervisor supports all AEP network design issues throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, which is headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and is comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations and holds regular teleconference sessions on network findings, “lessons learned” in the field, and potential network engineering solutions to common network design and implementation issues. Cable design and implementation issues throughout the AEP service areas are regularly studied and recommendations are made through this committee.

Process

Network Engineers require cable manufacturers to provide drawings of cable electrical and physical characteristics and provide certified test results. They will conduct periodic plant visits of the cable manufacturers.

AEP does perform some independent testing of cables using both internal laboratories (such as taking and examining cable wafer sections at their Dolan labs) and external labs.

Engineers noted that the quality of the cables they are receiving is very high.

3.4.2 - Ameren Missouri

Construction & Contracting

Cable Quality Control

People

Network standards, including standard designs for cable, are the responsibility of the Standards Group. This group develops both construction standards and material specifications for designs and equipment used in the network underground.

Organizationally, the Standards group is led by a Managing Supervisor, and is part of the Distribution Planning and Asset Performance Department, part of Energy Delivery Technical Services. Within this organization are experts who focus on developing and maintaining specific underground standards. For example, they have a cable engineer, who is an expert with cable and cable systems, and responsible for the development of cable standards for the company.

Ameren Missouri’s present standard calls for the use of EPR insulated cable for all cable systems. Because of limited duct size, Ameren Missouri has implemented the use of reduced-diameter 15 and 35kV cables for the replacement of paper – insulated lead-covered cables (PILC) cables. The reduced-diameter cable (145 mils vs. 175 mils for 15kV cable ; 300 mils vs. 345 mils for 35 kV cable) is being used for new and replacement applications in areas of St. Louis with small conduit sizes, and has resulted in significant cost savings.

Process

New reduced-diameter cables are accepted by Ameren Missouri without any supplemental diagnostic testing over what is performed by the cable manufacturer. Ameren Missouri believes that they are receiving higher quality cable in that the cable manufacturers have to run their cable manufacturing process more slowly to meet the tolerances required by Ameren Missouri. Ameren Missouri engineers noted that they have never had a true cable failure; that is, a cable failure due to a manufacturer flaw in the cable itself.

Ameren Missouri uses a vendor alliance with their network cable supplier.

3.4.3 - CenterPoint Energy

Construction & Contracting

Cable Quality Control

People

CenterPoint has formed a cable committee to address cable quality control issues. This committee meets monthly to discuss and resolve cable issues, including logistical and scheduling issues. The committee is comprised of an Engineering Projects lead, an Operations Manager, a Standards & Materials representative, representatives from Purchasing and Logistics, and a representative from CenterPoint’s cable vendor.

Note that CenterPoint has a sole supplier relationship with the cable vendor who supplies their EPR power cable.

Process

CenterPoint performs a “witness test” of every single reel that they purchase. For their EPR cables, a CenterPoint representative goes to the vendor laboratory, and witnesses the cable acceptance testing done by the vendor in accordance with ICC recommendations. The CenterPoint inspector has the right to reject an entire reel based on the outcome of this testing.

In addition, CenterPoint sends a 70ft sample from every reel to an independent laboratory for additional testing and analysis. This extra step has been useful to CenterPoint in identifying and addressing changing quality trends.

See Attachment - G , for a copy of the CenterPoint Cable Specification, which describes the qualification procedure in more detail.

Technology

CenterPoint uses EPR aluminum cables with a flat strapped neutral as a standard primary power cable for Major Underground (750 AA and 1000 AA at 15kV, 1250 AA at 35kV). CenterPoint uses XLPE insulated cables in URD applications.

3.4.4 - Con Edison - Consolidated Edison

Construction & Contracting

Cable Quality Control

People

Cable Supply

Con Edison has entered into an exclusive arrangement with its cable supplier. This single source has provided Con Edison preferred pricing and high levels of responsiveness from the cable manufacturer. Part of the arrangement with the cable manufacturer is that Con Edison doesn’t pay for the cable until it is installed in the ground. This provision has helped to reduce the lead time in obtaining cable from the manufacturer, and is an incentive for Con Edison to develop accurate forecasts of cable needs.

Incoming cable is not tested by Con Edison. The utility relies on the manufacturer’s report of testing performed by the manufacturer itself. These tests include partial discharge tests, ac voltage tests, and solderability tests on primary cables.

The arrangement with the cable vendor is not tied to the ongoing performance of the cable itself. When Con Edison has encountered problems, the utility has been able to track the problem back to a specific cable lot or reel. For example, in one case, they discovered some reels where the cable jacket was a bit thin. Con Edison has found the manufacturer to be highly responsive to problems that occur.

Cable Testing Laboratory

Con Edison has its own cable testing laboratory, which has been in operation since the 1970s. This laboratory has over 100,000 cable and accessory specimens. Sometimes the lab sends specimens to outside labs to obtain independent analysis and opinions.

Con Edison invests in keeping its laboratory staff current on the latest thinking in cable testing. They are active in industry groups. They invest in rotating new people into the cable department, including engineers from Con Ed’s Gold program (a mentoring program for high potential engineers and business professionals).

Process

Feeder Testing

Con Edison performs regular HIPOT testing of its network feeders (13.8 and 27 kV). HIPOT testing is the application of a specific voltage (high potential) on its network cables for a specific period of time to expose/bring to fruition incipient faults in the distribution system. Con Edison has a clear procedure that documents its approach to regular HIPOT testing.

HIPOT testing is performed at Con Edison for two main reasons:

1. A routine test to ensure that feeder insulation meets acceptable limits before the feeder is put into service. This applies to both new feeders about to be put into service, and to failed feeders that have been repaired and are about to be returned to service.

2. Scheduled tests performed annually (Annual Testing Program) on selected feeders for the purpose of revealing incipient faults that need to be restored to the proper insulation level.

See Cable Testing / Diagnostics for more information.

Technology

Cable Design

Con Edison is working with cable manufactures to remove potentially hazardous substances from their distribution cables. These substances include the fire-retardant bromides used in the Dual-Layer EAM cable insulation and the lead in the primary EPR cable insulation.

3.4.5 - Duke Energy Florida

Construction

Cable Quality Control

People

The specification of cable used in the urban underground networks in Duke Energy Florida is the responsibility of the Standards group, which oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies.

Process

The standard primary feeder cables supplying the Clearwater network are 4/0 cu XLPE insulated cables. Outside the network, Duke Energy Florida will use both 4/0 cu and 1000 MCM AL XLPE cable for feeder exits. Standard secondary cable sizes are 4/0 cu and 500 cu, also XLPE insulated. Duke Energy Florida has no remaining lead cables in their underground system.

Incoming cable and cable accessories are spot inspected to identify failures.

Duke Energy Florida currently uses a Facility Management Data Repository to report and document failed equipment. The report includes all relevant information, such as who discovered/reported the defect, where it happened, etc. These reports are issued as bulletins over the company’s internal network first to Standards, and then companywide via a Web portal. The emphasis at Duke Energy Florida is to catch defects before they lead to failures. The Network Group led the state in 2015 with these “good catches” that identified defects and corrected them before they caused network problems.

Failed cable samples are sent to a Duke Energy Florida Engineer for forensic analysis and/or sent to external laboratories for analysis. Overall, Duke Energy Florida has seen very few failures over the years.

Duke Energy Florida conducts routine cable diagnostic testing to determine the integrity of its primary cables, utilizing the services of a cable diagnostic testing contractor. Cable testing is age-based – with cables selected for testing that are 25 years or older, or that are suspect based on performance. Duke Energy Florida tests 80 segments per month over a nine-month period per year. The diagnostic testing performed by the contractor is not feasible in all situations, depending on factors such as manhole placement, circuit configuration, circuit condition, or feeder operation. Cable replacement decisions are driven by diagnostic test results. Depending on test results, the PQR&I group will determine whether a cable has integrity and remaining life or needs replacement. If replacements need to be made, the other Asset Managers who deal with circuit components are consulted to identify equipment replacement needs on the identified circuits.

Duke Energy also performs routine cable replacements that are based on cable age and performance history, rather than on diagnostic testing results. This is the case in St. Petersburg, where older cables are being replaced based on age and performance history, as these cables were not appropriate candidates for diagnostic testing (because of significant branching of cable sections.)

Asset Management is in the process of incorporating cable testing prior to energization of new cables into their program. The company believes this commissioning testing to be a good quality control check that can forestall outages.

Technology

Duke Energy Florida uses contractor cable testing that includes a checklist of over 170 cable conditions. The specific approach to diagnostics is proprietary.

Duke Energy Florida currently utilizes push on and crimped splices as a standard, but is considering standardization on cold shrink splices using shear bolt connections as a future standard. Overall, older push on and crimp solutions have experienced some failures due to workmanship issues, and Duke Energy Florida believes that the new standard will minimize workmanship problems.

3.4.6 - Duke Energy Ohio

Construction & Contracting

Cable Quality Control

People

Cable specifications are prepared by the Underground Standards group, located in Charlotte.

Current standard cables used for the Duke Energy Ohio Cincinnati network are 4/0 cu EPR and 750 cu EPR cables (750 with a flat strapped neutral).

Process

New cables are accepted by Duke Energy Ohio, after successfully passing a DC Hi pot acceptance test and an AC Tan Delta test. The AC tan delta is used to establish a baseline for future cable testing. The testing and establishment of this baseline is performed by one of the underground crews, compromised of individuals who have developed expertise in AC Tan Delta testing.

Duke Energy Ohio is not using a vendor alliance with their network cable supplier. They do have a vendor alliance in place with a cable company for much of their non-network cable.

3.4.7 - Energex

Construction & Contracting

Cable Quality Control

People

Cable quality control is the responsibility of the Standards group, part of System Engineering within Asset Management. The Standards group is comprised of engineers, mostly four-year degree qualified positions, though some are engineering associate positions.

Energex has comprehensive engineering standards, construction standards, and maintenance standards. Standards are made available to employees on the internet. Energex performs a complete review of all standards on a one to three-year cycle. As changes occur mid cycle, Energex distributes bulletins that provide the updated information to the employee base.

Process

Cable is commission tested by Energex before energization. The type of test depends on the cable type. Energex performs a DC hi pot test for commissioning PILC cable, and an AC VLF hi pot commissioning test for XLPE insulated cable. This commissioning testing is in addition to the manufacturer’s own cable testing, required by Energex specifications. If a cable is found to be faulty, the batch number is identified and the manufacturer is notified. This may result in cable recalls in some cases, with stock from that batch pulled from Energex supply and returned to the manufacturer.

Technology

A notable practice is the use of a specially coated XPLE cable jacket that is termite resistant. In some areas termites or white ants have eaten away at the outer sheath material in older XPLE cables. This new cable jacket material repels termites.

3.4.8 - ESB Networks

Construction & Contracting

Cable Quality Control

People

Cable quality standards at ESB Networks networks are developed jointly by the Underground Networks group and Strategic Procurement groups within Assets and Procurement, and the Network Investment groups within the Asset Investment organization.

Process

All incoming cable is subject to cable inspection procedures. Prior to taking delivery, the cable manufacturer is required to take samples and conduct tests of new cables that conform to ESB Networks requirements. ESB Networks must sign off on these test results before receiving a cable shipment. As an additional precaution, cable installers are required to inspect cable while on the job, as they are the last line of cable quality control for ESB Networks.

ESB Networks has also established a close working relationship with cable manufacturers. For example, a one company representative visits every two months and delivers training for ESB Networks. Vendors have also worked to develop accessories to suit ESB Networks’ unique cable requirements.

Material deficiencies with UG materials are handled informally; if a field crews has an issue with a piece of material, it is the crews’ responsibility to report the problem to its manager, who has the authority to stop an installation until appropriate replacement material is delivered to the site.

Technology

At LV, ESB Networks uses sector shaped solid aluminum cable

At MV, they use XLPE insulated round aluminum conductor with a durable jacket. ESB Networks reports excellent performance of the XLPE cables, noting that they have not experienced a cable failure unrelated to a dig in or a joint problem since 1982.

3.4.9 - Georgia Power

Construction & Contracting

Cable Quality Control

(Cable Inventory)

People

Network standards, including standard designs for cable, are the responsibility of the Standards Group within the Georgia Power Network Underground group. This group develops specifications and standards for cable and cable accessories used in the network underground.

Process

Much of Georgia Power’s existing cable is 300 MCM three-phase 20 kV PILC. Georgia Power is not aggressively retiring PILC, but is moving more toward solid-dielectric (mostly EPR) cable for new installations and replacement. When the PILC fails, it is replaced with either the same type or with 350 MCM 25 kV (reduced diameter) EPR.

The Georgia Power Network Underground group has not historically performed routine diagnostic testing of network cables other than fault location testing and proof testing after cable repair. Therefore, cable is replaced on an as-needed basis as determined by inspection, cable failure, or on recommendation of the supervising engineer.

Georgia Power makes certain that it is prepared for contingencies by performing regular stock checks. Engineering makes sure that cable inventory levels can support both normal and anticipated emergency requirements. GA Power keeps several thousand feet of primary cable which could be temporarily installed above ground in case of emergency such as major ductline damage. (See Figure 1).

Figure 1: Cable Inventory

Technology

The company uses its “Maximo” software system for checking and maintaining up-to-date data on the amount of cable and types of cable available. Stock is routinely replenished before it is needed.

3.4.10 - National Grid

Construction & Contracting

Cable Quality Control

People

National Grid has a well-documented underground construction standard for cables that includes descriptions of standard cable types, cable storage and handling practices, cable ampacity tables, and cable installation practices. The standard also includes guidelines for items such as calculating pulling tensions, proper racking, use of end caps, use of arc proof tapes, proper tags and identification, etc.

The cable standard is maintained by Distribution Standards, part of Distribution Engineering Services. The group is also responsible for developing material specifications. Standards are updated on a five - year cycle. The materials specifications section is updated annually.

Current standard primary cables for the National Grid networks in NYE are 500MCM Cu for mains, and 4/0 Cu for taps and transformer leads at 13.2kV. For 34.5, standard sizes are 750 Cu for mains; and, 2/0 Cu for taps and transformer leads. In addition, compact flat strap 500MCM Cu is used in reduced duct sizes for both 13.2kV and 34.5kV. (Aluminum primary conductors are sued on non-network radial systems such as URD or UCD.)

For network secondary, conductor sizes range from #2 to 500 cu.

Current standard duct size is 5 inches. Much of the existing duct system is 4 inch.

Process

New cables are accepted by National Grid without any supplemental diagnostic testing over what is performed by the cable manufacturer.

Technology

Current standard primary cables for the National Grid networks in NYE are 500MCM Cu for mains, and 4/0 Cu for taps and transformer leads at 3.2kV. For 34.5kV, standard sizes are 750 Cu for mains; and, 2/0 Cu for taps and transformer leads. In addition, compact flat strap 500MCM Cu is used in reduced duct sizes for both 13.2kV and 34.5kV. (Aluminum primary conductors are used on non-network radial systems such as URD or UCD.)

EPR insulated cable is the current standard for network primary feeders. For secondary cables, National Grid uses EPR insulated cables with a cross linked heavy duty black chlorosulfonated polyethylenee (Hypalon) jacket.

3.4.11 - PG&E

Construction & Contracting

Cable Quality Control

People

Cable specifications are prepared by a cable engineer within the Electric Distribution Standards and Strategy group, located in San Francisco.

Current standard cables used for the PG&E network are 750 cu, 500 cu, 250 cu, and #2 cu PILC cables at 12 kV, and 1100 Al, 600 Al, and 1/0 Al XLPE or EPR cables at 35 kV.

For network secondary, they use 1000 cu (for transformer ties), and 250 or 500 Cu EPR cables (for the street mains.)

Process

New cables are accepted by PG&E without any supplemental diagnostic testing over what is performed by the cable manufacturer. They have implemented proactive VLF testing of installed network feeders.

PG&E uses a vendor alliance with their network cable supplier.

3.4.12 - SCL - Seattle City Light

Construction & Contracting

Cable Quality Control

People

SCL does an incoming inspection of network equipment. They have a person who is responsible

for incoming equipment quality control.

Process

Incoming Network Equipment Inspection

SCL does an incoming inspection of network equipment, including cable, elbows, T-bodies, and so on. Cable is sampled and tested at random. These tests can include X-raying to identify deficiencies.

Cable Testing

SCL uses dc HIPOT proof testing (putting a high-voltage dc signal on the cable) prior to

energizing cables. 15-kV cable is limited to 26 kV dc, and 26-kV cable is limited to 47 kV dc.

SCL performs this test before energizing a new cable or prior to re-energizing an existing cable.

3.4.13 - Survey Results

Survey Results

Construction

Cable Quality Control

Survey Questions pulled from 2012 survey results - construction

Question 5.9: Do you have a process for inspecting or testing incoming network materials?

Question 5.10: If yes, what material is inspected or tested?

Survey Questions pulled from 2009 survey results - construction

Question 5.9: Do you have a process for inspecting or testing incoming network materials?

Question 5.10: If yes, what material is inspected or tested?

3.5 - Civil Construction

3.5.1 - AEP - Ohio

Construction & Contracting

Civil Construction

People

Civil Construction for AEP Ohio, including construction of manholes, vaults, and duct lines, is performed by a local civil contractor. AEP has a close working relationship with a civil engineering firm, with the primary civil engineer at that firm having worked for AEP Ohio for many years and is thus experienced with the AEP Ohio underground networks.

Coordination with contractors is performed by both the Network Engineering group, who works closely with civil contractors on civil designs, and service center management, who provide contractor coordination and oversight.

Process

Network Engineers work with civil engineers (contractor) to plan and design civil construction projects using single-line drawings that are then converted to electronic blueprints. These blueprints, once approved by engineering, are turned over to the contractor firm for execution. If there is cause to deviate from the original design for the construction, the civil engineering contractor works with a network engineer to resolve any problems.

Required civil repairs, discovered by inspection of manholes or vaults by AEP Ohio personnel, are reported to Engineering and outsourced to the civil engineering firm. Defects are input into the AEP Network Electrical Equipment Database (NEED) database, detailing the nature and severity of the structural deficiencies. Network Engineers, in consult with the Network Engineering Supervisor, then prioritize the civil repairs and send work orders to the civil contractor.

Technology

Civil designs created by the AEP Network Engineers are based on the AEP Network Planning Criteria. Single-line drawings of proposed civil construction, such as manholes and vaults, are converted to electronic blueprints in MicroStation and AutoCAD. Upon completion of projects, final blueprints are updated and GIS updates are made by the GIS group in parallel.

AEP utilizes its Network Electrical Equipment Database System (NEED) database, which is a legacy system that houses information about network assets and is used to aid in prioritizing and scheduling network repairs.

3.5.2 - Ameren Missouri

Construction & Contracting

Civil Construction

People

Ameren Missouri’s Civil and Structural Design Group, part of Energy Delivery Technical Services, is responsible for designs and standards for civil construction and repair. As an example, this group develops design standards for precast manholes. The group is also involved in deciding the best approach for making repairs to civil infrastructure, such as manholes and vaults. Ameren Missouri uses civil design contractors to supplement their civil design efforts.

Ameren Missouri uses contractors to perform much major civil construction work, such as building vaults, manholes and duct bank systems. They also make civil repairs to existing infrastructure. Repairs can range from epoxy injection, crack filling, and replacing deteriorated vault roofs.

Figure 1 and 2: Vault Roof Repair

Ameren Missouri has a Resource Management Group responsible for managing outside contractors. This group is organizationally part of Energy Delivery Technical Services. The group, led by manager, is comprised of construction supervisors who manage outside contractors.

Ameren Missouri has two or three contractors “of choice" for underground work. Ameren Missouri has a three or four year agreement in place with these contractors. The contractors are part of the union, hired from the local bench.

Process

An example of civil construction work being performed at Ameren Missouri is replacing deteriorated vault roofs. Deteriorated roofs are typically identified through vault inspections performed by Ameren Missouri employees. These deteriorated roofs are particularly problematic in manholes that contain roof mounted secondary ring buses. Ameren Missouri’s civil and structural design group has developed standards for new vault roofs, including a thicker ceiling to meet a traffic rating, and a larger grate opening. In addition they have standardized on a vented panel for both sides of the vault.

Ameren Missouri’s roof standard includes concrete specifications that require the contractor to take samples of each pour and perform testing, such as water content and slump tests, to assure that the concrete meets strength requirements.

Figure 3: Concrete Testing

Figure 4: Concrete Test Samples

Technology

Ameren Missouri has precast, poured in place, and brick and mortar manholes and vaults in service. Their present manhole and vault standards call for a precast design.

3.5.3 - CEI - The Illuminating Company

Construction & Contracting

Civil Construction

People

Civil construction, including the installation of vaults, manholes and duct back is performed by contractors at CEI.

CEI typically retains the services of five different contractors to perform civil work (construction and maintenance).

Process

The Underground Network Services group has one supervisor who runs the contractor crews.

3.5.4 - CenterPoint Energy

Construction & Contracting

Civil Construction

(Manholes)

People

All civil work in major Underground at CenterPoint is contracted, with the civil construction work being performed by one major contractor, with 14 different civil crews. This includes the construction of street vaults, manholes, and duct bank. CenterPoint also contracts out some of their civil design work, with the contractor performing surveying, obtaining easements and preparing manhole and conduit drawings for new projects.

Process

CenterPoint contractors “Pour in place” to build new manholes. Precast units are usually the choice of customers who are providing the manholes.

Technology

Manholes are capped with OSHA approved slotted cast lids.

3.5.5 - Con Edison - Consolidated Edison

Construction & Contracting

Civil Construction

People

Construction Group

Con Edison’s service territory consists of four regions: Manhattan, Brooklyn/Queens, Staten Island, and Bronx/Westchester. The Manhattan Region is made up of three districts, including one headquartered at the

W 28th St. Work Out Center. The term Work Out Center refers to a main office facility to which field construction and maintenance resources report. To provide a perspective on the size of a workout center, about 300 people work at the W 28th Street Work Out Center, and they can field about 125 crews.

The construction department consists of several groups, including the Subsurface construction (SSC) group. The SSC deals with vaults, conduit ducts, and other civil work. Much of this work is contracted.

Process

Con Edison has a specification that lists all standard and nonstandard types of transformer manholes and vaults and describes their application in forming various arrangements of single or multi-bank installations for 208V network systems.

Con Edison uses two standard-sized equipment installations within vaults: a 500-kVA transformer with protector (also referred to as a “network unit”), and 1000-kVA network unit. For 500-kVA network units, there are two standard reinforced concrete vaults: one that houses the network unit itself (the overall inside dimensions are: 11 ft, 0 in. L x 4 ft, 2 in. W x 7 ft, 0 in. H), and another that houses the crab connections of multiple transformer ties and services or street ties, or both (the overall inside dimensions are: 8 ft, 6 in. L x 5 ft, 5 in. W x 7 ft, 6 in.). These vaults are either pre-cast or field poured, depending on conditions.

For 1000 kVA network units, there are six standard and one nonstandard reinforced concrete vaults. Three of these are for the purpose of housing the transformers-protector units (each vault with different dimensions, and one vault design with a service takeoff). The remaining four are bus vaults, designed to accommodate the interconnections of 1000 kVA network unit secondaries, street ties and service take-offs (each with different dimensions and including a single bus, single bus with diving bell, double bus, and double bus with diving bell vault design). The standard vault structures are available as pre-cast or field poured, depending on conditions.

Con Edison has specifications for pre-cast vaults for use in sidewalk areas. These structures are designed to satisfy typical or “ideal” conditions. Cable entries and other openings are fixed for the most common applications of pre-cast structures, which makes for an inherent lack of flexibility in installation. Therefore, certain field conditions preclude the installation of pre-cast structures, and field-poured installations must be used.

Con Edison field-inspects a percentage (target – 50%) of the field-poured manholes and vaults installed each year. The focus of the inspection is to ensure the proper and adequate placement of rebar in the concrete.

Con Edison has a specification for the design and construction of 265/460 transformer vault and network compartments by a contractor. This specification describes the division of responsibility between the contractor and Con Edison, and provides the dimensional requirements as well as the design and construction requirements for these structures.

Con Edison’s manhole specification calls for pre-cast floors, walls, wedges, and roof slab, with a cast iron manhole frame and cover.

3.5.6 - Duke Energy Florida

Construction

Civil Construction

People

Duke Energy Florida relies on contractors to perform most civil construction work, including new construction and activities such as repairing duct bank, or replacing manhole and vault roofs and grating systems.

Good relationships have been formed between Duke Energy Florida and the preferred civil contractors who perform this work, many of which have been working for Duke Energy Florida for a number of years.

Process

Contractors, especially for larger projects, must go through an on-boarding process through the contract oversight group, including agreements to strictly adhere to Duke Energy Florida standards, safety practices, reporting procedures, and scheduling. Smaller civil project contractors, on an ad hoc basis, are hired based on expertise in specialties, such as manhole covers, construction repairs, and are not subject to an extensive on-boarding process.

3.5.7 - Duke Energy Ohio

Construction & Contracting

Civil Construction

(Manholes)

People

Most civil construction work at Duke, including manhole construction, is performed by contractors. Duke network resources will perform minor civil repairs.

Within the Dana Avenue construction and maintenance organization, Duke employs a T&D Construction Coordinator who interfaces with contractor crews, including civil contractors.

Duke Energy Ohio has installed manholes of many different dimensions. Their manhole system grew out of an old DC system that served Cincinnati in the early part of the 20^th century. Since that time, they have seen significant build out in the 1950s, 1970s and the 1990s. Their current manhole standard dimensions will not match many of the existing manholes.

Process

Duke Energy Ohio uses civil contractors to both perform civil construction and assist Duke in assessing the condition of facilities from a civil perspective. For example, the civil contractor will be called in to assess the roof condition or other structural condition issues in determining what repairs should be made to a vault or manhole.

Duke uses both “Poured in place” and pre-cast manholes, depending upon the circumstances.

Technology

In urban installations, Duke Energy Ohio encases conductors in concrete duct bank installations. Duke Energy Ohio does not use pre-cast duct bank, as each installation is unique size wise. Their standard duct bank installation includes grounding, tracer wire, and colored dye. Note that in rural areas of their territory, Duke Energy Ohio does not encase conduits in concrete.

See Attachment E for sample standard conduit drawings used by Duke Energy Ohio.

Duke Energy Ohio uses both pre-cast and “poured in place” manholes, depending upon the circumstances.

Pictures below show the installation of a precast manhole being installed in existing cable route. Note that precast manhole is made up of two bottom section, and a top section.

Figure 1 and 2: Precast manhole – bottom sections bolted together

Figure 3 and 4: Precast manhole – top section being lowered

3.5.8 - Energex

Construction & Contracting

Civil Construction

People

Civil construction standards are the responsibility of the Standards group, The Standards group is a part of the Asset Management group, and is comprised of mostly four-year degree qualified engineers, though some are engineering associate positions.

Energex performs a complete review of all standards on a one to three-year cycle. As changes occur mid cycle, Energex distributes bulletins that provide the updated information to the employee base. The bulletin details the change in standard and refers to the page number in the manual where the change has been made. Standards are made available to employees on the company internet.

All civil designs are approved by a licensed civil engineer to assure quality and meet the requirements of the Professional Engineers Act in Queensland. The civil engineers are part of the Design Group in Energex.

Civil construction is performed by a combination of Energex and contractor employees.

Process

Some civil construction is handled by outside contractors, inspected and monitored by the Energex Standards group. Contractors receive all their plans, specifications, scheduling, and cost estimates through the Standards group and an assigned project manager. Contractors are often used for tasks such as “proving the ducts” and backfilling.

Technology

Civil construction standards are all kept in documents in an electronic business management system. There are no hard copies of the standards; all are on the company intranet. Contractors also have access to the civil construction standards documents online.

3.5.9 - ESB Networks

Construction & Contracting

Civil Construction

People

Civil construction is supervised by the Contract Management group within the Network Investment groups, part of Asset Investment, within the Asset Management organization at ESB Networks. In addition to Asset Investment, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Assets & Procurement, Finance & Regulation, and Operations Management. These groups work closely together to manage the asset infrastructure at ESB Networks.

More specifically, construction and contracting is performed within two Network Investment groups – one responsible for planning network investments in the northern part of Ireland, and the other for planning in the south.

Construction standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Most civil construction is either performed by customers to ESB Networks specifications or is outsourced to trained and supervised contractors.

Process

ESB Networks works with a variety of contractors for civil construction through its Contract Management group. The group has developed thorough guidelines for contractor/construction. ESB Networks has developed an in-house training course for civil construction and contractor supervision, and every manager within the group must take and pass qualification exams to earn this position. The basic process for contract management is the following:

Initiate
Plan control
Execute
Closure

As a part of the entire process, contact managers inspect sites and gather any information that would inform and improve the processes involved and make recommendations for any changes.

ESB Networks has developed a contractor capability with six different international contractors coming into the country with over 20 different nationalities represented. This has posed a challenge in understanding the individual contractor’s culture and communicating clearly ESB Networks’ safety rules. As a result, safety rules are strictly managed by ESB Networks Contract Management personnel. As a part of this process, contractors are brought to ESB Networks in the early stages and evaluated on work quality and safety procedures, with ESB Networks managers making specific recommendations for improvements. Contractors receive a monthly performance review.

All accidents or near misses are scrupulously reported. Accidents must be reported to the CEO within 24 hours. In the event contractors do not comply with rules on inspection, the entire operation is shut down. The principal contract manager on any project that experiences problems is accountable at the highest level, and must give a thorough explanation of how/why an accident, near miss, or problem occurred.

Technology

ESB Networks has developed its construction and contractor management standards by utilizing the tools and techniques detailed in “The Project Management Body of Knowledge Guide”© (PMBOK) from the Project Management Institute (see Figure 1). All contractor guidelines, standards, specifications, and work processes are detailed in an online repository for contractor use. Safety and safe procedures are emphasized throughout any construction and contractor engagement.

Figure 1: PMBOK Guide

3.5.10 - Georgia Power

Construction & Contracting

Civil Construction

People

Civil structure design is the responsibility of the Network Underground engineering staff and its Standards Group. This group develops design standards for manholes, vaults, substations, duct lines, etc. The group is also involved in deciding the best approach for making repairs to civil infrastructure, such as manholes and vaults.

On specific projects, the design engineer is responsible for both civil and electrical design for company-owned facilities. Also, for customer-owned vaults which will contain GPC equipment, the GPC design engineer is responsible for coordinating with the customer’s engineers and architects, and for communicating to them the functional requirements of the vault.

The engineer also works closely with preferred contractors and customer building contractors, providing them with approved civil construction plans and overseeing their projects from beginning to end. Many Georgia Power customers have on-premises spot networks, for example, and the GPC engineer works with the customer building contractors to ensure the vault will meet the Network Underground requirements. The group often out-sources large civil construction projects to its preferred contractors, but all work is performed by Network Underground-approved standards and is supervised by engineers.

Process

Two examples of civil construction work performed at Georgia Power is the replacement of deteriorating brick vault roofs and the upgrading of manholes from standard, solid manhole covers to SWIVELOC manhole designs in select, high-traffic areas of downtown Atlanta (See Figure 1 and Figure 2.). The group is also contemplating moving to traffic-bearing vault grates in downtown areas.

Figure 1: SWIVELOC manhole collar

Figure 2: Underside of SWIVELOC lid

Technology

Civil engineers have access to reference designs in the Georgia Power Network Underground Standards book for duct line banks, manholes, vault, and other civil engineering standards adopted by the Network Underground group.

3.5.11 - HECO - The Hawaiian Electric Company

Construction & Contracting

Civil Construction

People

Civil Construction at HECO is the responsibility of the Construction Management Department, located within the Technical Services Division of the System Operations Department.

Most civil construction, including the installation of vaults, manholes and duct bank, is performed primarily by contractors at HECO. The Construction Management group manages the work of these contractors.

In URD developments, the developer is responsible for purchasing and installing the ducted manhole system per HECO specifications. The C&M Planning group of the C&M Underground Division has Construction inspectors who monitor the work of the developers and contractors to assure it meets HECO standards.

The C&M Underground group also has one Utility Assistant who performs small civil and structural tasks such as cutting a hole into an existing manhole.

Technology

In most applications, primary cables are installed in schedule 40 PVC conduits encased in 3- -inch concrete per HECO’s guidelines. Single phase cables are installed with a 3-inch “concrete cover” while three phase primary is installed with a 3- inch “concrete envelope”

See Attachment G.

3.5.12 - National Grid

Construction & Contracting

Civil Construction

People

Civil designs are performed by the Distribution Design group, part of the Engineering organization. There are two designers who perform network designs for the National Grid Albany network. Both designers work very closely with the field engineer, part of Distribution Planning, assigned to the underground department to support the Albany network.

The National Grid network field resources (network crews) are part of the group responsible for the underground system in eastern New York, called Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Civil Group is comprised of Mechanics, Laborers, and Equipment Operators, and is led by a supervisor. This group includes a machine shop located in Albany. The group has 23 field resources. This group performs minor civil projects, street lighting, heavy equipment (track diggers, bulldozers, cranes, tractor trailers, etc.), machine shop and “Haz Mat” cleanup.

Much of the larger civil construction work at National Grid is performed by external contractors.

Technology

All duct lines in the network at National Grid are concrete encased, including primary and secondary.

National Grid standards calls for pre-cast manholes and vaults. Standard vault size is dictated by size of the network unit. , National Grid has detailed standards that describe their underground electric vault requirements.

Figure 1: Vault Entrance

Figure 2: Vault ventilation grate

3.5.13 - PG&E

Construction & Contracting

Civil Construction

People

Civil designs, such as vault design, are performed by the Civil Engineering group within the Substation Engineering department.

Most civil construction work at PG&E is performed by civil construction resources from the PG&E Gas Division or by external contractors. PG&E network resources will perform minor civil repairs.

Technology

All duct lines in the network at PG&E are concrete encased, including primary, secondary and fiber ducts. Note that PG&E’s network design guidelines allow for no more than two feeders from the same network group in any one duct line.

PG&E uses both pre-cast and “poured in place” vaults. In their congested downtown area, most are poured in place. The rest of the system uses primarily pre-cast units. PG&E has detailed standards that describe their underground electric vault requirements.

3.5.14 - SCL - Seattle City Light

Construction & Contracting

Civil Construction

People

Organization

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Process

Bi-weekly Crew Coordination Meeting

SCL convenes a bi-weekly crew coordination meeting focused on the project status of each active network project. Meeting participants include the supervision and others from the network design group (engineers), civil crew representatives, electrical crew representatives (including crew leaders), and customer service representatives who deal with customers who are adding load.

This meeting is effectively used to manage network construction projects. Representatives review the project status of both civil and electrical projects and identify actions necessary for the projects to proceed. A report is used that shows critical project milestones such as the vault acceptance date and feeder in date. Note that a similar form is used to track the progress of civil construction projects.

The meeting is also used to establish action items to identify network conditions that must be addressed. One example would be the identification of vault locations where ventilation is inadequate for the summer heating season. The group will identify an action plan to make contact with building owners to address these deficiencies.

3.5.15 - Survey Results

Survey Results

Construction

Civil Construction

Survey Question taken from survey results 2015 Survey results - Summary Overview

Question 012: Within your company, what percentage of the work for each task is contracted?

Survey Questions taken from survey results 2012 Survey results - Construction

Question 5.4: Do you contract any network civil construction work?

Question 5.5: If using contractors, what % of your total network civil construction work is contracted?

Survey Questions taken from 2009 Survey results - Construction

Question 5.3: Do you contract any network civil construction work? (This question pertains to question 5.4 in the 2012 survey)

Question 5.4: If using contractors, what % of your total network electrical work is contracted? (This question pertains to question 5.5 in the 2012 survey)

Question 5.5: Total number of Network civil construction workers

3.6 - Contracting

3.6.1 - AEP - Ohio

Construction & Contracting

Contracting

People

Day-to-day electric work in the network is performed by AEP Network Mechanics, with contractors used only for special projects and for civil work. All civil design and construction work associated with network projects, including design and construction of manholes, vaults and duct lines, is outsourced to civil contractors.

At the time of the practices immersion, AEP Ohio was engaged in several large projects that involve contractor resources, including a large project to identify and replace selected secondary cables (mainly butyl rubber and PILC), and a project to update network communication and control infrastructure. Contractors are being utilized on both of these large projects to perform the field work. AEP employees provide oversight and project management of these activities.

AEP Ohio employs two engineering contractor technicians who serve as engineering assistants, working closely with engineers, preparing construction prints and work order documentation.

Rubber goods testing is performed by a contractor.

Coordination with contractors is performed by both the Network Engineering group, who works closely with civil contractors on civil designs, and service center management, who provide contractor coordination and oversight.

Process

Design, construction, and repair of civil assets at AEP Ohio are outsourced to a civil contractor that has many years of experience working with AEP Ohio. The contracting firm works closely with the AEP Network Engineers before, during, and on final completion and inspection of any new civil construction or repairs. AEP has a close working relationship with a civil engineering firm, with the primary civil engineer at that firm having worked for AEP Ohio for many years and is thus experienced with the AEP Ohio underground networks.

AEP Ohio conducts periodic status meetings to monitor progress and manage completion of its larger projects.

3.6.2 - Ameren Missouri

Construction & Contracting

Contracting

People

Ameren Missouri has a strong contractor presence in its underground operations. They utilize contractors for performing much major civil construction work, such as building vaults, manholes and duct bank systems, and for selected inspection programs, such as manholes. Contractors are also used to perform core business tasks, such as cable splicing.

Ameren Missouri has a Resource Management Group that is organizationally part of Energy Delivery Technical Services. The group, led by manager, is comprised of construction supervisors who manage outside contractors. Construction supervisor positions are filled by resources with field experience (such as former linemen) or experienced with project estimation and management (such as former estimators).

Ameren Missouri has two or three contractors “of choice" for underground work. Ameren Missouri has three or four-year agreements in place with them. The contractors are part of the union and, hired from the local bench.

Process

Ameren Missouri enters into three or four-year agreements with “contractors of choice” for underground work. These contracts are awarded through a major formal sourcing event that involves issuing requests for quotes for contractor services. Contractors provide information such as unit prices, safety performance, etc. Once contracts are established, the underground group can employ their services without having to go out for bid on each separate project. Note that the underground group is not required to use the “contractors of choice” exclusively - they may competitively bid work to other contractors if business requirements warrant.

The Resource Management Group monitors contractor performance. Contractors provide weekly reports on their progress and spending. Ameren Missouri establishes contractor scorecards, which include a set of key performance indicators (KPI’s) against which the contractor’s performance is evaluated. The Resource Management Group reviews KPI’s quarterly with contractors.

When Ameren Missouri decides to outsource a project to one of these contractors, they request a cost estimate. In some cases they ask the contractor for a fixed price - such as a unit price to install a new manhole or to prepare a splice. In other cases, they will request a time and material estimate based on agreed-to pricing rates in the contract.

Contractors utilized for manhole inspections will address civil problems identified as required by the Missouri Public Service Commission (PSC). In some cases, contractors must use ground penetrating radar to find the manhole location (for example, manholes, which have been paved over).

Contractors are also utilized for civil work. For example, Ameren Missouri uses contractors to replace deteriorated vault roofs. Ameren Missouri provides the contractor with concrete specifications, and requires that the contractor take samples of each concrete pour to assure that it meets Ameren Missouri’s strength specifications.

Contractors perform directional boring, mostly in conjunction with cable replacement.

Contractors also perform cable splicing. At the time of the practices immersion, about half of the splicing work was being performed by outside contractors.

3.6.3 - CEI - The Illuminating Company

Construction & Contracting

Contracting

People

Civil construction, including the installation of vaults, manholes and duct back is performed by contractors at CEI.

CEI typically retains the services of five different contractors to perform civil work (construction and maintenance).

Process

The Underground Network Services group has one supervisor who runs the contractor crews.

3.6.4 - CenterPoint Energy

Construction & Contracting

Contracting

People

CenterPoint’s underground organization is centralized, with the resources who work with the major underground infrastructure reporting organizationally to one group - Major Underground. The field resources, Cable Splicers and Network Testers, who construct, maintain and operate the system, are part of the Major Underground organization.

Major Underground does outsource some of its work to external contractors. They have a Construction Coordinator who coordinates with contractors to accomplish this work. This Coordinator also works closely with the Lead Engineering Specialist within the Feeder design group on new construction work.

All civil work in Major Underground at CenterPoint is contracted, with the civil construction work being performed by one major contractor, with 14 different civil crews. This includes the construction of street vaults, manholes, and duct bank. CenterPoint also contracts out some of their civil design work, with the contractor performing surveying, obtaining easements and preparing manhole and conduit drawings for new projects.

CenterPoint also uses a contractor to perform inspections of civil facilities that are built by customers. This inspection will occur within 24 hours of the customer completing his work. At CenterPoint the customer has the option of building his own civil infrastructure on his property to CenterPoint specifications. The inspector assures that the work does meet specs. Note that these inspections exclude inspections of customer vaults in buildings.

CenterPoint also contracts underground boring.

Process

90% of the construction contracts are bid on a unit basis, such as cost per foot or cost per cubic yard. The design contracts are typically built with T&M rates based on the job description and work type.

CenterPoint has entered into a longer term relationship with their civil contractor – a 2 year term, with an option to continue for a third year. They have created an alliance relationship, which invests both parties in the other’s success. The parties will meet periodically to review performance, profits, and to establish future benchmarks.

Note that this contractor also performs non civil work on CenterPoint’s behalf. The terms of the alliance apply to all of the contractor’s work.

Contractors are required to certify that they have performed certain training with their resources. This includes training on excavation safety and the shoring of trenches. Contractors must show documentation of training, adherence to safety requirements, and their safety record to be considered.

Most of the work contractors do is de-energized, so PPE such as FR clothing is not required. Contractors will not chip concrete around energized conductors. CenterPoint will either de-energize facilities or perform the civil work themselves. (For example, CenterPoint will build a manhole over a hot duct)

Technology

Civil Design Contractors will utilize Microstation and AutoCad to prepare drawings.

3.6.5 - Con Edison - Consolidated Edison

Construction & Contracting

Contracting

People

Much of the civil work associated with subsurface construction is performed by contractors. Con Edison has a Subsurface Construction (SSC) group who interfaces with deals with vaults, conduit ducts, and other civil work.

Con Edison has a specification for the design and construction of 265/460 transformer vault and network compartments by a contractor. This specification describes the division of responsibility between the contractor and Con Edison, and provides the dimensional requirements as well as the design and construction requirements for these structures.

3.6.6 - Duke Energy Florida

Construction

Contracting

People

Contractor work at Duke Energy Florida is awarded through the Resource Management group. A resource planner and scheduler within the within the Resource Management group will assist with the contract details.

When a contractor is hired to perform work for the network system, Network Specialists temporarily oversee and coordinate the contractor’s day-to-day work. Duke Energy Florida requires on-site oversight of contractors while they are on the job.

Duke Energy Florida does not maintain a civil construction crew for building and maintenance of network buildings, vaults, manholes, or other non-electrical construction. Instead, the network group uses a “turn-key” contractor with a long tenure of providing work for the company, especially on large civil projects. Duke Energy Florida uses other, smaller contractors to perform smaller work, such as civil repairs and upgrades.

Duke Energy Florida will utilize contractors for electrical work as well, with contractors performing tasks such as cable pulling and preparation of splices.

Preparation of switching orders and the performance of actual switching of the network are handled by Duke Energy Florida network employees.

Process

Contractors, especially for larger projects, must go through an on-boarding process through the contract oversight group, including agreements to strictly adhere to Duke Energy Florida standards, safety practices, reporting procedures, and scheduling. Smaller civil project contractors, on an ad hoc basis, are hired based on expertise in specialties, such as manhole covers, construction repairs, and are not subject to an extensive on-boarding process.

Contractors are also called in when a network project is so large that it would impact the daily operations and overwhelm the work capacity of the company network personnel. For example, Duke Energy Florida is using contractors now to replace feeder cable throughout the network system (as described in the Cable Replacement section).

In the future, Resource Management intends to become more involved in contractor and construction projects. Plans are in place to meet twice a month with the network system group to determine when and where they need more construction work, contractors, scheduling, etc.

3.6.7 - Duke Energy Ohio

Construction & Contracting

Contracting

People

Duke Energy utilizes contractors to perform electrical work in their network. Because they have a network rehabilitation effort underway, they have supplemented their regular workforce with contractors to accomplish this work.

Rather than assign the contractor crews to separate work, Duke intermingles the contractor employees with their native crews. A given work crew would have a Duke crew leader, and crew members who may be either Duke or contractor resources.

In part, they did this because some of the contractor resources, though journeymen lineman, had limited experience working with network systems. Duke assigned these resources to work as ground hands until they could gain experience with their network system. In other cases, Duke was able to find and secure contractors who were familiar with working in network systems.

These contractor employees work seamlessly with Duke employees on the crew. The contract was awarded to an IBEW contractor, the same union that represents Duke field employees.

About one third of the total network workforce of 68 is contractor employees.

Duke also hires contractors to perform civil construction work.

Process

Duke Energy believes that labor resource limitations should never be a reason not to do necessary work. With the need for additional resources to address network rehabilitation projects they have underway, they consequently have supplemented their work force with contractors.

The T&D Construction Coordinator within the Dana Avenue Construction and Maintenance department is responsible for managing external contracts.

As the contractors are incorporated into the crews, there day to day reporting relationship is through the crew leader and construction supervisors, the same as a Duke employee.

Note that contractor resources are not used to prepare terminations or splices.

3.6.8 - Georgia Power

Construction & Contracting

Contracting

People

Organizationally, Georgia Power field resources that construct, maintain, and operate the network infrastructure fall within the Network Underground group.

Underground construction crews, consisting of resources who install cable and cable systems including civil construction, cable pulling and cable splicing, fall within the Network Construction department that is organizationally part of the Network Underground group, responsible for the construction of all underground network infrastructure throughout the state of Georgia, including Atlanta, Athens, Macon, Savannah, and Valdosta. The Network Construction group is also responsible for all concrete-encased duct line construction throughout Georgia Power, both network and non-network distribution. Georgia Power has decided that the Network Underground construction standards for duct lines should be adopted throughout the system, regardless of whether the duct lines are for network or non-network distribution. The company believes that standardizing on duct line construction throughout Georgia Power gives the company greater system-wide uniformity and ease of maintenance.

The Network Construction group utilizes contractors for performing much of the major civil construction work. Georgia Power has a few contractors of choice for underground work, and has standing agreements with these companies, many of which have been working for Georgia Power for a number of years. Contractors of choice adhere to the contractor’s safety rules, and do have the authority to operate the Georgia Power system.

Management of contractors is the responsibility of a supervisor within the Network Construction group. This contract manager reports to the Network UG Construction manager.

Process

If there is a big construction job or extensive night work that needs to be done, Georgia Power may assign the work to its preferred contractor(s). The supervising manager hands the plans over to the contractor and coordinates the work from beginning to end. Relying on contractors is especially productive as major projects ebb and flow, and Georgia Power wants to retain its own duct line, cable, and construction crews for smaller jobs that need a fast response and/or for work that may be too complex for contractors to handle in a reasonable amount of time. In some cases, contractors and Georgia Power Network Underground crews may work together on a project.

3.6.9 - HECO - The Hawaiian Electric Company

Construction & Contracting

Contracting

People

Most civil construction, including the installation of vaults, manholes and duct back, is performed primarily by contractors at HECO. The Construction Management group manages the work of these contractors.

In URD developments, the Developer is responsible purchasing and installing the ducted manhole system per HECO specifications. The C&M Planning group of the C&M Underground Division has Construction Inspectors who monitor the work of the developers and contractors to assure it meets HECO standards.

Process

HECO requires all contractors to receive basic safety orientation and to be certified as having completed this training. The training is conducted by the HECO safety department. See Safety - Contractor Safety Orientation and Certification .

3.6.10 - National Grid

Construction & Contracting

Contracting

People

National Grid routinely uses contractors to perform major civil construction work. A Field Construction Coordinator within Construction Delivery manages the contractor crews.

Electrical work as well as design work is normally performed by National Grid resources, though some projects are out sourced.

Process

National Grid has identified prime vendors and backup vendors by area. Projects below $100,000 are assigned to the prime vendor (or backup) and are not individually competitively bid. However, projects over $100,000 each are competitively bid.

National Grid solicits lump sum bids for civil work. They are in the process of moving to a rate based bidding approach; that is, receiving and evaluating bids based on a daily rate for a civil crew. National Grid is also exploring unit pricing and is developing underground units.

Contractors are qualified through ISNET World^[1] , a worldwide contractor database that houses safety statistics/contractor evaluations, etc. This qualification assures that contractors are certified to National Grid standards.

Civil contractors will enter energized vaults and manholes if they are qualified to work in confined spaces. Civil contractors will also break in and out of energized duct banks. If the project involves moving of electrical facilities, National Grid electrical crews would be used.

Technology

National Grid tracks the number of contractor resources in a data base (ISNET).

^[1] ISNetworld is the global resource for connecting corporations with safe, reliable contractors in capital-intensive industries. isnetworld.com

3.6.11 - PG&E

Construction & Contracting

Contracting

People

PG&E normally does not supplement their native workforce with contractors to perform routine work (construction and maintenance) in the network. However they do utilize external contractors to perform certain targeted work types. For example, PG&E uses an external contractor to perform environmental cleanups of vaults and manholes.

External contractors are managed by the particular group, which engages the contractor.

Process

PG&E has well defined procedures for external contractors that list exactly where the contractor will work and what they are to do. As for internal employees, these work procedures are written in a table format, and are supplemented by checklists where applicable to simplify their use. Contractors will complete the checklists for the work they are performing.

One example of an activity normally contracted at PG&E is the cleaning of vaults or manholes than may have environmental concerns, such as biohazards.

Another place where contractors are used is the high-rise transformer replacement program. Within this program, any oil filled units within the footprint of the building will be replaced with dry-type transformers. For these change outs, PG&E has hired an external contractor to do all of the work “turnkey”, including all of the connection work.

Another example of the use of contractors is in the implementation of PG&E’s new SCADA monitoring project. This project includes the installation of new fiber optic cable. PG&E has hired a contractor to pull the new fiber through the existing duct system.

Also, as part of the SCADA monitoring project, PG&E has hired a contractor to install the required sensors on the network units. When implementing the SCADA project, PG&E did a pilot, which showed that existing PG&E crews didn’t have the required expertise to do the sensor installations, as these installations involve drilling and thermal welding – skills for which PG&E crews are not trained. Consequently, they elected to hire external contractors.

Contractors will also be brought in to tackle specialty problems. For example, PG&E hired a particular university to model their 34.5kV feeders in order to assess where to place field switches to resolve problems with breakers opening based on inrush current and harmonics.

Another example is the hiring of an external contractor to assist PG in developing an oil analysis program for network equipment, with triggers for action based on test results.

Another example is the use of an external testing laboratory to analyze oil samples. PG&E uses this laboratory to test the efficacy of its internal laboratory. For a period of time, they will double sample, with one sample being sent to the external lab.

Technology

PG&E is in the process of implementing tablet computers. Work procedures, such as those used by contractors, are being entered into the tablet computers. Instead of writing information onto manual checklists, employees and contractors can enter the information directly into tablet computers or use bar coding to inventory equipment.

3.6.12 - Portland General Electric

Construction & Contracting

Contracting

People

For CORE work, the use of contract services is applied to civil work, including things such as manhole lid replacement and construction and repair of duct banks. PGE does not typically utilize external contractors for electrical work in the core. The company may utilize “overhead” crews at times to perform certain work activities such as pulling cable.

Figure 1: Cables from duct bank

The Contract Services and Inspection (CS&I) department performs contract management. There are five construction managers within the CS&I group who provide project oversight on any work by contractors regarding PGE-owned infrastructure. This oversight includes the performance of inspections of contractor work. For larger projects, PGE may outsource inspections to external experts, such as POWER Engineers, Inc.

Third-party contractors involve Service & Design Project Managers (SDPMs) as well. For customer-provided infrastructure, such as spot network vaults that will ultimately house PGE facilities, customers will utilize third-party vault contractors who have received certifications from PGE. Field Construction Coordinators (FCC) working within the SDPM department inspect spot network construction performed by third-party contractors.

PGE issues three levels of certifications depending on the size and complexity of the civil structure to be designed and built. Level 1 involves installing a conduit duct bank. Level 2 covers vaults up to 7 x 12 ft (2 x 3.7 m) in size. Level 3 is anything above that size. The certification function is transferring to a contract management group.

Process

The day-to-day construction management of contracted work, such as holding weekly project status meetings, is the responsibility of a construction manager working for CS&I. In addition, for some large projects, typically at the transmission level, external inspectors may be retained.

The construction managers and inspectors work with contractors to ensure that the work carries out according to PGE specifications and standards, and meets quality expectations.

3.6.13 - SCL - Seattle City Light

Construction & Contracting

Contracting

People

Organization

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations — Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system.

3.6.14 - Survey Results

Survey Results

Construction & Contracting

Contracting

Survey Question taken from 2015 Survey results - Summary Overview

Question 012: Within your company, what percentage of the work for each task is contracted?

Survey Questions taken from Survey Questions 2012 Survey results - Construction

Question 5.5: If using contractors, what % of your total network civil construction work is contracted?

Survey Questions taken from Survey Questions 2009 Survey results - Construction

Question 5.4: If using contractors, what % of your total network electrical work is contracted? (this question is 5.5 in the 2012 survey)

3.7 - Crew Makeup - Job Progression

3.7.1 - AEP - Ohio

Construction & Contracting

Crew Makeup - Job Progression

People

Electrical work on the AEP Ohio network is performed by Network Mechanics who report to Network Crew Supervisors at a service center. Project work orders, repairs, and maintenance are scheduled and dispatched from this center. Civil construction crews are provided by AEP Ohio’s Civil Engineering contractor.

Process

Crew Makeup

AEP Ohio Network Mechanics perform all electrical maintenance and network installations. Network Mechanics are members of the union (IBEW), and are categorized a D, C, B, or A-level grades, with Network Mechanic “A” being the highest rank. Each position has certain work duties associated with it (for example, a person must be at the Network Mechanic “B” level before working with primary distribution).

Network Mechanics working in the field are led by a Network Crew Supervisor, which is a non-bargaining job position. Network Crew Supervisors are typically promoted from the AEP Network Mechanic ranks.

Network Mechanics move up the ranks through a combination of on-the-job training (OJT) and formal training classes. Although there are formal tests at the end of each class, job progression is not determined solely by test results. Note that the progression through the Network Mechanic job family is not an “up or out” program (i.e., AEP does not mandate that every employee achieve the Network Mechanic A position in a prescribed time period, though attainment of the journey worker position is encouraged.) Pay increases associated with the achievement of particular levels are a function of company-union contracts and vary across AEP operating companies.

Training

Trainees must take eight separate formal training courses. Each of these courses is about two weeks in length and spread over a four-year time period. Some classes are led by a formal training supervisor, while other specialized courses are taught by Network Engineers or other experts. Trainees begin with basic distribution training and advance to courses on network protectors, cable pulling and replacement, and network maintenance and operations. In addition to craft training, AEP employees also receive ongoing safety training and participate in periodic outage drills.

In addition to formal training, “on the job” training (OJT) is also an advancement requirement. Field employees are expected to develop a “jack-of-all-trades” skillset. To foster this job competency, roles and responsibilities are regularly rotated on the crews, giving employees the opportunity to experience and hone their skills in a variety of job situations and have ample hands-on experience with a number of tasks. OJT requirements are not prescriptive. Rather, Network Crew supervisors assign personalized OJT opportunities to meet specific employee needs. If a Network Crew Supervisor (or Network Mechanic) believes that an individual requires experience in a given area, the supervisor will ensure that the employee is given an opportunity to gain experience by adjusting the OJT assignment to meet those specific needs.

Field crews also receive training in coordinating with civil contractor resources for large-scale jobs, such as the on-going replacement of secondary cable in the AEP Ohio system.

A practice of note at AEP is their investment in cross-operating company training. The parent company regularly makes training available to all its operating companies, allowing personnel to travel to other sites and receive specialized training or have visiting trainers from other operating companies hold sessions at its various AEP training facilities.

Technology

AEP Ohio has a well-maintained and extensive training center in its Groveport training facility (see Figures 1, 2, and 3). The center includes an indoor training facility for overhead line work, and a specific training center focused on Network system training.

Figure 1: AEP Ohio indoor training facility. The network training center is located within this facility

Figure 2: Cable splicing area at AEP Ohio training facility

Figure 3: Network protector cabinets at AEP Ohio training center

The training center enables hands on training with commonly used equipment. For example, every network protector model in use at AEP Ohio is represented at the center, and personnel are trained in the safe operation and maintenance of each. Transformers, switches, cable splicing materials, and SCADA devices are available for demonstration and hands-on training within the center as well.

AEP equips its network mechanic trucks with onboard computers, making all training materials, practice instruction, and troubleshooting guides available online for use in the field.

3.7.2 - Ameren Missouri

Construction & Contracting

Crew Makeup - Job Progression

People

Organizationally, Ameren Missouri field resources that construct, maintain, and operate the network infrastructure fall primarily within three groups, all part of Energy Delivery Distribution Services. One is the Underground Construction group, one is the Service Test group, and one is the Distribution Operating group.

The Underground Construction Department consists of Cable Splicers, Construction Mechanics, and System Utility Workers. Cable Splicers and Construction Mechanics are journeymen positions. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Construction Mechanics perform the civil aspects of the work. System Utility Workers serve as helpers to the other two positions, and perform duties such as cable pulling and manhole cleaning. Note that at the time of the practices immersion, Ameren Missouri was implementing a new position, called the System Journeyman, which combines the duties of Cable Splicer and Construction Mechanic. System Journeyman are responsible for performing minor civil work such as installing cable, switching and tagging, and performing cable testing and cable splicing activities.

Maintenance and operations of network equipment such as network transformers and network protectors are performed within the Service Test Group and Distribution Operating Group. The Service Test Group is made up of Service Testers and Distribution Service Testers. Service Testers perform low-voltage work only. They focus on things such as voltage complaints, RF interference complaints, and testing and maintaining batteries. Distribution Service Testers perform network protector maintenance, transformer maintenance including oil testing, and fault location. The Distribution Service Tester position works routinely with network infrastructure. Distribution Service Test group positions are typically filled from the Service Testers, Traveling Operator positions, or Gardener positions (a practice related to a historic practice of filling department positions with resources who maintained substations.)

The Distribution Operating group is made up of Traveling Operators, who perform switching on the system, including placing tags and obtaining clearances. They act as first responders and troubleshooters.

See Organization

Process

Ameren Missouri has a 30 month mandatory progression for Cable Splicers, Construction Mechanics, and System Journeymen, whereby employees must move through a program of formal training, on the job training (OJT) and testing and achieve the journeyman level within this period. Employees must spend at least one year as a System Utility Worker before entering the program.

Ameren Missouri has recently designed a formal training program for underground construction worker progression. In the past, there was no formal journeyman program for underground, and all training associated with underground was performed in-house, within the department. More recently, Ameren Missouri has implemented a formal program, with the training, testing and proficiency demonstration conducted at the Dorsett training facility. This 30-month program includes things such as electrical principles and theory. A recent change is that System Journeymen, a new position, are sent to a six-week course on switching and grounding, and electrical excavation issues. This training, held at the Dorsett training facility, is important to System Journeyman, as they have switching and tagging responsibility.

At the time of the practice immersion, Ameren Missouri was investigating new programs to filter prospective underground workers to assure they identify the right workers for underground positions. These programs would be analogous to overhead line worker boot camps, where perspective linemen are given hooks and an opportunity to climb to assess their fit for line worker positions.

Distribution Service Testers have a similar mandatory progression program, with employees expected to reach the journeyman level in 22 weeks. Like the positions within the Underground Construction Group, the Distribution Service Tester program also consists of formal training, testing and on the job training. Distribution Service Test employees receive significant on-the-job training both as they advance to the journeyman level, and on an ongoing basis. The department manager rotates crews on four-month assignments to assure that employees get exposure to various assignments, including network maintenance, capacitor maintenance, and fault location.

Working with the union, the Distribution Service Test Group has developed a set of basic entrance requirements to screen applicants. These requirements are summarized in a set of Pre-evaluation Modules for the Distribution Service Test position that require applicants to demonstrating the ability to perform tasks such as:

Properly lift and transport up to 60 pounds,
Operate and perform work from a bucket truck,
Set up and work from a ladder,
Perform work in enclosed spaces,
Utilize hand tools,
Lift and use an Extendo stick,
Walk and perform work on uneven ground and terrain,
Climb to the top of a power transformer and work on a primary bushing.

As a specific example, Ameren Missouri asks applicants to demonstrate the ability to go up in a bucket and remove and replace a capacitor oil switch within 20 minutes. Applicants must be able to meet the entrance requirements to enter the job family.

Technology

Much of the formal training associated with the advancement to the journeyman level for Cable Splicers, Construction Mechanics, System Journeyman, and Distribution Service Testers is performed at Ameren Missouri’s Dorsett training facility.

Ameren Missouri employees also receive a number of safety related courses such as manhole entry and rescue.

3.7.3 - CEI - The Illuminating Company

Construction & Contracting

Crew Makeup - Job Progression

People

CEI has one Underground Network Services Center to support the Underground, including the networked secondary and non network ducted conduit system. The service center includes the Underground Electricians who construct, maintain and operate the underground system.

The Underground Electrician family of jobs is represented by collective bargaining – UWUA Local 270.

The Underground Electrician family is comprised of an Electrician A, B, C and Leader. The Electrician C is an entry level job, normally filled from internal candidates and selected based on seniority. Jobs in the underground department are “sought after” and are thus filled internally, often from meter reading.

People in this job family move from an Underground Electrician C, to a B, and finally to an A, which is the journeyman level. Advancement in the family involves “on the job” training, formal skills demonstration and testing. Advancement is not through an automatic mode of progression – management determines the number of positions at each classification.

Note that journeymen in this classification are “jacks of all trades”; that is, they will perform all required work in the ducted manhole system, including maintenance of network equipment, preparation of splices, pulling cable, etc.

See Organization.

Process

Advancement through the Underground Electrician job family involves a combination of training, job skills demonstration, and testing.

Employees are required to review training modules for selected tasks (example: Manhole / Vault Entry). The employee is responsible to review the module and discuss its contents with their supervisor. They will then take a written test to demonstrate their understanding of the material included in the module.

Employees are each given a “skills book” that lists the individual skills they are responsible to learn and demonstrate in order to advance. The employee will develop these skills through on the job training. When an employee feels he is proficient in a certain skill, he can demonstrate the skill, and have it signed off in the skills book. As employees within a classification demonstrate skill proficiency, they move up in pay within that classification.

In order to be eligible to advance from one classification to the next, employees must pass a progression test, administered by the training department. Advancement is not automatic – management determines the number of positions at each classification.

Technology

The skills book is filled out manually by the employee.

3.7.4 - CenterPoint Energy

Construction & Contracting

Crew Makeup - Job Progression

People

CenterPoint’s underground organization is centralized, with the resources who work with the major underground infrastructure reporting organizationally to one group - Major Underground. The field resources, mostly Cable Splicers and Network Tester, who construct, maintain and operate the system, are part of the Major Underground organization.

Both the Cable Splicer and Network Tester family of jobs are represented by collective bargaining – IBEW, local 66.

Crew Leaders at CenterPoint are non bargaining positions. A Crew Leader has around 15 resources working for him. These resources work in smaller groups sized depending upon the project. The senior position on the crew, a Head Cable Splicer or Head Network Tester, is the on-site leader of the crew.

The Cable Splicer family is comprised of a Helper, Apprentice Cable Splicer, Journeyman Cable Splicer and a Head Cable Splicer. The Helper is an entry level job, normally filled from the outside. Apprentice positions are normally filled from the Helper position. CenterPoint requires Helper candidates to have a high school diploma or GED.

Similarly, the Network Tester family is comprised of an Apprentice Network Tester, a Journeyman Network Tester and a Head Network Tester. The Apprentice is an entry level job, normally filled from external candidates. CenterPoint desires Apprentice network Tester candidates to have an Associates education in electronics or equivalent electrical experience.

CenterPoint also uses Heavy Equipment Operators (three positions).

Process

Advancement through the Network Tester and Cable Splicer job families involves a three year apprenticeship program that includes a combination of training, job skills demonstration, and testing.

Network Testers are hired as apprentices, and enter into a three year apprenticeship program. They initially attend a three week orientation program that includes pole climbing. New employees must successfully complete this three week orientation to remain in the apprenticeship program. After the first 90 days of being accepted into the program, Network Testers participate in a second three week program where they receive additional overhead line training and company orientation. (Major Underground employees support overhead departments in emergency restoration efforts).

The apprenticeship program is broken in to 6 six month classes that include classroom training, OJT, and testing to move from one class to the next. Movement from one class to the next is accompanied by salary increases. If an individual cannot pass the tests and other requirements, he will not advance. He will be given a second opportunity to pass and advance, If he cannot, he is rejected from the program. (He may be able to find other opportunity within CenterPoint).

At the completion of the three year program, the employee becomes a journeyman Network tester.

Similarly, Apprentice Cable Splicers, selected from Helpers who have completed one year with the company, enter the Cable Splicer apprenticeship program. They, too initially attend a three week orientation program that includes pole climbing. After being accepted into the Apprenticeship program, cables splicers participate in a second three month program where they receive additional overhead line training and company orientation. Cables Splicer overhead line training is more intense that that of network Testers because their job classification requires them to work with riser poles.

At the completion of the three year program, the employee becomes a journeyman Cable Splicer.

Head Cable Splicer and Head Network Tester positions are filled only when there is an opening. Candidates must interview for these positions, and the most qualified individual is selected - not necessarily the senior man.

Employees are required to review training modules for selected tasks (example: Splicing – See Attachment - F .) The employee is responsible to review the module and discuss its contents with their supervisor. They will then take a written test to demonstrate their understanding of the material included in the module.

3.7.5 - Con Edison - Consolidated Edison

Construction & Contracting

Crew Makeup - Job Progression

People

Construction Group

Con Edison’s service territory consists of four regions: Manhattan, Brooklyn/Queens, Staten Island, and Bronx/ Westchester. The Manhattan Region is made up of three districts, including one headquartered at the W 28^th St. Workout Center. The term “Workout Center” refers to a main office facility to which field construction and maintenance resources report. To provide a perspective on the size of a workout center, about 300 people work at the W 28^th Street Workout Center, and they can field about 125 crews.

The Construction department consists of several groups:

Underground Group - The underground group is made up of Splicers, who splice cable of all voltages.
Installation and Apparatus (I & A) Group (includes a services group) - The I&A group installs and maintains network equipment, including transformers and network protectors. Within I&A, in Manhattan, there is a services group dedicated to connecting customers to the distribution network. In other locations, the services group may sit in a different part of the organization. This group does the splicing on the secondary system and deals with customer connection issues.
Subsurface Construction (SSC) Group - The SSC deals with vaults, conduit ducts, and other civil work. Much of this work is contracted.
Cable Group - The Cable group pulls in new cable and retires cable.

Note: the West 28^th Street “Workout” Center also contains the Emergency Group (also called #9), which responds to smoking manholes, burnouts, and other emergencies. This group reports organizationally to the Field Operations Department (FOD).

Manhattan’s districts have seen significant load growth (overall, 3-4 %, but in pockets, the load growth is much greater). For example, in upper Manhattan and Harlem, properties are being converted to apartment buildings or commercial high-rise buildings.

This trend has created significant work in connecting new services, adding spot networks, and adding network transformers to reinforce the street grids. Con Edison has also had to create new networks by breaking an existing network into two to accommodate this increased load. An example would be the creation of the Fashion Network to transfer load from the Herald Square network.

Con Edison believes it easier to maintain smaller networks; however, with less copper in the street, smaller networks can be considered less reliable. When Con Edison does encounter problems, particularly in the summer, the utility engages in “shunting,” which is the term they use to describe running cables above the street to bypass or “shunt” the problem and pick up the loads from an alternative source. The utility also runs generators if necessary to provide support to pocket areas during emergencies to meet customer load expectations.

Network Job Progression, OJT

Workers enter as a General Utility Worker (GU) and then progress either through the Splicer or the I&A Mechanic families with on-the-job training (OJT), training, and testing.

In the Underground group (Splicers), a person can progress to a Splicer in as little as two years. Con Edison does not have a mandatory automatic mode of progression; that is, employees are not mandated to progress to a journeyman position within a given period of time. Nor are employees prevented from advancing if they accomplish the prerequisite time, training, and testing.

After 18 months, GU’s are eligible for splicing school, a three-month program offered by Con Edison and conducted at their training center. When employees return to the field from Splicing School, they are assigned to a supervisor who is responsible for their training and development while on field assignment. Con Edison has specific OJT requirements that Splicer candidates must satisfy before being able to progress to a Splicer. (See Attachment C for a listing of the specific tasks in which a Splicer candidate must demonstrate proficiency.)

Splicer candidates can perform their OJT requirements over a minimum seven-month period. When candidates believe they are ready to perform an OJT, they inform their supervisor and the splicer with whom they are presently working. If all agree that the candidate is ready to “solo,” the OJT moves ahead. The candidate, supervisor, and training splicer review the OJT and hold a job briefing. The candidate then performs the OJT with as little input from the observer (supervisor or training splicer) as is possible. The supervisor evaluates and documents the OJT. (See Attachment D for a sample evaluation sheet used by Con Edison to evaluate and document the OJT accomplishment [ESP0061].)

After completing the OJT requirements, Splicer Candidates can then take a written and practical promotional exam and progress to a Distribution Splicer (journeyman position).

In the I&A group, individuals can progress to a journeyman Splicer as well. A GU can progress to a Mechanic B after six months, a Mechanic A after two years, and then become a splicer in the I&A organization. As described above, there is formal training and testing associated with this.

Con Edison directs General Utility workers (GUs) to either the Underground area (Splicers) or I&A area based on need.

Overtime

Workers expend 30 – 40 % of their time on overtime. Work is planned for 10-20% overtime, with emergencies and efforts to complete system reinforcement projects prior to the summer loading season adding to the levels of overtime worked. The company implements 12-hour shifts in these high work periods.

Supervisors get paid to work overtime at a straight time rate.

Planning and Survey Group

The Planning and Survey group is a subset of the Field Engineering group, and consists of Surveyors, who perform survey work associated with new construction, and Planning Inspectors, who go into the field, and assess the specific field conditions and determine what is necessary for the new installation to be built successfully. Planners and surveyors can work separately, or work together on projects. This group works closely with Energy Services, taking layouts developed from maps by Energy Services on Microstation, and field checking them to identify the specifics of the job and ensure that the layout reflects field conditions. This group prepares job sketches to obtain the necessary permitting to complete the job.

3.7.6 - Duke Energy Florida

Construction

Crew Makeup - Job Progression

People

Organizationally, Duke Energy Florida field resources that construct, maintain, and operate the urban underground and network infrastructure within Clearwater and St. Petersburg fall within a specific Network Group which is part of the Construction and Maintenance Organization. More broadly, Duke Energy Florida’s Construction and Maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager. The region consists of various Operation Centers, organized either geographically or functionally throughout the Region. For the urban underground infrastructure (manhole ducted underground systems, including networks) in the region, Duke Energy Florida has established a separate Operation Center, led by a supervisor, and comprised of craft workers who work with all of the network manhole and duct line systems in both St. Petersburg and Clearwater.

Duke Energy Florida has two craft worker classifications for working on network infrastructure – Network Specialists and Electrician Apprentices (EAs). Note – historically, there were three different Journeymen classifications: Cable Splicers, Automatic Equipment Specialists, and Electricians. The Automatic Equipment Specialists, Cable Splicers, and Electricians were combined into one classification called Network Specialists to prove more flexibility in work assignments. Currently, the Network Construction and Maintenance group consists of five Electrician Apprentices and five Network Specialists. Of the ten resources, five are typically assigned to Clearwater, and the remaining five to St. Petersburg, though resources are moved between both based on work needs.

Electrician Apprentices are the entry level position into the Network Construction and Maintenance department. Electrician Apprentices provide assistance to Network Specialists while receiving on the job training. In addition, Electrician Apprentices are able to splice URD cable and any cable in the network system excluding lead and submarine cable.

The Network Specialist position is considered a “jack-of-all trades” position. The Network Specialist can splice all cables (including lead and submarine cable), pull cable, and perform switching. Maintenance and operations of network equipment such as network transformers and network protectors are also performed by the Network Specialists.

The Network Construction and Maintenance group also utilizes contractors for performing much of the major civil construction work. Duke Energy Florida has a few contractors of choice for underground work, and has standing agreements with these companies, many of which have been working for Duke Energy Florida for a number of years. In addition to using contractors to performing civil construction work, Duke Energy Florida, may employ contractors to perform electrical work, including pulling cable and splicing. This work will be done under the safety and quality oversight of designated Network Specialists.

Duke Energy Florida maintains a central training facility in Clearwater that primarily focuses on Overhead training, although there are some underground network training facilities there. Most of the training for Electrician Apprentices and Network Specialists, however, is delivered either as on the job training, or delivered in sessions held within their Clearwater supply and maintenance facility, located within the same complex as the Clearwater network underground office. Most training, both formal and on the job, is delivered by senior Network Specialists and Engineers. Training associated with advancement within the Electrician Apprentice family is managed informally, and led by the Network Specialists.

Process

Electrician Apprentices are the entry level position in Duke Energy Florida’s Network Construction and Maintenance group and can progress into a Network Specialist position based on seniority, qualifications, and if an open Network Specialist position is available. All Electrician Apprentices and Network Specialists are represented by collective bargaining, IBEW. Currently, there is no test or examination to progress from an Electrician Apprentice to a Network Specialist. Network Specialist progression is based on both seniority and qualifications as an Electrician Apprentice; that is, vacant positions are filled by the senior qualified man.

Current Training/Progression Practices

There is no automatic progression at Duke Energy Florida from Electrician Apprentice to Network Specialist as Electrician Apprentices will need to bid out of their job classification after a Network Specialist position becomes open. Prior to being able to bid for a Network Specialist position, the Electrician Apprentice must complete between 48 and 54 months of on the job training to become qualified.

The Electrician Apprentices are trained on the job under the guidance of Network Specialists. The program is managed informally. After successful demonstration of knowledge and completion of work tasks, Network Specialists will sign off on a training sheet. As the task sign off sheets are completed, the Electrician Apprentice will progress up through four job steps. At the highest level, Electrician Apprentices are qualified to bid on available Network Specialist jobs. The senior qualified Electrician Apprentice will get preference for the available Network Specialist position.

There is currently no job forecasting at Duke Energy Florida. Electrician Apprentice and Network Specialist positions are posted on demand. Once a person either leaves the position or files his retirement paperwork, the job will be posted for qualified Electrician Apprentices to bid.

Training Practices of the Future

The training program at Duke Energy Florida is currently in transition for Electrician Apprentices. Duke Energy Florida will begin to use formalized training for step advancement through the Electrician Apprentice position. Included in the formalized training are prepared job aids detailing procedural step-by-step instructions how to perform tasks. Example job aids include how to enter manholes, identification of transformers, grounding, cable piercing, and electrical theory instruction.

In addition to job aids, work methods for the work tasks performed by Electrician Apprentices and Network Specialists are being prepared. The work methods explain the procedural “how-tos” for performing specific tasks such as Grounding and Piercing Underground Cable,

(see Attachment G ). Work methods used for tasks performed sometimes exceed the safety and work practices standards defined by the rest of the company outside of the Network Maintenance and Construction group because work on the network is specialized and has different requirements from overhead line work.

Job aids and work methods that are being developed, will be separated into four phases for formalized training. Each of the phases represents the training expectations for one year. Completion of each of the four phases will allow for progression through each of the four steps for Electrician Apprentices. Electrician Apprentices will be required to demonstrate competency of the job aids and work methods for his current job step before advancing to the next step.

Currently, the job aids and work methods are in development. Once completed, incoming Electrician Apprentices starting at step level one will be expected to show competency in the job aids and work methods before progressing up in steps. Electrician Apprentices at higher steps when the new training is implemented will not be required to complete job aids and work methods for their continued progression. Additional required formal classroom training is being discussed prior to implementation.

Technology

Training associated with advancement within the EA family is managed informally, and led by the Network Specialists.

Within their Clearwater facility, Duke Energy Florida has established training aids, including a simulated manhole where training can be performed on various activities in a simulated manhole environment. This simulated manhole, made of plywood, is mounted on wheels so that it can be moved within the training center see Figures 5-1 and 5-2). It contains cable racks, and can be used to simulate cable racking for both primary and secondary cables. For training. Network Specialists will typically outfit the manhole with commonly used materials and equipment, with cutaways (such as a cable limiter with insulation cut away, exposing the fusible link), so that EAs in the program are exposed to components.

Figure 1: Manhole simulator - exterior

Figure 2: Manhole simulator – interior

Network Specialists also maintain a “Training Board" which contains samples of all the primary and secondary components used on their system (see Figure 3).

Figure 3: Training Board

Finally, Duke Energy Florida utilizes training aids such as figure 3 to provide insight into typical devices used on the system (components display, primary switched, Network Protectors).

All Duke Energy Florida employees receive a number of periodic safety-related courses and refreshers, such as manhole entry, manhole rescue, and CPR training. (See Safety and Drills sections in this report.)

3.7.7 - Duke Energy Ohio

Construction & Contracting

Crew Makeup - Job Progression

People

The Dana Avenue underground group is comprised of Cable Splicers and Network Service Persons. These are bargaining unit positions. Advancement in both job families is through an automatic mode of progression.

Process

Job advancement within the Splicer family is through an automatic mode of progression. That is, employees in this job family are expected to progress to the senior level (an “up or out" program.)

The process for hiring Splicers into the department is as follows:

First, Duke Energy Ohio will run an advertisement to solicit interest in the position. They screen resumes looking for a few key skill sets. Once they’ve developed a potential list of candidates, they invite those candidates in to take an aptitude test. (Their historical experience has been a high failure rate by applicants taking this test.)

Potential applicants also undergo hands-on testing at Duke’s DANA Ave training center, including things such as digging a hole and performing tests of their manual dexterity. Then, applicants undergo a rigorous “two on one” interview. From these various tests, applicants are scored. They can receive a high pass, pass, low Pass, or fail.

Employees are hired from this candidate pool.

New hires come into the department as a Cable Helper for the first six months. During this six-month time, they receive both classroom and on the job training, and are then brought in for a test, where they are asked to prepare a simple splice. If they pass this test, they advance to a C Splicer.

An individual will spend two years as a C Splicer, during this time period, they receive both formal and on-the-job training. After two years they are brought back in for a test where they prepare a more complex splice, and a transition joint. If successful, they will then advance to a B Splicer.

Individuals will spend a year and a half as a B Splicer. During this time, they undergo more rigorous classroom training, and more OJT. At this point, they take a test that includes the preparation of a five way splice. If successful, they will be promoted to an A Splicer. The A Splicer is the journeyman level in the job family.

Upon need, Duke will fill either Senior Splicer positions or Network Service Person positions from the A Splicer position. Duke’s current procedure is to select the most senior man to fill the Senior Splicer or Network Service Person positions. The Network Service Person does 100% network type of work including maintaining network equipment such as network protector. The Senior Splicer does all work from the top side of the switch up, such as making high side connections, and building terminal poles.

Dana Avenue supervision noted that one shortcoming of the existing system, is that it prevents them from hiring a “skill set”, such as a breaker expert.

Note that climbing is not a requirement for advancement in the Cable Splicer job family. At Duke Energy Ohio, the District offices are responsible for house drops. Any work performed by Dana Avenue can be performed out of the bucket or ladder.

Cable Splicers are required to have a CDL license.

3.7.8 - Energex

Construction & Contracting

Crew Makeup - Job Progression

People

The journeyman position for working with cable systems at Energex is the cable jointer position. Employees move through the jointer apprenticeship program in about three and one half years. The apprenticeship includes formal training, testing, on the job training, and time in grade. At the conclusion of the apprenticeship, persons in the program must still complete a “basket of skills” required by the electrical office. These skills are over and above the skills that are taught as part of the apprenticeship, but necessary for the employee to be a fully qualified jointer. Employees complete this basket of skills in the first 18 months after apprenticeship. Consequently, it takes 5-6 years in total before an employee is fully qualified to run a job. See attachment for a sample of the basket of skills required for cable jointers. ( Attachment A: Cable Jointer Skills )

Energex’s training requirements match the requirements of the Australia Qualifications Framework (AQF), and are thus, accredited. This qualification is recognized throughout Australia and is “fully transportable". So, an employee who receives a qualification as a Cable Jointer from Energex would be recognized as a cable jointer outside of Energex. Energex complements the training requirements outlined by the AQF with training requirements specific to the electric industry, such as a requirement to be able to terminate cables on switch gear. Training courses are developed by reviewing documented work practices, and with input from Energex people with strong knowledge of the work.

The following two agencies drive job progression/competency:

Electrical Safety Office requires that employees show competency and currency in the following:
- Performs licensing, policing, and proof of the currency of employee competency and skills.
- Defines the competencies in which employees must be proficient. Requires that employees are licensed and that we can show proof of competency and currency.

Workplace Health and Safety Office mandates the following:
- Requires that employees have a safe system of work.
- Decides which safety training employees should receive, such as training on proper PPE, for example.

Process

Training is based on work practices. Work practices are developed with input from SMEs, and with input from the Operating Advisory Council (OAC). Note that the OACs are made up of representatives from Standards, Design, and field personnel such as cable jointers. The work practices group documents how tasks are performed. The OAC decides whether the work requires an employee to demonstrate competency, and if that competency needs to be periodically reviewed. High-risk tasks may require frequent refreshers to renew competency. Lower risk tasks may only require a one-time training.

3.7.9 - ESB Networks

Construction & Contracting

Crew Makeup - Job Progression

People

Cable splicing at ESB Networks is performed by Network Technicians, the journey worker position. The Network Technician is a mutli-faceted position, performing both line work, such as building pole lines, and electrical work, such as making connections at a transformer. Network Technicians work on all voltages from LV through transmission voltages (400kV). Note that ESB Networks created the Network Technician position in the 1990s by combining a former Line Worker position and Electrician position.

Work specialization for Network Technicians is by assignment. ESB Networks has implemented a system of approvals that ultimately “allows” an NT to complete a particular work type. This effectively specializes the NT into three specific areas:

Area Staff – This is a customer facing position that services as the first point of contact for faults on the system, analogous to a “trouble man” position at many US utilities.
HV Stations - NTs in this area specialize in high voltage (HV) sub-stations. Within this section there may be approved cable jointers and commissioners.
Lines Staff – NT ’ s in this area specialize in line construction. Within this section there may be approved cable jointers.

In Dublin, where the majority of the distribution infrastructure is underground, Network Technicians work mainly as cable jointers, installing underground cables and accessories. ESB Networks rotates Network Technician work assignments as business needs require.

The Training and Asset Management groups work closely with Network Technicians working as cable jointers to ensure that they understand the science of cable joints and have an appreciation for the importance to long-term joint reliability of performing the proper steps associated with cable joint preparation.

ESB Networks has a four-year apprentice training program for attaining the journeyman Network Technician position. The content of this program conforms to a national standard (Ireland). The journeyman position is qualified as both a “linesman” and an “electrician.” (Historically, at ESB Networks, a “linesman” builds lines, and an “electrician” makes connections such as at a transformer.)

Process

The apprentice program consists of formal training (both ESB Networks-offered training and university training), testing, on-the-job training (OJT), and demonstration of proficiency. One of the points in the apprenticeship is a “One Stop” in the third year of the apprenticeship. The One Stop is a demonstration by the apprentice of the ability to perform construction of a MV line (10 kV), including the construction of multiple spans, installation of transformers, installation of secondary, installation of services to the meter, commissioning equipment (such as performing a Meggar test on the transformer), and energizing facilities.

Much of the formal training associated with the apprenticeship occurs at the ESB Networks training facility. This facility includes an indoor training facility with sample equipment from the station level down to LV network built to the specifications of its system (for example, 38-kV and 10-kV spacing on equipment). ESB Networks’ training approach is to expose apprentices to the practical application by having them work on real equipment in this test environment before exposing them to field conditions. This approach gives apprentices an opportunity to familiarize them with the equipment and its operation in a safe environment, before working that same equipment in the field.

Throughout the apprenticeship, the apprentice must complete a training and assessment record that tracks the progress of both the formal course work taken in a university setting, as well as on-the-job training (see Figure 1 and Figure 2). In addition, ESB Networks utilizes a very detailed and comprehensive “Apprentice Handbook”, which must be completed during the four year apprenticeship. At the conclusion of the apprenticeship, the apprentice is given a certificate and a card certifying that he is a qualified electrician.

Figure 1 and 2: Apprenticeship training and assessment record

3.7.10 - Georgia Power

Construction & Contracting

Crew Makeup - Job Progression

People

Organizationally, Georgia Power field resources that construct, maintain, and operate the network infrastructure fall within the Network Underground group, a central organization that is responsible for all network infrastructures, led by a manager. The Network Underground group is responsible for network underground infrastructure throughout the state of Georgia, including Atlanta, Athens, Macon, Savannah, and Valdosta. The Network Underground group is responsible for all of the manhole and duct line systems at GA Power, both network and non-network.

The Network Underground group consists of Test Engineers, Cable Splicers, Duct Line Mechanics, Civil Construction Engineers (for design and supervision), Test Technicians, Winch Truck Operator (WTOs), and Light Equipment Operators.

Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Cables splicers also pull cable and operate network equipment.

Duct Line Mechanics perform the civil aspects of the work, including duct line, manhole and vault construction. Duct Line Mechanics may also pull cable. The Network UG Construction group also utilizes contractors for performing much of the major civil construction work. Georgia Power has a few contractors of choice for underground work, and has standing agreements with these companies, many of which have been working for Georgia Power for a number of years. Cleaning and civil maintenance is inspection-driven. If, during routine inspections, a field engineer, Test Technician, or journeyman finds and documents the need for civil maintenance or cleaning into the company’s DistView or GIS system, the appropriate construction crew or cleaning crew is dispatched for further analysis and action.

Maintenance and operations of network equipment such as network transformers and network protectors are performed by Test Technicians within the Test Group of the Network UG Operations and Reliability group.

The Winch Truck Operator position (WTO) is a helper type position and is not unique to the Network Underground department. WTOs send down material and supplies to Duct Line and Cable Splicing crews when working on network underground projects.

Process

Winch Truck Operators (WTOs) are the entry level position at Georgia Power’s Network Underground group and can matriculate into either a Cable Splicer or Duct Line Mechanic Apprenticeship based on seniority and the employee’s desire to work in either area. Senior WTOs bid on open Duct Line or Cable Splicer Apprentice openings. Some employees never enter the apprenticeship programs, however, and remain as WTOs. There is no test or examination to enter into these Apprenticeships.

A typical cable-splicing crew consists of three men, including a Senior Cable Splicer, a Cable Splicer (the Journeyman position), and a Winch Truck Operator. Cable Splicer is one distinct job family within Georgia Power’s Underground Network group with the following progression:

Apprentice Cable Splicer
Journeyman Cable Splicer
Senior Cable Splicer

Georgia Power typically runs a six-man crew for duct line work, but it depends on the nature and scope of the work. Duct Line Mechanic is another distinct job family within Georgia Power’s Underground Network group. Duct Line Mechanics are responsible for duct line work in the manholes and vault construction (pouring duct lines, construction, etc.). The Duct Line Mechanic group consists of the following positions:

Duct Line Apprentice
Duct Line Mechanics (Journeyman)
Senior Duct Line Mechanic

All Cable Splicers and Duct Line Mechanics are IBEW. All network field workers report out of the Network Underground group’s main office in Atlanta, but the group also has 11 people stationed at another office on the north side of the city to be physically closer to their area of responsibility. There are 28 Journeyman Cable Splicers/Senior Cable splicers in Atlanta and 9 more in Augusta and Savannah. There are 12 Duct Line Mechanics. All normally work day shift only, but can be temporarily rescheduled for night work as needed. In total, Georgia Power Network Underground employs 72 union personnel.

Training

Both the Cable Splicer and Duct Line job groups have a three-year job progression to achieve journeyman status. Both job families require a combination of time, on the job training, formal training and testing to advance. Training, broken into six-month modules, is delivered at at the Georgia Power Network Underground training center, and taught by senior personnel. Each module has three-weeks of classroom training and requires extensive on-the-job training (OJT) to reinforce the skills presented in the formal training.

As a part of formal training, Apprentices must pass a test at the end of each six-month module before proceeding to the next level. Apprentices have two opportunities to pass each test. Apprentices receive a salary increase as they pass each level.

If an employee advances to Senior Duct Line Mechanic and wants to switch to Cable Splicer, he must go back through the three-year cable program and pass the apprentice program for a cable splicer. Georgia Power employs many more Cable Splicers than Duct Line Mechanics. The more popular job progression within the company is to move from a WTO to the Cable Splicer apprenticeship (more popular than the Duct Line Mechanic Apprenticeship, even though these positions pay about the same.) Note that the cable splicer job family is more technical than is the duct line mechanic family, and therefore requires more technical training, both formal and OJT.

The Network Underground group exposes apprentices to as many OJT tasks as possible. For example, the group will assign an apprentice with a Senior Cable Splicer to perform a particular task such as the preparation of a straight lead splice. Each Apprentice has an OJT book that contains a checklist of the various tasks that are required. The apprentice’s supervisor must sign and date the OJT checklist when the Apprentice has worked on a particular task. There are some tasks that are not formally part of the training program, but that the network underground leadership expects the apprentices to accomplish during their OJT. One such task is the proper racking of a manhole. It is the apprentice’s responsibility to ensure his supervisor signs and dates completed tasks in the OJT booklet.

Advancement is based on formal training and testing, not on completion of the OJT booklet; the supervisor can make arrangements to ensure each Apprentice receives the appropriate OJT tasks, whenever possible. Formal training often includes hands-on tasks, such as cable splicing. For example, two supervisors can evaluate an Apprentice’s splice and determine whether the apprentice prepared the splice correctly, examine the measurements, and make sure the splice meets Network Underground group specifications. Eventually, throughout the three-year program, these OJT tasks are completed.

Job Forecasting

It is notable that the Georgia Power Network Underground group regularly forecasts both union and non-union job function staffing levels on a three-year basis, based on anticipated promotions, attrition, and retirements. The group often rotates a Senior Cable Splicer or Duct Line Mechanic into a three-month rotation as a crew/distribution supervisor to gain management experience. The company calls this process “blue-slipping.” (Name comes from a blue slip of paper that was used to document the change). Network Underground supervisors confer and vet the top candidates to rotate into these “blue slip” positions. The “blue slip” rotation does not guarantee the supervisory job once it is vacant, but the “blue slipped” employees receive first consideration and interviews for any non-union supervisor positions that open up. The rotation also gives senior splicers and mechanics a chance to see if the management roles are jobs they might prefer. During the time of the “blue slip” rotation, these employees receive a temporary salary increase. If an employee moves out of the union into a supervisor position, the employee has two years to decide whether he would like to stay on as a supervisor or move back to his union position.

Georgia Power also offers a distribution engineering course, a two-week week class in basic distribution design that every new Georgia Power engineer attends. In addition, every Georgia Power engineer attends a network orientation session to introduce them to the network side of the business, and to gain recruits for the Network Underground group.

Technology

Much of the formal training associated with the advancement to the Journeyman level for Cable Splicers and Duct Line Mechanics is performed at the Georgia Power Network Underground training facility in Atlanta (See Figure 1 through Figure 4).

Figure 1: Training Center – Network Unit. Note cutaway of termination chamber

Figure 2: Training Center – Joint assembly practice area

Figure 3: Training Center – Full size manhole

Figure 4: Training Center – Termination assemble practice area

All Apprentices, as well as other Georgia Power employees, receive a number of safety-related courses, such as manhole entry, rescue, CPR, and storm emergency drills. (See Safety and Drills sections in this report.)

3.7.11 - HECO - The Hawaiian Electric Company

Construction & Contracting

Crew Makeup - Job Progression

People

At HECO, underground work is performed by both Cable Splicers from the C&M Underground Division, and Lineman from the Overhead C&M groups.

The C&M Underground Division at HECO is part of the Construction and Maintenance organization. The group is comprised of two UG supervisors, fifteen Cable Splicers, 2 Utility Mechanics, and 2 Utility Assistants. The Cable Splicer is the journeyman position in the department. These individuals perform all activities associated with the construction, maintenance and operation of the Underground system, including working with lead (PILC) cable and transition splices.

Note that the Underground group does not install or maintain network equipment such as network transformers or network protectors. Network equipment construction and maintenance is the responsibility of the Substation group at HECO. The Substation group is part of the Technical Services Division of the System Operations Department.

The Overhead C&M groups also perform work with underground facilities (normally, URD facilities). The journeyman position in the Overhead groups is a lineman.

The Cable Splicer and Lineman family of jobs are represented by collective bargaining – IBEW local 1260

Process

HECO has an automatic mode of progression for the lineman classification. Employees who enter the department are expected to successfully complete all required training and achieve the journeyman lineman position in four years.

A lineman who enters as an apprentice into the Overhead group must complete 6000 hours of work as an apprentice, including formal and on the job training, in order to become a Lineman – First Year. Apprentices who have completed the training must pass a timed open book test that is administered by the State of Hawaii in order to achieve their certificate and advance. Once a worker achieves this level - Lineman – First Year - he must demonstrate that he can perform all of the skills associated with the job in order to advance to a full journeyman Lineman one year later. See Attachment F for a list of the skills and training requirements (formal “Modules”, “On the Job”, and “Related” training) that are part of the Overhead Lineman apprentice program at HECO.

Cable Splicer positions are filled in the C&M Underground department from the Journeyman Lineman position in the Overhead Group. The Cable Splicer would receive a combination of formal and on-the-job training in order to be certified as a Senior Cable Splicer after one year. The Underground department normally draws the most experienced Lineman as the positions in the C&M Underground group are sought after.

Note that journeymen in this classification are “jacks of all trades”; that is, they will perform all required work in the ducted manhole system, including maintenance of equipment, preparation of splices, pulling cable, etc. The only exception is working with network transformers and network protectors, which is the responsibility of the Substation group.

Technology

HECO has documented training modules for the Lineman and Cable splicer job families.

HECO has a training yard located at a power plant site.

3.7.12 - National Grid

Construction & Contracting

Crew Makeup - Job Progression

People

The National Grid network field resources (network crews) are part of the group responsible for the underground system in eastern New York, called Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Civil Group is comprised of Mechanics, Laborers, and Equipment Operators, and is led by a supervisor. This group includes a machine shop located in Albany. The group has 23 field resources.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics, is led by three supervisors. Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. Maintenance Mechanics perform network switching, fault location, minor vault maintenance, and inspection and maintenance of network equipment such as transformers and network protectors. The total UG Electric East group has 29 field resources.

The Electrical Group field classifications are represented by a collective bargaining agreement. (Union IBEW in New York, multiple unions in NE). Advancement in union positions in UG East is through an automatic progression to a journeyman.

Process

All positions (Cable Splicers and Maintenance Mechanics) start as a Helper for six months. After these six months, candidates take a review exam to see if they’re eligible to progress.

Upon progression, candidates become an “A” employee (Cable Splicer A or Maintenance Mechanic A) for 12 months, Then they move to “B” level for 24 months, and then finally advance to a “C”, which is the journeyman level. Progression through the levels involves a combination of formal training, and on-the-job training. Employees are expected to fully advance to the “C” level in 42 months.

For each step of the progression, the employee must pass the training school for that step, and pass a review by a panel of his/her supervisors. Those that do not pass the formal testing for advancement the first time do get a second chance. If they fail a school or supervisory review, employees are allowed time to upgrade their knowledge and offered a second chance at the school or review. The progression is automatic in terms of time, but they must pass the schools and reviews and advance to the C level in 42 months. If an employee does not pass on the second try, he is given a time period to bid out to another department.

Chief positions are posted as they become vacant. Candidates who bid on these vacancies are expected to have a minimum of three years at the “C” level.

At each level, employees receive formal classroom training. Each school (A,B, & C) are ten days long, and typically held in Syracuse, NY. In addition, formal training classes are provided periodically throughout the progression series, such as network protector diagnostics (three days), safety training, etc. All field employees also participate in four days of Annual Expert Training in Schenectady, NY, regardless of their progression status (Helper through Supervisor).

The formal training in the mode of progression includes internally offered training as well as external training. For example, National Grid will bring in Richards Manufacturing or Eaton to perform training on network protector maintenance for Maintenance Mechanics.

Some of the training includes common modules to both underground and overhead resources, such as First Aid, or Bucket Rescue.

The administration of on-the-job training is handled informally. National Grid does not use an OJT checklist. Rather they assure that resources are exposed to the various work types through job assignment.

National Grid has developed an annual expert training curriculum to provide incumbent employees with three to four days of refresher training.

Technology

The formal training for Cable Splicers includes courses such as:

Cable Splicer A Training
- Safety
- Work area protection
- Enclosed space training
- Tools
- Test equipment
- Troubleshooting streetlights
- Cable, joints and terminations
- Hoisting and rigging
- Electrical symbols

Cable Splicer B training
- Safety
- Dig Safe
- Transformer theory
- Rotation testing
- Network system presentation
- Pin pointer
- Cable joints and terminations

Cable Splicer C training
- Safety
- Test equipment
- Transformers
- MOV arrestor’s
- Corrosion
- Tags
- One line diagrams
- Forms
- Failure paths and causes
- Clearance and control
- Cable joints and terminating

In addition to these courses, Cable Splicers receive a number of other safety and environmental related courses, including lead awareness and manhole entry and rescue.

National Grid has a two training centers that contain classrooms and field equipment used for underground training, One is in Syracuse, NY, and one in Milbury, MA. Most training for UG NYE is in Syracuse. In addition, Annual Expert Training and some miscellaneous training is conducted at the training center in Schenectady, NY.

3.7.13 - PG&E

Construction & Contracting

Crew Makeup / Job Progression

People

The PG&E network field resources (network crews) are part of the Maintenance and Construction- - Electric Network organization. The group is comprised of Cable Splicers, a bargaining unit position. Cable splicers perform both cable work, such as cable installation and splicing, and network equipment work, such as network protector and transformer maintenance. Advancement in the Cable Splicer job family is through an automatic mode of progression.

In San Francisco, PG&E typically runs 4 three man crews in the evening. A crew is normally made up of a Journeyman Cable Splicer, who does most of the network Protector work, and two helpers (usually Apprentice Cable splicers.

PG&E also has three Cable Crew foremen on the night shift. The Cable Crew Foreman is a working position, with one foreman typically taking clearances and installing grounds, and the others overseeing the crews.

PG&E also uses a position called a Cableman which is a troubleshooter for the underground system, part of PG&E’s Restoration group (not part of the M&C electric Network organization). There are six Cableman who work for the company. They work a a rotating shift , and have coverage 24/7. The cableman is a position that must be bid into.

Note that the network crews in San Fransicso work exclusively at night ^[1] . They have made this decisions for two main reasons.

Restrictions on blocking traffic during the day as prescribed by the San Francisco Municipal Transportation Authority,
Concerns by Network Planning around operating in an N-1 contingency during the higher loads experienced during the day.

Note that PG&E is currently working in identifying feeders and units that can be taken out during the day to try to spread some of the planned maintenance activities in the network to the daytime hours.

^[1] Note that Cable splicers are assigned during the day to work on San Francisco’s radial underground system. These crews can be redirected to address network issues that may arise during the day. However, all planned work on the network is performed at night.

Process

Employees enter the Cable Splicer family from the T&D Assistant, an entry level position at PG&E.

To be a T&D Assistant, PG&E requires a high school diploma, and successful passing of various tests, such as math and memory test, in addition to standard hiring testing (such as drug testing).

When candidates enter the Cable Splicer job family, they enter as an Apprentice Cable splicer. There is a 30 month mandatory progression to the Journeyman Cable Splicer position.

There is specific training and testing that must be completed, and on the job training (OJT) that must be demonstrated and signed off upon. Employees are also sent into the “PGE Academy”, a formal training program for Apprentice Cable Splicers. This program is distinct from a similar PG&E apprentice program for lineman. The PG&E Academy has an Apprentice Coordinator who keeps track of the progression, and works with the apprentices in the program.

Formal training is supplemented by on the job training. Locally, the crew foremean or supervisor will do informal training, giving apprentices opportunities to experience different work types. Note that PG&E has worked with Cable Splicers to develop a training program for apprentices that includes significant hands on training opportunities.

PG&E has a position called a Cable Crew Foreman. This is a working position. The Cable Crew Foreman is a bid position, typically filled by the senior qualified interested Cable Splicer. PG&E will upgrade a Cable Splicer to a Cable Crew Foreman on certain jobs. There are three Cable Crew Foremen who work the night shift. One takes the clearances, one oversees the crews, and the other assistance where necessary.

PG&E also has a position called a Cable Man (6 total positions). The Cable Man serves as an underground troubleshooter. The Cable Man position is typically filled from the senior qualified Cable Splicer, The Cable Men, part of the restoration group, work a rotating shift and provide 24/7 coverage.

Technology

The formal training associated with the PG&E Academy for apprentice cable splicers includes courses such as:

Introduction To Cable Splicing. Focuses on PILC cables and and teaches the duties of the helper. It includes content such as manhole safety, setup, the use of construction manuals, work procedures, and tools. Safety and quality are emphasized and participants must demonstrate the ability to build a lead splice.
Beginning Lead Splicing. This course revisits the teachings from the introduction course, and includes participants building six major projects of increasing. This particular course is very hands on.
Intermediate Lead. This course focuses on safety, and includes content on basic electricity, and on building transformer banks.
Advanced Lead Training. At this point, participants will have from 2 to 2 ½ years of training and experience. This course includes content about the overall electrical system, various system configurations, fault indication, fault location, as well as requiring the completion of a complicated splice.
Underground Fundamentals. This course is provided to both Cable Splicers and Linemen. It focuses on non-lead cables and splices. It includes discussion of pre-molded splices, the function of stress cones, fault finding, and secondary. It is a “back to basics” course, even though it is offered later in the progression for Cable Splicers.

In addition to these courses, Cable Splicer apprentices receive a number of safety related courses, including lead exposure and manhole entry and rescue.

PG&E has a well equipped training center that contains classrooms, and field equipment used for training.

Figure 1: Training Facility - Cable Racks

Figure 2: Training Facility - UG Equipment

3.7.14 - Portland General Electric

People

The craft workers assigned to the CORE group, which is a part of the Portland Service Center (PSC), focus specifically on the underground CORE, including both radial underground and network underground infrastructure in downtown Portland. An Underground Core Field Operations Supervisor leads the CORE group.

Currently, the following 16 people work in CORE:

Four non-journeymen,
Eleven journeymen (e.g., assistant cable splicers, cable splicers, foremen)
One Special Tester

Resource in the CORE include the following:

Crew foreman: Crew foreman (a working, bargaining unit position), required to be a cable splicer
Cable splicer: This is the journey worker position in the CORE.To become a cable splicer in CORE, an employee must spend one year in the CORE area as a cable splicer assistant.
Cable splicer assistant: A person entering the CORE as a cable splicer assistant must be a journeyman lineman. All cable splicers start as assistant cable splicers for one year to learn the system and network.

The Cable Splicer position is a “jack-of-trades” position with work including the following:

Cable pulling
Splicing
Cable and network equipment maintenance
Cleaning
Pulling oil samples from transformers

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault, while the helper usually stays above ground, carrying material and watching the barricades and street for potential hazards.

In addition, a crew may include an equipment operator who will operate the cable puller, vacuum truck, or other equipment. Note that some work, such as backhoe work, is usually performed by external contractors.

Progression

The journeyman position within the CORE group is the cable splicer position. Journey linemen fill cable splicer positions by progressing through a formal advancement program.

In terms of the lineman progression, an employee should achieve journeyman status within 3.5 years after achieving the apprentice position. Someone inexperienced, such as a new employee hired off the street, must complete a two-year pre-apprenticeship before becoming an apprentice. Therefore prior to becoming journeymen, most inexperienced workers serve as both pre-apprentices and apprentices, taking a total of 5.5 years. Workers should achieve the journeyman level at the end of the apprenticeship.

Pre-Apprentice/Apprentice: A pre-apprentice studies for up to two years in order to be eligible for an apprenticeship. The pre-apprenticeship includes training, both formal and on the job, in addition to the achievement of certain milestones (demonstrated ability to perform certain work). The move from pre-apprentice to apprentice depends on whether an opening for an apprentice position appears. Although it is possible to spend a lot of time as a pre-apprentice waiting for an apprentice opening, PGE commits to finding an apprenticeship for new hires in about two years. The pre-apprentices are tested monthly on the achievement of their milestones.

Journeyman Lineman: An apprentice follows a seven-step, 3.5-years-long apprenticeship before becoming a journeyman. They must work for a certain number of hours in different disciplines, including secondary systems, underground primaries, and hot stick usage. The apprentice must pass a number of tests/on-the-job (OJT) requirements before becoming a journeyman lineman.

Note that an experienced line worker who has completed an apprenticeship and has relevant experience elsewhere may be hired directly as a journeyman.

Journeyman lineman perform work on both overhead and underground distribution systems, including the performance of cable splicing in underground residential distribution (URD) systems. In the CORE, however, where the infrastructure is both conventional (radial) and network underground in ducted manhole systems, the cable splicer position, which is filled from the journeyman lineman position, performs work.

Cable Splicer: A journeyman lineman enters the CORE group as a cable splicer assistant and spends 12 months of continuous experience learning the area and the work processes, as specified in the bargaining union contract. During this time, they gain experience in the type of work performed in the CORE, including activities such as network protector testing, vault cleaning, performing inspections, and preparing a trifurcating splice. After one year, they become a cable splicer. After only one year, a cable assistant may not be fully proficient on all aspects of the required task, but will have enough experience to run a crew as a temporary foreman. The training and on-the-job experiences provided to the cable splicer apprentice are managed informally.

Overall, PGE has some issues retaining and recruiting workers for the network underground work, because many prefer working on the overhead system.

Other Crews and Positions

Special Tester: PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. Outside the network, Special Testers work with reclosers and their settings, performing cable testing and cable fault location. Within the network, the Special Tester works closely with the network protectors, becoming the department expert with this equipment. PGE has embedded one Special Tester within the CORE group. This individual receives specialized training in network protectors from the manufacturer, Eaton.

The Special Tester usually partners with cable splicers, working as part of a crew. The “special testing” crew includes the Special Tester, a crew foreman or cable splicer, a lineman/cable splicer, and a topman. The topman stays outside the hole and watches the manhole/vault entrance to ensure zero accidents.

In addition to network protector (NP) testing and settings, the Special Tester focuses on power quality issues, including customer complaints about voltage.

Network Protector Crew: The CORE group has created a dedicated crew that deals with network protectors and performs other construction work. This crew is comprised of cable splicers who receive formal training and attend conferences to gain experience with network protectors. This crew includes a foreman, journeyman (who rotates every three months), and Special Tester.

PGE has approximately 230 network protectors on the system, with half included in the 480 V spot networks, and half in the 120/208 V area grid systems. Presently, they have three construction/maintenance crews, and will add the dedicated crew protector crew.

Journeyman Locator: The CORE has a cable splicer/journeyman in charge of “locate” requests, and this role is never outsourced. The network had 1600 locates last year. Ideally, the locator works with the Mapper to ensure accurate maps.

Infrared (IR) Thermography Tech: IR techs inspect primary systems and network protectors as part of the Quality and Reliability Program (QRP). PGE has three IR techs who mainly focus on the transmission system. They also work on high-priority secondary systems.

None of the IR techs are dedicated solely to the CORE.

Training

In addition to the training provided as part of the apprenticeship programs, PGE provides employees/contractors with other types of training. For example, the Change Management/Continuous Improvement Group oversees information technology (IT) training programs, and the Contract Management Group supervises training for external contractors to qualify them for designing building vaults to PGE specifications.

Process

For routine training, PGE often brings in a vendor such as Richards, Raychem, or Eaton, who provide hands-on training associated with their equipment (e.g., asking Raychem to train on preparing a Raychem transition joint). Training is periodical and often scheduled during slow periods, such as when the city mandates that PGE crews cannot work on the streets because they block traffic, usually in June. The CORE will also send folks to vendor-offered conferences and training courses.

On the network, many work practices pass down through practical experience rather than through formal training classes.

Safety Training

Compliance training includes vault rescue, pole top rescue, and all other federally mandated training. The vault rescue class is a company-wide training undertaken annually, and workers train in a shallow vault that does not always resemble the deeper network vaults. Accordingly, the CORE may augment this training with more specific vault rescue training geared to the network vaults, which would take place in a live vault since they do not have a deep test vault. PGE also provides annual computer-based training on “Confined Space” practices.

PSC will bring in an external vendor to give lead and asbestos training, as needed.

PGE has invested in the documentation of “Safe Work Practices” in the form of laminated sheets and notes for certain work/tasks. PGE plans to expand this concept to include work practices specific to the CORE.

Fire Department Training: PGE periodically coordinates with the Portland Fire Department for training, covering actions to take if there is a fire in a vault or manhole. In the past, PGE ran exercises on a yearly basis with the fire department, and intends to reestablish these. If a vault rescue is needed, the Portland Fire Department (PFD) utilizes their own rescue equipment. The PFD’s response time is good because they operate from locations across the downtown area.

Emergency Drills: PGE conducts system-wide outage restoration drills once a year, prior to the fall storm season. In the past, this included some scenarios that involved the CORE network system. For example, a recent drill was substation-centric, and the tested scenarios simulated the outage of one of the stations supplying the network.

PGE also conducts annual earthquake drills, which are tabletop exercises organized by the Business Continuity Group. These drills do not always involve the network, depending on the scenario chosen.

PSC has no written guidelines specifically related to unforeseen events occurring on the network.

During an emergency,PGE follows the principals of the incident command system (ICS) at the management level.

Overhead Training

The CORE journeymen, who work almost exclusively with urban underground systems day to day, are required to support restoration work on the overhead system when needed. In restoration, they generally work in two-man crews addressing wire-down situations. In order to reinforce these skills, the CORE group conducts annual training on overhead systems in a de-energized training yard, where it reviews various overhead line work scenarios.

IT Training

PGE offers training on new IT systems, such as Maximo. This training was initially offered on a monthly basis, but as employees have become accomplished, the company has shifted to quarterly sessions. The change management/continuous improvement group provides this training.

Training at the System Control Center (SCC): The bulk of the training for dispatchers associated with network is informal and “on-the-job.” The company does offer an optional computer-based training course, developed by SOS Computer Training Specialists and designed for the North American Electric Reliability Corporation (NERC) system operators, which includes a module related to network systems.

External Contractor Training

PGE issues a certification to external contractors who build vaults. PGE offers different levels of certification to contractors depending on the vault size and complexity. Level 1 involves installing a conduit duct bank pack in a subdivision. Level 2 covers vaults up to 7 x 12 ft (2 x 3.7 m) in size, and Level 3 covers anything above that size.

At the time of the immersion, customers could choose from two different contractors (as they had received a PGE certification) for large vault construction, with a Level 3 designation.

The certification function is transferring to the contract management group.

Civil Work

PGE contracts out all civil work, including manhole lid replacement and duct work construction and repair. PGE provides project management to civil crews but does not offer civil crews any particular training.

Note that PGE typically does not use external contractors to perform electrical work in the CORE. It uses overhead crews for assistance in activities such as pulling cable.

3.7.15 - SCL - Seattle City Light

Construction & Contracting

Crew Makeup - Job Progression

People

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable Splicers perform all electrical aspects of network construction, operations, and maintenance. All electrical employees who work in the network are either Crew Chiefs, journeyman Cable Splicers, or apprentices in the mode of progression, working their way towards the journeyman level.

Mode of Progression

SCL uses a three-year automatic mode of progression. This mode includes 8000 hours of On the Job Training (OJT) and testing. They have experienced a very low dropout rate from the program. This is in part because they administer a highly selective front end test and interview process to accept apprentices into the program. Also, a Cable Splicer position at SCL is a highly sought-after position.

Training

In addition to the training associated with the mode of progression, SCL provides network crews with opportunities for training including mandatory safety training for processes such as manhole entry and manhole rescue. SCL also periodically sends personnel to conferences and specialized training sessions such as the Cutler Hammer School, etc.

Crew Makeup

A network crew is normally made up of one Crew Chief, one or two Cable Splicers, and one apprentice. The type of work to be done and SCL work rules will dictate the appropriate crew makeup. For example, performing switching in a vault requires at least two journeyman-level employees to be in the vault. These and other work rules and safety practices are spelled out in the Washington State Safety Standards for Electrical Workers, Chapter 296-45 WAC.

3.7.16 - Practices Comparison

Practices Comparison

Construction & Contracting

Job Progression

2015 Survey Results

Older Survey Results

3.7.17 - Survey Results

Survey Results

Construction & Contracting

Crew Makeup - Job Progression

Survey Questions taken from 2015 survey results - Summary Overview

Question 011: Within your company, how many Full Time Equivalent resources (FTEs) make up the following functions?

Survey Questions taken from 2012 Survey results - Construction

Question 5.1: Total number of Network field electrical workers (do not count “civil” workers)

Question 5.2: Do you contract any network electrical (not civil) construction work?

Question 5.6: Not counting training that is part of your apprentice programs, How many hours of training (on average, per person) does your field force receive in a year?

Survey Questions taken from 2009 Survey results - Construction

Question 5.1: Do you have a distinct field group focused on the construction, maintenance and operation of the network? Or are your field workers part of a group that also works with non network systems?

Question 5.2: Total number of Network field electrical workers (do not count “civil” workers) ( this question is 5.1 in the 2012 survey)

Question 5.3: Do you contract any network electrical (not civil) construction work?

Question 5.7: Not counting training that is part of your apprentice programs, How many hours of training (on average, per person) does your field force receive in a year? (This Question is 5.6 in the 2012 survey)

3.8 - Field IT Technology/Training

3.8.1 - Portland General Electric

Construction & Contracting

Field IT Technology/Training

Process

PGE is moving away from handheld radios and paper records, and has equipped field workers with mobile technology, including smartphones, tablets, and laptops. All company-issued phones are smartphones, and many field employees will be given tablets to help them access reports and take photos to attach to work orders.

To lay the groundwork for the new mobile technology, PGE set up an ongoing process to talk to crews about the need for the new technology. For workers unfamiliar with the technology, PGE offered a training program before implementation of the new systems. A week before the rollout, work groups spent the entire day with instructors giving lessons with laptops.

PGE also provides ongoing technical support for laptops, with each field device fitted with a sticker containing the 24-hour support phone number. A technical support employee can operate the worker’s laptop remotely and solve the problem.

First responders and repair crews have used laptops for over five years, and each truck is fitted with a station allowing crews to access information from their trucks.

Figure 1: laptop in PGE work truck

Maximo is at the center of the new data collection system, and Field Manager allows crews to access daily work assignments remotely. Workers can also access the Computer-Generated Imagery (CGI) Asset and Resource Management Scheduler, which imports job assignments from Maximo.

With the new system, distribution crews, planners, schedulers, inspectors, and dispatchers all use the same platform, improving communication and coordination. To accommodate the different roles within the organization, employees access different dashboards with the information they need.

The new mobile system means that crews do not have to visit the yard every morning to receive work orders. They can also use gas cards to fuel trucks at any gas station instead of the yard, allowing them to spend more time in the field.

When crews begin a shift, they login, indicate that they are proceeding to a job, and check in when they arrive and leave the site. With this information, PGE can track time and work out costs.

Dispatchers can send the closest qualified crew to a particular job, reassigning workers if a job is more complex than anticipated and ensuring that crews are given balanced workloads.

If a crew notes that assets need repair, they can create an electronic work order in the field rather than filling in paper requests. Field Manager allows crews to receive, update, and close jobs, supporting flexible dispatching and work planning. The system allows crews to respond to outages more quickly [1].

R. Lewis II. “Mobile Tools Maximize Productivity at PGE.” Transmission and Distribution World, January 27, 2015. http://www.tdworld.com/features/mobile-tools-maximize-productivity-pge(accessed November 28, 2017).

3.9 - Manholes

3.9.1 - Ameren Missouri

Construction & Contracting

Manholes

People

Ameren Missouri has a Civil and Structural Design group, part of Energy Delivery Technical Services. The group is responsible for developing civil designs and standards for civil construction and repair. As an example, this group develops design standards for precast manholes. The group is also involved in deciding the best approach for making repairs to civil infrastructure, such as manholes and vaults. Ameren Missouri will utilize civil design contractors to supplement their civil design efforts.

Ameren Missouri uses contractors for performing much of the major civil construction work, such as building vaults, manholes, and duct bank systems, and for making civil repairs to existing infrastructure. Repairs can range from epoxy injection to fill cracks, to replacing deteriorated vault roofs.

Ameren Missouri has a Resource Management group responsible for managing outside contractors. This group is organizationally part of Energy Delivery Technical Services. The group is led by manager, and is comprised of construction supervisors who manage outside contractors.

Ameren Missouri has a few contractors “of choice" for underground work. These are contractors with which Ameren Missouri has three or four year agreements. The contractors are part of the union, hired from the local bench.

Technology

Ameren Missouri’s manhole and vault standards call for a precast design for most applications. However, Ameren Missouri has precast, poured in place and brick and mortar manholes and vaults in service.

At the time of the EPRI practices immersion, Ameren Missouri was considering the selected use of new manhole covers that would allow gases from a manhole fire to be expelled, while retaining the cover. They were investigating the use of a system referred to by the trade name “SWIVELOC™”, consisting of a reinforced cover with a pivoting hinged assembly with two latches on the underside. One latch is fixed and the other is retractable for ease of installation of the cover. In the event of an explosion, these manhole covers are designed to pivot lift (or rise) upward on a hinge assembly and expel hot expanding gases associated with an arcing event or explosion. The retention of the cover by the latches and the scalloped rim on the underside of the cover also aid in expelling the gases at high speeds. This prevents an influx of air into the vault during the dynamic phase of the explosion, thereby reducing the size and duration of the event. The cover drops back into place once the hot gases are expelled and eliminates additional ingress of air into the vault after the event, which further reduces the risk of restrike. The construction of these covers also prevents the lid from being ejected from the frame, which places bystanders and adjacent property at risk.

3.9.2 - Duke Energy Florida

Construction

Manhole Cover Replacement Program

Process

Duke Energy Florida is undertaking a manhole cover replacement program starting in 2016 with 40 manholes being retrofitted with manhole lid restraint materials.

Technology

Duke Energy Florida is using East Jordan manhole lid restraint materials

3.9.3 - Georgia Power

Construction & Contracting

Manholes

People

Network standards, including standard designs for manholes, are the responsibility of the Standards Group within the Georgia Power Network Underground group. This group develops standards for manhole design and manhole covers used in the network underground. Georgia Power and its preferred contractors perform much of the major civil construction work, such as building vaults, manholes, and duct bank systems, and for making civil repairs to existing infrastructure.

Process

All project designs for manholes are done using AutoCAD, and the engineering group has “canned” examples or reference standard designs to facilitate design. Once designed, the manhole diagrams and drawings are assigned to a civil construction crew or a preferred contractor to complete the construction. Standard, precast manholes are used in the majority of the Georgia Power network underground systems throughout the state.

At the time of this EPRI immersion study, Georgia Power was in the process of replacing standard manhole covers with a SWIVELOC design at all manhole locations in Atlanta containing secondary grid cables (about 1300 locations), as part of a five-year program. The decision to replace the manhole covers with SWIVELOC manholes came after a manhole fire resulted in the ejection of several manhole lids in the downtown area (See Figure 1.).

Figure 1: SWIVELOC materials

The replacement effort is prioritized, with high-traffic areas and high visibility locations, such as around government buildings and civic arenas, having the highest priority.

Technology

The SWIVELOC design enables the manhole cover to rise and relieve the pressure, but contains the lid. It consists of a reinforced cover with a pivoting hinged assembly with two latches on the underside. One latch is fixed, and the other latch is retractable for ease of installation of the cover. In the event of an explosion, these manhole covers are designed to rise upward on a hinge assembly and expel hot expanding gases associated with an arcing event or explosion, without allowing the cover to fly off.

One of the challenges Georgia Power faced was how to restrain the manhole frame; that is, anchor it to the manhole roof. Working with the manufacturer, they developed a restraining system that involves 2 chains attached to the frame and running down through the manhole “neck” or “chimney.” The chains are attached to brackets which pull up on the manhole roof slab. The chains are tightened to pull the brackets firmly against the roof at the sides of the opening See Figure 2 and Figure 3.).

Figure 2: SWIVELOC manhole frame assembly

Figure 3: Manhole frame assembly

Another challenge addressed by Georgia Power was the difficulty in removing the manhole lids. They are using a lid design that includes extractor rails (See Figure 4.), which allows lid to be slid away from the manhole opening (See Figure 5.).

Figure 4: Underside of manhole lid – note extractor rails

Figure 5: Dragging a lid with rails

3.9.4 - Portland General Electric

Construction

Manholes

People

All civil work on the CORE infrastructure, including manhole cover replacement, is contracted. At PGE, the Contract Services and Inspection (CS&I) department supervises external contractors. Five construction managers work in the CS&I group and provide contractor oversight, including inspection of any work on PGE-owned infrastructure.

Process

Within the network, PGE uses solid manhole covers 32 in. (9.6 cm) in diameter and with venting holes. Note that because the city of Portland discourages manhole lids in the sidewalks, most are located in the street.

Figure 1: PGE manhole cover

Figure 2: PGE worker replacing manhole cover

Because the network has had some issues with manhole lids being ejected into the air from manhole events, PGE is presently testing and piloting various manhole led retention systems, such as Swiveloc, for use in the network.

If PGE decides to deploy manhole lid retention, the work will be outsourced, with inspection of the contractor work to be performed by either the Field Construction Coordinators (FCC) or the CS&I group. This decision depends on the magnitude of the deployment.

PGE has been piloting and evaluating manhole lid retention systems as part of an initiative called the Performance Improvement Assessment (PIA). PIA utilizes detailed root-cause analyses performed by the Network Engineers to drive actions, such as reinforcing vault and manhole structures, in order to improve performance.

3.9.5 - Survey Results

Survey Results

Construction & Contracting

Manholes

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 9 : Please indicate where you use vented vault and manhole covers to prevent accumulation of gases. (Not including vented gratings for transformer cooling)

Question 10 : If you apply vented covers selectively, what criteria do you use to select locations?

Question 11 : Are you using manhole cover restraints in parts of your system?

Question 12 : If yes, what criteria do you use to select locations at which to apply a cover restraint?

Survey Questions taken from 2015 survey results - Design

Question 061: Are you retrofitting older existing covers with vented covers?

Question 062: Are you using manhole cover restraints in parts of your system?

Question 063: Are you retrofitting older existing covers with cover restraint systems?

Question 064: Are you performing targeted cover restraint retrofits based on (check all that apply):

3.10 - Master Reel

3.10.1 - CenterPoint Energy

Construction & Contracting

Master Reel

People

CenterPoint has a sole supplier relationship with the cable vendor who supplies their EPR power cable for their Major Underground three phase application.

Process

CenterPoint takes delivery of cable reels on consignment from the cable vendor. That is, CenterPoint does not own the cable until it is moved onto a partitioned Master Reel.

For individual projects, crews will pull cable off of the Master Reel, and onto partitioned reels used to pull cable at the job site.

Figure 1: Master Reel"

Figure 2: Partitioned Reels"

3.11 - Material Failure Reporting System

3.11.1 - AEP - Ohio

Construction & Contracting

Material Failure Reporting System

(Unsatisfactory Performance Report)

People

Identification of unsatisfactory equipment performance at AEP Ohio is the responsibility of the Network Mechanics. As problems with equipment are identified during work activities, they are reported to an Operations Coordinator, who is located at the service center, and Network Engineering. Network Engineering at AEP Ohio is comprised of Network Engineers who report to a Network Engineering Supervisor. The reporting process is informal.

AEP Ohio utilizes a Standards Committee approach to establishment of network material specifications. This group uses a regional approach, with representation from each of the AEP operating companies. This group would respond to a report of unsatisfactory equipment performance and take action if necessary to reach consensus on a change in standard or material specification. AEP engineers noted that each of them has a certain areas of specialty (such as a focus on network transformers), and that a given engineer may respond to and resolve issues that surface from the field.

AEP will issue bulletins on an as-needed basis to inform the workforce of identified equipment problems.

Process

AEP Ohio Network Mechanics will identify and report failed equipment through the performance of regular inspections of equipment, including vaults, transformers, network protectors, secondary and primary cable, and network switchgear (see Maintenance and Operations). Also, any failure on remotely monitored equipment is communicated to the Operations Center through the SCADA system.

Problems with equipment that are not reported through inspection documentation or through SCADA are reported to Network Engineering through an informal process.

Technology

All network protectors are equipped with the Eaton Vaultgard monitoring and control system and connected by a double loop, fully redundant fiber-optic communications network (see Figures 1 and 2).

Figure 1: Vault wall mounted control box for Eaton Vaultgard monitoring and control system

Figure 2: Training center sample control box for Eaton

3.11.2 - Ameren Missouri

Construction & Contracting

Material Failure Reporting System

(Unsatisfactory Performance Report)

People

Ameren Missouri has a Standards Group, led by a Managing Supervisor, and reporting to the Manager – Distribution Planning and Asset Performance. The Standards Group is responsible for developing and maintaining distribution standards for the company, including network equipment. In addition, this group prepares material specifications for distribution equipment, and engineering practice guidelines.

Within this organization are experts who focus on developing and maintaining specific underground standards. For example, cable engineers, who are experts with cable and cable systems, are responsible for the development of cable standards for the company (See Cable Design). Another example of department expertise is a staff member who is a tools expert. ). Another example of department expertise is a staff member who is a tools expert.

Standards Group engineers / subject matter experts are available to respond to questions and issues raised by the field force. The group has implemented a formalized Unsatisfactory Performance Report (UPR) Process used by the field force to report problems with distribution materials.

Process

The Standards Group has implemented a formalized Unsatisfactory Performance Report (UPR) Process used by the field force to report problems with distribution materials. Standards engineers assigned to respond to the UPR must provide some feedback to the person who submitted the UPR within 20 calendar days of receipt of the UPR.

The UPR process includes:

Claimant completes the UPR form and submits to the Supervisor of Standards with a sample of the defective equipment if possible;
Supervisor enters the information into a UPR database and assigns the UPR to a Standards engineer;
Engineer reviews report and sample and determines response based on knowledge of item or report from manufacturer after submittal to manufacturer for analysis;
Engineer responds to claimant and forwards to secretary;
Secretary distributes to distribution list and posts on Standards website

Technology

See Attachment B for a sample of the UPR form.

3.11.3 - CEI - The Illuminating Company

Construction & Contracting

Material Failure Reporting System

(Unsatisfactory Performance Report)

People

FirstEnergy’s Unsatisfactory Performance Reporting (UPR) process is administered by the corporate Design Standards group.

Process

The Unsatisfactory Performance Report is a form that is used by the field force to report and initiate an investigation of defective materials. (See Attachment - I)

A field crew would turn in a completed UPR form and the defective material to the standards department who would investigate the failure. This investigation could involve analysis at FirstEnergy’s laboratory ( BETA Lab ).

Note, the UPR process focuses on material issues, not workmanship issues. The Region decides whether or not to initiate the UPR process for a failed piece of equipment.

Technology

UPR Forms are filled out manually and mailed to the Standards Department. Copies of the blank UPR forms are available to employees on the First Energy Intranet.

3.11.4 - CenterPoint Energy

Construction & Contracting

Material Failure Reporting System

People

CenterPoint’s Material Failure Reporting System is administered by the Distribution Standards and Materials group within Electric Distribution Engineering (not part of the Major Underground group).

Process

The Material Failure Reporting System utilizes a green tag with a unique number on the tag. The number on the tag enables the failed unit to be tied in with a particular outage case number or with a particular construction project. When an employee discovers a problem with a certain piece of material, he will fill out the green tag and place it on the unit. This tag is a trigger for the Standards and Material group to perform an investigation into the cause of the material failure.

Note: Because much of the material types used by the Major Underground group are unique to major underground infrastructure (network protectors, for example), most material failures of major underground equipment are investigated by Major Underground department resources themselves, rather than the Standards and Materials group.

Technology

Information recorded on the tags is entered into a Material Failure Reporting System data base. CenterPoint is currently revising this program, tying the information from the Material Failure Reporting system with their SAP system.

3.11.5 - Con Edison - Consolidated Edison

Construction & Contracting

Material Failure Reporting System

People

Underground Network Equipment Standards Committee

Con Edison has an underground network standards committee that meets periodically (usually about six times a year) to address issues with underground standards and equipment. The committee includes representatives from the Distribution Equipment Engineering department, the transformer repair shop, and field construction representatives, both union and management.

At these meetings, the group reviews equipment failure causes and characteristics. The members of the team perform vendor visits and attend seminars to give presentations. Con Edison focuses the meeting content on current needs and issues, such as responding to a safety incident. Con Edison has found this committee to be highly valuable for identifying and resolving issues with equipment and standards.

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including cable and joint failure analysis specimen retrieval and tracking. Failed specimens are sent to the Cable Testing Laboratory

Cable Testing Laboratory

Con Edison has its own cable testing laboratory, which has been in operation since the 1970s. This laboratory has over 100,000 cable and accessory specimens. Sometimes the lab sends specimens to outside labs to obtain independent analysis and opinions.

Con Edison invests in keeping its laboratory staff current on the latest thinking in cable testing. They are active in industry groups. They invest in rotating new people into the cable department, including engineers from Con Ed’s Gold program (a mentoring program for high potential engineers and business professionals).

Cable Failure Analysis

Con Edison’s goal is to perform a failure analysis on every cable and splice failure that occurs. The utility is able to perform an actual analysis on 80 – 90% of the problems that occur; the remainder represent problems that are destroyed or inaccessible. See Maintenance - Failure Analysis for more information.

Transformer Failure Analysis

Con Edison performs a root cause analysis of all network transformer removals including units that failed in service, units that were removed because of failed dissolved-gas-in-oil-analysis (DGOA), units that were removed because of failed oil temperature, pressure, or level indications from the RMS system, and units that failed during testing. See Maintenance - Failure Analysis for more information.

3.11.6 - Duke Energy Florida

Construction

Material Failure Reporting System

(Equipment Failure Reporting)

People

Prior to the consolidation with Duke Energy, the former Progress Electric (responsible for the network systems in southern Florida) used a Facility Management Data Repository to report failed equipment. The report, developed by Progress Electric, includes all relevant information, such as who discovered/reported the defect, where it happened, etc. These reports were issued as bulletins over the company’s internal network first to Standards, and then companywide via a Web portal.

The former process included tagging failed material and sending it to Standards for evaluation. After the Duke Energy consolidation, materials are still sent to the Standards group, but the process for reporting equipment failures has become more informal. Once a component is sent to the Standards organization, there is a component engineer who may perform forensic analysis on failed equipment to understand failure causes. Performance of the forensic analysis within Duke Energy Florida is dependent on the complexity of the failure and the backlog of work for the component engineer. If Duke Energy is not able to perform the failure analysis, Standards will engage external laboratories to assist with failed component analyses.

Process

While the process for reporting and performing analysis of failed components is informal, Duke Energy Florida does have formal processes to communicate findings within the company. For material deficiencies, Duke Energy Florida will issue a Material Advisory to first line supervision to share with direct report field crews. The Material Advisory is a bulletin that describes the material deficiency and any appropriate action(s) for the component.

For events that are related to work methods, Duke Energy has a “Good Catch” reporting process, where work method issues are reported through an electronic mechanism, Plantview. After the “Good Catch” is captured in Plantview and an investigation is performed, findings are shared in the weekly safety communication, “Connection.” The Network Group provided the most “Good Catches” at Duke Energy Florida in 2015, which were identified as work methods issues that were corrected before any network problems resulted.

Technology

Duke Energy Florida has an extensive electronic system for reporting events, Near Misses, Good Catches and recording Events and event details through its PlantView system. PlantView is described in the Safety section of this report.

3.11.7 - Duke Energy Ohio

Construction & Contracting

Material Failure Reporting System

Process

Duke Energy Ohio does not have a formal process for reporting material failures. As issues with material are identified, they are forwarded to the Standards Department.

Technology

Issues with particular materials that are relative to all are often communicated through a PD^[1] letter

The PD letter is a bulletin used to communicate a safety issue, safety changes or a work practices change.

^[1] Power Delivery letter

3.11.8 - Energex

Construction & Contracting

Material Failure Reporting System

(Unsatisfactory Performance Report)

See Failure Analysis

3.11.9 - ESB Networks

Construction & Contracting

Material Failure Reporting System

(Unsatisfactory Performance Report)

Process

ESB Networks does not have a formal process for reporting the unsatisfactory performance of materials. Material deficiencies with UG materials are handled informally; if a field crew has an issue with a piece of material, it is the crew’s responsibility to report the problem to its manager, who has the authority to stop an installation until appropriate replacement material is delivered to the site. If ESB Networks’ analysis reveals a manufacturer issue, the manufacturer is informed and a more formalize process commences.

3.11.10 - Georgia Power

Construction & Contracting

Material Failure Reporting System

(Unsatisfactory Performance Report)

People

Network standards are the responsibility of the Standards Group within the Network Underground group. The standards group is comprised of two principal engineers who work in the Network Underground group. One of these engineers reports to the Network UG Engineering group, and the other, directly to the Network UG Manager. The Standards Group is responsible for developing and maintaining all network standards for the company, including network equipment. In addition, this group prepares material specifications for network equipment, and engineering practice guidelines.

Within this organization are experts who focus on developing and maintaining specific underground standards. For example, network engineers who are experts with cable and cable systems are responsible for the development of cable standards for the company (See Cable Design in this report.). The Standards Group engineers/subject matter experts are available to respond to questions and issues raised by the field force.

Process

The process for reporting failed equipment is informal. For example, if a splice fails, the foreman may package and send the failed splice into the Network UG Testing Center to be examined by the standards group. Some forensics analysis of failed joints and terminations is performed by Georgia Power engineers, and other analysis is performed by NEETRAC. If it is determined by testing and forensics that the equipment needs to be replaced with a different type of equipment, the Standards Group decides on the appropriate replacement (after testing) and the new equipment becomes a part of the Network Standard.

Technology

The Georgia Power Network Underground group is responsible for cable standards of all duct line and manhole systems in the Georgia Power infrastructure. The Network Standards book contains specifications on cables, splices, racking, and duct line and vaults. The document is kept up-to-date by the Standards group and is available online and in printed form. Note that radial distribution standards are developed and maintained by a separate group, not part of Network Underground.

3.11.11 - National Grid

Construction & Contracting

Material Failure Reporting System

(Material Problem Report (MPR))

People

National Grid does perform failure analysis of selected failed components. The person identifying the equipment defect initiates the failure analysis process by completing a Defective Equipment Report form and submitting it to the Standards Department. Information about failed equipment is also provided through the Work Methods representatives.

Engineers within the Standards Department decide which failures are to be analyzed and the method of analysis. This is an informal process administered by standards engineers.

Standards engineers maintain a file of selected received failure reports, and use them to make recommendations for working methods, material uses, project upgrades, standards, and other relevant areas. Engineers also conduct on-site examinations of failures, and collect materials to be sent to one of two National Grid testing laboratories, located in Syracuse NY, and Worcester, Mass. The laboratory analyzes failed equipment and materials, including items such as splices, fire damaged cables or equipment, and insulation (e.g. for water presence). External services are also used by National Grid as required for certain analyses. For example, National Grid may send a failed component to the manufacturer for analysis.

Process

Failures are inspected in the field by standards engineers or on site engineering crews. Field reports and material samples are provided to Standards for a complete analysis at either an internal or external laboratory.

Standards Engineering prepares a failure report describing all of the pertinent details of an incident, including the date, time, location, and equipment involved. The sequence of events is reconstructed, along with a damage report. The goal is to identify the root cause and make recommendations to mitigate the problem in the future. In particular, these reports identify issues with materials, workmanship and construction, standards compliance, and other relevant factors. These can include poor practices by field personnel or cases where company or regulatory standards were likely not followed.

Analysis reports include the following major sections: i) Event Description, ii) Description of Failed Equipment (and any reference material, if needed), iii) Failure Examination / Material Dissection, and iv) Analysis and Conclusions.

i) Event Description

A discussion of the specifics of the event, including the time since installation, is determined. The detailed breakdown of the sequence of events is presented, along with details of working personnel involved in both the event itself and any inspections conducted subsequently.

ii) Description of Failed Equipment

The equipment description includes the specific component(s) received for analysis (for example, a splice adapter with two segments of cut cable still attached), the equipment manufacturer and model number, the nature of the damage, age and catalogue numbers if appropriate, and references to instruction and operations manuals.

iii) Failure Analysis and Material Dissection

A Material Dissection or Failure Analysis goes into detail describing the conditions of the materials and projected reasons for the failure. For example, if instructions for a cable splice were not followed properly, or if other materials appear to have been used incorrectly, this will be discussed. Photographs are taken as needed to document and support the analysis. Indicators such as arc tracks, spots of electrical discharge, and etching can be identified along with a determination of how they were formed. Components in the vicinity of the assumed failure can be tested to see if and how they contributed to the failure. For example, a segment of cable connected to a failed dead break elbow can be tested for insulation failure or treeing.

iv) Analysis and Conclusions

The goal of the engineering analysis is to identify the reason for the failure, corrective measures that could or should be taken, and any other recommendations that would be useful. If the problem was caused by improper installation, the workmanship issues are identified and reported with a suggestion that they be corrected. If installation has been done properly but an equipment failure was the cause of the problem, a review of that equipment may be suggested. In some cases the engineering analysts recommend that the equipment no longer be used for a particular purpose.

See Attachment C for a sample Failure Analysis Report.

Mitigating or extenuating conditions are important and are discussed in these reports, along with suggestions to avoid future failures. For example, in a fire analysis report from 2009, it was found that the involved 4.16 kV cables were not fire wrapped in the vicinity of the failure. In this case, the failure occurred at the mouth of a duct, where the cables where not wrapped because of proximity to adjacent cable. National Grid initiated a dialogue with suppliers of fire-proofing materials to investigate the development of a new material such as a sealant that can be used as an alternative to fire wrap at duct mouth installations.

Technology

National Grid maintains equipment for performing failure analysis in its internal laboratories.

National Grid also utilizes the services of external laboratories as required.

3.11.12 - PG&E

Construction & Contracting

Material Failure Reporting System

(Material Problem Report (MPR))

People

PG&E has a standards department, entitled Electric Distribution Standards and Strategy located in San Francisco. The department, part of the Distribution Engineering and Mapping group, is responsible for developing and maintaining distribution standards for the company, including network equipment.

Within this organization are experts who focus on developing and maintaining specific underground standards. For example, they have a cable standards engineer, who is an expert with cable and cable systems, and responsible for the development of cable standards for the company.

Also within this organization, PG&E has a position called Senior Distribution Specialist, assigned to the underground system. This specialist is a subject matter expert, and acts as an interface between the Standards Department and field resources. (See Senior Distribution Specialist for more information). Specialists act as the “eyes and ears” of the Standards Department, and meet with standards engineers every two months to address issues.

The Electric Distribution Standards and Strategy group works closely with the Material Problem Report (MPR) process. This process is also supported by a separate group at PG&E that is responsible for the overall MPR process.

Process

The material problem report process is a formal method for field employees to communicate material problems to management. When an employee encounters a problem with a piece of equipment, they go to a computer and fill out an electronic MPR form. (A lineman, who might not have access to a computer during the day, would complete the MPR form and then input the information into the computer at the end of the day, or ask a clerk to enter the information on his behalf,)

For problems with underground equipment, the MPR forms will typically flow to the senior distribution specialist underground. The MPR form will ultimately be routed to the individual in the company who is responsible for resolving the problem. The process itself is formal, and includes a requirement to respond to the individual who submitted the form in a prescribed number of days.

For example if the MPR were turned in first place, this would find its way to the cable standards engineer who deals with splices.

PG&E noted that they don’t often see MPR forms on major network equipment. Typically when they do, these reports are related to equipment that applies to both network and not network underground such as transition joints.

Technology

PG&E has an MPR website where the results of the resulting investigation initiated by the MPR are communicated.

PG&E may elect to issue a utility bulletin for significant changes. Also depending on the situation, the resolution of the MPR may be communicated to cruise the detail board sessions.

3.11.13 - Portland General Electric

Equipment Failure Reporting

People

PGE has a documented process for reporting failed equipment called the Material Failure Reporting Procedure. The procedure defines roles for those involved in the process, including line crews, storeroom personnel, standards engineers, Distribution Engineers, and supply chain personnel.

Standards engineers coordinate failure analyses with a PGE Special Tester, a PGE lab technician, the manufacturer, a third-party tester, or a combination of these parties.

PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. The tester is an expert on network protectors within the organization and also works to resolve equipment problems. The Special Testers support the network department, and one individual is embedded with the network CORE group.

Although PGE has its own testing lab, it is no longer fully staffed, and most failed components are tested externally by external laboratories and manufacturers. One major example is cable failures, which are sent to a third-party testing facility.

The Standards Department has provided explanations and demonstrations to field line operations on the reporting process.

Process

Although PGE has a process for reporting equipment failures and prioritizing repairs, the utility has a policy for immediate repairs if a major issue is found. When a manhole/vault needs urgent attention, a repair and maintenance crew dispatches as soon as possible.

Component Failure: For forensic analysis of failed components, PGE follows a material failure reporting process, fully documented in the Material Failure Reporting Procedure. The document includes the specific actions that an employee must take when encountering a faulty piece of material/equipment, and also lays out the forensic analysis process. The Standards Department will periodically provide training to field line operations on the reporting process.

Where possible, PGE will seek a refund or replacement for materials and components under warranty.

Figure 1: Secondary cable undergoing failure analysis

Material Failure Reporting Process

When they discover a failed component,line workers take photos of the equipment, note the location, and complete a failed material tag available from regional storerooms[50]. The photos are sent via email to the standards department. The storeroom receives the failed material and checks weekly with the Standards Department regarding which failed materials to retain and discard.

At the next stage of the process, a standards engineer uses the information on the failed material tag to contact the distribution engineer responsible for the feeder before compiling the report and forwarding the information to the distribution engineer. In turn, the distribution engineer adds any requested information to the report and returns it to the standards engineer.

Figure 2: Front and back of material failure tag

Once the standards engineer has the report, the engineer contacts other utilities to determine if they have had similar experiences with the failed material before notifying the vendor. The distribution engineer and supply chain will remain informed of any progress. The vendor determines if other companies have had the same problem, assesses whether the failure is associated with a particular batch, and finds out if there have been any previous recalls for the part number.

The supplier reports the findings to PGE and either determines if the remaining inventory of the material is usable, or issues a recall form and contacts the supply chain. In turn, the supply chain decides what action to take with the remaining inventory and informs the store rooms of the decision.

Figure 3: Flow chart of the material failure reporting procedure

Once the failure analysis is completed, the resolution is discussed with Distribution Engineers, line crews, and safety representatives. A TechNote article, a Material News Alert, or another method communicates the resolution, and a material failure database records the material failure.

Due to a number of failures, PGE has built a library of failure modes on T-Bodies. The utility has a long history of these failures, so the library makes it easier to analyze any problems. Most failures occur in the bushing because the lineman used the incorrect torque. PGE has scaled back the use of these T-Bodies.

For vehicle issues, crews need to fill out “pre-trip” and “post-trip” reports, and call the garage for a repair.

3.11.14 - Survey Results

Survey Results

Construction & Contracting

Material Failure Reporting System

Survey Questions taken from 2018 survey results - Asset Management

Question 20 : Do you track cable and equipment failures?

Question 21 : If you track equipment failures, which of the following do you track?

Question 25 : Please describe your failure investigation process. Include a description, if applicable, of what drives corrective actions.

Survey Questions taken from 2012 survey results - construction

Question 5.9: Do you have a process for inspecting or testing incoming network materials?

Question 5.10: If yes, what material is inspected or tested?

Survey Questions taken from 2009 survey results - construction

Question 5.10: Do you have a process for inspecting or testing incoming network materials? (this question is question 5.9 in the 2012 survey)

Question 5.10 B : If yes, who performs these inspections and tests?

3.12 - Organization

3.12.1 - AEP - Ohio

Construction & Contracting

Organization

People

Construction of network infrastructure at AEP Ohio is performed by Network Mechanics, a bargaining unit position responsible for performing all network construction and maintenance activity, including cable pulling, cable splicing, and network equipment construction and maintenance. Organizationally, network field resources are centralized, with the field resources who work with the Columbus networks reporting out of one service center, and resources who work with Canton networks reporting out of another. These service centers are led by a supervisor, and consist of Network Crew Supervisors, the front line leadership position, and the Network Mechanics. Organizationally, the service centers are part of Regional Operation reporting ultimately to the Vice President of Distribution Regional Operations.

The electrical work associated with network construction is performed by AEP Network Mechanics. All civil design and construction work on network projects, including design and construction of manholes, vaults and duct lines, is outsourced to civil contractors. AEP has a close working relationship with a civil engineering firm, with the primary civil engineer at that firm having worked for AEP Ohio for many years and is thus experienced with the AEP Ohio underground networks.

Coordination with contractors is performed by both the Network Engineering group, who works closely with civil contractors on civil designs, and service center management, who provide contractor coordination and oversight.

The Network Engineering group reports to the AEP Network Engineering Supervisor, and is organizationally part of the Distribution Services organization, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Network Engineering Supervisor and the distribution services organization reporting to the AEP Vice President of Customer Services, Marketing and Distribution Services support all AEP network designs throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

3.12.2 - Ameren Missouri

Construction & Contracting

Organization

People

Organizationally, Ameren Missouri field resources that construct, maintain, and operate the network infrastructure fall primarily within three groups, all part of Energy Delivery Distribution Services. One is the Underground Construction group, one is the Service Test group, and one is the Distribution Operating group.

Underground (UG) construction crews, consisting of resources who install cable and cable systems including civil construction, cable pulling and cable splicing, fall within a construction department that is organizationally part of the Underground Division, responsible for underground infrastructure within a defined geographic territory that includes downtown St. Louis, and thus, the St. Louis network infrastructure. The Underground Division is led by manager, and is comprised of both an Engineering group and an Underground Construction group. The UG Construction group is led by a Construction Superintendent. The Underground Construction Group is responsible for all of the conventional (manhole and conduit system) underground in the Division, and all work with larger cable (500 MCM and above).

Reporting to the Construction Superintendent are construction supervisors who lead the field force. The supervisors include an overall construction supervisor, two cable splicer supervisors (one for network and one for non network infrastructure), a supervisor for utility men, and a rotating supervisor.

The Underground Construction Department consists of Cable Splicers, Construction Mechanics, and System Utility Workers. Cable Splicers and Construction Mechanics are journeymen positions. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Construction Mechanics perform the civil aspects of the work. System Utility Workers serve as helpers to the other two positions, and perform duties such as cable pulling and manhole cleaning. Note that at the time of the practices immersion, Ameren Missouri was implementing a new position, called the System Journeyman, which combines the duties of Cable Splicers and Construction Mechanics. System Journeyman are responsible for performing cable work, civil construction, and operating network equipment.

The Underground Construction Group also utilizes contractors for performing much of the major civil construction work, and for performing selected equipment inspections. Ameren Missouri has a few contractors “of choice" for underground work. Ameren Missouri has longer term (three and four year) agreements in place with these contractors.

Maintenance and operations of network equipment such as network transformers and network protectors are performed by resources within the Service Test Group and Distribution Operating Group. Organizationally, both these groups are part of Distribution Operations, led by a manager. Within Distribution Operations, there is a Reliability Support Services group led by superintendent. Reporting to the Superintendent Reliability Support Services are both the Service Test Group and the Distribution Operating Group, each also led by a supervisor.

The Service Test Group is made up of Service Testers and Distribution Service Testers. Service Testers perform low-voltage work only. They focus on things such as voltage complaints, RF interference complaints, and testing and maintaining batteries. Distribution Service Testers perform network protector maintenance, transformer maintenance including oil testing, as well as fault location. It is the Distribution Service Tester position that works routinely with network infrastructure. Distribution Service Test group positions are typically filled from the Service Testers, Traveling Operator positions, or Gardener positions (a practice related to a historic practice of filling department positions with resources who maintained substations.)

The Distribution Operating Group is made up of Traveling Operators, who perform system switching, including placing tags and obtaining clearances. They also act as first responders and troubleshooters.

Process

Ameren Missouri has a 30 month mandatory progression for Cable Splicers, Construction Mechanics, and System Journeymen, whereby employees must move through a program of formal training, on the job training (OJT) and testing and achieve the journeyman level within this period (See Crew Makeup / Job Progression). Employees must spend at least one year as a System Utility Worker before entering the program.

Distribution Service Testers have a similar mandatory progression program, with employees expected to reach the journeyman level in 22 weeks. The Distribution Service Tester program also consists of formal training, testing and on the job training. The program is comprised of four levels, with testing at each level and a final test given at the end of the program. Employees are required to pass each test to advance the next level.

3.12.3 - CEI - The Illuminating Company

Construction & Contracting

Organization

People

Organizationally, at most FirstEnergy companies, the responsibility for construction and maintenance of the underground ducted manhole system falls under the Substation group. In much of FirstEnergy’s service territory, ducted manhole systems comprise a relatively small percentage of the overall distribution. The organization at CEI is the exception to this rule, standing alone, and separate from the substation group because of the large size of the ducted manhole system serving Cleveland and its surrounding areas. The CEI ducted manhole system represents 80% of the total ducted manhole system infrastructure at all of FirstEnergy. The CEI Underground Network Services department (Underground department) is the only stand alone underground group in all of FirstEnergy.

The Underground Network Services department is led by a manager, responsible for all the distribution facilities in the ducted manhole system, whether they be radial distribution or network secondary distribution. His responsibility includes substation exit cables. The manager is a degreed engineer (Masters) with over twenty five years of experience in engineering, operations, and construction.

The Underground department is comprised of 57 employees, including the manager, five supervisors, 48 field electrical workers (called UG Electricians), and support personnel.

See “ Crew Makeup / Job Progression ” for a more detailed description of the workforce.

Process

The Underground department performs construction and maintenance of the ducted manhole system at CEI. The Underground department employees at CEI are the only CEI employees trained to enter a manhole.

The design of the underground system is the responsibility of the Underground / LCI group within Engineering Services. However, the Planner / Scheduler, a position within the UG department, does occasionally participate in redesigning or reconfiguring the system in response to a failure.

CEI has one Underground Network Services Center to support the Underground, including the networked secondary and non network ducted conduit systems. The service center includes Underground Electricians who construct, maintain and operate the underground system, as well as automobile mechanics and meter readers.

3.12.4 - CenterPoint Energy

Construction & Contracting

Organization

People

CenterPoint’s underground organization is centralized, with the resources who work with the major underground infrastructure reporting organizationally to one group - Major Underground. At CenterPoint, the term “major underground” is used to describe the three phase underground system that supplies the urban portions of the Houston metropolitan area using ducted manhole systems, and including the secondary network systems. It consists of three phase facilities supplying commercial and industrial customers (with the exception of the network, which serves residential load as well). URD installations and single phase underground line extensions are not considered part of Major Underground, and are managed by other CenterPoint service centers.

The Major Underground organization, comprised of 208 total resources, includes Key Accounts, Engineering and Design resources, support services, and the field force responsible for all construction, operations and maintenance activities. In addition, where other departments have resources focused on supporting Major Underground, many of these groups have physically stationed resources, 36 in total, within Major Underground, reporting in a matrixed^[1] manner.

Most Major Underground resources physically report to the same location, the Service Center – Underground Operations, located in Houston. In addition, a training facility and equipment yard for Major Underground are stationed at the Service Center.

Field resources are split into two high level groups, “Cable” and “Relay”. The Cable group is comprised of people in the Cable Splicer classification who do all cable work, including installation, testing, locating, maintenance, splicing and removal. The Relay group is comprised of people in the Network Tester classification, work with testing and locating underground cable and equipment, including transformers, switches and network protectors. This group also does all system protection and relay panel work.

Field resources are further broken into groups of about 15, each reporting to a Crew Leader, a non-bargaining position at CenterPoint.

^[1] The term “matrix” employee refers to an employ from another department having a dual reporting relationship, one a solid line to his supervisor, and the other a dotted line to the supervisor in the department to which he is assigned.

3.12.5 - Con Edison - Consolidated Edison

Construction & Contracting

Organization

People

Construction Group

Con Edison’s service territory consists of four regions: Manhattan, Brooklyn/Queens, Staten Island, and Bronx/ Westchester. The Manhattan Region is made up of three districts, including one headquartered at the W 28^th St. Workout Center. The term “Workout Center” refers to a main office facility to which field construction and maintenance resources report. To provide a perspective on the size of a workout center, about 300 people work at the W 28^th Street Workout Center, and they can field about 125 crews.

The Construction department consists of several groups:

Underground Group - The underground group is made up of Splicers, who splice cable of all voltages.
Installation and Apparatus (I & A) Group (includes a services group) - The I&A group installs and maintains network equipment, including transformers and network protectors. Within I&A, in Manhattan, there is a services group dedicated to connecting customers to the distribution network. In other locations, the services group may sit in a different part of the organization. This group does the splicing on the secondary system and deals with customer connection issues.
Subsurface Construction (SSC) Group - The SSC deals with vaults, conduit ducts, and other civil work. Much of this work is contracted.
Cable Group - The Cable group pulls in new cable and retires cable.

Note: the West 28^th Street “Workout” Center also contains the Emergency Group (also called #9), which responds to smoking manholes, burnouts, and other emergencies. This group reports organizationally to the Field Operations Department (FOD).

Manhattan’s districts have seen significant load growth (overall, 3-4 %, but in pockets, the load growth is much greater). For example, in upper Manhattan and Harlem, properties are being converted to apartment buildings or commercial high-rise buildings.

This trend has created significant work in connecting new services, adding spot networks, and adding network transformers to reinforce the street grids. Con Edison has also had to create new networks by breaking an existing network into two to accommodate this increased load. An example would be the creation of the Fashion Network to transfer load from the Herald Square network.

Con Edison believes it easier to maintain smaller networks; however, with less copper in the street, smaller networks can be considered less reliable. When Con Edison does encounter problems, particularly in the summer, the utility engages in “shunting,” which is the term they use to describe running cables above the street to bypass or “shunt” the problem and pick up the loads from an alternative source. The utility also runs generators if necessary to provide support to pocket areas during emergencies to meet customer load expectations.

Network Job Progression, OJT

Workers enter as a General Utility Worker (GU) and then progress either through the Splicer or the I&A Mechanic families with on-the-job training (OJT), training, and testing.

In the Underground group (Splicers), a person can progress to a Splicer in as little as two years. Con Edison does not have a mandatory automatic mode of progression; that is, employees are not mandated to progress to a journeyman position within a given period of time. Nor are employees prevented from advancing if they accomplish the prerequisite time, training, and testing.

After 18 months, GU’s are eligible for splicing school, a three-month program offered by Con Edison and conducted at their training center. When employees return to the field from Splicing School, they are assigned to a supervisor who is responsible for their training and development while on field assignment. Con Edison has specific OJT requirements that Splicer candidates must satisfy before being able to progress to a Splicer. (See Attachment C for a listing of the specific tasks in which a Splicer candidate must demonstrate proficiency.)

Splicer candidates can perform their OJT requirements over a minimum seven-month period. When candidates believe they are ready to perform an OJT, they inform their supervisor and the splicer with whom they are presently working. If all agree that the candidate is ready to “solo,” the OJT moves ahead. The candidate, supervisor, and training splicer review the OJT and hold a job briefing. The candidate then performs the OJT with as little input from the observer (supervisor or training splicer) as is possible. The supervisor evaluates and documents the OJT. (See Attachment D for a sample evaluation sheet used by Con Edison to evaluate and document the OJT accomplishment [ESP0061].)

After completing the OJT requirements, Splicer Candidates can then take a written and practical promotional exam and progress to a Distribution Splicer (journeyman position).

In the I&A group, individuals can progress to a journeyman Splicer as well. A GU can progress to a Mechanic B after six months, a Mechanic A after two years, and then become a splicer in the I&A organization. As described above, there is formal training and testing associated with this.

Con Edison directs General Utility workers (GUs) to either the Underground area (Splicers) or I&A area based on need.

Overtime

Workers expend 30 – 40 % of their time on overtime. Work is planned for 10-20% overtime, with emergencies and efforts to complete system reinforcement projects prior to the summer loading season adding to the levels of overtime worked. The company implements 12-hour shifts in these high work periods.

Supervisors get paid to work overtime at a straight time rate.

Planning and Survey Group

The Planning and Survey group is a subset of the Field Engineering group, and consists of Surveyors, who perform survey work associated with new construction, and Planning Inspectors, who go into the field, and assess the specific field conditions and determine what is necessary for the new installation to be built successfully. Planners and surveyors can work separately, or work together on projects. This group works closely with Energy Services, taking layouts developed from maps by Energy Services on Microstation, and field checking them to identify the specifics of the job and ensure that the layout reflects field conditions. This group prepares job sketches to obtain the necessary permitting to complete the job.

Process

Splicing

Con Edison has a process in place to promote the ongoing quality of splices by assigning personal accountability for the performance of the splice to the individual Splicer who prepared it.

In the past, when working with lead splices, Splicers permanently stamped (imprinted) their initials directly into the lead of the splice as a way of tracking who prepared the splice. Newer splices are bar coded with information about the splice including the name of the Splicer. The bar code is produced from a splice ticket that contains information about the splice, including the name of the Splicer.

Splicers are responsible for the performance of their splice for five years after the installation. Con Edison selected five years, because the utility has found splice defects due to workmanship issues usually occur within the first five years after a splice installation.

If problems are encountered with a particular Splicer’s workmanship, depending on the circumstances, Con Edison may elect to send the Splicer back to splicer school, or administer formal discipline steps (warning, letter in the file, etc.).

UG Network Equipment Standards Committee

Con Edison has a UG Network standards committee that meets periodically (usually about six times a year) to address issues with UG standards and equipment. The committee includes representatives from the Distribution Equipment Engineering department, the Transformer repair shop, and field construction representatives, both union and management. At these meetings, the group reviews equipment failure causes and characteristics. The members of the team perform vendor visits and attend seminars to give presentations. Con Edison focuses the meeting content on current needs and issues, such as responding to a safety incident. Con Edison has found this committee to be highly valuable for identifying and resolving issues with equipment and standards.

Pre-cast Concrete Conduits

Con Edison uses 4-in., pre-cast concrete conduit sections for housing electric cables in open trench installations. These conduit sections are square in cross section, and are ordered for either strait runs or bends. Con Edison uses bell end conduits for entrance into manholes. These pre-cast conduit sections can be joined together as required, using male ends that connect with a plastic coupling. Con Edison requires that the conduits be able to pass specific tests, including a mandrel test to ensure the conduits are open, transverse loading tests, compression load tests, and a friction test. (See Attachment E, photographs of Con Edison Pre-cast Concrete Conduit.) , photographs of Con Edison Pre-cast Concrete Conduit.)

For secondary cable installations where space may be limited, or the soil is unstable, Con Edison may use alternative conduit materials such as steel, fiberglass, and high-density polyethylene (HDPE). For example, steel conduits may be used in an open trench where the soil is unstable, for a jacking or driving operation, or where space is limited due to a shallow trench. Fiberglass conduits may be used in damp soil locations where corrosion is a problem. Con Edison has well-written guidelines that define conduit types and appropriate usage.

When Con Edison must install new duct banks, particularly in Manhattan, they often find it difficult to bring in heavy machinery. In these situations, the utility assembles a large group of laborers to hand dig the trenches to install new duct banks. Con Edison often schedules this work at night, to avoid the some of the challenges of performing this work during the day, such as vehicular and pedestrian traffic and other work restrictions.

Cable-Pulling Duct Preparation

One big challenge that Con Edison faces is obstructions in the ground. Crews often find that ducts have collapsed or are obstructed. These obstructions can be due to foreign utilities or vibrations from the subway that over the years cause ducts to collapse, etc. In Manhattan, crews encounter obstructions in 45-50% of their projects.

Prior to installing cables in conduits, Con Edison has a defined set of operations that are performed on the conduit systems.

These operations include:

Rodding the ducts to establish that a clear passage exists through the conduit between structures and to provide a means of installing various lines to perform subsequent cleaning, mandreling, and cable-pulling operations.
Brush duct to remove any soil or debris that might have entered the duct since it was installed.
Clean duct if soil or debris prevents the rodding device from passing from one structure to another.
Perform mandrel operation to establish that a specific size passageway exists from one end of the duct to the other, and to establish that the alignment of the duct is such that horizontal and vertical bends meet the specified minimum radii requirements.
Install 1/2-in. steel rope, 9/16-in. steel rope, or 1/4-in. polypropylene rope (depending on the timing and type of pull).

Cable Supply

Con Edison has entered into an exclusive arrangement with its cable supplier. This single source has provided Con Edison preferred pricing and high levels of responsiveness from the cable manufacturer. Part of the arrangement with the cable manufacturer is that Con Edison doesn’t pay for the cable until it is installed in the ground. This provision has helped to reduce the lead time in obtaining cable from the manufacturer, and is an incentive for Con Edison to develop accurate forecasts of cable needs.

Incoming cable is not tested by Con Edison. The utility relies on the manufacturer’s report of testing performed by the manufacturer itself. These tests include partial discharge tests, AC voltage tests, and solderability tests on primary cables.

The arrangement with the cable vendor is not tied to the ongoing performance of the cable itself. When Con Edison has encountered problems, the utility has been able to track the problem back to a specific cable lot or reel. For example, in one case, they discovered some reels where the cable jacket was a bit thin. Con Edison has found the manufacturer to be highly responsive to problems that occur.

Technology

Trucks

Con Edison provides its employees with the specialized tools and equipment that they need to do their jobs, including trucks outfitted for the different types of work that they perform. Employees stated that they believed Con Edison provides them with good quality trucks, appointed with the equipment they need to perform their work. People demonstrated a sense of pride in their trucks and associated equipment.

Con Edison’s network resources use specially equipped box trucks. Each department truck is outfitted to meet the needs of that group, including multiple storage bins for housing the on-board equipment.

For example, I&A mechanics use a box truck equipped with the specialized equipment they need to perform their job duties, such as network protector test kit, outriggers, and a hydraulic boom with a winch for lifting equipment.

Emergency Workers utilize box trucks (similar to I&A mechanics), which are outfitted with the tools, test equipment, etc. they need to respond to and troubleshoot emergencies. These trucks are painted red for high visibility and recognition.

Fault Location Operators use a box truck equipped with a Capacitive DC test set and a Galvanometer.

Splicers utilize a specially outfitted van, rather than a box truck, because they have less equipment and fewer tools than I&A Mechanics.

Another example of a specialized vehicle is a heavy-duty tandem axle flatbed underground cable-puller truck that is used by Cable pullers to pull and remove cable.

Con Edison trucks are outfitted by a firm called Dejana.

(See Attachment F New-Style Box Truck w/ Boom.)

(See Attachment G for the Dejana Hub Drive Cable Puller Brochure.)

3.12.6 - Duke Energy Florida

Construction

Organization

People

Body Organizationally, Duke Energy Field resources that construct, maintain, and operate the urban underground and network infrastructure fall within a specific Network Group which is part of the Construction and Maintenance Organization. More broadly, Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager. The region consists of various Operation Centers, organized either geographically or functionally throughout the Region.

The Network Group is organized functionally, and has responsibility for construction, maintain and operating all urban underground infrastructure (ducted manhole systems), both network and non-network, in both Clearwater and St. Petersburg. The Network Group is led by a supervisor who reports to the Region General Manager. The group consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journeyman worker position), all part of the Network Specialist job family.

The Network Specialist is a “jack-of-all-trades” position, responsible for all facets of underground work, including cable pulling, splicing, and maintaining and operating equipment such as cables, joints, network switches, transformers and network protectors. Network Specialists also work with the installation and maintenance of automation associated with the equipment they manage. For example, Duke Energy Florida recently completed a major project to add automation (remote monitoring and control) to field located primary distribution switches, such as automatic throw over switches (ATSs) that are commonly used to provide a primary and alternate feed to larger customers. It is the Network Specialist craft that installed the automation on the switches.

Duke Energy Florida relies on contractors to perform most civil work, such as repairing duct bank, or replacing manhole and vault roofs and grating systems. Good relationships have been formed between Duke Energy Florida and the preferred civil contractors who perform this work. The Network Group may add contractor resources to address peaks in their work load. For example, at the time of the practices immersion, six contractor resources were being utilized to pull in new cable and prepare cable splices associated with a reliability driven cable replacement program.

Process

The ten craft workers are responsible for all major underground (ducted manhole systems) infrastructure in both Clearwater and St. Petersburg. Three resources are assigned to Clearwater, and seven are assigned to St. Petersburg, but resources are moved freely to both areas based on work needs. Network Specialists may be upgraded to an oversight position, depending on work needs. For example, at the time of the practices immersion, a Network Specialist provided oversight for incremental contractor crews.

3.12.7 - Duke Energy Ohio

Construction & Contracting

Organization

People

Duke Energy Ohio’s organization for construction of their network infrastructure is centralized, with the resources reporting to the Dana Avenue Construction and Maintenance facility. This organization, referred to as “Network Services” or the “Dana Avenue”, does all work associated with the Cincinnati network, as well as certain functions, such as fault location, for the entire division.

The Dana Avenue Construction and Maintenance organization ^[1] , led by Manager, is comprised of 59 total resources, including a Field Work Coordinator, Project Manager, T & D Construction Coordinators, and three Construction and Maintenance Supervisors, two of which lead field employees (46) focused on the network.

Duke Energy Ohio has two primary job families for underground field resources – Cable Splicers and Network Service Persons. Cable Splicers do all cable work, including installation, testing, locating, maintenance, splicing and removal. Underground Service Persons work with non - cable underground equipment, including maintenance and inspection of transformers, switches and network protectors. This group also does programs network protector relays.

Process

Duke has a five year automatic mode of progression whereby employees must move through a program of formal training, on the job training (OJT) and testing and become a journeyman within the five year period (See Crew Makeup / Job Progression ) . Employees enter the department as Helpers, and then advance through various Cable Splicer positions (Cable Splicer C, Cable Splicer B, etc) until they achieve the Cable Splicer A, which is a journey worker position. At this point they can either advance to a Senior Cable Splicer, or they can advance to an Underground Service person.

^[1] Official title of the organization is DD OH/KY – Joint Trench Operations, part of Field Operations. It is referred to as “Dana Avenue” or “Network Services”.

3.12.8 - Energex

Construction & Contracting

Organization

People

The journeyman position for working with cable systems at Energex is the cable jointer position. Employees move through the jointer apprenticeship program in about three and one half years. The apprenticeship includes formal training, testing, on the job training, and time in grade. At the conclusion of the apprenticeship, persons in the program must still complete a “basket of skills” required by the electrical office. These skills are over and above the skills that are taught as part of the apprenticeship, but necessary for the employee to be a fully qualified jointer. Employees complete this basket of skills in the first 18 months after apprenticeship. Consequently, it takes 5-6 years in total before an employee is fully qualified to run a job. See attachment for a sample of the basket of skills required for cable jointers. ( Attachment A: Cable Jointer Skills) )

Energex’s training requirements match the requirements of the Australia Qualifications Framework (AQF), and are thus, accredited. This qualification is recognized throughout Australia and is “fully transportable". So, an employee who receives a qualification as a Cable Jointer from Energex would be recognized as a cable jointer outside of Energex. Energex complements the training requirements outlined by the AQF with training requirements specific to the electric industry, such as a requirement to be able to terminate cables on switch gear. Training courses are developed by reviewing documented work practices, and with input from Energex people with strong knowledge of the work.

The following two agencies drive job progression/competency:

Electrical Safety Office requires that employees show competency and currency in the following:
- Performs licensing, policing, and proof of the currency of employee competency and skills.
- Defines the competencies in which employees must be proficient. Requires that employees are licensed and that we can show proof of competency and currency.

Workplace Health and Safety Office mandates the following:
- Requires that employees have a safe system of work.
- Decides which safety training employees should receive, such as training on proper PPE, for example.

Process

Training is based on work practices. Work practices are developed with input from SMEs, and with input from the Operating Advisory Council (OAC). Note that the OACs are made up of representatives from Standards, Design, and field personnel such as cable jointers. The work practices group documents how tasks are performed. The OAC decides whether the work requires an employee to demonstrate competency, and if that competency needs to be periodically reviewed. High-risk tasks may require frequent refreshers to renew competency. Lower risk tasks may only require a one-time training.

3.12.9 - ESB Networks

Construction & Contracting

Organization

People

Construction and contracting work is supervised by the Contract Management group within the Network Investment groups, part of Asset Investment, within the Asset Management organization at ESB Networks. In addition to Asset Investment, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Assets & Procurement, Finance & Regulation, and Operations Management. These groups work closely together to manage the asset infrastructure at ESB Networks.

More specifically, construction and contracting is performed within two Network Investment groups – one responsible for planning network investments in the northern part of Ireland, and the other for planning in the south.

Construction and civil engineering standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

The Contact Management group works directly with contractors throughout the entire time-span of individual construction projects.

3.12.10 - Georgia Power

Construction & Contracting

Organization

People

Organizationally, Georgia Power field resources that construct, maintain, and operate the network infrastructure fall within the Network Underground group, led by the Network Underground Manager.

Underground construction crews, consisting of resources who install cable and cable systems including civil construction, cable pulling and cable splicing, fall within the Network Construction department that is organizationally part of the Underground Network group. This group, led by the Network Construction Manager, is responsible for network underground infrastructure construction throughout the state of Georgia, including networks in Atlanta, Athens, Macon, Savannah, and Valdosta.

In addition, all design, construction and supervision of concrete-encased duct lines installations throughout the state of Georgia, whether they are for network infrastructure or non – network infrastructure, is performed by the Network Construction Duct Line construction crews and network civil engineers and/or its contractors. Georgia Power has decided that the network underground construction standards for duct lines should be adopted throughout the system, regardless of the distribution type. The company believes that standardizing on duct line construction throughout Georgia Power gives the company greater system-wide uniformity and ease of maintenance. Also, the network crews are the only crews in distribution who are trained and equipped for enclosed space entry. (Direct-buried cables and duct which is not concrete-encased are designed and built by other organizations within Georgia Power.)

Civil construction work, if extensive, is often sent to preferred contractors and supervised by construction supervisors from the Network Underground group.

Projects of $2 million or less are brought before the Regional Distribution Council for approval. Any projects that require more funding are sent to upper management for review and funding approvals.

The Underground Construction group consists of Cable Splicers, Duct Line Mechanics, Test Technicians, Winch Truck Operator (WTOs), and Light Equipment Operators. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices, and operating network equipment. Duct Line Mechanics perform the civil aspects of the work, such as duct line and manhole construction. Cable pulling is normally performed by Cable Splicers, but is sometimes performed by Duct Line Mechanics.

The Underground Construction group also utilizes contractors for performing much of the major civil construction work. Georgia Power has a few contractors of choice for underground work, and has standing agreements with these companies, many of which have been working for Georgia Power for a number of years. Cleaning and civil maintenance is inspection-driven. If, during routine inspections, a field engineer, Test Technician, or journeyman finds and documents the need for civil maintenance or cleaning into the company’s DistView or GIS system, the appropriate construction crew or cleaning crew is dispatched for further analysis and action.

Maintenance and operations of network equipment such as network transformers and network protectors are performed by Test Technicians within the Test Group of the Operations and Reliability group within Network Underground.

Process

A typical cable-splicing crew consists of three men, including a Senior Cable Splicer, a Cable Splicer (the Journeyman position), and a Winch Truck Operator. Cable Splicer is one distinct job family within the Georgia Power Network Underground group and has the following three levels of classification:

Cable Splicer Apprentice
Cable Splicer (Journeyman)
Senior Cable Splicer

The Senior Cable Splicer is in charge of the crew, but also performs work in manholes and vaults. This crew is responsible for all network electrical work within manholes and vaults. The WTO is a helper-type position on these crews and is not unique to the Network Underground department; WTOs are used throughout the Georgia Power Company in both network underground and distribution (radial) networks.

Georgia Power typically runs a six-man crew for duct line work, but it depends on the nature and scope of the work. The Duct Line Mechanic is one distinct job family in the Georgia Power Network Underground group and is responsible for duct line work in the manholes and vaults construction (pouring duct lines, construction, etc.). The Duct Line Mechanic group consists of the following positions:

Duct Line Apprentice
Duct Line Mechanic (the Journeyman position)
Senior Duct Line Mechanic

The crews work co-operatively together, and may substitute some senior members in crews as needed. For example, a Senior Cable Splicer may assist a duct line crew when needed. Similarly, at times, Duct Line Mechanics may help pull cable. Duct Line Mechanics do not splice cable, however.

If there is a big construction job or extensive night work that needs to be done, Georgia Power can bring in its preferred contractor(s). The supervising manager hands the plans over to the contractor for completion. The manager coordinates with the contractor foreman, or he may assign a Georgia Power foreman to coordinate with the contractor. Relying on contractors is especially productive as major projects ebb and flow, and Georgia Power wants to retain its own duct line, cable, and construction crews for smaller jobs that need a fast response and/or for work that may be too complex for contractors to handle in a reasonable amount of time.

3.12.11 - HECO - The Hawaiian Electric Company

Construction & Contracting

Organization

People

The C&M Underground Division at HECO is part of the Construction and Maintenance organization. The group is comprised of two UG supervisors, fifteen Cable Splicers, 2 Utility Mechanics, and 2 Utility Assistants. The Cable Splicer is the journeyman position in the department. These individuals perform all activities associated with the construction, maintenance and operation of the Underground system, including working with lead (PILC) cable and transition splices. The Underground group does most of the work on underground distribution in urban areas.

HECO also has “Overhead” C&M groups that also perform work with both overhead and underground facilities. The journeyman position in the Overhead groups is a lineman. When the Overhead group works with underground facilities, they work primarily with 12kV URD facilities.

All the people in the underground and overhead groups (non-supervisors) are represented by a collective bargaining agreement (IBEW).

Process

The Underground Group performs all activities associated with the construction, maintenance and operation of the underground system, except working with network transformers and network protectors. The UG Group’s duties include cable pulling and installation, cable splicing, underground equipment inspection and maintenance and fault location. The UG group performs all primary fault location for the island of O’ahu. The Underground work exclusively works with lead cables / lead splices / transition splices for HECO.^[1] The UG group will also install Substation exit cables.

The Underground group will perform cable installation and maintenance of network feeders. However, the UG group does not install or maintain network equipment such as network transformers or network protectors. Network equipment construction and maintenance is the responsibility of the Substation group at HECO. The Substation group is part of the Technical Services Division of the System Operations Department.

The Overhead group also performs construction, maintenance and operations of underground facilities, although most of their underground focus is with URD. The Overhead group will perform secondary fault location, and will prepare poly splices.

^[1] HECO only performs lead wipes on their 46kV gas filled cable. (This is lead cable impregnated with pressured nitrogen to keep out moisture). This cable is scheduled to be replaced with EPR cable. All other splices are transition splices (lead – poly).

3.12.12 - National Grid

Construction & Contracting

Organization

People

The National Grid network field resources (network crews) are part of the group responsible for the underground system in eastern New York, called Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Civil Group is comprised of Mechanics, Laborers, and Equipment Operators, and is led by a supervisor. This group includes a machine shop located in Albany. The group has 23 field resources.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics, is led by three supervisors. Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. Maintenance Mechanics perform network switching, fault location, minor vault maintenance, and inspection and maintenance of network equipment such as transformers and network protectors. The total UG Electric East group has 29 field resources.

The Electrical Group field classifications are represented by a collective bargaining agreement. (Union IBEW in New York, multiple unions in NE). Advancement in union positions in UG East is through an automatic progression to a journeyman.

Construction management also includes resources such as Schedulers and Work Coordinators. These resources work closely with field supervisors to schedule and resource plan the work. Work coordination includes performing pre job field checks to identify the things that must be addressed before the job commences.

Process

National Grid has a 42 - month automatic mode of progression whereby employees must move through a program of formal training, on the job training (OJT) and testing and become a journeyman within the 36 month period. (See Crew Makeup / Job Progression). Apprentices must serve as a helper for six months before entering this program,

3.12.13 - PG&E

Construction & Contracting

Organization

People

The PG&E network field resources (network crews) are part of the Maintenance and Construction- Electric Network organization. The group is led by a Superintendent, VP, who is responsible for the secondary network infrastructure in the Bay Area Region, including San Francisco and Oakland. Note that this individual’s responsibility includes radial distribution in both San Francisco and Oakland.

Reporting to the superintendent, VP are three Distribution Supervisor positions who supervise the network field resources, two in San Francisco and one in Oakland. There is also a distribution supervisor who leads the Network Protector Maintenance / Repair Shop, and a Supervisor of the Compliance group, responsible for quality compliance,

The field groups are comprised of cable splicers, a bargaining unit position (IBEW). Cable splicers perform both cable work, such as cable installation and splicing, as well as network equipment work, such as network protector and transformer maintenance. Advancement in the Cable Splicer job family is through an automatic mode of progression.

In San Francisco, PG&E network crews work the night shift ^[1] . They typically run four 3- man crews in the evening to perform maintenance. A crew is normally made up of a Journeyman Cable Splicer, who does most of the network protector maintenance work, and two helpers (usually Apprentice Cable splicers).

PG&E also has three cable crew foremen on the night shift. The Cable Crew Foreman is a working position, with one foreman typically taking clearances and installing grounds, while the others overseeing the crews.

PG&E also uses a position called a Cableman who is a troubleshooter for the underground system, part of PG&E’s Restoration group (not part of the M&C electric network organization). There are six of these cablemen who work for the company. They work a rotating shift , and have 24/7 coverage.

PG&E has a General Construction group, also comprised of cable splicers, who work with both the radial and network cable infrastructure. Resources in this group are roving, and act as “internal contractors”, moving to where needed and supporting the Maintenance and Construction- Electric Network organization.

Process

PG&E has a 30 month automatic mode of progression whereby employees must move through a program of formal training, on the job training (OJT) and testing; they then become a journeyman within this period. (See Crew Makeup / Job Progression)

Employees enter the department as Apprentice Cable Splicers.

^[1] Note that Cable Splicers are assigned during the day to work on San Francisco’s radial underground system. These crews can be redirected to address network issues that may arise during the day. However, all planned work on the network is performed at night.

3.12.14 - Portland General Electric

Construction & Contracting

Organization

People

Construction activities associated with the network infrastructure at PGE (part of the downtown CORE system) involve a number of departments. Because much of the construction on the network is not only for customer-owned facilities, such as building vaults, but also performed by external contractors, many construction practices involve working with third parties.

Service & Design at the Portland Service Center (PSC): Service & Design’s role is to work with new customers or existing customers with new projects, making it responsible for new connections, new buildings, and remodeling. The supervisor for Service & Design’s wider responsibility includes the downtown network. The supervisor reports to the Service & Design Manager, who is a peer of the Distribution Engineering and T&D Standards Manager. Both of these positions report to the General Manager of Engineering & Design and directly to the vice president.

The “Mapper/Designer” reports to the Supervisor of Service & Design at PSC and provides the computer-aided design (CAD), geographic information system (GIS), and design service.

A Field Inspector meets with contractors. Two inspectors work for the Service & Design organization, and one specializes in the network.

Service & Design Project Managers (SDPM): SDPMs, who also report to the supervisor for Service & Design, work almost exclusively on customer-driven projects, such as customer service requests. They also liaise with new customers in preparing designs. At present, two Service & Design Project Managers cover the network. SDPMs oversee projects from first contact with the customer to the final completion, and coordinate and manage construction designs and customer connections to ensure full compliance.

Ideally, a SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC), as well as the ability to use or learn the relevant information technology (IT) systems. PGE prefers to have a selection of SDPMs with a diverse range of experience and backgrounds, so the position does not necessarily require a four-year engineering degree. The managers can be degreed engineers, electricians, service coordinators, and/or designers [1].

SDPMs work on both CORE and non-CORE projects. This allocation of work ensures that expertise is distributed and maintained across departmental and regional boundaries [1].The Project Managers are separate from Distribution Engineering and T&D Standards.

Distribution/Network Engineers: Three Distribution Engineers cover the underground network and work with customers to design and operate customer-owned facilities. The Distribution Engineers are not based in the PSC or CORE group but work very closely with these groups through the entire project life cycle. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to perform certain planning tasks.

Network engineering also develops and maintains the standards for the network, and supports planning activities by providing the loading information used to create CYME and PSSE models.

Standards Department: The Manager of Distribution Engineering and T&D Standards oversees the Standards Department. The Distribution Engineers who support the network prepare and maintain network standards, which are forwarded to the Standards Department for inclusion in the company standards. The group employs one technical writer and four standards engineers.

Contract Services and Inspection (CS&I): At PGE, the CS&I department supervises contract management. Five Construction Managers work in the CS&I group and inspect any work performed by contractors on PGE-owned infrastructure. Field Construction Coordinators (FCC) inspect facilities built by customers. For larger projects, PGE may outsource inspections to external experts, such as POWER Engineers, Inc.

When constructing facilities, such as vaults, which will house PGE equipment, customers can choose from two third-party vault contractors who have received approval certifications from PGE.

Civil Engineers/External Contractors: PGE will typically contract civil engineering and structural design tasks, seeking contractors who prepare designs that conform with Oregon Public Utility Commission (OPUC) requirements. Generally, if civil issues are found with structures, such as a crumbling vault wall, an external structural expert will be consulted.

Synergy with PacifiCorp: PGE shares the downtown area with PacifiCorp, and although there is a defined boundary, some vaults, manholes, and duct banks share infrastructure among the two companies. PGE and PacifiCorp work closely to coordinate on managing shared infrastructure.

CORE Underground Group

The resources that comprise the group that services the downtown underground “core” infrastructure are physically located in one location. It services an approximately 1.5 mi2 (3.9 km2) territory bounded by the Willamette River in the East and the 405 freeway in the West. The underground group services both the network and radial systems located in the core, with network comprising about half of the system. PGE operates a number of underground crews responsible for the radial system and network in the PSC area. The CORE group is led by an Underground Core Field Operations Supervisor, who reports to the Response & Restoration Area Line Manager (ALM).

Crews

The PSC craft workers are responsible for radial underground, overhead, and network systems based on the geography. The CORE group, which is a part of the PSC, focuses specifically on the underground CORE. It includes both radial underground and network underground infrastructure in downtown Portland.

Currently, the following 16 people work in CORE:

Four non-journeymen
Eleven journeymen (e.g., assistant cable splicers, cable splicers, foremen)
One Special Tester

Resources in the CORE include the following:

Crew foreman: Crew foreman (a working, bargaining unit position)
Cable splicer: This is the journey worker position in the CORE.To become a cable splicer in CORE, an employee must spend one year in the CORE area as a cable splicer assistant
Cable splicer assistant: A person entering the CORE as a cable splicer assistant must be a journeyman lineman. All cable splicers start as assistant cable splicers for one year to learn the system and network.

The cable splicer position is a “jack-of-all trades” position with work including the following:

Cable pulling
Splicing
Cable and network equipment maintenance
Cleaning
Pulling oil samples from transformers

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault, while the helper usually stays above ground carrying material and watches the barricades and street for potential hazards.

In addition, a crew may include an equipment operator who will operate the cable puller, vacuum truck, or other equipment. Note that some work, such as backhoe work, is usually performed by external contractors.

Technology

PGE uses a number of key IT products to support the management of their network infrastructure, including a GIS system (ArcGIS), a work management system (Maximo), and an Outage Management System (OMS), specifically Oracle NMS. A brief description of these technologies and their capabilities are presented here.

Geographic Information System (GIS) – ESRI ArcGIS/Schneider ArcFM

PGE uses ArcFM GIS software for designing network layouts and creating a work package with details for relevant personnel, including construction and contract crews. ArcFM builds upon ESRI’s Arc GIS. Schneider Electric’s ArcFM software is a map-focused GIS solution that allows users to model, design, maintain, and manage systems, displayed graphically alongside geographical information.

ArcFM uses open-source and component object model (COM) architecture to support scalability, user configurability, and a geographical database. The system includes a recording system for asset data and a model of the distribution system. ArcFM also includes a Microsoft Silverlight interface that supports data management, planning, design, and analysis through a desktop computer. The mobile functionality supports data validation and editing in the field, and the system is web-compatible for remote access.

ArcFM includes tools that allow network editing, GIS asset management, design integration, and work management.

Maximo for Utilities 7.5

IBM’s Maximo for Utilities 7.5 system supports asset and work management processes for transmission and distribution utilities, covering most asset classes and work types. The system allows users to create work estimates and manage field crews. Maximo can integrate with a number of systems, including fixed-asset accounting, mobile workforce management solutions, and graphical design systems. The Maximo Spatial system is compatible with map-based interfaces, such as ESRI ArcGIS, and follows J2EE standards [26].

Maximo for Utilities supports operations across a number of areas:

Estimating compatible units (CUs)
Managing field crews
Tracking skills and certifications
Integrated fixed-asset accounting
Supporting field workforce management
Graphic design functionality
GIS integration
Using Gantt views for analyzing work orders
A compatible unit library helps planners and designers estimate CU when creating a project.

Maximo 7.5 can upgrade with a number of optional modules. These include the Asset Management Scheduler, which allows tasks to display in a Gantt view that shows the task dependencies and durations specified in the work order. The Spatial Asset Management module includes a map-based interface to track assets and locate work order and/or service request locations [2].

The PowerPlan Adapter is a corporate-level suite intended to facilitate accounting during operations. The system automates asset lifecycle management and supports compliance monitoring. The PowerPlan Adapter aggregates work orders and ensures that all aspects of a task are included, and users can add costs for labor, materials, and contractors when they arise [3].

Outage Management System (OMS)/Oracle NMS

PGE migrated to an Oracle NMS outage management system, which is based upon WebSphere technology [4]. Oracle NMS is a scalable distribution management system that manages data, predicts load, profiles outages, and supports automation and grid optimization. The system combines the Oracle Utilities Distribution Management and Oracle Utilities Outage Management systems in a single platform. The system supports outage response and the integration of distributed resources [5].

Oracle NMS blends SCADA function and GIS models to combine as-built and as-operated views of the system. The application includes a number of advanced distribution management functions, including network status updates in real time, monitoring and control of field devices, switch planning and management, and load profiling. Oracle NMS can integrate with other SCADA and GIS systems, and monitors network health using data from a number of systems [6]. The NMS includes a simulation mode for training and supports switch planning and control.

Oracle NMS maintains a network model that handles the whole grid, includes every device, and integrates with existing systems using standards-based protocols such as Inter-Control Center Communications Protocol (ICCP), Common Information Model (CIM), and MultiSpeak-based web services. The system can also integrate with a range of GIS and advanced metering infrastructure (AMI) systems.

PGE’s NMS/OMS integrates outage information and location, switching, and work management functionality into a single system. Operators can view and manage system status and operational data in real time, and the system uses a data model to predict the location of outages. The system can present data on a dashboard and through customized reports.

Northwest Public Power Association. “Service & Design Project Manager Level II/III.” NPPA.com. https://www.nwppa.org/job/service-design-project-manager-level-iiiii/ (accessed November 28, 2017).
IBM. “IBM Maximo for Utilities, Version 7.5.” IBM.com https://www.ibm.com/support/knowledgecenter/en/SSLLAM_7.5.0/com.ibm.utl.doc/c_prod_overview.html (accessed November 28, 2017).
Maximo Adapter. PowerPlan, Atlanta, GA: 2017.https://powerplan.com/resources/minimize-risk-and-optimize-maximos-implementation-with-powerplan(accessed November 28, 2017).
D. Handova, “PGE: Driving Customer Value With Network Management Systems.” EnergyCentral.com. http://www.energycentral.com/c/iu/pge-driving-customer-value-network-management-systems(accessed November 28, 2017).
Modernize Distribution Performance All the Way to the Grid Edge. Oracle, Redwood Shores, CA: 2015. http://www.oracle.com/us/industries/utilities/network-management-system-br-2252635.pdf(accessed November 28, 2017).
Modernize Grid Performance And Reliability With Oracle Utilities Network Management System. Oracle, Redwood Shores, CA: 2014.

3.12.15 - SCL - Seattle City Light

Construction & Contracting

Organization

People

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable Splicers perform all electrical aspects of network construction, operations, and maintenance. All electrical employees who work in the network are either Crew Chiefs, journeyman Cable Splicers, or apprentices in the mode of progression, working their way towards the journeyman level.

Mode of Progression

SCL uses a three-year automatic mode of progression. This mode includes 8000 hours of On the Job Training (OJT) and testing. They have experienced a very low dropout rate from the program. This is in part because they administer a highly selective front end test and interview process to accept apprentices into the program. Also, a Cable Splicer position at SCL is a highly sought-after position.

Training

In addition to the training associated with the mode of progression, SCL provides network crews with opportunities for training including mandatory safety training for processes such as manhole entry and manhole rescue. SCL also periodically sends personnel to conferences and specialized training sessions such as the Cutler Hammer School, etc.

Crew Makeup

A network crew is normally made up of one Crew Chief, one or two Cable Splicers, and one apprentice. The type of work to be done and SCL work rules will dictate the appropriate crew makeup. For example, performing switching in a vault requires at least two journeyman-level employees to be in the vault. These and other work rules and safety practices are spelled out in the Washington State Safety Standards for Electrical Workers, Chapter 296-45 WAC.

Process

Bi-weekly Crew Coordination Meeting

SCL convenes a bi-weekly crew coordination meeting focused on the project status of each active network project. Meeting participants include the supervision and others from the network design group (engineers), civil crew representatives, electrical crew representatives (including crew leaders), and customer service representatives who deal with customers who are adding load.

This meeting is effectively used to manage network construction projects. Representatives review the project status of both civil and electrical projects and identify actions necessary for the projects to proceed. A report is used that shows critical project milestones such as the vault acceptance date and feeder in date. See Attachment E , for a sample network jobs project summary. Note that a similar form is used to track the progress of civil construction projects.

The meeting is also used to establish action items to identify network conditions that must be addressed. One example would be the identification of vault locations where ventilation is inadequate for the summer heating season. The group will identify an action plan to make contact with building owners to address these deficiencies.

Incoming Network Equipment Inspection

SCL does an incoming inspection of network equipment. They have a person who is responsible for incoming equipment quality control. Each incoming transformer and network protector is tested when received at the test facility before being made available for field service. The test facility prepares an inspection report documenting the results of the inspection.

See , for a copy of SCL Network Transformer Inspection Checklist that guides the inspector through the inspection. , for a copy of SCL Network Transformer Inspection Checklist that guides the inspector through the inspection.

Other network equipment, such as cable, elbows, T bodies, etc. are sampled and tested at random. These tests can include X-raying to identify deficiencies.

Technology

Network Tools

SCL crews believe their tools to be of top quality. An example would be the network protector test kits (Richards) that the crews use to perform network protector maintenance. See Attachment G , contains a brief sample listing of the types of smaller tools typically provided to the crews.

3.12.16 - Survey Results

Survey Results

Construction & Contracting

Organization

Survey Questions taken from 2015 survey results - Summary Overview

Question 011: Within your company, how many Full Time Equivalent resources (FTEs) make up the following functions?

Survey Questions taken from 2012 survey results - construction

Question 5.1: Total number of Network field electrical workers (do not count “civil” workers)

Question 5.2: Do you contract any network electrical (not civil) construction work?

Question 5.6: How many hours of training (on average, per person) does your field force receive in a year?

Question 5.7 : Do you routinely conduct post construction audits to ascertain / assure the quality of the construction?

Question 5.8 : If Yes, what are the major items that are assessed during a post construction audit?

Question 5.9 : Do you have a formal process for reporting construction standards or material specifications deficiencies?

Question 5.11 : Do you utilize Mobile Data Units in your network fleet?

Survey Questions taken from 2009 survey results - construction

Question 5.1: Do you have a distinct field group focused on the construction, maintenance and operation of the network? Or are your field workers part of a group that also works with non network systems?

Question 5.2: Total number of Network field electrical workers (do not count “civil” workers) (This question is 5.1 in the 2012 survey)

Question 5.3: Do you contract any network electrical (not civil) construction work? (This question is 5.2 in the 2012 survey)

Question 5.7: How many hours of training (on average, per person) does your field force receive in a year? (this question is 5.6 in the 2012 survey)

Question 5.8 : Do you routinely conduct post construction audits to ascertain / assure the quality of the construction? (this question is 5.7 in the 2012 survey)

Question 5.9 : Do you have a formal process for reporting construction standards or material specifications deficiencies?

Question 5.11 : Do you utilize Mobile Data Units in your network fleet?

Question 5.12 : If so, what system are you using?

3.13 - Pre-cast Concrete Conduits

3.13.1 - CEI - The Illuminating Company

Construction & Contracting

Pre-cast Concrete Conduits

People

Civil construction, including the installation of vaults, manholes and duct back is performed by contractors at CEI.

CEI typically retains the services of five different contractors to perform civil work (construction and maintenance).

Process

The Underground Network Services group has one supervisor who runs the contractor crews.

Technology

Cables in underground network areas are installed in PVC DB-120 conduit encased in concrete with conduit spacers as per FirstEnergy s Network Design Practices Guideline. The design will include four inch spare conduits for additional secondary cables, and, where it is feasible that primary could be installed, two six-inch conduit spares in the lowest row on the duct bank.

3.13.2 - Con Edison - Consolidated Edison

Construction & Contracting

Pre-cast Concrete Conduits

People

Pre-cast Concrete Conduits

Con Edison uses 4-in., pre-cast concrete conduit sections for housing electric cables in open trench installations. These conduit sections are square in cross section, and are ordered for either strait runs or bends. Con Edison uses bell end conduits for entrance into manholes. These pre-cast conduit sections can be joined together as required, using male ends that connect with a plastic coupling. Con Edison requires that the conduits be able to pass specific tests, including a mandrel test to ensure the conduits are open, transverse loading tests, compression load tests, and a friction test.

For secondary cable installations where space may be limited, or the soil is unstable, Con Edison may use alternative conduit materials such as steel, fiberglass, and high-density polyethylene (HDPE). For example, steel conduits may be used in an open trench where the soil is unstable, for a jacking or driving operation, or where space is limited due to a shallow trench. Fiberglass conduits may be used in damp soil locations where corrosion is a problem. Con Edison has well-written guidelines that define conduit types and appropriate usage.

When Con Edison must install new duct banks, particularly in Manhattan, they often find it difficult to bring in heavy machinery. In these situations, the utility assembles a large group of laborers to hand dig the trenches to install new duct banks. Con Edison often schedules this work at night, to avoid the some of the challenges of performing this work during the day, such as vehicular and pedestrian traffic and other work restrictions.

Figure 1:

Figure 2:

Figure 3:

3.13.3 - Duke Energy Ohio

Construction & Contracting

Pre-cast Concrete Conduits

People

Most civil construction work at Duke is performed by contractors. Duke network resources will perform minor civil repairs.

Within the Dana Avenue construction and maintenance organization, Duke employs a T&D Construction Coordinator who interfaces with contractor crews, including civil contractors.

Process

Duke Energy Ohio uses civil contractors to both perform civil construction and assist Duke in assessing the condition of facilities from a civil perspective. For example, the civil contractor will be called in to assess the roof condition or other structural condition issues in determining what repairs should be made to a vault or manhole.

Technology

In urban installations, Duke Energy Ohio encases conductors in concrete duct bank installations.

Duke Energy Ohio does not use pre-cast duct bank, as each installation is unique size wise. Their standard duct bank installation includes grounding, tracer wire, and colored dye.

Note that in rural areas of their territory, Duke Energy Ohio does not encase conduits in concrete.

See Attachment E for sample standard conduit drawings used by Duke Energy Ohio.

3.14 - Project Management

3.14.1 - AEP - Ohio

Construction & Contracting

Project Management

People

Project Management (PM) activities are performed at various levels at AEP. For large programs, such as the ongoing secondary cable replacement project or network remote monitoring upgrade project, AEP will assign a project manager who will lead and coordinate among the various internal and external stakeholders. For the largest projects, AEP may dedicate additional resources for activities such as cost management, scheduling and reporting. For large projects that may involve an extended contractor team, the AEP project manager will coordinate closely and regularly with the vendor project manager. AEP may select a project manager for a special project from any part of the organization.

PM for the larger projects is the responsibility of Customer Service Representatives (CSRs). The CSRs, which are part of the regional organization, work as key account reps and work closely with Network Engineers when new customer service is requested. Together, they determine the most cost-effective design and scope of the project.

AEP Network Engineers have project management responsibility for all network projects and programs from capacity planning to inspection and maintenance to construction, from project inception through completion. Project management over civil construction, performed by a contractor at AEP Ohio, is also the responsibility of this group, based in the downtown Columbus, Ohio offices. The group leader, which is the Network Engineering Supervisor, reports indirectly to the parent company Vice President of Distribution Services.

Process

AEP Ohio Customer Service Representatives are assigned to an area of expertise, such as public works, manufacturing, office complexes, etc., rather than to a geographic area as is done at many companies. This specialization and experience is leveraged when working with Network Engineers for specifying the requirements and estimating the costs for new customer service and reinforcement projects.

AEP Network Engineers are responsible for all project management, from network capacity analyses through final inspection. Network Engineers manage the following:

Project analyses for capacity, load flow, and costs
Final design and detailed plan hand-off to its civil engineering contractor
Support of construction
Civil work permits and material acquisition
Final inspection

For any large-scale projects, the Network Engineers must work with the parent company, AEP. Many large-scale, company-wide projects, such as the secondary cable replacement program, have assigned leadership who coordinates across companies and may leverage existing groups with multi AEP Operating Company representation, such as the Network Standards Committee. Even with the largest cross company projects, local management is the responsibility of the AEP Ohio Network Engineers and the Network Engineering Supervisor.

Technology

Network Engineers and Customer Service Representatives maintain management spreadsheets to track the progress of any new customer service projects (see Figure 1). AEP Ohio maintains its own work spreadsheets and analyses to track large-scale network projects and programs. AEP will utilize Gantt charts and graphics, were practical, to facilitate communication of project status.

Figure 1: Excerpt from AEP asset program report

3.14.2 - Ameren Missouri

Construction & Contracting

Project Management

People

Most projects involving the design and construction of urban underground infrastructure within St. Louis are primarily the responsibility of the engineers within the Division Engineering Group in the Underground Operations Center. Only projects in excess of $25-million are assigned a specific corporate project manager (not part of the engineering group).

Organizationally, the Underground Operations Center is part of Energy Delivery Distribution Services, reporting to a VP. This center, led by a manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, service issues, and project management.

All of the engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement. The Energy Services Consultants (Estimators) have a combination of years of experience and formal education, including two and four-year degrees, and are part of the union, IBEW.

Construction managers are also involved in project management, such as work prioritization, resourcing, and scheduling. They worked closely with the engineering group to manage construction projects with the network.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis including project plans for execution.

Process

Engineers within the Division Engineering Group informally manage most projects. These project managers (engineers) prepare a monthly forecast and budget for their projects and are responsible for staying within the authorized limits. The engineers participate in weekly meetings with construction management to focus on work resourcing and scheduling.

On larger projects, engineers look at actual man-hours versus estimated on a monthly basis in order to manage progress, and critique the quality of their estimates so as to better estimate projects in the future. This monthly analysis is also used to improve the standards to assure that the resources and dollars associated with compatible units for construction standards are appropriate and realistic.

Work scheduling is a joint effort involving engineers, estimators, and construction supervisors. Ameren Missouri has formed a work prioritization and scheduling group, which is comprised of engineering and construction people within each district who focus on prioritization and scheduling. This group meets weekly review project at resourcing and scheduling.

New job requests flow through engineering, where they are assigned to an estimator. The estimator develops a cost and resource estimate and loads it into Ameren Missouri’s work prioritization and scheduling (WPS) system, a scheduling system based on their DOJM system. When the project has been approved, it is entered into the work schedule. (Note that projects over 80K require specific approval at Ameren Missouri.)

Work dates are entered manually into the work schedule. The system looks at resource availability based on crew assignments already entered and provides an indication of when the project can be resourced and thus scheduled. For larger, more time-consuming projects, it is difficult to project the required date until the design is complete. In these cases, an educated guess of the required date and resource expectation is entered to provide some long-term planning information to construction.

Project managers (engineers, estimators, and construction supervisors) meet weekly and review reports produced by WPS. The reports provide a listing of what work must be done next week, and a forecast of what’s upcoming. The review is used to make decisions about resourcing and work schedule. Within the system, work types are broken into categories, so that managers can compare customer work, for example to maintenance work and adjust resources as required. This review, for example, may reveal a manpower deficiency that leads to the necessity of contractors.

Technology

Estimators use the Distribution Operational Job Management (DOJM) to prepare job estimates. This system enables an estimator to build a job using compatible units that represent certain construction standards, which are accompanied by estimates of required labor hours, materials and their associated costs. The DOJM system is based on a Severn Trent product.

Ameren Missouri uses a work prioritization and scheduling system, based on the DOJM system.

3.14.3 - CEI - The Illuminating Company

Construction & Contracting

Project Management

People

Project Management – assuring that the scope, schedule and budget of underground projects are being met - is the responsibility of the supervisors with in the UG Network Services Department.

The supervisors work in tandem with project management personnel within the regional Engineering Services organization (Project and Portfolio Management subgroup), who focus primarily on progress and expense reporting, and project overage / underage justification.

Process

The UG Network Services supervisors meet weekly to assess the needs of the coming week and to develop a schedule. An advanced distribution specialist within the department prepares the schedule, and fine tunes it to meet daily requirements. The final crew assignments are updated by the supervisors CEI’s CREWS scheduling system.

UG Supervisors travel to field sites daily to assure that the people, equipment, and materials are brought to bear on the execution of projects. They interface with customers, address all resource issues, and monitor work progress at the jobsite. They are sometimes accompanied by asset management personnel – usually to provide training for these individuals.

CEI job designs include estimated resource requirements. UG department supervisors monitor actual resource expenditure and compare to these estimates. Crew leaders complete daily timesheets recording the hours expended against each project.

CEI has assigned one supervisor the responsibility for managing contractor crews performing work on the underground system.

Technology

CEI uses an in house scheduling system called CREWS, to schedule work, and track progress and accomplishment.

3.14.4 - CenterPoint Energy

Construction & Contracting

Project Management

People

CenterPoint’s underground organization is centralized, with the resources who work with the major underground infrastructure reporting organizationally to one group - Major Underground. At CenterPoint, the term “major underground” is used to describe the three phase underground system that supplies the urban portions of the Houston metropolitan area using ducted manhole systems, and including the secondary network systems. It consists of three phase facilities supplying commercial and industrial customers (with the exception of the network, which serves residential load as well). URD installations and single phase underground line extensions are not considered part of Major Underground, and are managed by other CenterPoint service centers.

The Major Underground organization, comprised of 208 total resources, includes Key Accounts, Engineering and Design resources, support services, and the field force responsible for all construction, operations and maintenance activities.

Management of the construction of projects is the responsibility of the Crew Leaders within Major Underground. The Crew Leader is a non-bargaining position at CenterPoint, responsible for leading both the Cable and Relay construction organizations. Crew Leaders work closely with Engineering Department in managing projects. See Design - Organization for more information.

For larger projects, the Key Accounts organization provides overall project management and coordination activities. See Design - Key Accounts for more information about this group.

Process

The Key Accounts group provides project coordination for new projects, and stays current with the happenings / growth at key commercial customers such as medical centers, municipalities, and universities. They also provide a single point of contact for large national retail chains. They are involved in power quality and reliability issue resolution, relocations, and long term O&M rehab projects. They also interface with governmental agencies.

3.14.5 - Con Edison - Consolidated Edison

Construction & Contracting

Project Management

People

Project Management

Energy Services has two project manager positions — the CSR Project Manager, who manages smaller projects less than 1000 kW, and the CPM Project Manager, who manages larger projects, 1000 kW and greater.

The CSR and CPM Project Managers receive the layout and issue work orders to construction management (for contracted work) and electric operations to execute the project. They ensure that the customer gets service on time. They coordinate dates, check the customer’s work to make sure it makes sense, ensure that the termination points are adequate, obtain city approvals, etc.

New Service Design

The Energy Service Organization at Con Edison has various subsections that are involved in the process of responding to customer requests for service: the Service Assessment team, Engineering, Layout, and Project Management.

Planning and Survey Group

The Planning and Survey group is a subset of the Field Engineering group, and consists of Surveyors, who perform survey work associated with new construction, and Planning Inspectors, who go into the field, and assess the specific field conditions and determine what is necessary for the new installation to be built successfully. Planners and surveyors can work separately, or work together on projects. This group works closely with Energy Services, taking layouts developed from maps by Energy Services on Microstation, and field checking them to identify the specifics of the job and ensure that the layout reflects field conditions. This group prepares job sketches to obtain the necessary permitting to complete the job.

3.14.6 - Duke Energy Florida

Construction

Project Management / Scheduling

People

The Resource Management group provides project management support services to the Duke Energy Florida Construction and Maintenance organization. Duke Energy Florida recently assigned one Project Manager, from the Resource Management group, to support network systems. Previously, there was no designated project manager in this role. Part of the rationale for the assignment of the project manager is a network revitalization effort underway at Duke Energy Florida. (See Network Revitalization – Florida Primary and Secondary Network Improvement Plan).

The Project Manager provides project management support services to the Network Group, and works closely with engineering and network supervisors to make sure the needs, requirements, and challenges of the network systems are understood and addressed.

Project Managers are required to go through a formal Project Manager Training designed for Duke Energy. Training is administered through the Duke Energy Project Management Center of Excellence (PMCE). The Project Manager assigned to the network group has experience with design, engineering, and GIS, including working with networks.

Scheduling

Historically, scheduling of work on the network system was handled within the St. Petersburg Operation Center by the supervisor of the network group. The Operation Center was responsible for prioritizing and scheduling the work for network crews.

Within the past few years, Duke Energy Florida has been in a transition phase with centralized scheduling. A scheduler at Duke Energy Florida coordinates work orders and new service for customers in the Clearwater and a second scheduler will focus on St. Petersburg. The schedulers all work for the Resource Management group.

In the new scheduling approach, the schedulers assigned to coordinate work orders for network crews also support the work order needs of the Engineering group. Both schedulers will also work with contractor crews to track work orders and keep work progressing. The current schedulers have previous experience with GIS and active working knowledge of the electrical distribution system to provide adequate support to supervisors and field crews. By design, the schedulers have a background in engineering with a solid foundational knowledge of workflow processes.

Process

Project Managers are responsible for making sure project milestones are met including schedules, budget, resources, building plans, documentation, and meeting customer needs. Project Managers are brought in to help when certain minimum monetary thresholds are met or on public works projects with regulatory requirements. Project Managers will also be involved in work affecting large commercial customers (or high profile, major accounts) with complaints or concerns.

Once assigned to a project, Project Managers will closely monitor the progress of the project to make sure timelines are on schedule and money spent (and projected spend) is within the budget. If projects are falling behind, the Project Manager will document the reasons and potential impacts to the overall project. To help ensure the project is progressing as planned, Project Managers will have weekly meetings with stakeholders to confirm resources, materials, manpower, and updated schedules.

Project Management has worked closely with upper management and the network group in developing improvement plans for the network. For example, when the network improvement initiative began, the project manager worked closely with network leadership to identify and document the gaps and determine the resources required for accomplishment. The project manager was subsequently responsible for formulating plans to address the defined needs.

Going forward, the Network Project Management group will also be responsible for planning network maintenance programs and inspections.

Scheduling

Working with the network supervisor, the schedulers are aware of the priority of work on the network system along with the resource requirements to complete the work at hand. Supervisors will inform the Scheduler of upcoming projects with priority to be entered into the ARM Scheduler software. Schedulers reach out to the network crews about the status of jobs, but most network crews will complete work orders on their mobile data terminals without assistance from the schedulers.

Technology

Duke Energy Florida uses a Work Management Information System (WMIS), by Logica (now part of CGI). WMIS will be used to track costs and time worked on larger network system projects overseen by the network project manager. The company anticipates using Microsoft’s SharePoint to help coordinate and share documents and information among various stakeholders in the organization. SharePoint will serve as a repository to share and organize Duke Energy Florida’s documents across the entire enterprise.

ARM Scheduler is part of the ARM Software Suite made by Logica. Only schedulers have direct access to update ARM Scheduler [1]. As a result, ARM Scheduler will export the queue of work orders to the network crews’ mobile data terminals or laptops (using WMIS) for field assignment and completion. Duke Energy Florida is considering a transition to Maximo’s scheduler and work management software.

[1] CGI-ARM-Scheduler.pdf

3.14.7 - Duke Energy Ohio

Construction & Contracting

Project Management

People

At Duke, project management of network projects is a shared responsibility among multiple resources in both the Design and Construction organizations

The Engineering and Design Group has two Customer Project Coordinators (CPCs) who are responsible for much of the project management, as well as design, for network projects that interface with customers. Note that the CPC’s assigned to perform network design, also perform non-network designs.

At Duke, the CPC position is a non bargaining position with an educational requirement of an Associates degree. CPC’s perform the design for new business work and service upgrades. They will follow the project throughout its life, including communications with customers on items such as project status, obtaining loading information, and scheduling outages.

CPC’s that are selected to work in the network area are usually more experienced employees who have worked at other locations, and are experienced with Duke’s information technology. For very large projects, the department supervisor, the Distribution Design Supervisor, supports these individuals by providing overall department project management, and in preparing progress reports for upper management.

In addition, the network engineer gets involved in supporting these projects as required, and is actively involved with all network projects. The network engineer works closely with Planning and Construction and acts as an “operational asset” for the Dana Ave group. The Network Engineer also provides project management support, dealing with things such as change out issues, material orders, project planning issues, scheduling outages, etc. The network engineer also acts as a “point man” for problem resolution of issues coming out of Dana Avenue. Any questions that arise, whether they are electrical issues, cable issues, structural issues, etc, are funneled through the network engineer for answers. For those that the Network Engineer cannot answer, he will forward to the appropriate resources and act as a coordinator for obtaining a response.

When the project gets to construction, the crew Supervisors provide day to day project management, such as scheduling the work, assigning resources, assuring the material is available, etc.

Technology

Duke is not using a specific project management technology. They are using other technologies, such as design tools, accounting tools, and outage management tools to aid them.

In some cases they are using manual triggers, such as releasing a job folder to construction after receiving customer easements, payments, and signed documents.

Duke utilizes a GIS system, GE Energy Smallworld, as a design tool for much of their system. However, the network system is not modeled in Smallworld. Network design is done using drawing tools such as Microstation (Bentley) or AutoCad.

Duke is also using a material order system called JET (Job Estimating Tool) for network projects. This system is scheduled to be replaced by a system called Expert Designer (Bentley), which will use Microstation to build a cost estimate, and to order a bill or materials.

Duke has an accounting system that tracks all costs associated with a project. Any project with a cost over $50000 is tracked individually.

Duke’s outage system is used to schedule and manage any tagging or switching associated with a particular project.

3.14.8 - Energex

Construction & Contracting

Project Management

People

Energex has a strong project management focus. They have a group that serves as a program office that is comprised of project managers. Energex has 35 project managers within the program office, who manage the largest projects. The resources that comprise this group come from a variety of backgrounds.

Some are professional project managers. These tend to be the senior employees who are assigned the largest and most complex projects.
Some are personnel with strong field experience, and complement that with project management expertise.
Others serve as project coordinators. These personnel manage smaller jobs, where coordination is often the prime role of the PM. Personnel who serve as project coordinators come from a variety of backgrounds.

The group also has two program managers and schedulers who are adept with the company’s IT systems.

Process

CBD projects tend to be on the smaller side of projects managed by this group. Project managers are typically assigned to projects that require coordination among different departments. Because connections in the CBD typically involve relay controlled switchgear, they require the involvement of various departments, such as people to address the protective schemes, coordination with the control room, etc., as well as coordination between customers and the city. Because of the need to coordinate the activities of these various groups, a project manager is assigned and is responsible for identifying the various resource requirements, “bundling” the work, and completing the project.

Projects to connect new customers within the CBD involve connection to Energex’s multiple feeder meshed 11 kV network. As these projects tend to be more complex, they involve the assignment of a project manager. A project manager is assigned to the project just after the approach is developed by the planning department, and as it is handed off to the design area Project managers are measured on adhering to project cost estimates and clearly defined project schedules.

( See the New Service Design section in this report. )

Project managers use Gantt charts to track and report on project progress. Gantts are built from the bottom up, using anticipated resource requirements for each project task. Project managers manipulate the assignment of resources to meet project targets.

The program office works closely with the construction areas to schedule the work. The construction group includes a scheduling function, which takes the completed construction plan, and using the company’s Ellipse system, schedules the work down to the work group leader level. There is strong collaboration between the scheduling group and the program office.

Technology

Energex uses Primavera as their resource planning tool. Project resource estimates, which are entered into Ellipse, are rolled up into an overall resource plan within Primavera. Primavera produces an overall program estimate. (For example, Primavera produces a high level estimate for a program such as an 11 kV feeder re-conductor program, which provides a high level resource estimate and schedule.) As the program is implemented, Energex creates, schedules, and completes individual projects as part of that program. These individual projects are managed using Ellipse.

3.14.9 - ESB Networks

Construction & Contracting

Project Management

People

ESB Networks has established a Program Management organization, responsible for providing project portfolio management of the distribution investment plan.

Process

All construction and contracting is organized into distinct categories, so that managers can compare customer work, for example, to maintenance work and adjust resources as required. This review, for example, may reveal a manpower deficiency that leads to the necessity of contractors.

3.14.10 - Georgia Power

Construction & Contracting

Project Management

People

All projects involving the design and construction of urban underground infrastructure within Georgia Power are the responsibility of the engineers within the Network Underground group. The Network Underground group, led by the Network Underground Manager, consists of both engineering and construction resources responsible for the network underground infrastructure at Georgia Power. Project management is a shared responsibility among engineers within the Network UG Engineering group, marketing resources who work within Georgia Power’s marketing group, and construction resources.

The engineering group is led by a manager, and is comprised of design engineers, engineering representatives, and GIS Technicians. The engineers do both electrical and civil design. For smaller projects, the primary responsibility for project management lies with the engineers within the Network UG Engineering group.

For projects to serve new customers or significant load increases, the engineers partner with representatives from the Marketing group, including Key Account representatives for the largest customers.

The Marketing group members have a combination of years of experience and/or formal education, including two and four-year degrees, and work closely with the Underground Network design engineers on projects. They gather load forecast and revenue information and assist with financial analysis of proposed projects. They also involved with communicating with customers.

The Construction manager and distribution supervisors (Foremen) are also involved in project management, such as work prioritization, resourcing, and scheduling. They work closely with the engineering group and marketing to manage customer construction projects within the network.

There are primarily two types of construction projects that involve personnel in the Network Underground group: 1) the addition of new networks or network substations, including duct line work throughout the Georgia Power system and 2) projects that require construction at customer sites, including spot networks.

Network capacity upgrades and new networks are initiated by Area Planners. Area Planners are responsible for different areas of the state, such as Atlanta, Savannah, Macon, Augusta, Athens, and Columbus and are responsible for the substations in those areas to make sure the transformers have the capacity to handle projected future loads. These Area Planners are geographically based both in Atlanta and the southern part of Georgia. Those outside of Atlanta work in offices closest to the areas they are responsible for, while three Area Planners are based out of the company’s downtown Atlanta offices and are responsible for the Atlanta Metro area and a few networks in Macon and Augusta.

Projects of $2 million or less are brought before the Regional Distribution Council for approval. Any projects that require more funding are sent to the vice president of the Network Underground group and upper management for review and funding approvals.

Process

For network capacity upgrades and new networks, Area Planners meet monthly with the Network Underground supervising engineers to update the network expansion or upgrade plans. Area Planners look at least four years out for any anticipated new network projects.

Engineering and Marketing work together on new service projects, regardless of which group makes initial contact with the customer. The Marketing department has a project manager designated to work on network projects, but other Key Account Managers may also be involved, particularly if their assigned customers are involved

Many projects that come into the Underground Network group are large, and span many months (or even years).

Marketing gathers load and revenue information, assists with financial analysis, and helps communicate with customers. Marketing usually prepares initial cost and revenue options on new projects for customers with the following three options:

All upfront costs to the customer, with standard rates afterwards.
Least upfront cost for customer, with project costs added to the subsequent service cost.
A combination of both.

It is the job of the marketing department to provide the loading requirements to engineering. Some, but not all, Marketing project managers are engineers, so they are usually very accurate and conservative in their load assessments.

The marketing group has identified an individual who serves as a key contact to the Network UG group. This person has forged a strong relationship with engineers within Network UG, and the Network UG manager reports that this strong relationship has been beneficial to the partnership between the two groups.

The Georgia Power Network Underground group uses a team approach to streamline project management by coupling a design engineer with a project manager or a key account. The design engineer focuses on the technical aspects and communicates them to the project managers. Key account managers interface with the customer and the project manager.

Once a project package is assembled, it is presented to the Regional Distribution Council (RDC), a Georgia Power decision making body comprised of leaders from across the company. The primary purpose of the RDC is to ensure company-wide consistency in the allocation of budget resources. It reviews and approves all major distribution construction projects. The Marketing project manager and design engineer present the final package. Typically the design engineer presents and answers questions about the technical aspects of the project, while the project manager can present and then answer any financial, management, or scheduling questions.

Every job has a Microsoft Excel tracking spreadsheet associated with it. All phases of the project are tracked and entered into the spreadsheet by the project manager. The company does not use Gantt charts as projects too often come in spurts; for example, there may be a tremendous portion of the budget spent up front, followed by no activity for many months, and then another burst of activity. Georgia Power has found that typical Network Underground projects do not lend themselves to predictable, even schedules of financial outlays.

The group is held accountable for results, however. This is the primary reason the Marketing group, working with design engineers, performs detailed profitability analyses before presenting the final package to the RDC. Because of this careful upfront analysis, Georgia Power Network Underground projects rarely go over budget.

The group feels there is a good relationship and clear communications between Marketing and Engineering. This is essential as customers expect a high level of expertise and competency from Georgia Power because of the size and scope of the projects - mostly multi-million dollar projects that span over a long period of time and that are highly complex in execution and design.

For these reasons, design engineers may work directly with customer project managers to ensure the project is going as planned. Engineers may make pre-project site visits. It is not uncommon for customers to call or meet with the design engineer directly on key aspects of the project throughout its implementation. Customers also communicate directly with the Marketing project manager and/or Key Account associates as well.

All internal network underground projects are scheduled and managed by supervisors within their area of responsibility, such as civil projects (the replacement of brick roof vaults, SWIVELOC manholes, for example) and network upgrade projects (the replacement of network protectors, new networks). These supervisors also meet on a regular basis to update each other on progress and receive any on-going information that would affect the completion and prioritization of projects. These supervisors work directly with engineering to make certain they have the resources (both human and material) and are meeting the standards set by the Georgia Power Network Underground Standards Group.

All projects, whether internally or customer driven, have a formal transmittal document for transferring the project drawings to the work crews, signed by the engineer, with the job name, job numbers, job location, and complete description of the project. The job transmittal packet also includes the formal work order, which includes all the financial aspects of the project, such as costs and their associated account numbers. Another piece of the package is a safety review which lists all hazards on the jobsite and any safety-related procedures which will be needed.

Technology

For the estimation of project costs, Georgia Power has a custom software program, written by Georgia Power staff (legacy system), called the Job Estimation and Tracking System, or JETS. The system is used to develop project estimates, both preliminary estimates and approved work order estimates. The system has all the necessary pieces that go into calculating the job cost, overhead, material, etc.

All project designs are done using AutoCAD, and the engineering group has canned examples or reference standard designs, such as standard manhole, vault, and duct line modules, as well as cable racking diagrams, that can be “dragged” into the CAD of the project and modified as needed. The group uses the online Standards book for applying Network Underground design standards. The work crew receives any duct line drawings, plan and profile construction drawings, cable-pulling sketches, etc. in the transmittal packet that the cable and construction crews need for the project (See Figure 1 through Figure 3.).

Figure 1: Excerpt from job sketch

Figure 2: Sample Drawing showing duct bank position

Figure 3: Excerpt from vault drawing – electrical details

3.14.11 - HECO - The Hawaiian Electric Company

Construction & Contracting

Project Management

People

In general, project management – assuring that the scope, schedule and budget of underground projects are being met - is the responsibility of the supervisors with in the C&M organizations (Overhead and Underground) at HECO. For large, complex projects, HECO assigns specific managers from their Project Management Division.

C&M Planning

HECO has a C&M Planning group within their Construction and Maintenance Division that focuses on project planning and scheduling. This group consists of seven resources that perform all of the planning and scheduling resources for HECO C&M. Of the seven, one resource is focused on providing the planning and scheduling for the Underground group.

The C&M planning group works closely with C&M supervisors to plan and schedule the work of the department. Prior to the formation of this group, HECO field supervisors were spending large amounts of time performing project planning and scheduling activities, preventing them from being in the field supervising the crews. HECO formed this distinct group to focus on project planning and scheduling activities, and to free up field supervisors to be in the field.

Project Management Division

For large, complex projects, HECO assigns specific managers from their Project Management Division. The Project Management Division is a separate division of the Engineering department. It is led by a Director, and is comprised of 4 project managers, 1 administrator and 1 project analyst. The Project Management group is assigned large projects, in excess of 2.5 million dollars. These projects often have community implications and PUC permitting requirements that are the responsibility of the project managers.

Note: this group’s responsibility is not limited to underground projects. They will manage all larger projects on behalf of HECO.

Process

C&M Planning

The C&M Planning group works closely with C&M supervisors to plan and schedule work. Responsibilities include (partial list):

Receiving and logging job packages from Engineering (System Reinforcement work, for example), CID (new service work), or System Operations (a Repair Order, for example),
Preparing a “Field Check” package for the supervisors to assist them in field checking a job and estimating resource requirements,
Setting up the work packages^[1] for the crews,
Creating work packages for planned maintenance activity,
Ordering outside services such as traffic control, excavations services, etc,
Submitting " holdoffs", which is part of HECO’s feeder clearance process,
Assigning resources to projects, considering training, vacation, and other issues that affect resource availability,
Prioritizing and scheduling projects.

C&M Planners work in the office, and rarely go into the field. They work collaboratively with Field supervisors, who do spend most of their time in the field.

The C&M Planning group’s roles and responsibilities are more developed for overhead work support. Their roles and responsibilities with respect to Underground are still under development. For example, the C&M Planning group does not schedule programmatic maintenance of underground facilities.

Project Management Division

The Project Management Division is comprised of Project Managers who work collaboratively with C&M, Asset Management, and Engineering to develop a project scope, schedule and budget, as well as manage larger projects. They will form project teams, prepare all required PUC permitting, track project progress, and prepare and conduct presentations of project status to senior management.

The Project Management group also serves as a project management knowledge center for HECO, staying current with Project management techniques (from the PM Institute, for example) and offering internal project management training.

HECO has done a good job of defining this group’s role, and integrating it with the rest of the organization in a manner that is clear, with well defined roles and responsibilities.

Technology

HECO is currently using a HECO developed system to plan and schedule their work.

HECO is currently evaluating eMESA, a work management and scheduling tool by DTS, Inc. They ultimately plan to use this software as a front end to their Ellipse Maintenance Management software.

HECO project managers are using Microsoft Project and Chart Pro, both industry standard software products for establishing work breakdown structures and managing and reporting progress of projects.

^[1] HECO Work packages include all of the required forms associated with a project including engineering drawings, bills of material, work orders, other forms, such as a “node form” used to capture and enter transformer information in a data base, etc.

3.14.12 - National Grid

Construction & Contracting

Project Management

People

Complex projects can involve interaction between many organizational groups. National Grid has implemented formalized project management procedures that define how these groups shall interact to ensure successful completion of projects. Procedures and roles are outlined in the Project Management Playbook - a document designed to standardize operations and roles of various personnel in complex collaborative projects.

The people involved, and procedures to be followed, differ depending on the scope of the project. For large and medium complexity projects (generally over $1 million cost and/or of high complexity), National Grid assigns a project manager. The project manager is responsible for the overall process, with individual responsibilities laid out in the Project Management Playbook. There are 13 project managers company-wide focused on distribution and sub-transmission projects. Network projects represent a very small percentage of the overall work managed by these project managers.

Smaller projects, under $1 million, are managed by front line supervisors and a specific project manager is not generally assigned. Additionally, the procedures to be followed can be much simpler than for complex projects. To address these smaller projects, National Grid has a customer order fulfillment group. This group shepherds smaller projects through the process, addressing things such as cost estimating, obtaining easements, and assuring proper work package close out.

The Portfolio Management Office (PMO) is responsible for managing the aggregate work plan, or portfolio of all projects/programs competing for common resources and dollars. This group provides both quantitative analysis and governance oversight for projects and programs in the portfolio. The PMO provides scheduling, finance, and resource availability through periodic measurement, monitoring, and controls. The PMO sets individual project fiscal year spending limits and progress targets, established within fiscal year budget constraints. The PMO supports project and portfolio management tools, including a scheduling tool, a “lessons learned” database, and other project management information systems to standardize processes leading to greater efficiency. The PMO governs substation capital projects, sub-transmission projects, programs such as feeder hardening, Department of Transportation (DOT) projects, distribution line capital projects, reliability enhancement programs, equipment, facilities, and operations & maintenance programs.

A project is initiated by a person or organization denoted as the Project Sponsor. The Project Sponsor brings a proposal to the Portfolio Management Office which helps develop an initial assessment of resource requirements, and a project team is appointed. At this stage a project’s complexity level is determined, which then determines how other personnel are brought onto the Project Team and how resources are allocated. The Project Sponsor is responsible for documenting the initial project plan, statement of work, schedule (or needed date), objectives, and a conceptual estimate.

A Project Manager and Project Team are assigned in the initiation phase by the Project Sponsor and the PMO. The Project Manager is the person ultimately accountable for all stages of the process and sees the project from conceptualization through to completion. Project managers are assigned only for large and medium complexity projects (e.g., over $1 million); for smaller projects, front line supervisors can be assigned the role and the process simplified considerably.

The Project Team consists of all personnel required for the project, and may include engineering and design, construction, operations, asset management, purchasing, permitting, various other team members, and functional managers. They are identified during the planning and initiation stages of the project.

Process

Project Management Playbook

To help deliver capital projects on time, on budget, and within scope and quality requirements, National Grid has implemented a Project Management Playbook (PMP) which ensures collaborative project management processes, procedures and measurements are embedded and embraced universally by the organization. The PMP describes the overall structure of procedures in the project management process. The lifecycle of a project has several distinct phases (described below), and major functions are performed in each phase. Procedures describe detailed step-by-step actions and associated roles and responsibilities for accomplishing these functions. These procedures provide guidelines related to defining, authorizing, accomplishing, and controlling project objectives, monitoring and controlling risks, and obtaining customer satisfaction. They help with planning and controlling work scope, cost, schedule, and quality. In conjunction with procedures for Engineering, Construction, Operations, Permitting and Licensing, Corporate Finance, Plant Accounting, Purchasing, and others, they provide the framework for end to end Project Management.

National Grid uses a portfolio management process to measure, monitor, and control the entire portfolio of projects/programs through all steps of the project’s life cycle. This is accomplished by weighing individual projects against all other projects and given priorities for resources, material, and budget allocation, while considering general constraints including “Ready for Load” dates, available resources, fiscal year budget spending limits and regulatory commitments. While the Portfolio Management Office (PMO) is responsible for monitoring and governing the Project Management Process, individual Project Managers retain full ownership and accountability for their individual projects.

At each stage of a project, individuals are assigned tasks according to procedures in the Project Management Playbook using special “RACI” charts, which define their responsibilities and deliverables, at each project stage. RACI is a labeling system that defines individual and organizational roles according to the following scheme:

R: Responsible individual(s) actually perform the activities or are responsible for action/implementation; and responsibility can be shared.
A: Accountable individuals are ultimately in charge, are responsible for assigning the degrees of responsibility to “R” individuals, and have yes / no authority and veto power. Only a single “A” can be assigned to a single function.
C: Consulted individual(s) are those who must be consulted prior to any final decision or action. Their feedback may be factored into the process, so “C” communication is considered two-way.
I: Informed individual(s) need to be informed after a decision or action is taken. They provide no feedback; communication with these individuals is, procedurally speaking, one-way.

National Grid has defined specific project phases for high and mid-complexity projects. In order to streamline day to day operations, simpler projects go through the same phases but with fewer procedural requirements, also described in the PMP. To aid the overall flow of these processes, RACI charts in the project management playbook are used to define the hierarchy and relationships between various project team members, codifying standard practices to ensure optimal collaboration between team members using clearly defined standards. The project phases include:

Phase 0: Project Identification.

An individual, or organization, proposes a project, and an investment estimate with an initial resource plan developed with the Portfolio Management Office (PMO). A project team is appointed to evaluate various options and to complete a conceptual engineering report for the preferred option. A project scope, schedule, and budget are developed. A Preliminary Works Sanction (PWS) paper or Strategy Paper is written by the Project Sponsor. The paper documents the initial project plan, statement of work, schedule (or need date), objectives and conceptual estimate. The PWS/Strategy is then approved by management - this approval authorizes more detailed engineering. The project then gets put into the five (5) year business plan, which is approved by Investment Management.

Phase 1: Project Initiation.

Project Team members are assigned, a Project File is created, and the project is kicked off.

Phase 2: Project Planning.

Key project parameters of cost, scope, schedule, and quantity are further developed. In the Preliminary Engineering step, project Cost, Schedule, Scope, and Quality (CSSQ) is base lined to establish performance metrics. In Final Engineering and Design, detailed engineering occurs, final design drawings are issued, and materials are ordered.

Phase 3: Project Execution.

The Project is constructed in field, tested, commissioned and turned over to Operations when it is ready to be put into service. Project Execution procedure is done in compliance with the National Grid Investment/Construction Playbook which discusses common control principles for delivering capital investments.

Phase 4: Project Monitoring and Control

The project is evaluated against project baseline for variances. Monitor and control functions must occur throughout entire life cycle of project for successful management. In this step, project risks are monitored, CSSQ requirements are controlled, and project execution is managed. During this step, project spending is compared to the original baseline cost plan and Delegation of Authority (DOA) requirements and updated for the monthly Resource Allocation Committee (RAC) meetings.

Phase 5: Project closeout

The project team assesses outcome of project and performance of project team. Best practices and lessons learned are captured for future projects. The project is accepted by the Project Sponsor and project is administratively and contractually closed out.

Technology

Project management procedures are outlined in the Project Management Playbook, which describes procedures for projects of varying complexity levels (each one given a numerical level designator). Other information systems and tools are maintained by the Portfolio Management Office (PMO).

The Project Management Playbook (PMP) describes people, processes, and responsibilities. For each step, the PMP includes a chapter describing the sequence and description of activities to be executed to complete each phase of project delivery. Activities along the main process flow path are indicated with Directorys. Each task is numbered and a brief description of the task is displayed, and task descriptions are expanded within each step of the procedure. Tasks are color coded to correspond with the principal owner, indicated by the RACI charts.

Primavera ( http://www.oracle.com/us/corporate/Acquisitions/primavera/index.html ) is a project portfolio management tool to help “optimize resources and the supply chain, reduce costs, manage changes, meet delivery dates, and ultimately make better decisions, all by using real-time data” It is used for project scheduling and department resource loading.

Severn Trent Operational Resource Management System (STORMS) is National Grid’s work management system developed by Worksuite. The work management system includes tools to initiate, design, estimate, assign, schedule, report time/vehicle use, and close mainly distribution line work.

Success Enterprise is an estimating and cost management suite, allowing multi-user collaboration and real-time evaluation of cost estimates based on actual costs and statistical analysis.

PeopleSoft from Oracle is a large enterprise information management suite. National Grid uses it for tasks including project status reporting, initiating purchase orders and requests for materials from stores.

A database of lessons learned and actual project costs is maintained to assist with future planning and project management needs. This is maintained by the Portfolio Management Office.

3.14.13 - PG&E

Construction & Contracting

Project Management

People

At PG&E, project management of network projects is the responsibility of the supervisors within the M&C Electric Network group. In addition, PG&E has a Project Coordinator who works closely with the supervisors and provides administrative support.

In addition, the planning engineer gets involved in supporting network projects as required, and is actively involved with all network projects.

3.14.14 - Portland General Electric

Construction & Contracting

Project Management

People

In the CORE, many projects are customer-driven new construction projects that draw together experts from many areas of the company. Project management is an important process coordinating the various activities required from initial planning to project completion.

Project Management Office (PMO) Group: The larger, more complex projects are managed by the PMO. This group, which is a part of the Transmission and Distribution (T&D) organization, is involved in the early stages of coordinating with System Planningand takes responsibility for projects once the Planning Engineers have developed a shortlist of solutions. Because of an increasing number of more complex projects, PGE is expanding its PMO Group.

Every large project requires expertise from various parts of the company, and the PMO coordinates the activities of these various subject matter experts (SMEs). The project team will have a defined Project Manager and a Materials Coordinator. The Corporate Capital Review Group and Corporate Risk Assessment will review most projects.

For network/CORE projects, the T&D Project Manager working in the PMO Group serves as the Project Manager. The manager has responsibility for all projects in the CORE, including large complex projects, such as the Marquam Substation project. The present manager has a Project Management Professional (PMP) certification and project management experience with another utility. The PMP designation is not necessarily a requirement for T&D Project Managers.

PGE is bringing a number of additional organizational functions into the PMO, making it easier to manage the overall expenses and cash flow for transmission and distribution. An external consultant is guiding the expansion of the PMO. Previously, PGE’s portfolio management group consisted of four individuals with responsibility for managing projects, but the new structure will improve the division of labor and enhance accountability. The expanded PMO will improve processes for communicating the budgetary forecasts needed for corporate planning. A new office location will provide a space for project meetings and ensure that discussions provide clearer details of ongoing project and risk status. As the PMO Group takes on more projects, it will receive additional human resources.

PGE also intends to employ a portfolio manager, who will collate and assess all ongoing projects. The portfolio manager will evaluate the inherent risks and determine whether a project should be accelerated or slowed down.

Service & Design at the Portland Service Center (PSC): Service & Design has a project management role associated with customer-generated new projects or remodeling projects, including work in the downtown network. The supervisor for Service & Design reports to the Service & Design Manager, who is a peer of the Distribution Engineering and T&D Standards manager. Both of these positions report to the General Manager of Engineering & Design and directly to the vice president. A “Mapper/Designer” reports to the Supervisor of Service & Design and provides the computer-aided design (CAD), geographic information system (GIS), and design service.Two Field Inspectors work for the Service & Design organization, and one specializes in the network.

Service & Design Project Managers (SDPMs): SDPMs, who also report to the supervisor for Service & Design, work almost exclusively on customer-driven projects, such as customer service requests, and liaise with new customers in preparing designs. SDPMs oversee projects from first contact with the customer to the final completion, and coordinate and manage construction designs and customer connections to ensure full compliance. At present, two SDPMs cover the network.

Ideally, a SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC), as well as the ability to use or learn the relevant information technology (IT) systems. PGE prefers to have a selection of SDPMs with a diverse range of experience and backgrounds, so the position does not necessarily require a four-year engineering degree. The managers can be degreed engineers, electricians, service coordinators, and/or designers.

SDPMs work on both CORE and non-CORE projects. This allocation of work ensures that expertise is distributed and maintained across departmental and regional boundaries.

Distribution/Network Engineers: For non-customer generated work, the Distribution Engineers may also have formal project management responsibility. The Distribution Engineers are not based in the PSC or CORE group but work very closely with these groups through the entire project life cycle. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees these engineers. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to perform certain planning tasks.

The new network substation project (the Marquam project) is an example in which the Network Engineers have elevated project management responsibility, as they have the expertise with network systems to effectively provide leadership for this effort. As a non-customer-generated project, this falls outside the responsibility of SDPMs. As a large complex project, this project also has PMO oversight.

Contract Services and Inspection (CS&I): At PGE, management of contractors is the responsibility of the CS&I department. Five Construction Managers work in the CS&I group provide project management support to contracted projects, and inspect any contractor work on PGE-owned infrastructure. For larger projects, PGE may outsource inspections to external experts.

Key Customer Manager (KCM): PGE has nine KCMs reporting to Manager of the Business Group. Generally, they are geographically distributed, with three on the west side, one downtown, one in Salem, three on the east side, and one acting as a rover. KCMs liaise with large customers and communicate their needs.

Process

The project management process is in transition at PGE.

The T&D planning group, in close cooperation with the Network Engineers for network work, identifies the need for a project and undertakes studies to identify multiple potential solutions before choosing the lowest cost, least risk solution and proceeding. Historically, the project schedule and estimate were developed, and approval for the funding was obtained before the project was forwarded to the PMO Group.

In future, to streamline the process, engineering will involve the PMO earlier in the process during the development of the cost estimate and schedule, before sending the project to the Corporate Capital Review Group for funding approval. With the new process, under PMO leadership, more engineering analysis will be undertaken before seeking funding approval. This will resolve one of the challenges with the historic approach, in which costs were estimated and approved using very little engineering analysis, and actual costs often escalated after approval.

The PMO will assemble a project team that includes representatives with a range of expertise, depending upon the type and scope of the project. The assembled team will visit the project site(s) and determine the scope before submitting a project for approval.

One concern with the new process is that engineers will invest time in performing preliminary studies. In addition, if the project is not approved, the upfront time commitment to prepare the estimate could waste resources. Therefore, it is important to promote better synergy between engineering and the PMO to streamline the project management process leading up to approval. Once a project is approved, the PMO will escalate the process and work with the team created during the estimating and scheduling phase of the project to plan, engineer, permit, and construct the project.

For internally-driven projects, the PMO oversees the project development, while for externally-driven projects, SDPMs usually oversee the project. For external projects, the PMO is only involved for large projects with complex coordination requirements. Depending upon the makeup of the project team, the engineering group may control the entire project and only involve the PMO if concerns arise, such as a risk of missing deadlines. For other projects, the PMO may be more intimately involved.

Within the CORE, the PMO is only involved with large projects that interface with the transmission system, such as the new network substation project. The PMO does not deal directly with equipment and material vendors, which is the responsibility of the materials coordinator. However, the PMO is heavily involved with scheduling and will offer an opinion about the resources required.

In general, no official processes that determine whether a project or task should use internal or external resources exist because this depends upon the available internal resources, and the preferences of senior engineers and Project Managers. For example, most substation work is now contracted out due to limited resources. On the distribution system, many of the tasks require local knowledge, workmanship, and expertise, so PGE is more comfortable with internal crews undertaking the work.

Project Scheduling SharePoint: On a monthly basis, all the Project Managers maintain a schedule for their individual projects and post it to a SharePoint site. This site also has the following:

Forecast cost information
Actual cost information
Brief report of monthly activities
Link to the schedule
Other commonly searched for documents are attached as well

This information is not commonly shared with other groups. Project Managers issue weekly reports to the PMO manager, which takes the form of a bulleted list of task updates. Shorter term studies are performed by T&D Planning Engineers, who share the results with stakeholders via SharePoint. These results are used to justify potential capital projects.

Customer-Generated Projects

For customer-requested projects, project management is the responsibility of the SDPMs. PGE follows a specific process/flow, which does not significantly differ for spot or grid networks. The process begins when a customer contacts the service coordination desk and receives a work order number, which allows system to track the process. The customer is assigned to one of the SDPMs, who will discuss the project with the customer and determine what information has been provided, what is still needed, and a timeline for any scheduled visits.

The SDPM coordinates with the distribution engineering team to determine exactly what is needed. Every new load is analyzed using PSSE, under the direct supervision of Distribution Engineers. The Distribution Engineers determine the electrical design needed to service the new load.

The distribution design is sent from distribution engineering to the SDPM, who determines the route that the conduit(s) must follow and where to install them. For example, if a distribution engineer specifies that they need to run two 500 MCM copper cables from a particular manhole to the building panel, the SDPM determines exactly how to accomplish that. Once the SDPM completes the design layout, Distribution Engineers confirm the electrical layout. The SDPM also works with the building architect(s) on the design/construction of any new vaults to assure that the designs meet PGE specifications.

PGE has created a one-note “database” containing all of the new or proposed construction in the downtown area. This information is tracked, with many of the items proposing and anticipating what could be needed. The information is shared with the manager of the SDPMs on an informal basis to track progress and check that the anticipated projects will actually occur. The database acts as a way to record and monitor information on different projects due to the large volume of projects across the downtown district.

Technology

PGE uses a number of key IT products to support project management. A brief description of these technologies and their capabilities are presented here.

Geographic Information System (GIS) – ESRI ArcGIS/Schneider ArcFM

PGE uses ArcFM GIS software for designing network layouts and creating a package with work details for relevant personnel. For construction, the system creates a list of materials that can be shared with the relevant people.

ArcFM uses open-source and component object model (COM) architecture to support scalability, user configurability, and a geographical database. ArcFM includes tools that allow network editing, GIS asset management, design integration, and work management.

Maximo for Utilities 7.5

IBM’s Maximo for Utilities 7.5 is a work management system that allows users to create work estimates and manage field crews. Maximo can integrate with a number of systems, including fixed-asset accounting, mobile workforce management solutions, and graphical design systems. The Maximo Spatial system is compatible with map-based interfaces, such as ESRI ArcGIS, and follows J2EE standards [1].

Maximo for Utilities supports operations across a number of areas:

Estimating compatible units (CUs)
Managing field crews
Tracking skills and certifications
Integrated fixed-asset accounting
Supporting field workforce management
Graphic design functionality
GIS integration
Using Gantt views for analyzing work orders

A CU library helps planners and designers estimate CUs when creating a project [2].

Asset and Resource Management (ARM) Field Manager: ARM Field Manager is a mobile platform that allows crews to access and report data for all work, including customer service information, emergency situation reports, procedure-based maintenance work, and CU-based construction work.

T. Saunders, J. Souto Maior, and V. Garmatz. “IBM Maximo for Utilities.” IBM, 2012. ftp://ftp.software.ibm.com/software/tivoli_support/misc/STE/2012_09_11_STE_Maximo_for_Utilities_Upgrade_Series_v4.pdf(accessed November 28, 2017).
Maximo Adapter. PowerPlan, Atlanta, GA: 2017.https://powerplan.com/resources/minimize-risk-and-optimize-maximos-implementation-with-powerplan(accessed November 28, 2017).

3.14.15 - SCL - Seattle City Light

Construction & Contracting

Project Management

People

Bi-weekly Crew Coordination Meeting

SCL convenes a bi-weekly crew coordination meeting focused on the project status of each active network project. Meeting participants include the supervision and others from the network design group (engineers), civil crew representatives, electrical crew representatives (including crew leaders), and customer service representatives who interface with customers (for example, load additions).

Process

The Crew Coordination meeting is effectively used to manage network construction projects. Representatives review the project status of both civil and electrical projects and identify actions necessary for the projects to proceed. A report is used that shows critical project milestones such as the vault acceptance date and feeder in date. See Attachment E , for a sample network jobs project summary. Note that a similar form is used to track the progress of civil construction projects.

The meeting is also used to establish action items to identify network conditions that must be addressed. One example would be the identification of vault locations where ventilation is inadequate for the summer heating season. The group will identify an action plan to make contact with building owners to address these deficiencies.

This forum has been a highly effective project management tool for SCL in updating project status, resolving problems, and meeting project goals.

3.14.16 - Survey Results

Survey Results

Construction & Contracting

Project Management

Survey Questions taken from 2015 survey results - Summary Overview

Question 12: Within your company, what percentage of the work for each task is contracted?

Survey Questions taken from 2012 survey results - construction

Question 5.3 : If using contractors, what % of your total network electrical work is contracted?

Question 5.9 : Do you have a process for inspecting or testing incoming network materials?

Question 5.10 : If yes, what material is inspected or tested?

Survey Questions taken from 2009 survey results - construction

Question 5.4 : If using contractors, what % of your total network electrical work is contracted? (this question is 5.3 in the 2012 survey)

Question 5.10 : Do you have a process for inspecting or testing incoming network materials? ( This question is 5.9 in the 2012 survey)

Question 5.13 : Do you utilize work management software to assist in assigning resources, scheduling, and managing the execution of network projects?

Question 5.14 : What work management system are you using?

3.15 - Separable Connector Installation

3.15.1 - Duke Energy Florida

Construction

Separable Connector Installation

Technology

Duke Energy Florida’s cable design calls for the use of T-bodies (600A separable connectors) for both straight splices and Y and H splices, so that cables can be easily separated for fault locating, maintenance and for future system enhancements. Note that the center plugs that were historically used in the T-bodies were designed with an exposed metal ring which was prone to deterioration / corrosion with age and with prolonged submersion in water. See Cable Replacement for more information on Duke Energy Florida’s formal primary cable replacement program, which includes replacement of older style T-bodies.

Network transformers are suppled using ESNA style (separable) connections.

3.15.2 - HECO - The Hawaiian Electric Company

Construction & Contracting

Separable Connector Installation

People

HECO Cable Splicers install separable connector installations, including 600 A “T” bodies and 200 A Elbows.

Process

HECO Cable Splicers demonstrated proper installation procedures of separable connectors systems, including careful, correct preparation and installation.

See Attachment I for a diagram that shows the proper cable jacket and insulation cut back dimensions as well as racking position for 1000A and 500A 15kV cables.

The photographs below depict HECO Cable Splicers preparing cable for and installing a 600 A T Body.

Figure 1: Measuring and Cutting the Cable Insulation

Figure 2: Cable Cutter

Figure 3: Shaping the edge

Figure 4: Shaping cutter

Figure 5: Preparation – Installing a T Body

Figure 6: Preparation – Installing a T Body

Figure 7: Preparation – Installing a T Body

Figure 8: Preparation – Installing a T Body

Figure 9: Preparation – Installing a T Body

Figure 10: Press

Figure 11: Preparation – Installing a T Body

Figure 12: Preparation – Installing a T Body

Figure 13: Preparation – Installing a T Body

Figure 14: Preparation – Installing a T Body

Figure 15: Preparation – Installing a T Body

Figure 16: Preparation – Installing a T Body

Figure 17: Preparation – Installing a T Body

Figure 18: Preparation – Installing a T Body

Figure 19: Preparation – Installing a T Body

Figure 20: Preparation – Installing a T Body

Figure 21: Preparation – Installing a T Body - Using Spanner Wrench

Figure 22: Preparation – Installing a T Body

Figure 23: Preparation – Installing a T Body

Figure 24: Preparation – Installing a T Body

Technology

Some of the tools used to install a “T” body are depicted in the photographs above.

3.15.3 - Survey Results

Survey Results

Construction & Contracting

Separable Connector Installation

Survey Questions taken from 2009 survey results - Operations

Question 7.17 : Do you use separable connectors (such as “T” Bodies and elbows) in your network system?

Question 7.18 : Have you experienced failures with these connectors / connector systems (such as 600A T - bodies)?

Question 7.19 : If Yes, please rank the primary causes of the failures you’ve experienced.

3.16 - Splicing

3.16.1 - AEP - Ohio

Construction & Contracting

Splicing

People

Electrical work on the AEP Ohio network, including cable splicing, is performed by unionized Network Mechanics who report to Network Crew Supervisors and work out of a Service Center. Project work orders, repairs, and maintenance are scheduled and dispatched from this center.

The AEP Ohio Network Mechanic is a “jack of all trades” position, performing all electrical construction and maintenance in the network including cable splicing. Network Mechanics are members of the union, and are categorized as D, C, B, or A-level grades, with Network Mechanic “A” being the highest rank.

Process

AEP Ohio has had generally good performance with the performance of its splices. The company presently uses both cold shrink and heat shrink splice kits, but are moving to the use of cold shrink kits. They have found that hand-taped splices that were made from the 1960s and 1970s are beginning to fail, and that when they do, the failures are sometimes catastrophic.

AEP Ohio uses lead cables, but is transitioning to EPR insulated cable in the network (see Figures 1 and 2). Thus, Network Mechanics rarely prepare lead-lead joints. Most work with lead is in preparing transition joints, from lead to EPR.

Figure 1: Lead cable joints

Figure 2: Cable Joints - EPR, using 600-A ESNA T-bodies. Note the inserts for spiking cable

Technology

Smallworld is used to record information about cable installations. The location of cable joints is not recorded.

AEP Ohio does infrared (IR) inspection of cable joints. When the company initiated the program, personnel identified problem areas (hot spots) and addressed the critical locations. This inspection identified areas where splices were prepared improperly. AEP experts report that it took about four years for them to identify and remedy the problems, and that now they rarely identify failing joint locations (detect arcing) using IR.

3.16.2 - Ameren Missouri

Construction & Contracting

Splicing

People

Organizationally, Ameren Missouri Cable Splicers who work in the St. Louis network reside within the Underground Construction department. The Underground Construction department, led by a Construction Superintendent, is part of the Underground Division. The Underground Construction Group is responsible for all of the conventional (manhole and conduit system) underground in the Division, and all work with larger cable (500 Kcmil and above).

The Underground Construction department consists of Cable Splicers, Construction Mechanics, and System Utility Workers. Cable Splicers and Construction Mechanics are journeymen positions. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Construction Mechanics perform the civil aspects of the work. System Utility Workers serve as helpers to the other two positions, and perform duties such as cable pulling and manhole cleaning.

Note that at the time of the practices immersion, Ameren Missouri was implementing a new position, called the System Journeyman, which combines the duties of Cable Splicers and Construction Mechanics.

Cable Splicer and System Journeyman apprentices receive formal training in preparing joints at the Dorsett Training center as part of the apprentice program. This is supplemented by on-the-job exposure to working with both lead and solid dielectric cables and joints.

This formal training program associated with underground construction worker progression is relatively recent. In the past, there was no formal journeyman program for underground, with all training associated with underground performed in-house, within the department. More recently, Ameren Missouri has implemented a formal program for Cable Splicers and for System Journeymen (a new position at Ameren Missouri than combines the duties of the Cable Splicer and Construction Mechanic, and thus has splicing responsibility), with the training, testing and proficiency demonstration conducted at the Dorsett training facility. The program is a 30 month program, and includes things such as electrical principles and theory, as well as instruction on splice preparation.

Process

Ameren Missouri Cable Splicers prepare lead joints, solid dielectric (EPR - EPR) joints, and transition joints.

Ameren Missouri management actively works with Cable Splicers to reinforce splicing skills. Construction Supervisors will provide work assignments that provide the required on – the - job training to keep skills sharp. They will periodically reinforce proper techniques by showing training videos for proper splice preparation on inclement weather days.

Standards engineers also contribute to the skills reinforcement. One example of this was a decision to require a small stainless steel wire brush to be included in the splice kit provided by the manufacturer. This assures that the brush is available to the Cable Splicer to wire brush an aluminum connection to assure the splice is sound.

Technology

Ameren Missouri uses heat shrink joints. At the time of the practices immersion, they were considering the use of cold shrink joints in certain applications, such as a trifurcating splice. They are considering the cold shrink technology because of experience with failed heat shrink splices due to improper heating and shrinking of the sleeve.

Figure 1: Preparing a Heat Shrink Joint

Figure 2: Preparing a Heat Shrink Joint

Ameren Missouri is also considering moving from compression to shear bolted connections. This potential change is being driven by experience with failed splices because of installation issues associated with compression connections such as using the wrong dies, wrong materials, or inadvertent cutting of cable strands. The bolted connector has a range connection, and thus addresses some of these issues. The cable splicer can rotate the shear bolt connection so the bolts are facing the worker, solving one of the challenges of the compression connection - getting the large crimping tool oriented correctly. The connectors will have solid stops, and can thus be used in a transition joint.

3.16.3 - CEI - The Illuminating Company

Construction & Contracting

Splicing

People

CEI Underground Electricians perform work on lead cables, and prepare transition splices.

Process

CEI has made a decision not to expand the lead cable system. Normally, they no longer will prepare a lead splice (wipe a splice). If they need to make a repair to a failed section of lead cable, they will cut out the damaged section and put in two transition splices with a section of extrudable cable (EPR) to replace the damage section.

Very rarely, in situations where they don’t have room to make the transition, they will prepare a lead splice.

Technology

CEI tracks the location of transition splices on their feeder prints. They are not tracking who prepared the splice.

3.16.4 - CenterPoint Energy

Construction & Contracting

Splicing

People

Cable splicing at CenterPoint is performed by the Cable Splicers who work in the Cable Groups of the Major Underground department. Major Underground has two Cable groups: the “Cable A” group, focused in downtown Houston, and the “Cable B” group, focused in South Houston, Spring Branch and Greenspoint.

Process

CenterPoint uses hand taped splices. This is true of both splices between two sections of like cable, and transition splices between cable sections of different types. They have experimented with modular splicing designs such as the splicing systems offered by Raychem and 3M, but have found that that the installation workmanship had to be almost perfect for these types of splices to be reliable. Further, CenterPoint has done laboratory testing that shows that their hand taped approach to splicing is more reliable.

(See Failure Analysis (Splice) )

CenterPoint’s experience with hand taped splices is that they are very reliable. CenterPoint management reports that they have experienced very few splice failures. When they experience a splice failure, they perform an analysis on each failed splice. If they experience a splice failure in the first two years of its life, the cause is usually due to a workmanship issue.

One of their challenges is that it is becoming difficult to find vendors who can supply the molten metal used to make the splices.

See the video below

for videos of the CenterPoint Hand Taped Splice procedure.

Below are various photographs of the splicing procedure.

Figure 1: Preparing the splice

Figure 2: Preparing the splice

Figure 3: Preparing the splice

Figure 4: Preparing the splice

Figure 5: Melting the lead

Figure 6: Melting the lead

Figure 7: Lowering the molten lead"

Figure 8: Pouring the lead

Figure 9: Preparing the splice

Figure 10: Preparing the splice

Figure 11: Preparing the splice

Figure 12: Preparing the splice

Figure 13: Heating the Epoxy filler

Figure 14: Loading the Epoxy filler

Figure 15: Lowering the Epoxy filler

Figure 16: Injecting the epoxy filler

CenterPoint does not test PILC cable for moisture content before splicing,

Technology

CenterPoint is entering facilities information into a GIS system (ARC Map); however, this system is not yet being used to produce underground maps because of the congestion on GIS produced maps.

CenterPoint has the ability to track the location of splices in their GIS system.

3.16.5 - Con Edison - Consolidated Edison

Construction & Contracting

Splicing

People

Con Edison distinguishes between Cable Splicers who perform splicing, and Installation and Apparatus (I & A) Mechanics who install and maintain network equipment, perform secondary splicing, and make customer connections. Con Edison further delineates tasks through its organization, with separate groups performing splicing tasks, I&A tasks, cable pulling, fault locating, and field inspections.

The Underground Group is comprised of Cable Splicers, who splice cable of all voltages.

The Installation and Apparatus (I & A) Group installs and maintains network equipment, including transformers and network protectors. Within I&A, in Manhattan, there is a services group dedicated to connecting customers to the distribution network. In other locations, the services group may sit in a different part of the organization. This group does the splicing on the secondary system and deals with customer connection issues.

Process

Con Edison has a process in place to promote the ongoing quality of splices by assigning personal accountability for the performance of the splice to the individual Splicer who prepared it.

In the past, when working with lead splices, Splicers permanently stamped (imprinted) their initials directly into the lead of the splice as a way of tracking who prepared the splice. Newer splices are bar coded with information about the splice including the name of the Splicer. The bar code is produced from a splice ticket that contains information about the splice, including the name of the Splicer.

Splicers are responsible for the performance of their splice for five years after the installation. Con Edison selected five years, because the utility has found splice defects due to workmanship issues usually occur within the first five years after a splice installation.

If problems are encountered with a particular Splicer’s workmanship, depending on the circumstances, Con Edison may elect to send the Splicer back to splicer school, or administer formal discipline steps (warning, letter in the file, etc.).

Technology

Con Edison provides its employees with the specialized tools and equipment that they need to do their jobs, including trucks outfitted for the different types of work that they perform. Employees stated that they believed Con Edison provides them with good quality trucks, appointed with the equipment they need to perform their work. People demonstrated a sense of pride in their trucks and associated equipment.

Splicers use a specially outfitted van, rather than the box truck used by , because they have less equipment and fewer tools than I&A Mechanics.

3.16.6 - Duke Energy Florida

Construction

Splicing

People

Organizationally, the Duke Energy Florida resources that construct and maintain the urban underground and network infrastructure fall within the Network Group which is part of the Construction and Maintenance Organization. More broadly, Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager. The region consists of various Operation Centers, organized either geographically or functionally throughout the Region.

The Network Group is organized functionally, and has responsibility for construction, maintain and operating all urban underground infrastructure (ducted manhole systems), both network and non-network, in both Clearwater and St. Petersburg. The Network Group is led by a supervisor who reports to the Region General Manager. The group consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position), all part of the Network Specialist job family.

The Network Specialist is a jack-of-all-trades, position, responsible for all facets of UG work, including preparation of splices. Both Network Specialists and Electrician Apprentices can prepare splices, though Electrician Apprentices are limited to preparing only cold shrink joints.

Process

Duke Energy Florida has historically used push on and crimp splices, but are looking to transition to a different splice technology due to the frequency of workmanship issues that have arisen with this type of splice connection. They have been evaluating cold shrink splice kits and shear bolt connections (see Figures 1 and 2). Cold shrink splice kits provide better alignment of conductors between joined cables when compared with push on splices. Shear bolt connections have the advantage of removing workmanship problems as the bolts will snap off at the correct tension, so there is never too little or too much compression on the cable in the splice. Heat shrink joints are also used within Duke Energy Florida, but only for submarine cables.

Figure 1: Shear Bolt Connector

Figure 2: Heat shrink joint with shear bolt connection (submersible application)

3.16.7 - Duke Energy Ohio

Construction & Contracting

Splicing

People

Cable splicing at Duke Energy Ohio is performed by Cable Splicers within the Dana Avenue underground group.

Duke has had good performance from their splices. They attribute this to the training and continuing education they provide to Cable Splicers. Each of their Cable Splicers was certified through Tyco (Raychem), their primary splice provider. Each Cable Splicer receives periodic retraining.

Process

Duke Energy Ohio uses mostly heat shrink splices. They have opted for heat shrink versus cold shrink splices because of the smaller size of the heat shrink splice, and the limited shelf life of cold shrink splices. About 60-70% of the connectors they use in their splices are shear bolt connectors.

According to Duke, the heat shrink splices have performed very well for them. Also, transition splices have performed well.

Duke Energy Ohio will perform a forensic analysis on selected joint failures. This analysis is normally performed by an independent laboratory.

Technology

Duke Energy Ohio uses heat shrink splices, mostly Tyco products.

Figure 1: 15kv Splice

3.16.8 - Energex

Construction & Contracting

Splicing

People

The Journeyman position for working with cable systems at Energex, including cable splicing and cable pulling is the cable jointer position. Employees move through the jointer apprenticeship program in about three and one half years. The apprenticeship includes formal training, testing, on the job training, and time in grade. At the conclusion of the apprenticeship, persons in the program must still must complete a “basket of skills” required by the electrical office. These skills are over and above the skills that are taught as part of the apprenticeship, but necessary for the employee to be a fully qualified jointer. Employees complete this basket of skills in the first 18 months after apprenticeship. Consequently, it takes 5-6 years in total before an employee is a fully qualified to run a job.

All jointers within the underground group are trained for CBD cable joining, operating in confined spaces, safe work practices in pits, and both high-voltage and low-voltage cabling. Jointers are trained in both Australian Qualifications Framework (AQF) and network-specific tasks before working on CBD underground splicing.

( See the Training section in this report. )

Process

Jointers work with cable and cable accessory installation and maintenance, including cable pulling, splice preparation, and cable replacement.

Technology

Energex utilizes a shear bolt connection, rather than a compression type connection for splicing, when preparing an 11 kV cable joint. They implemented the use of shear bolt technology for improved reliability.

3.16.9 - ESB Networks

Construction & Contracting

Splicing

People

Cable splicing at ESB Networks is performed by Network Technicians, the journey worker position. The Network Technician is a multi-faceted position, performing both line work, such as building pole lines, and electrical work, such as making connections at a transformer. Network Technicians work on all voltages from LV through transmission voltages (110kV). Note that ESB Networks created the Network Technician position in the 1990s by combining a former Line Worker position and Electrician position.

Work specialization for Network Technicians is by assignment. In Dublin, where the majority of the distribution infrastructure is underground, Network Technicians work mainly as cable jointers, installing underground cables and accessories. ESB Networks rotates Network Technician work assignments as business needs require.

ESB Networks has a four-year apprentice training program for attaining the journeyman Network Technician position.

Network Technicians who worked as cable jointers work closely with both the Training group and the Asset Management groups at ESB Networks. Network Technicians readily bring information about problems with particular cable joints back to these groups.

The Training and Asset Management groups share the process of performing forensic analysis of failed joints and in preparing the failed component summary reports. Within both groups, ESB Networks has significant cable/cable accessory expertise. Both groups work closely with Network Technicians to ensure that they understand the science of cable joints and have an appreciation for the importance to long-term joint reliability of performing the proper steps associated with cable joint preparation.

Process

ESB Networks’ Network Technicians prepare lead joints, pre-molded solid dielectric (XLPE) joints, and transition joints. For most applications, they have standardized on cold shrink joint technology.

ESB Networks has performed significant testing of splices/joints, including variability tests and partial discharge tests. ESB Networks uses this information to reinforce the splicing training provided to Network Technicians.

ESB Networks has established a strong working relationship with cable joint manufacturers, and noted that the company has worked with cable manufacturers to include ESB Networks specific instructions as part of the cable splice kits they provide.

Technology

ESB Networks uses XLPE insulated round aluminum conductor cable with a durable jacket as a standard at MVs (10 kV in Dublin, 20 kV in outlying areas). For LV cable, ESB Networks utilizes sector-shaped solid aluminum cable. ESB Networks has standardized on cold shrink splice technology (both Raychem and 3M). ESB Networks had historically used heat shrink technology, but had experienced some performance issues in coastal areas, where salt contamination could affect improperly heat-shrinked terminations. The company had good experience with the integrity of cold shrink terminations in these coastal areas, and decided to standardize on cold shrink technology throughout their service territory (see Figure 1 and Figure 2).

Figure 1: Cold shrink joint (tube and connector)

Figure 2: Shear bolt connector

ESB Networks has worked closely with cable joint manufacturers to develop a splicing approach that minimizes opportunities for human error. Working with manufacturers, ESB Networks has developed a short splice design that does not require the use of mastic. The company has developed a custom splice kits with preparation instructions, including a custom “cut back” template included with each kit (see Figure 3). ESB Networks representatives indicated that it takes about 40 minutes to prepare a cold shrink joint (see Figure 4).

Figure 3: ESB Networks cutback template

Figure 4: Preparing a cable joint

3.16.10 - Georgia Power

Construction & Contracting

Splicing

People

Cable splicing is performed by the Cable Splicer craft at Georgia Power. The Cable Splicing crews report directly to Distribution Supervisors within the Network Construction group, part of Network Underground. The Network Construction group, led by a manager, performs network construction activity, and is comprised of Cable Splicers, Duct Line Mechanics and Test Technicians. There is also a crew in Savannah which reports to the Operation & Reliability Manager. That crew coordinates with the Construction group.

Cable Splicers receive formal training in preparing joints at the Georgia Power Atlanta training center as part of their progression to the journeyman position. Training consists of formal classroom training, including hands-on cable splicing, led by Senior Cable Splicers. “Practice” splices are examined and critiqued by two supervisors (See Figure 1 through Figure 4.). Formal classroom training consists of three weeks of training for every six-month training step. (See Job Progression in this report.) In performing on-the-job training (OJT), field work is supervised by Senior Cable Splicers and project supervisors (See Figure 5 through Figure 12.).

Figure 1: Training facility - Lead Splice preparation area

Figure 2: Training Facility – sample joints

Figure 3: Training facility – cable termination practice area

Figure 4: Training facility – tool bench

Figure 5: Lead joint preparation – jobsite

Figure 6: Lead joint preparation – jobsite

Figure 7: Lead joint preparation – jobsite

Figure 8: Lead joint preparation – jobsite

Figure 9: Lead joint preparation – jobsite

Figure 10: Lead joint preparation – jobsite

Figure 11: Lead joint preparation – job site, note splicing truck

Figure 12: Typical “bread truck” used by cable splicing crew

Process

The Georgia Power Network Underground Cable Splicers prepare lead joints, solid dielectric (EPR - EPR) joints, and transition joints. Cable Splicers routinely work with lead cables and accessories, and thus maintain their expertise.

Georgia Power is maintaining its lead cable infrastructure wherever possible. The engineers find it reliable, cost-effective and easier to work with in confined manholes and vaults where there is limited space for the larger accessories, such as Y-splices, required for EPR cables (See Figure 13.). For example, an EPR Y-splice at 20kV takes up virtually all the wall space in most manhole locations, limiting future expansion flexibility. Lead splices are currently more compact than EPR and fit more easily into the existing underground infrastructure’s manholes and conduits.

The Network Underground group is concerned that there is only one source for its lead cable, and it may become more aggressive in the future in replacing lead, particularly as smaller form-factor EPR becomes available.

GPC joint preparation

GPC Join Preparation

Technology

In places where EPR or XLPE cable is used, Georgia Power has used heat-shrink splices and terminations for several years, but now prefers to use cold-shrink joints (the current standard). In the past the group has had some performance problems with heat shrink joints, finding failed joints due to improper heating and shrinking of the sleeve. Georgia Power is using both compression and shear bolt connections in preparing splices (See Figure 13 and Figure 14.).

Figure 13: Mechanical connection for a Y splice – shear bolts connector

Figure 14: Shear bolt connector – bolts designed to “shear” when desired torque is achieved

3.16.11 - HECO - The Hawaiian Electric Company

Construction & Contracting

Splicing

People

HECO Cable Splicers perform work on lead cables, and prepare transition splices.

Process

HECO has made a decision not to expand the lead cable system. If they need to make a repair to a failed section of lead cable, they will cut out the damaged section and put in two transition splices with a section of extrudable cable (XLPE) to replace the damage section.

Very rarely, in situations where they don’t have room to make the transition, they will prepare a lead splice.

Technology

HECO is using a hot shrink transition splice.

HECO does not track the location of transition splices on their maps. They are not tracking who prepared the splice.

3.16.12 - National Grid

Construction & Contracting

Splicing

People

Cable splicing in the Albany network at National Grid is performed by Cable Splicers within Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. Cable Splicers are part of the Electrical Group. The Underground lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. They are trained to work with both lead and poly splices.

Cable Splicer apprentices (Cable Splicer A) receive formal training and on the job training in preparing joints and terminations as part of the formal job progression.

Process

National Grid no longer installs new lead cable, but has lead cables in service, both primary and secondary. Consequently, Cable Splicers must work with lead, and with transition joints.

Figure 1: Lead joint

Figure 2: Lead joint

Standard splices for EPR to EPR primary cables are cold shrink. Standard transition splices of EPR to PILC are heat shrink. In certain applications, hand applied splices may be used.

Blood tests for employees to ascertain lead levels are not mandatory, but available to Cable Splicers.

3.16.13 - PG&E

Construction & Contracting

Splicing

People

Cable splicing at PG&E is performed by Cable Splicers within both the M&C Electric Network group, and the General Construction group.

Much of the work within the M&C Electric Network group involves working with network equipment, such as performing network protector maintenance and transformer oil testing. In San Francisco, much of the cable work, including preparation of splices is shared between the cable splicers within M&C Electric Networks, and the General Construction group. In Oakland, there are particular Cable Splicers who focus on cable work, and others who are normally assigned to working with network equipment.

PG&E Cable Splicers prepare lead joints within the 12 kV network part of their system (PILC cable). Note that outside of the cities, most Cable Splicers have limited experience with preparation of lead splices other than building transition joints. Consequently Cable Splicers from San Francisco and Oakland are periodically sent to other areas to prepare lead splices.

The cable engineer within the Electric Distribution Standards and Strategy group is responsible for establishing standards for splicing.

Cable Splicer apprentices receive formal training at the PG&E Training center in preparing lead joints as part of the apprentice program. This is supplemented by on-the-job exposure to working with lead cables and joints. One distribution supervisor noted that he supplements the formal training with additional lead training within the office. One week before his apprentices go to the formal training, he brings them into the office and gives them practice and training that will facilitate their learning in the weeklong formal session.

Process

PG&E Cable Splicers use lead splices within the 12 kV network system (PILC cable). PG&E resources noted that lead joints have been very reliable.

PG&E historically used heat shrink transition joints to transition from lead to non - lead cable. They have recently (within the past year) moved to using cold shrink transition joints as a standard.

Figure 1: Lead joint

Figure 2: Preparing a lead joint

3.16.14 - Portland General Electric

Construction & Contracting

Splicing

People

Cable splicing is the responsibility of the Underground Group, also known as the CORE group.

Organizationally, this group is part of the Portland Service Center (PSC) and is responsible for the underground CORE, which includes both radial underground and network underground infrastructure in downtown Portland. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

The journeyman position in the CORE group is the cable splicer. A typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault, while the helper usually stays above ground, carrying material and watching the barricades and street for potential hazards.

The cable splicer position is a “jack-of-all-trades” position, whose responsibility includes cable pulling, splicing, equipment maintenance, and inspection.

To become a cable splicer in CORE, an employee must spend one year in the CORE area as an assistant cable splicer, in which the employee’s job assignments familiarize the employee with the CORE underground system. For example, this year cable splicer assistants will be expected to prepare a straight splice and trifurcated splice. Often provided by a vendor, more formal training also supplements on-the-job training. For example, Raychem has conducted hands-on training in preparing a transition joint.

Network engineering develops and maintains the standards for the network, including standards for splicing, which are forwarded to the Standards Department for inclusion in company standards manuals.

Process

PGE has transitioned from heat shrink to cold shrink splices. Crews occasionally will use heat shrink technology on the secondary system, but primary systems all use cold shrink. This change was made to assure more consistency in the splice preparation, as PGE had experienced some historic failures with the heat shrink splices. For trifurcating splices, crews still use a heat-shrink component.

Figure 1: Secondary moles

The cable splicers are meticulous in splicing, with one person preparing the cable joint while another reads out loud the directions provided with the splice kit.

Figure 2: Cable Joints

PGE no longer prepares lead splices, other than a lead-EPR transition joint.

PGE has experienced some historic failures in T-body connections. The company attributes these failures to incorrect torqueing of the splice inserts. PGE has built a library of failure modes for T-Bodies and uses this for analysis.

PGE uses compression connections for its splices, as these have been effective. It is trialing the use of bolted connections at one major customer and is monitoring the effectiveness of this type of connection. For this particular customer, PGE is also capturing photographs of all of the splices at the customer’s request.

Technology

Burndy Mole Connectors: PGE uses Burndy MOLEs, which are engineered connectors that provide for multiple connections at a single junction point. These connectors offer a safer and easier installation than traditional soldered or taped connectors, taking up less room in crowded manholes. The Burndy Mole is an engineered connector that is essentially a bus bar with several cable outlets with mechanical installation. The connectors include cable limiters.

Transformer Connectors: The connections of the feeders to the transformers are straight connections rather than elbows, because PGE prefers not to place an extra bend in the cable.

3.16.15 - SCL - Seattle City Light

Construction & Contracting

Splicing

People

At Seattle City Light, all network electrical workers are part of the Cable Splicer family; that is, the journeyworker Cable Splicer performs all of the tasks associated with building, maintaining, and operating a network system including cable pulling, splicing, construction, equipment inspection, and maintenance.

Organization

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable Splicers perform all electrical aspects of network construction, operations, and maintenance. All electrical employees who work in the network are either Crew Chiefs, journeyman Cable Splicers, or apprentices in the mode of progression, working their way towards the journeyman level.

Mode of Progression

SCL uses a three-year automatic mode of progression. This mode includes 8000 hours of On the Job Training (OJT) and testing. They have experienced a very low dropout rate from the program. This is in part because they administer a highly selective front end test and interview process to accept apprentices into the program. Also, a Cable Splicer position at SCL is a highly sought-after position.

Training

In addition to the training associated with the mode of progression, SCL provides network crews with opportunities for training including mandatory safety training for processes such as manhole entry and manhole rescue. SCL also periodically sends personnel to conferences and specialized training sessions such as the Cutler Hammer School, etc.

Crew Makeup

A network crew is normally made up of one Crew Chief, one or two Cable Splicers, and one apprentice. The type of work to be done and SCL work rules will dictate the appropriate crew makeup. For example, performing switching in a vault requires at least two journeyman-level employees to be in the vault. These and other work rules and safety practices are spelled out in the Washington State Safety Standards for Electrical Workers, Chapter 296-45 WAC.

Technology

SCL uses various types of splices including lead splices, heat-shrink splices, and cold-shrink splices. The majority of splices they use (80%) are heat-shrink, hand-taped splices. Less than 8% of their splices are lead.

SCL prefers the heat-shrink splice to the cold-shrink splice, because they have had a low failure rate with heat-shrink splices. However, most of the splice failures they do experience are with poly splices. They have had very little failure of their lead splices.

SCL is currently developing a process for following up on poly splice failures with a laboratory analysis.

3.16.16 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter 15: Cable Accessories

3.16.17 - Survey Results

Survey Results

Construction

Splicing

Survey Questions taken from 2012 survey results - Construction

Question 5.6 : How many hours of training (on average, per person) does your field force receive in a year?

Question 5.13 : When you prepare a splice, do you track and record who prepared the splice?

Survey Questions taken from 2009 survey results - Construction

Question 5.7 : How many hours of training (on average, per person) does your field force receive in a year?

3.17 - Three Phase Pad Mounted Transformer Installation

3.17.1 - CenterPoint Energy

Construction & Contracting

Three Phase Pad Mounted Transformer Installation

People

Three phase padmounted equipment is installed by the Major Underground field force, typically Cable Splicers or Heavy Equipment Operators. CenterPoint has historically assigned this work to particular individuals who have become expert users of the equipment used to set transformers.

Process

CenterPoint demonstrated the ability to safely and efficiently install new padmounted transformers with one qualified resource using a material handling truck with a remote control console worn by the operator.

Figure 1: CenterPoint Operator with Remote Control Console worn around his neck

Figure 2: Material Handling Truck

The Operator was able to attach the lifting sling to the transformer without having to climb onto the truck bed by using a hand fashioned hook stick made from a copper ground rod.

Figure 3: CenterPoint Operator with hand fashioned hook stick

Figure 4: Material Handling Truck lifting transformer

The Operator was deft in positioning the transformer over the pad and placing it in the right position.

Figure 5: CenterPoint Operator moving unit to pad

Figure 5: CenterPoint Operator positioning unit on pad

Technology

CenterPoint utilizes a heavy duty underground material handling truck with a remotely operated lifting device, as shown in the pictures above.

3.18 - Training Facility

3.18.1 - Portland General Electric

Construction & Contracting

Training Facility

People

PGE’s general training philosophy for workers in the CORE is to be at least two deep in terms of expertise at all positions.

Process

PGE holds training within an area located in the store room. The company may develop training on its own or oftentimes bring in a manufacturer to deliver training on a particular product or tool. Personnel often split into groups and allocate to various “stations” for training. The Portland Service Center (PSC) hasa network protector training area with both a CMD and a CM52, which are both dead-front units. All installed protectors on the network are one of these two styles. This location also receives new devices for a quality assurance (QA) check and testing.

Figure 1: Network protector cabinets used for training

Figure 2: Store room area used for training and NP testing

Figure 3: Store room area used for cable joint training

Compliance training includes vault rescue, pole top rescue, and all other federally mandated training. The vault rescue class is a company-wide training undertaken annually, and workers train in a shallow vault that does not always resemble the deeper network vaults. Accordingly, PSC may augment this training with more specific vault rescue training geared to the network vaults, which would take place in a live vault since the company does not have a test vault. PGE also provides annual computer-based training on “Confined Space” practices.

The CORE journeymen, who work almost exclusively with urban underground systems day to day, are required to support restoration work on the overhead system when needed. In restoration, they generally work in two-man crews addressing wire-down situations. In order to reinforce these skills, the CORE group conducts annual training on overhead systems in a de-energized training yard, where they review various overhead line-work scenarios.

3.19 - Resource Management

3.19.1 - Portland General Electric

People

Obtaining resources for construction on the CORE system involves a number of departments.

Planning and designing internal and external projects involve Service & Design Project Managers (SDPMs) and the Project Management Office (PMO). However, they do not deal directly with equipment and material vendors, which is the responsibility of the Materials Coordinator.

Scheduling crews and matching them to the available work is the responsibility of the Planning and Scheduling Department.

Process

Inventory and Logistics: PGE has a system to ensure that crews receive inventory/assets on time and according to the right specifications and standards, as determined by network engineering and network planning. They take into account the long lead times for the equipment that many of the jobs require. For example, a 1500 kVA transformer may take nine months from order to delivery.

Scheduling: About three years ago, PGE moved from an all-paper system to a work management system using Maximo. All the work provided to the crews is scheduled in Maximo and sent to the field through electronic field devices. Early in the adoption of this system, PGE experienced a learning curve. Some work orders became lost, and workers struggling to utilize the new system. An intensive information technology (IT) training program targeted to field workers rectified these challenges.

Until about two years ago, the CORE area was “siloed” in that the CORE group management made scheduling decisions without involving other organizations. CORE work now passes through the Planning and Scheduling Department, which looks at resourcing and scheduling across the company.

Developing Work Packages

PGE uses ArcFM as its current design product to create a materials list and a “package,” which is forwarded to various project stakeholders, including the field crews, customer, inspector, and contractor. The package contains multiple documents including the following:

Generic information
Electrical layout information for crews
Conduit plan for the contractor and city
Vault details for crews, including the vault “butterfly” view

Most of the materials used for network construction already have estimated man-hours details included in the design system, so that when a designer selects an asset, the system will calculate the man hours/labor needed for installation. However, those numbers may not always reflect actual field requirements and are adjusted accordingly. The information is available in Maximo and allows a comparison of estimated and actual labor costs.

Technology

Geographic Information System (GIS) – ESRI ArcGIS/Schneider ArcFM

PGE uses ArcFM GIS software for designing network layouts and creating a package with work details for relevant personnel. For construction, the system creates a list of materials that can be shared with the relevant people.

ArcFM uses open-source and COM architecture to support scalability, user configurability, and a geographical database. ArcFM includes tools that allow network editing, GIS asset management, design integration, and work management.

Maximo for Utilities 7.5

For work scheduling, PGE uses the Maximo for Utilities 7.5 system, which covers most asset classes and work types. The system allows users to create work estimates and manage field crews. Maximo can integrate with a number of systems, including fixed-asset accounting, mobile workforce management solutions, and graphical design systems. The Maximo Spatial system is compatible with map-based interfaces, such as ESRI ArcGIS, and follows J2EE standards [1].

T. Saunders, J. Souto Maior, and V. Garmatz. “IBM Maximo for Utilities.” IBM, 2012. ftp://ftp.software.ibm.com/software/tivoli_support/misc/STE/2012_09_11_STE_Maximo_for_Utilities_Upgrade_Series_v4.pdf(accessed November 28, 2017).

3.20 - Vault Grounding

3.20.1 - AEP - Ohio

Construction & Contracting

Vault Grounding

People

During the design phase, AEP Network Engineers lay-out the design of network vaults and manholes using one-line drawings that indicate the position and dimensions of all internal components, such as duct lines, cable position and racking, transformers and network protectors, secondary bus, and grounding. These drawings are then converted to electronic architectural drawings by a Technician using MicroStation and AutoCAD. AEP works closely with its Civil Engineering contractor to prepare associated civil designs.

Process

New manholes and vaults are designed with two ground rods at opposite corners and a ground ring, typically 4/0 cu. AEP is not tying the grounding with the manhole or vault rebar.

Technology

Wherever possible, AEP Ohio uses pre-cast manholes and vault designs. These designs include ground rod sleeves, as each new manhole and vault is designed to be grounded with two driven ground rods at opposite corners the vault, with a ground ring (usually 4/0 cu) around the vault/manhole. The grounding is not tied to the vault / manhole rebar. Note that this design differs from an historic design which had the ground bus mounted to the vault ceiling. AEP moved away from this design as deteriorating vault ceilings in older vaults could compromise the grounding system integrity. In spot network vaults on customer premises, the vault grounding is usually tied to the customer’s steel building frames (see Figures 1 and 2).

Figure 1: Manhole grounding (older design) with ceiling-mounted grounding, Note ground pad

Figure 2: Manhole grounding (newer design) with floor-mounted ring bus

3.20.2 - Ameren Missouri

Construction & Contracting

Vault Grounding

( Indoor Substation Grounding)

People

Design of network vaults and non network “indoor rooms” is the responsibility of the Engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The Underground Division is led by a manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by a supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including grid network vault designs and indoor room designs, including grounding. All of the engineering positions are four year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

Process

For indoor substations, the customer is responsible for providing the vault, including space in the room for the required equipment. These specifications, provided by Ameren Missouri, include 3-hr fire-rated doors and space for ventilation, lighting, pulling eyes, an oil retention tank, and a ground grid.

An engineer from the Engineering group performs a soil analysis to understand the resistivity of the soil before using a modeling program to design the ground grid. Once this is built, relay testers will ensure that the system provides sufficient grounding in the same way that they test standard substations. Once this is installed and approved through testing, the customer can complete the room.

Although Ameren Missouri does not stipulate that customers must tie their building ground into Ameren Missouri’s ground system, most do, because they will benefit from Ameren Missouri’s superior ground grid.

Technology

Ameren Missouri uses modeling software for grounding call WinIGS (Integrated Grounding System analysis and design), developed by Dr. A. P. Sakis Meliopoulos, Georgia Tech.

3.20.3 - CEI - The Illuminating Company

Construction & Contracting

Vault Grounding

Process

At CEI, in a vault in a customer’s building, the transformer ground is tied in with a ground around the vault and is tied in with the building ground.

3.20.4 - CenterPoint Energy

Construction & Contracting

Vault Grounding

Process

For spot network vaults, CenterPoint separates its vault ground from the building ground. They require that customers drive two ground rods for each vault.

Technology

CenterPoint is using a molten (lead wipe) connection for grounding equipment to the ground ring in a vault. They are currently investigating other methods of making these connections.

Figure 1: Molten Ground Connection

Figure 2: Molten Ground Connection

3.20.5 - Duke Energy Florida

Construction

Vault Grounding

Process

Every Duke Energy Florida manhole and vault has a driven ground.

Each manhole has a ground ring around the roofline which is tied to the driven ground.

In vaults, all network equipment is tied to ground. At spot network locations within building vaults, the network system ground is separate from the building ground.

3.20.6 - Duke Energy Ohio

Construction & Contracting

Vault Grounding

Process

For spot network vaults, Duke Energy Ohio interconnects its vault ground with the building grounding^[1] .

Technology

Duke Energy Ohio is using flat stock for the ground ring in their vaults, with bolted connections.

Figure 1: Vault ground ring – Copper flat stock

Figure 2: Transformer ground – bolted connection to ground ring

^[1] Duke cited an instance where their fire control system “saw" a bad three-phase elevator motor in a building, and opened all the breakers.

3.20.7 - National Grid

Construction & Contracting

Vault Grounding

Process

National Grid ties all of its vault equipment to ground, including the switch handle on the transformer primary ground switch and network protector operating handle.. National Grid standards call for the vault ground to be kept separate from the building ground. For customer services, National Grid runs full sized insulated neutrals into the customer building connecting to the neutral bus. It is the customer’s responsibility to ground the neutral bus on their end.

Spot network vaults are equipped with a ground fault protection system designed to trip (open) all of the network protectors in the vault in the event of a ground fault. The customer is required to buy, install, and wire the National Grid approved ground fault protection system. Ground fault protection system equipment is installed in the customer’s electric room. A current transformer required to monitor neutral currents is installed in National Grid’s transformer vault.

Technology

National Grid is using a copper ground ring in their vaults.

Figure 1: Primary switch handle grounded

Figure 2: Connection to ground ring

Figure 3: Transformer grounding

Figure 4: Vault grounding

3.20.8 - PG&E

Construction & Contracting

Vault Grounding

Process

For spot network vaults, PG&E separates its vault ground from the building grounding,

Technology

PG&E uses a copper ground ring in their vaults.

3.20.9 - Portland General Electric

Construction & Contracting

Vault Grounding

See Manhole and Vault Design

3.20.10 - SCL - Seattle City Light

Construction & Contracting

Vault Grounding

Process

SCL’s grounding practice in building vaults is to tie the system ground in with the building steel / grounding system.

SCL runs a separate low-voltage secondary neutral (in addition to the tape shield) through each vault tied in with the substation ground. This neutral is necessary for two reasons: to maintain ground connectivity to maintain the same potential from one vault to another, and to carry the neutral currents experienced with system imbalances.

3.20.11 - Survey Results

Survey Results

Construction & Contracting

Vault Grounding

Survey Questions taken from 2015 survey results - Design

Question 52 : In designing your network vault, what ground resistance do you requirefrom the ground system inside the vault?

Survey Questions taken from 2012 survey results - Design

Question 4.10 : In designing your network vault, what ground resistance do you require from the ground system inside the vault?

Question 4.11 : In a building vault, do you tie your neutral in with the building steel / ground system?

Survey Questions taken from 2009 survey results - Design

Question 4.10 In a building vault, do you tie your neutral in with the building steel / ground system? (this question is 4.11 in the 2012 survey)

4 - Design

4.1 - Cable Design

4.1.1 - AEP - Ohio

Design

Cable Design

People

The specification for cable used in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineers in collaboration with the Network Engineering Supervisor. These personnel are geographically based in downtown Columbus at AEP Ohio’s Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is part of the Distribution services group at AEP, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Distribution Services group, including the Network Engineering Supervisor supports all AEP network design issues throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Cable design and implementation issues throughout the AEP service areas are regularly studied and recommendations are made through this committee.

Process

Cables and associated materials for a particular project are selected during the design phase or during maintenance and repair by network engineers. These engineers use tools such as CMYECAP (to determine cable ratings) and CYME SNA (to perform load flow analysis) to determine the correct cable for any network design, including primary and secondary.

AEP Ohio uses the following cable types in its new network designs for medium-voltage cable:

1/0 TR-XPLE (primarily used in URD applications)
4/0 TR-XPLE
500 cu flat strap EPR with a thin jacket (to fit into 3” and 3 1/2” ducts)
750 copper and aluminum EPR cable, used in distribution and for feeder exits. 750 cu with a flat strap neutral is also used for station exits and distribution in smaller ducts.

AEP Ohio uses the following cable types in its new network designs for low-voltage cable:

750 cu EAM (ethylene-alkene copolymer) cable for network secondary.

For primary cable, these design preferences have been in place for some time.

AEP has lead cable installed for both primary and secondary. For primary cables, AEP is replacing lead cable (PILC) with EPR insulated cable as repairs or changes are being made. For secondary cables, AEP is replacing existing styrene-butyl and lead cable with EAM cable in an extensive cable replacement project ($300 million) throughout AEP operating companies, including AEP Ohio (see Network Revitalization).

AEP’s secondary cable design preferences were developed by the an engineer within the Network Engineering group, and are based on cable rating models and AEP Ohio’s specific characteristics based on thermal resistance, duct line configuration, and manhole requirements. Working with the Network Standards Committee, the engineer arrived at secondary cable design preferences based on the models.

AEP Ohio’s philosophy is the make the maximum use of the existing duct space, as expanding duct space can be very expensive. Thus, for its targeted secondary cable replacement program, AEP Ohio has standardized on 750 Cu EAM insulated cables as this is the largest sized cable that will fit in its standard 3 ½ inch duct. Note that the ultimate decision on both cables to replace and the size and type of cable to use for replacement was left up to individual AEP operating companies as part of their replacement program

AEP Ohio’s secondary cable replacement program includes replacement of butyl rubber cable and lead secondary cables. AEP engineers noted that while lead cables are not as high a priority as replacing butyl rubber cables, lead cable failures can result in a hot fire which can spread to adjacent cables and other facilities.

AEP designs its duct and manhole system in a way that physically separates the electrical facilities to assure contingency operation (see Figure 4-13 and Figure 4-14). For example, in systems with an N-2 design criterion, AEP will run no more than two network feeders that supply a given network within the same duct bank, manhole, or vault. For an N-1 design, the design will arrange feeders so that the loss of a single duct bank, manhole, or vault will not result in a customer outage.

Figure 1: Cabling in manhole. Note primary racked on the top of the manhole; secondary racked on the bottom

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Figure 2: PILC cables, lead joints

AEP uses arc proof tapes on all network primary cables within manholes or vaults. Secondary and service cables are not arc proofed, but are physically separated from primary cables in the vault to the degree possible.

Technology

AEP Ohio uses CYMECAP and CYME SNA for cable design modeling and selection. The Network Engineers perform load flow analysis and cable rating studies for primary and secondary cable for new designs and system upgrades or repairs.

AEP utilizes crabs for its secondary network buss work (see Figures 3 and 4).

Figure 3: Secondary crabs

Figure 4: Secondary crabs

4.1.2 - Ameren Missouri

Design

Cable Design

People

Network standards, including standard designs for cable, are the responsibility of the Standards Group. This group develops both construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs.

Organizationally, the Standards Group is led by a Managing Supervisor, and is part of the Distribution Planning and Asset Performance Department, part of Energy Delivery Technical Services. Within this organization are experts who focus on developing and maintaining specific underground standards. For example, they have a cable engineer, who is an expert with cable and cable systems, and responsible for the development of cable standards for the company.

Standards are available in both an online and printed book format. Updated versions of the book format version are issued every 2-3 years.

See Standards

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development of conduit system standards and cable replacement strategies for the company.

See Unsatisfactory Performance Report

Process

Ameren Missouri’s present standard calls for the use of EPR insulated cable for all cable systems. Because of limited duct size, Ameren Missouri has implemented the use of reduced-diameter 15 and 35kV cables for the replacement of paper – insulated lead-covered cables (PILC) cables. This reduced-diameter cable (145 mils vs. 175 mils for 15kV, and 300 mils vs. 345 mils for 35 kV) is being used where conduit sizes are small, such as downtown St. Louis for both new and replacement applications, and has resulted in significant cost savings.

The reduced-diameter cables are tested and installed just like their full-diameter counterparts using qualified cold-shrinkable, heat-shrinkable, or special molded accessories with push-on cable adaptors with the reduced-diameter cables. Ameren Missouri believes that they receive higher quality cable in that the cable manufacturers have to run their cable manufacturing process more slowly to meet the tolerances required by Ameren Missouri. To date, there have been no reduced-diameter cable or accessory failures unrelated to workmanship.

The cables must be stripped carefully so that the underlying insulation is not damaged as there is less margin for error with the reduced insulation. Ameren Missouri routinely reminds construction personnel that they are working with a special cable and need to handle it appropriately. The cable engineer from the Standards Group will occasionally assist the training department in training splicers for making up cable accessories. Ameren Missouri will also conduct training classes using experienced retirees as instructors.

The purchase price of reduced-diameter cables is comparable to the price of full-diameter cables. However, some accessories used with reduced-diameter cables may have a higher total installed cost than a similar push-on device. Further, reduced-diameter cables have a minimum bending radius that is slightly less than a similar full-diameter cable, but this has not been an issue. Finally, reduced-diameter cables have dielectric losses that are somewhat higher than similar full-diameter cables. In addition, Ameren Missouri is using the reduced-diameter cables to transition between PILC cables and has experienced no problems using the reduced-diameter cables in trifurcating transition splices.

Ameren Missouri’s revitalization efforts may result in the installation of new duct systems with adequate conduits size. In this case, Ameren Missouri would use standard wall cable.

Technology

Current standard cables used for the Ameren Missouri network are 4/0 Al, 350 cu, 750 cu at 13.8kV. For network secondaries, they use 500 Cu EPR cables for the street mains and transformer ties.

Figure 1: Primary Cables

Figure 2: Primary Cables – Transformer termination

4.1.3 - CEI - The Illuminating Company

Design

Cable Design

(Cable and Splice Design)

People

The Supervisor, Underground / LCI Section at CEI has significant experience with cable and cable system design. It is the Engineering Services group that maintains and establishes cable standards for the region, and designs and prepares construction drawings for the conduit system.

FirstEnergy has chosen to keep this responsibility in the region ^[1] , because the expertise is housed at CEI, as 70% of the ducted conduit system in the company is located at the Illuminating Company.

Process

CEI has a significant amount of Paper Insulated Lead Cable (PILC) cable installed (80% of their ducted manhole system), as this was their standard in the past (three conductor paper lead cable). When they decided to move to a non-lead cable type, they formed a committee and worked closely with a manufacturer to develop a new cable specification. They elected to go with a flat strapped cable because of the reduced diameter, and with EPR insulation, chosen because of its flexibility. In selecting standard EPR cable sizes, the committee inventoried the PILC cable sizes being used to understand the current carrying needs of these feeders, as EPR cables would ultimately be used to replace failed cable sections. They selected two standards sizes to meet their needs - 3/0 and 500 kcmil Cu EPR 15 kV class cables.

When CEI began using EPR Cable construction, they needed to develop a transition splice (stop joint) to transition from lead cable to EPR cable as lead cable sections were replaced or added on to. Originally, CEI developed an in house transition joint that involved performing lead wipes (similar to traditional lead splices). Ultimately, they worked closely with manufacturers (Raychem and 3M, for example) to develop a transition splice from lead to the flat strapped EPR, that could withstand the changing oil pressures (from daily load swings., temp, elevations, etc.)

CEI will typically “pilot” or laboratory test a new piece of equipment, such as a splice, prior to installing it on their system (See Beta Lab - Testing Laboratory ). The transition splices were fully tested prior to selection.

Technology

CEI has approximately 16000 ft of primary cable installed. They have a significant amount of Paper Insulated Lead Cable (PILC) cable installed, as this was their standard in the past. For network primary cables, CEI’s current standard is Ethylene Propylene Rubber (EPR) insulated cable. Cross Linked Polyethylene (XPL) insulated cable is used for primary feeder substation getaways (750 AA). For secondary network cables, CEI uses XLP insulated cable (500 Cu).

CEI uses various types of splices including lead splices (occasionally), heat-shrink splices, and cold-shrink splices. CEI’s preferred splice is a Raychem Heat shrink transition splice, though they acknowledge that training and proper workmanship are essential to making up these splices properly. They also are using a 3M cold shrink splice

Note: CEI uses the following technology at steam crossings to eliminate cable failures:

CEI elected to use high temperature withstand silicone rubber jacketed cables (rated to 200 degrees C) in cable runs in close proximity to steam lines. (See Attachment - H)

When CEI sold the steam system, they also required the new owner to respond to and repair steam leaks in a timely fashion in order to minimize the exposure of the electrical system to the high temperatures associated with these leaks.

The application of the high temperature withstand silicone rubber jacketed secondary cable effectively eliminated the cable failures at steam crossings.

^[1] In anticipation of the retirement of a key CEI individual with cable and splice design expertise, FirstEnergy has assigned a senior engineer from their corporate Design Standards group to work closely with this individual to gain experience and document knowledge. It is anticipated that this Senior Engineer will provide cable and splice design expertise to CEI in the future.

4.1.4 - CenterPoint Energy

Design

Cable Design

People

Network design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group deals with the design of three phase pad mounted transformer installations, including looped commercial developments. This group, the Padmounts group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is not typically involved in network design.

Another sub group focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. This group, called the Vaults group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. Note this group designs submersible network vaults as well as building vaults.

The final subgroup is one focused on distribution feeder design. This group, the Feeders group, focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

CenterPoint uses EPR aluminum cables with a flat strapped neutral as a standard primary power cable for Major Underground (750 AA and 1000 AA at 15kV, 1250 AA at 35kV). CenterPoint uses TR - XLPE insulated cables in URD applications.

CenterPoint does have Paper Insulated Lead Covered [PILC] cable as well as butyl (rubber) cables installed.

4.1.5 - Con Edison - Consolidated Edison

Design

Cable Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Cable Design

For network primary cables, Con Edison uses Ethylene Propylene Rubber (EPR) insulated cables as its standard. EPR cable was chosen due to its flexibility. (Note: Con Edison has Crosslinked Polyethylene [XLP] and Paper Insulated Lead Covered [PILC] cable installed. PILC cable makes up about 20% of the utility’s installed plant.)

For secondary network cables, Con Edison uses cables insulated with “Integral” Filled Ethylene Alkene Rubber (EAM). This particular cable is flexible, and is jacketed with a durable low-smoke, zero-halogen material that is extruded over the insulation.

Con Edison has a cable engineer who works closely with cable manufacturer, and is instrumental in the ultimate design of the cable, development of cable specifications, and constructions.

4.1.6 - Duke Energy Florida

Design

Cable Design

People

The specification of cable used in the urban underground networks in Duke Energy Florida is the responsibility of the Standards group, which oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies.

Process

The standard primary feeder cables supplying the Clearwater network are 4/0 cu XLPE insulated cables. Outside the network, Duke Energy Florida will use both 4/0 cu and 1000 MCM AL XLPE cable for feeder exits. Standard secondary cable sizes are 4/0 cu and 500 cu, also XLPE insulated. Duke Energy Florida has no remaining lead cables in their underground system.

Stud moles are mounted on top of the protector, and use nut and cone connections to the cable (see Figure 1).

Figure 1: Secondary cable emanating from network protector showing stud moles

Cables are racked on a galvanized steel cable rack, using steps and porcelain insulators. Primary feeders are usually mounted on cable racks in the lower part of the manhole, while secondary cabling is mounted above, higher in the manhole (see Figure 2).

Figure 2: Secondary cable racks. Note cable limiters attached to the moles

All network feeders in downtown Clearwater (supplying a true 125/216V network) have their own network cable manholes/duct lines (not shared with non-network circuits).

Duke Energy Florida uses cable limiters, with full section limiters on all street mains and half section limiters on all service connections.

Duke Energy Florida utilizes cable tags in the field, and maintains accurate maps showing feeder numbering.

4.1.7 - Duke Energy Ohio

Design

Cable Design

People

Duke Energy Ohio’s network system is comprised of both older paper insulated lead (PILC) cables (400 and 600 MCM) and newer EPR insulated cables. They have a fair amount of lead cable still in the ground, including both primary feeders and their network secondary cables.

New cable is EPR insulated. Because they have a lot of older 3 ½ inch square duct and 4 inch circular duct installed in the network, and because they typically pull three conductors in a pipe, their 15kV cable specification calls for 750 Cu EPR cables with a flat strapped neutral, to accommodate the small duct size.

Cable specifications are prepared by the Underground Standards group, located in Charlotte.

Process

Duke Energy Ohio has a vendor alliance in place with a particular cable company for much of their non-network cable. They do not have such an alliance in place with their network cable supplier.

New cables are accepted by Duke Energy Ohio, after successfully passing a DC Hi pot acceptance test and an AC Tan Delta test. The AC tan delta is used to establish a baseline for future cable testing. The testing and establishment of this baseline is performed by one of the underground crews, compromised of individuals who have developed expertise in AC Tan Delta testing.

Network Feeder “get away cables” (substation feeder exit cables) were historically designed as nitrogen gas filled cables, with the nitrogen used to resist water penetration. The substation group maintains this system of gas filled cables. When the there is a leak, the Dana Avenue group will trouble shoot it. They will fix, or sometimes, they may cap the feeder, changing the point to which the nitrogen is pumped. In other cases, they have eliminated the nitrogen, although they have found that this sometimes leads to additional failures due to moisture ingress. When they replace network “get away cables”, they will do so with EPR insulated cable. They do not have a proactive program to replace these older gas filled cables - replacement is usually driven by development / load growth.

Figure 1: Nitrogen supply to feeder exit cables

Technology

Current standard cables used for the Duke Energy Ohio Cincinnati network are 4/0 cu EPR and 750 cu EPR cables (750 with a flat strapped neutral).

Duke adopted these standards as a replacement for the 400 and 600 MCM PILC cables they were the former standard. They chose the EPR cable insulation type because, though a bit lossier than XLP cables, they found it to be more flexible. Also, the cables come strapped together (each leg) so that they can make one cable pull.

At the time of the immersion, Duke resources noted that they were exploring other cable type opportunities for use in their network, looking at things such as loss characteristics, cable flexibility, coatings of the jacket, etc.

Figure 1: Primary cable

Figure 2: Primary cable

Figure 3: Primary cable

4.1.8 - Energex

Design

Cable Design

People

Engineers within System Engineering, part of Asset Management, establish cable design standards for the Energex network underground CBD. Project engineers within the Design group, part of Service Delivery, apply the appropriate, approved Cable Design standards according to duct and conduit constraints, location, and earth ambient temperatures (see Table 1). Project engineers are geographically situated at 15 different “hub” locations throughout its territory. They are distributed geographically to be close to the field, but the assignment of work is not strictly geographic, with work often assigned based on work peaks and troughs.

[See the Standards section of this report]

Process

Energex uses both PILC cable, and XLPE insulated cable at 11 kV to supply the CBD. The company is not actively seeking to reduce the amount of PILC, but their current standard for new installations is to use XLPE insulated cable. PILC is only used in new applications where they are restricted because of the size of the existing duct system.

Technology

The standard XLPE cable used in the CBD is a triplex cable, using stranded aluminum conductors (400 mm² ). (See Figure 1) In areas of restricted conduit diameter, Energex may use XLPE insulated copper conductors (240 mm² ).

Figure 1: Cross-section of typical 11 kV triplex aluminum cable with XLPE insulation

Table 1:

Table 1. Energex current rating for CBD and zone substation feeders.

Energex uses an extensive low-voltage (secondary) system. Their typical secondary cable is a bundled sector shaped stranded aluminum conductor (see Figures 2 and 3).

Figure 2: Low-voltage cable

Figure 3: Low-voltage cables emanating (bottom) from the secondary switchboard (from the transformer secondary)

4.1.9 - ESB Networks

Design

Cable Design

People

The selection and criteria for network cable design is performed by engineers within the Underground Networks group, part of Assets and Procurement. This group works closely with the Asset Investment group, including the Network Investment groups and Specification groups to specify cable on behalf of ESB Networks.

ESB Networks has developed thorough guidelines for cabling. This guideline includes specific direction for optimizing designs.

Note that in addition to the Assets and Procurement and Asset Investment groups, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Operations, and Finance & Regulation. These groups work closely together to manage the asset infrastructure at ESB Networks.

Technology

While the focus of the practices immersion was on distribution, some information about HV cables is presented here.

Transmission/Sub-transmission

ESB Networks operates transmission cables at three primary voltage levels – 220 kV, 110 kV, and 38 kV, which are used primarily as sub-transmission (see Figure 1).

Figure 1: HV cable used by ESB Networks

For HV cables (110 kV and 220 kV), much of the in-service plant (42 percent) has been installed over the past seven years, including cable replacement.

At 110 kV, 77 percent of the in-service cable is XLPE insulated cable, 14 percent is fluid filled cable, and 9 percent is gas filled cable.

At 220 KV, 53 percent of the in-service cable is XLPE insulated, with the remaining 47 percent fluid filled.

At 38 kV, 86 percent of the in-service cables are XLPE insulated cables, with 11 percent fluid filled, and 3 percent paper insulated (PILC). Note that the 38-kV sub-transmission system that supplies the MV feeders serving Dublin is a meshed system. This meshed approach was chosen for added reliability – if ESB Networks loses a substation, it can close a bus tie and feed the rest of the bus from the remaining unit. Note that if the company takes out a 38-kV cable for service, ESB Networks must also take out one of the substation banks because of the short circuit duty.

To prevent circulation among the transformers, the transformers are interconnected with communications to form a transformer “team,” with one transformer considered the “master.” As its voltage varies, the other transformers (slave units) follow suit by changing taps to match the master. Operators have the ability to reconfigure the master-slave configuration to develop new transformer teams as necessary to deal with abnormal situations.

Distribution

For MV (distribution) cables, about 34 percent of the in-service plant has been installed over the past seven years, including cable replacement.

At 10 kV, about 78 percent is XLPE insulated (the current standard) round aluminum conductor with a durable jacket, 20 percent is paper insulated (PILC), and the remainder, 2 percent, is unknown.

At 20 kV, all in service cable is XLPE insulated. Note that the in-service PILC cables and older (pre-1981) XLPE cables are not convertible to 20 kV (water treeing).

ESB Networks reports extremely good performance from their XLPE insulated cables, noting that they haven’t experienced a cable failure unrelated to a dig in or joint failure since 1982.

4.1.10 - Georgia Power

Design

Cable Design

People

The specification of cable used in the urban underground networks supplying metropolitan area customers in Georgia is the responsibility of the Principal Engineers within the Network Underground group. The Network Underground group, led by the Network Underground Manager, consists of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure at Georgia Power. It is a centralized organization, responsible for all Georgia Power network infrastructure.

The Network Engineering group, led by the Network Underground Engineering Manager, is comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network, including cable design.

Georgia Power has a Standards Group that has developed cable specification standards for spot, primary, secondary, and substation designs used in the network underground. Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. It is a living document, and the responsibility of the Standards Group comprised of principal engineers in the Network Underground group. Standards are available in both an online and printed book format.

The Georgia Power Underground group is responsible for cable standards for all duct line and manhole systems at Georgia Power. (non-ducted manhole system standards are managed by a separate group, not part of the Network Underground group) The Network Standards book contains specifications on cables, splices, racking, and duct line and vaults. The document is kept up-to-date by the Standards group and is available online and in printed form.

Process

Cabling and associated materials can be selected during the design phase or during maintenance and repair using the Network Underground Specifications book, many with reference or model drawings to help insure that standards are met.

The standard primary feeder cables for new construction are 1000 MCM, EPR insulated cable for use in 6-inch ducts and 350 MCM reduced diameter EPR cable in 4 inch ducts. In downtown Atlanta the network system is constrained by an existing 4-inch conduit system. This limits the selection of cables that can be used. Wherever possible, the group is using 350 MCM, EPR cable with a compact flat strap neutral design.

Figure 1: EPR Cable

Georgia Power utilizes lead cable in their network. They are not aggressively trying to reduce the amount of lead cable, but are replacing lead with EPR insulated cables when opportunities arise. Some PILC is still being installed, in order to match existing cable and in order to maintain crew skills in splicing PILC.

Figure 2: PILC Cables

Georgia Power has had good success with their lead cable system - they find it reliable, compact, and it suits the legacy duct and conduits in its system. Georgia Power uses 3-conductor compact sector (300 mcm, 200 mils) PILC cable in these instances.

Another constraint (beyond the limitations of the existing duct system) to moving from lead to EPR is the space needed for Y-splices on the walls of manholes. Some manholes do not have enough room for racking they EPR Y-splices for 20 kV,, so lead is still the most reliable and space-saving option in those cases. Where EPR is used, the group is moving to a cold-shrink instead heat-shrink joint, as it is difficult to control uniform temperatures for the application of heat-shrink.

Technology

Georgia Power has recently installed a new online material system (“Maximo”) that tracks cable and materials available in the warehouse by a commodity number. Cable stock is regularly rotated in the warehouse. The software can also track and house maintenance records from inspections and trouble tickets, and generate work packages based on predefined triggers.

Georgia Power utilizes cable tags in the field, including tagging all primary cables and services going to customers. They do not tag the street mains.

4.1.11 - HECO - The Hawaiian Electric Company

Design

Cable Design

(Cable and Splice Design - 600 Amp connector systems)

People

The Technical Services Division within the Engineering Department at HECO has significant experience with cable and cable system design. It is the Technical Services Division that maintains and establishes cable standards for the region, and performs root cause analysis on splice, connector and cable failures.

HECO has a distinct C&M Underground Group that focuses on urban UG facilities on O’ahu. This group, made up of Cable Splicers, does all of the lead work on the island, including all transition splices.

HECO also has construction and maintenance (C&M) groups that are comprised of lineman that work with both overhead underground facilities. These groups will work on non - lead cables (poly cables), including making up poly (pre molded) splices. These groups do most of the work in URD areas and on HECO’s 12 kV distribution system.

Process

HECO’s current standard for cable is XLPE, with 1000 Kcmil Al, 1 conductor typically used for main runs. HECO does have a significant amount of Paper Insulated Lead Cable (PILC) cable installed, as this was their standard in the past. They also have some HMWPE (High Molecular Weight Poly Ethylene) cable installed.

HECO is no longer wiping lead splices with the exception of their 46kV gas filled lead cable system. In all other splices involving lead cables, HECO is using a hot shrink transition splice from lead to XLP.

For non-lead splicing applications, HECO is using a poly splice (Pre-molded splice).

Technology

HECO’s underground system is designed using separable connectors, with “T” bodies being used for inline junctions and “Elbows” being used for taps. In vaults where space is limited, HECO will utilize a “Vault Stretcher” which still enables the ability to tap off the connector, but takes us less space than a traditional T connection.

Figure 1 & 2: Separable Connectors

Figure 3: Separable Connectors – Vault Stretcher

HECO is using a hot shrink transition splice when transitioning from lead to XLP.

For non-lead splicing applications, HECO is using a poly splice (pre-molded splice).

4.1.12 - National Grid

Design

Cable Design

People

National Grid has an up-to-date underground construction standard for cables. This standard was developed and maintained by the Distribution Standards department, part of Distribution Engineering Services. Distribution Engineering Services is part of the Engineering organization, which is part of the Asset Management organization at National Grid. Within the Standards group, National Grid has two engineers that focus on underground standards.

Process

National Grid does not perform any initial acceptance test before installing new cables (beyond the acceptance testing performed by the cable manufacturer as part of the purchasing contract.) They have experienced good cable performance.

National Grid places primary cable tags at each access point, such as a manhole or vault, and at every termination.

Technology

National Grid’s network system is comprised of both paper insulated lead (PILC) primary cables and EPR insulated primary cables serving their 13.2 KV grid network and 34.5 KV spot network system in Albany. EPR insulation is their current standard for medium voltage cables.

Figure 1: Primary PILC cables and joints

For network underground secondary cable, National Grid uses lead and EPR insulated (current standard) conductor with a cross-linked heavy-duty black chlorosulfonated polyethylene (Hypalon) jacket.

Figure 2: Secondary cables

Current primary standard cables used for the Albany network are 1000 cu, 750 cu, 500 cu, and 350cu.

For network secondary, they use 500 Kcmil Cu mains, and 500 Kcmil, 4/0 and #2 Cu for services.

National Grid Albany uses arc proof tape in its network system, applying it to all cables and splices in network manholes.

4.1.13 - PG&E

Design

Cable Design

People

PG&E’s network system is comprised of paper insulated lead (PILC) primary cables serving their 12kV networks, XLPE insulated primary cables serving their 34.5kV networks, and newer EPR insulated cables spliced to lead cables where they must make dead front terminations. Newer 35 kV network cables are insulated with EPR.

All Cable Splicers are trained to prepare lead splices. However, much of the experience in doing so resides in the San Francisco and Oakland Underground departments, where splicers have an opportunity to practice lead splice preparation with some regulatory. Outside of the cities, most splicer work with lead involves the preparation of transition joints (outside the network, PG&E is transitioning away from lead cables). When the need arises to prepare lead splices outside the city arises, PG&E may send more experienced resources from the San Francisco or Oakland UG centers to perform the work.

Cable specifications are prepared by the Cable Standards engineer within the Standards Department.

PG&E does maintain a record of their cable assets. However, their asset data is incomplete. They record cable sizes and location of transition joints. They do not have a record of the splice manufacturer or the date the splice was installed.

Process

PG&E continues to use lead as their standard primary cable standard for their 12kV network primary, as it is highly reliable. In the network, when PG&E replaces a piece of cable, they may replace lead cable with lead cable or they may replace lead with EPR cable. The decision depends on a number of factors including the size of the manhole (there may not be room, for example, to properly install a cold shrink transition joint), the need to terminate on dead front equipment, and duct size. Note that 750 cu EPR with a flat strapped neutral is sometimes used as replacement for PILC cable where duct size is limited.

Figure 1: Primary Cables being prepared for transition to EPR cable

Figure 2: Primary Cables

Note that PG&E’s actively pursuing lead replacement in their radial systems.

PG&E has a vendor alliance in place with a particular cable company for much of their network cable.

PG&E does not perform any initial acceptance test before installing new cables (beyond the acceptance testing performed by the cable manufacturer as part of the contract.) They have experienced good cable performance.

Technology

Current standard cables used for the PG&E network are 750 cu, 500 cu, 250 cu, and #2 cu PILC cables at 12 kV, and 1100 Al, 600 Al , and 1/0 Al XLPE or EPR (more recent standard) cables at 35 kV.

For network secondaries, they use 1000 cu for transformer ties, and 250 or 500 Cu EPR cables for the street mains.

4.1.14 - Portland General Electric

People

Three Distribution Engineers cover and design the underground network, including cable design. The Distribution Engineers are not based in the Portland Service Center (PSC) or CORE group but have direct responsibility for the network and work closely with the CORE. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees these engineers.

The Distribution Engineers develop and maintain the standards for the network, which are forwarded to the Standards Department for inclusion in company standards documents. For example, Network Engineers developed the cabling rating standards for the network. Distribution Engineers assume responsibility for network standards as they have the expertise specific to network equipment.

Process

PGE generally uses flat strap EPR 500 MCM copper medium-voltage cables in its network, as three triplexed conductors fit into its 3.5 in. (8.9 cm) diameter clay conduits. In certain applications, the company uses a reduced insulation 750 MCM copper cable that fits into 4 in. (10 cm) conduits. For taps into a network vault, PGE typically uses 1/0 copper cables. PGE has lead cable installed in both its network primary and secondary. The company has a proactive effort underway to replace primary lead cables with EPR insulated cables in its network primary as opportunities arise.

Figure 1: Cables feeding into vault from duct bank

PGE uses transition, cold shrink, and heat shrink joints for transitioning from PILC to EPR. Splices are “pressed,” as field crews have more confidence in compression connections than in shear bolt technology. Note that with the EPR cable systems, PGE is trialing the use of bolted Energy Services Network Association (ESNA) style connections, such as Y and H connections.

Engineers use modeling tools to keep track of cable ratings and CYMCAP to determine cable ratings. The Transmission and Distribution Planning and Standards Department has developed peak cable rating guidance that specify the allowable normal and emergency loading for all cables on the network. PGE is improving its processes for documenting and standardizing equipment and procedures on the network, including cable ratings.

To isolate areas of the distribution system where cables may overload, Planning Engineers use CYMEDIST for the radial system and PSSE for the network. Using base case models and seasonal loading data, under different contingencies, engineers can ensure that lines do not exceed 67% of their normal seasonal thermal rating on the radial system, which translates to two-thirds of the normal capacity for a standard feeder. On the network, base loadings specify that no line should load at over 88% on the network. Any areas of concern are prioritized for equipment upgrades [1].

Distribution Temperature Sensing (DTS): In PGE’s DTS pilot, the company installed real-time line sensors on six network feeders to provide temperature readings for underground cables at two-second intervals. Because temperature influences capacity, the sensors may show where system upgrades may be required. In addition, the system could allow PGE to locate hotspots that indicate a potential cable failure. PGE has included the DTS in the new substation intended to begin operation in 2018-2019 [2].

Technology

Cable Standards

PGE has had few cable-related issues on the network, and part of that is related to a comprehensive specification for its standard 15-kV EPR jacketed concentric neutral cable with a flat strap neutral. This cable specification covers various sizes, including 0.39-, 0.59-, and 0.79-in2 (500-, 750-, and 1000-kcmil) copper-jacketed—all used on PGE’s network. The specification defines quality expectations, including that the cable design conforms to industry standards and specifications. For example, the center conductor is copper wire processed under ASTM B3, ASTM B496, and ICEA S-94- 649-2013, Part 2. The moisture barrier, outside diameter of the central conductor, and the conductor shield conforms to ICEA S-94-649-2013.

The concentric neutral conductor is flat-strap copper and able to handle a neutral fault current capacity of 18,000 A for 12 cycles at a maximum 221°F (105°C) normal operating temperature. The cable jacket is non-conducting black, polypropylene, or thermoplastic rubber.

PGE’s cable specification also includes requirements for cable delivery to assure reliability, such as the use of steel cable reels, cable end caps, and factory-installed pulling eyes, which act as a common eye for all three phases of the triplexed cable set and have a maximum working strength equal to the sum of the maximum allowable strengths for each of the center conductors of the triplexed cable set [3].

Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017). Portland General Electric. From L20506 15-kV EPR Jacketed Concentric Neutral Cable, internal document.

4.1.15 - SCL - Seattle City Light

Design

Cable Design

People

Organization

Network Design, including specification of cable types, at SCL is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A. The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Process

The majority of installed cables at SCL are Crosslinked Polyethylene [XLP] insulated cables. Ethylene Propylene Rubber (EPR) cable is used for all new construction at 13kV. SCL does have Paper Insulated Lead Covered [PILC] cable installed as well, comprising 8% of their installed plant.

Cable Rating

SCL rates cables at 90 ˚ C; that is, they develop a cable ampacity rating that limits the conductor heating to 90 ˚ C. SCL does not develop an emergency or 24-hour rating for feeders. They plan their system to the 90 ˚ C limit.

SCL develops feeder specific ratings based on field conditions. Using software, they develop ampacity ratings for circuits that consider factors such as cable type, duct bank configuration, soil resistivity, proximity of foreign utilities, design temperature (90 ˚ C), load factor (80%), etc. SCL performs both a summer and winter analysis. The summer ratings, which are the most conservative, are typically used for planning purposes.

SCL re-rates cables any time conditions in the field change that could affect cable rating, including the addition of another parallel circuit, the addition of a foreign utility such as a steam line, a new cable in the duct bank, etc.

The specific cable ratings are entered into the load flow software for planning analysis.

4.1.16 - References

EPRI Unde rground Distribution Systems Reference Book (Bronze Book)

Chapter Section 14.10 - Cable Design

4.1.17 - Survey Results

Survey Results

Design

Cable Design

Survey Questions taken from 2018 survey results - Asset Management

Question 6 : Please indicate the percentage of each cable type that comprise your network primary (MV) cable system

Question 7 : Please indicate the percentage of each cable type that comprise your network secondary (LV) cable system

Survey Questions taken from 2015 survey results - Summary Physical/General

Question 26 : Please indicate the percentage of each cable type that comprise your network primary cable system (total should equal 100%)

Question 27 : If you entered other for the previous question, please specify other conductors and percentages.

Question 28 : For primary cable, which of the following do you utilize (current standards)? (check all that apply)

Survey Questions taken from 2012 survey results - Summary Physical/General

Question 2.9 : Please indicate the percentage of each cable type that comprise your network primary cable system

Question 2.10 : For primary cable, which of the following do you utilize (current standards)?

Question 2.11 : Do you use low smoke zero halogen cable in your secondary?

Survey Questions taken from 2009 survey results - Summary Physical/General

Question 2.5 : Please indicate the percentage of each cable type that comprise your network primary cable system (this question is 2.9 in the 2012 survey)

4.2 - Cable Limiter Application

4.2.1 - AEP - Ohio

Design

Cable Limiter Application

People

The specification for using Cable Limiters in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineering group. This group, led by the Network Engineering Supervisor, has direct responsibility for all aspects of network design for AEP Ohio, and provides a consultative support role to the other AE operating companies. Organizationally, the Network Engineering group is part of the corporate Distribution services organization, geographically based in downtown Columbus at AEP Ohio’s Riverside offices, and ultimately reporting to the AEP Vice President of Customer Services, Marketing and Distribution Services. Distribution Services supports all AEP network designs throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues such as cable limiter application.

Process

AEP Ohio’s cable limiter placement approach conforms with guidance detailed in the “Westinghouse Book.” AEP Ohio uses cable limiters on all its 480 secondary networks, at both ends of the mains. The company also uses limiters in 216-V networks on cables sizes 250 MCM and above (though faults at 216 V will self-clear). AEP uses the “Bussman” type cable limiters (see Figure 1).

Figure 1: Cable limiter used by AEP Ohio

4.2.2 - Ameren Missouri

Design

Cable Limiter Application

People

Design of the urban underground infrastructure supplying St. Louis, both network and non- network, is the responsibility of the engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The Underground Division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group, led by a supervising engineer, is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including the application of cable limiters. All of the engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, including the replacement of deteriorated ceiling mounted secondary bus bar designs, with alternate designs, such as ring buses, and crab connections.

Ameren Missouri has a documented cable limiter application standard (See Attachment A ).

Process

Ameren Missouri uses standard link type limiters on each end of their 500 copper secondary mains from ring bus to ring bus, and between transformers and the ring bus.

Ameren Missouri uses high-capacity silver sand (bussman type) limiters on both ends between the ring bus and customer services.

For 480V spot network locations, Ameren Missouri uses silver sand fuses between the network protectors and the secondary collector bus.

In the network secondary, Ameren Missouri currently has historically used secondary ring bus designs in manholes and ceiling mounted secondary bus bar designs located within secondary service compartments, which are 8x8 vaults. The ceiling mounted structures are difficult to maintain, as it is difficult to insulate the overhead bus work. The bus work makes it difficult or impossible to repair deteriorated ceilings. Ameren Missouri is presently piloting the use of crab connections moving forward as a replacement to the service compartments, as these connections enable the bus work to be moved off of the ceilings. All structures are inspected once every 4 years. Any that are identified with bad ceilings are considered with replacement with crab connections if there is room.

Figure 1: Network Crab in manhole

For new designs, engineers within the underground department decide whether to use a secondary ring bus or crab connector. At the time of the immersion, the Ameren Missouri network revitalization team was considering using the crab connection approach with smart limiters going forward.

Technology

Ameren Missouri is piloting the use of a network crab that is made by TYCO. This particular crab connection comes with smart limiters. These limiters are used to connect cables onto the crab connection (using a shear bolt connections) and have plastic tubing so that the status of the limiter can be ascertained visually.

4.2.3 - CEI - The Illuminating Company

Design

Cable Limiter Application

People

The design of the network ducted manhole system, including the application of cable limiters, is performed by the CEI Underground / LCI group (Design Group), part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

The group’s responsibilities include network system and non – network system designs and the development of standards for the ducted manhole system including vault and manhole design standards and customer design standards.

Process

CEI utilizes cable limiters in their network secondary system in Cleveland. Much of the system was installed many years ago, and was designed using “mole limiters” on each end of the secondary mains that run from the network transformers to the first secondary mole, and at most junction points. Historically service taps were not protected by limiters; however, FirstEnergy’s current policy does call for cable limiters on all service taps. Any new installations follow the current FirstEnergy application policy.

The “mole limiter” is a unit installed in the cable that includes a fusible element, a high temperature filter shell, and an insulated sleeve. Cable limiters are designed to interrupt the circuit before the cables carrying a fault current are visually damaged, and to isolate the damage to the section of cable where the fault occurred.

CEI replaces limiters in kind if they encounter them in performing secondary network work. They acknowledge that they may have blown limiters in their secondary network system of which they have no knowledge.

First Energy has a documented practices guide for the installation of cable limiters, See Attachment - C . This policy applies whenever secondary cables are being added or replaced to a network secondary system.

The policy indicates that:

For Secondary Mains & Branches:

cable limiters shall be placed on both ends of all paralleled cables in looped secondary circuits
cable limiters shall be placed on the source end of all radial secondary circuits with one or two cables per phase.
cable limiters shall be placed on the both ends of all radial secondary circuits with three or more cables per phase.
cable limiters shall be placed on both ends of all transformer tap cables

For Service:

cable limiters shall be placed on the source end of all services with one or two cables per phase.
cable limiters shall be placed on the both ends of all services with three or more cables per phase.

Limiters are not required on cable lengths of less than eight feet if both ends of the cable are within the same enclosure.

Technology

See Attachment - D , for a copy of the FirstEnergy Material specification for cable limiters.

FirstEnergy is presently considering using a “see through” limiter to provide a visual indication of whether it is blown.

4.2.4 - CenterPoint Energy

Design

Cable Limiter Application

People

The design of the network ducted manhole system, including the application of cable limiters, is performed by the Engineering Department of the Major Underground Group.

The Vaults subgroup normally designs new services and secondary taps from spot network secondaries supplying the grid.

CenterPoint does not have a written cable limiter application policy.

Process

All points feeding the secondary network grid are protected by cable limiters. CenterPoint uses cable limiters any time they attach cables to the secondary bus. For example, in situations where they will supply the network secondary grid from a secondary collector bus in a vault, cable limiters would be used. Limiters are sized according to cable size.

CenterPoint also requires the use of cable limiters for cable services to customers. In these cases the customer provides both the cable and appropriately sized limiters. (Note that in most cases, customer services at CenterPoint are comprised of bolted attachments of customer bus bar to the CenterPoint secondary collector bus, rather than cables. Limiters, of course, are not used in these bus bar attachments.)

During Vault inspections, Network Testers will perform secondary cable continuity checks (Tong the secondary cables) to assure that the cable limiters are in tact. CenterPoint replaces limiters in kind if they encounter them in performing secondary network work.

Technology

CenterPoint uses the sand type cable limiters (Bussmann) as shown in the photographs below.

Figure 1: Cable limiters applied to secondary bus

Figure 2: Cable limiters applied to secondary bus, supplying street grid

4.2.5 - Con Edison - Consolidated Edison

Design

Cable Limiter Application

Process

Con Edison utilizes cable limiters in their network secondary system in New York. Cable limiters are designed to interrupt the circuit before the cables carrying a fault current are visually damaged, to isolate the damage to the section of cable where the fault occurred.

Con Edison does not have a good method of ascertaining whether or not cable limiters have blown. Utility crews take a current reading and use a device that puts a signal on the secondary, but these methods are not trusted by all the work groups at Con Edison.

Con Edison has asked three different manufacturers to develop a new limiter design that provides fault indication and can be quickly replaced. For example, one manufacturer has developed a cable limiter with a clear covering so that the user can see that the device is open. Con Edison is currently evaluating this product.

Technology

Con Edison is using cable limiters in both 216/125V and 480/277 V applications.

4.2.6 - Duke Energy Florida

Design

Cable Limiter Application

People

Standards for network design, including the application of cable limiters to the system, are the responsibility of the Duke Energy Florida Standards group, which oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies. The Design Engineers are engaged in a Duke Energy corporate-wide process to consolidate design standards for network systems among the various Duke operating companies, due to be finalized in 2017.

The Duke Energy Florida standards department has developed a Distribution Engineering Manual section on Secondary Networks, which provides information on cable limiter placement and coordination. See Attachment C.

Process

Duke Energy Florida does use cable limiters in its network secondary (see Figures 1 and 2). Cable limiters are installed at each secondary junction on the secondary mains on the outgoing secondary cable. In addition, cable limiters are installed at all service connections. Duke Energy Florida uses full section limiters on the street main secondary grid. Half section limiters are used on service connection junction points and are sized to match the conductor size. This is to ensure a service conductor fault will be isolated before damaging the secondary main and associated limiters. Limiters are sized such that when a primary fault occurs, the primary protection should clear before any limiters blow. For a secondary fault, the limiters should clear the fault before the network protector fuse opens. Based on past experience, the limiters behave as anticipated.

Figure 1: Cutaway of a link style cable limiter

Figure 2: Cutaway of link style cable limiters. Full section limiter in the foreground and half section limiter in the background

Technology

Duke Energy does not record the location of limiters in its GIS system, but does show the location of cable limiters in its manhole drawings and supporting detail sheet (see Figure 3). See Attachment E for a sample manhole drawing and supporting detail sheets, showing the location of cable limiters.

Figure 3: Excerpt from manhole drawing – note limiters

Figure 4: Secondary cables mounted on cable racks. Note cable limiters attached to the moles on the racks

4.2.7 - Duke Energy Ohio

Design

Cable Limiter Application

Technology

Duke Energy Ohio currently does not employ cable limiters in their network secondary. Their network is relatively compact, with a sizable fault duty. They have historically relied on this high fault duty to burn the cables clear in a fault. This worked effectively for their lead secondary system, as lead tends to separate and not smolder.

Note that going forward, their new standard is to use EPR insulated secondary cables. Duke is systematically replacing old mainline sections of the network with EPR insulated cable. They continue to rely on the high fault duties to burn the cables clear in a fault, but are interested in exploring new cable limiter technology.

4.2.8 - Georgia Power

Design

Cable Limiter Application

People

Network standards, including standards for cable limiter application, are the responsibility of the Standards Group and the Network Underground design engineers. These engineers are part of the Network Engineering Group, or principal engineers that report directly to the Network Underground Manager.

Organizationally, the Network Underground group is a separate entity, led by the Network Underground Manager, and consisting of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure, including the development of standards for network equipment.

Network design is performed by the Network Underground Engineering group, led by a manager, and comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees.

Process

Georgia Power does not routinely use cable limiters on its secondary grid system in Atlanta. This system has a fault duty of less than 10000A, and is being slowly phased out in place of spot networks. Georgia power does utilize cable limiters in its Savannah network.

During routine maintenance in Savannah, inspectors will tong the secondary to assure cable limiter continuity. Also, in Savannah, Georgia power has installed monitoring of the secondary in selected manholes. They utilize CT’s to monitor load shift that may occur on the secondary due to an open limiter. This monitoring is tied into operations through SCADA.

Georgia power will use current limiting fuses at the junction point between their system and the customer service down to a 600-A fuse. The fuses are installed to protect the Georgia Power bus from customer faults. Georgia power does not advertise the use of this fusing to the customer, as they provide the actual system duty to the customer, and expect the customer to install adequate protection, and not depend on the CLF.

Technology

Georgia Power is not recording the location of limiters in its GIS system, but does show the location of cable limiters in its vault drawings.

4.2.9 - HECO - The Hawaiian Electric Company

Design

Cable Limiter Application

Process

HECO utilizes cable limiters in their network secondary system in Honolulu. Cable limiters are designed to interrupt the circuit before the cables carrying a fault current are visually damaged, and to isolate the damage to the section of cable where the fault occurred.

HECO uses cable limiters on service taps from the street grid. Cable limiters are only used on the customer end of the service if the service terminates in a bus room; otherwise, the service would feed into the customer breaker.

Technology

HECO is using Molimiter type cable limiters in 208/120 V network applications. For 480/277 V spots, they are using sand type limiters (Amp trap limiters). See Attachment - B .

4.2.10 - National Grid

Design

Cable Limiter Application

People

National Grid has a documented cable limiter application procedure as part of their underground standards.

Process

Historically, National Grid Albany used cable limiters on network protector leads and on services. More recently. National Grid has been applying cable limiters to street mains in selected locations to assure that the secondary cable system can adequately clear solid faults.

National Grid’s network standards call for all new conductor installations to have limiters installed at each end of cable runs and at junction points. The cable limiters used are standard, non-replaceable type. Sand type current limiters are not used in the street grids.

For services with one or two conductors per phase, National Grid will install limiters on each phase conductor at the origination point. For services with more than two conductors per phase, limiters are installed on both ends of each phase conductor. In this application, National Grid uses link type cable limiters,

For services from spot networks, limiters are installed on both ends of each phase cable. In this application, National Grid uses current limiting (sand type) limiters.

National Grid has performed an analysis of their Albany network to determine the expected performance of network secondary cable circuits during solid type faults in order to identify areas of needed reinforcement in order to improve the fault clearing capability of the secondary system. This analysis resulted in recommendations to install cable sets and cable limiters at selected locations within the network.

Technology

National Grid uses link type cable limiters in their secondary network grid. They do not use current limiting (high capacity) limiters in their street grid or in network protector leads feeding the street grid.

In spot network applications, they will utilize current limiting (Sand Type) cable limiter.

4.2.11 - PG&E

Design

Cable Limiter Application

People

PG&E has a documented cable limiter application procedure as part of their underground standards.

Process

PG&E employs cable limiters in their network secondary grid, except for service entrances into buildings and in a few junctions where space is very limited. Where they feed into the street grid from a spot network vault, cable limiters are placed at both ends.

PG&E does not use cable limiters in spot network applications.

PG&E performs cable limiter continuity checks under two conditions:

In the event of a secondary fault on the secondary grid
In the event of load imbalances being detected during SCADA system reviews, which would indicate possible blown limiters.

Technology

PG&E uses mostly link type cable limiters, but will use sand type limiters in some 480 V applications.

PG&E has begun using clear limiters (Tyco) for all new and replacement installations. This type of limiter will enable inspectors to identify blown limiters through visual inspection and improves the quality of secondary terminations.

Figure 1: Clear Limiters (Tyco)

4.2.12 - Portland General Electric

Design

Cable Limiter Application

People

Standards, such as those governing the application of cable limiters, are the responsibility of distribution/network engineering, which develops and maintains the standards for the network. Distribution Engineers assume responsibility for network standards (rather than standards engineers), as the Distribution Engineers have expertise with network equipment. Distribution Engineers also provide the loading information used to create CYME and PSSE models. Network standards are forwarded to the Standards Department for inclusion of company standards references.

The Manager of Distribution Engineering and T&D Standards oversees the Standards Department, and its emphasis is the overhead system rather than the network system. The group recently underwent reorganization. It now employs one technical writer and four standards engineers.

Process

PGE uses mole limiters at all junction points in area networks. During vault inspections, crews check cable limiter continuity by tonging the secondary.

Cable limiters are not shown on network maps, such as butterfly drawings, which show vault/manhole details.

Technology Refer to Figure 1.

Figure 1: Mole limiters

4.2.13 - SCL - Seattle City Light

Design

Cable Limiter Application

Process

SCL utilizes cable limiters in their network secondary system in Seattle. Cable limiters are designed to interrupt the circuit before the cables carrying a fault current are visually damaged, to isolate the damage to the section of cable where the fault occurred. SCL does not perform cable limiter continuity checks as part of their manhole maintenance ( manhole drill ) unless there is a specific problem, outage, or other issue that they are following up on. These checks are usually performed as part of the troubleshooting of a problem.

Technology

SCL is using cable limiters in both 208/120 V and 480/277 V applications. Their Network Design criteria call for cable limiters to be installed at both ends of all secondary mains. SCL uses both “sand” type and “link” type cable limiters.

4.2.14 - Practices Comparison

Practices Comparison

Design

Cable Limiter Application

4.2.15 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Excerpts from Chapter 4, Network Underground

Chapter Section 4.2.10 - Cable Limiters In 208V Area Networks

Chapter Section 4.9.9 - Cable Limiters and Cable Damage Curves

EPRI Low-Voltage Training Material

Fuse and Cable Limiter Coordination

4.2.16 - Survey Results

Design

Cable Limiter Application

Cable Limiter

Survey Questions taken from 2015 survey results - Design

Question 65 : Do you use cable limiters in your network secondary system(s)?

Question 66 : If you use cable limiters please indicate where you install them (check all that apply)

Question 67 : If you use cable limiters, do you perform a protection coordination study between the network protector fuse, cable limiters, and the station’s feeder relay?

Survey Questions taken from 2012 survey results - Planning (Question 3.21) and Design

Question 3.21 : Do you calculate minimum available fault current at the fringes of the street secondary network cables (208Y/120 V) to assure self-clearing of street network cable failures?

Question 4.18 : Do you use cable limiters in your network secondary system(s)?

Question 4.19 : If you use cable limiters, do you perform a protection coordination study between the NP fuse, cable limiters and the station’s feeder relay?

Question 4.20 : If you use cable limiters please indicate where you install them

Survey Questions taken from 2009 survey results - Planning

Question 3.13 : Do you calculate minimum available fault current at the fringes of the street secondary network cables (208Y/120 V) to assure self-clearing of street network cable failures? (this question is 3.21 in the 2012 survey)

4.3 - Civil Design

4.3.1 - Duke Energy Florida

Design

Civil Design

People

Network design is performed by the Distribution Design Engineering group for Duke Energy Florida, which works out of offices in both downtown St. Petersburg and downtown Clearwater. The Distribution Design Engineering groups in Clearwater and St. Petersburg are led by a Manager, Distribution Design Engineering, and are organizationally part of a Distribution Design Engineering Group responsible for Duke Energy Florida’s Coastal region, led by a Director.

Network civil design is guided and supported by the Duke Energy Florida Standards group, which reviews, approves, and publishes civil design standards for underground structures, such as manholes, duct lines, and vaults. Duke Energy Florida has existing, older specifications for pre-cast manholes, but is in the process of merging them with Duke corporate standards. Most new vault or duct line designs are custom built, however. The Standards group maintains documentation of “as builts” and any custom civil designs on the network. Vault and manhole design standards are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D ). This document contains manhole standards for various manhole configurations, as well as information about manhole lids and cable racking materials and guidelines.

Process

Manhole civil designs vary depending on the manhole configuration. For example, a three-way manhole has a different shape than does a two way manhole. Most in service manholes were built many years and were poured in place. All network feeders in downtown Clearwater (supplying a true 125/216V network) have their own network cable manholes/duct lines (not shared with Non- network circuits).

The duct bank configuration can vary depending on infrastructure, but a typical configuration is a 3 x 3 duct bank. Duke Energy Florida is consistent in the assignment of duct positions. For example, primary cables (12470 / 7200V) are always pulled through the bottom duct positions. The neutral (Duke Florida does pull a separate neutral) is always pulled through a duct in the same position (duct number five). Secondary cables are run in the upper ducts.

A standard manhole configuration for Duke Energy Florida includes insulated metal cable racks that support cables, with primary feeders located on the lower racks and secondary feeders on the upper racks see Figures 1 and 2). Duke Energy Florida specifies the position of facilities on the cable racks, with positions closest to the wall being the cable ties across the vault, middle positions being the street mains, and outside (away from the wall) being for services. Each manhole has a ground ring around the roofline tied to a driven ground. Every Duke Energy Florida manhole and vault has a driven ground.

Figure 1: Cables feeding into manhole from duct bank

Figure 2: Cable racks supporting secondary

Many existing manholes contain three primary feeders in one manhole. The designers realize that placing multiple feeders in one manhole increases the exposure and consequences of an event occurring in that manhole. Thus, for newer designs, designers strive to minimize the number of feeders in any one manhole hole. In underground radial designs, cables are routed to avoid a single-point-of-failure by using looped cables from pull boxes.

Duke Energy uses “mole” connectors for secondary cables and applies cable limiters.

Technology

Duke Energy Florida is investigating the application of self-ventilating manhole systems, though hadn’t installed any at the time of the practices immersion. They noted that their manhole tops are not designed with “lips,” making the installation of a Stabilock style system much more problematic. To add the lip to the existing opening would result in an opening which is too small (29 ½ inches). Consequently, to install self-venting manhole systems that require the lip for retention requires a change out of the manhole roofs, which is a costly effort.

4.3.2 - Energex

Design

Civil Design

People

Civil Design is the responsibility of the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

The ducted manhole system at Energex is referred to as the “pit and duct” system. Cables installed within the CBD are run in conduits, typically through a multiple position 5X3 nested duct bank. (Outside of the CBD, Energex uses a combination of direct buried cables and cables installed in conduit.)

The duct bank is comprised of orange, light duty PVC conduits, and is not concrete encased, but backfilled using a sand bedding material.

Note that the location of cable installations within Brisbane is in the assigned electricity supply corridor, which is about one meter from the customer property line, within the “footpath.” Figure 1 shows a typical cross-section.

Figure 1: Example of Energex 11 kV preferred design.

Technology

Cables feeds run in and out of manholes, referred to as “pits.” Pits are normally precast enclosures, with a permanently mounted ladder, but may be poured in place in certain situations. Pit covers are re-enforced steel. Pits are traditionally used by Energex at transition points in the system, such as ingress/egress from buildings, or where conduit runs must go around a corner, cross streets, etc. (see Figures 2, 3, 4, and 5).

Figure 2: Typical pit cover, located in the footpath

Figure 3: Pit covers

Figure 4: Pit, with cover removed (Note permanently mounted ladder on left wall)

Figure 5: Pit, with cover remove

4.3.3 - ESB Networks

Design

Civil Design

See Vault Design

4.3.4 - Georgia Power

Design

Civil Design

People

Decisions about investment in maintenance or repairs of structures such as manholes, vaults, or duct banks are the responsibility of engineers responsible for civil and structural design within the Network Underground Engineering group. This group is responsible for determining inspection approaches for structures, and for developing strategies for responding to inspection findings. In addition, this group develops standards for structure design and repair.

Process and Technology

See Network Design

4.3.5 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 8.8 - System Rehabilitation Reconstruction

4.4 - Key Accounts

4.4.1 - AEP - Ohio

Design

Key Accounts

People

AEP Ohio has Customer Service Representatives that handle all key accounts, including the City of Columbus and the City of Canton governments and public works. Representatives cover key accounts by industry. For example, separate Customer Service Representatives are assigned to public works, manufacturing, major downtown office buildings, etc. They work directly with AEP Ohio’s Network Engineering group. These personnel are geographically based in downtown Columbus at AEP Ohio’s Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, which is part of Distribution Services, and reports ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Key accounts and their specific needs may also come before this committee for discussion and recommendations.

Process

Customer Service Representatives are assigned as key AEP contacts for large projects, such as major new load additions to the network, existing large customers who are adding load, or department of transportation projects which may significantly impact network facilities. On projects that impact he network, Customer Service Representatives work directly with the AEP Ohio Network Engineers that serve the networks in Columbus and Canton. Representatives know exactly which Engineer to contact for their Key Accounts based on the physical location of the account, as the Engineers are assigned a geographic area of responsibility that corresponds to the footprint of their particular networks of responsibility.

The Customer Service Representatives will gather load information and other requirements and supply those to the Network Engineering group, who will be responsible for the ultimate design

4.4.2 - Ameren Missouri

Design

Key Accounts

People

Ameren Missouri has a Key Accounts Group that works as a point of contact for major customers. For these customers, all communications flow through these key account representatives.

Ameren Missouri also has a Business and Community Relations group that interfaces with municipal entities.

4.4.3 - CenterPoint Energy

Design

Key Accounts

People

CenterPoint has a Key Accounts group focused on managing the largest and most critical of their commercial and industrial customer accounts. While commercial and industrial customers represent a small percentage of the total number of customers served by CenterPoint, they represent a larger percentage of the load.

The Key Accounts group is led by a manager and is comprised of eight Key Account Consultants. Organizationally, the Key Accounts group is part of the Major Underground organization, reporting to the Director. CenterPoint made the decision to place this group within Major Underground because a large portion of their key accounts are fed by the dedicated^[1] major underground system. However, the Key Accounts group also interfaces with major customers who are served from overhead distribution and with the CenterPoint overhead Service Centers who serve them. Note that CenterPoint has a separate group that interfaces with key transmission accounts.

The Key Account Consultant is a senior level position at CenterPoint. Candidates for this position are typically seasoned people who have utility experience and know the CenterPoint organization well. The manager believes that candidates from different company backgrounds – engineering, operations, and customer services, can make good Key Account consultants.

CenterPoint also has a position called a Service Area consultant. These individuals work with smaller customers and are situated out in the overhead service centers, not part of Major Underground. Many projects to serve customers through three phase padmount transformer installations work through the smaller Service Area consultants rather than the Key Accounts group.

The Key Accounts group reports that they have a strong relationship with Engineering, and that the organizational alignment with Major Underground is working well. EPRI researchers noted a strong working relationship as well.

The Key Accounts group received a high customer services rating in a 2007 JD Power Customer Satisfaction Survey.

^[1] The term “dedicated” underground at CenterPoint refers to three phase infrastructure is located entirely underground in their ducted manhole system. A dedicated network feeder does not mean that the feeder serves only a network. Rather, it refers to a feeder that is entirely underground. In fact, at CenterPoint, feeders that supply the underground network also supply radial load along the way. CenterPoint has 129 dedicated underground feeders of 1329 total feeders.

Process

The positioning of the Key Accounts group within Major Underground works well at CenterPoint. The Key Accounts consultants can easily interface with the Major Underground field groups, and support construction and maintenance projects by interfacing with the customers, scheduling major construction activities, arranging for scheduled outages, and communicating with customers during unscheduled outages.

The Key Accounts group provides project coordination for new projects, and stays current with the happenings / growth at key commercial customers such as medical centers, municipalities, and universities. They also provide a single point of contact for large national retail chains. They are involved in power quality and reliability issue resolution, relocations, and long term O&M rehab projects. They also interface with governmental agencies. For example, they are working on a process to interface more effectively with FEMA. As one CenterPoint Key Accounts Consultant phrased it, “We represent the interests of the customer within the company. The file never closes.”

CenterPoint has established and published unique telephone numbers to facilitate customers contacting CenterPoint representatives. Each major customer is provided with a card with the contact information printed on it. The larger Key Accounts have the personal contact information of their Key Accounts Representative, including cell and pager number.

Smaller commercial customers have access to a phone number during the day (8-5) that will direct them to an experienced call center representative. Between 5 and 8 pm, these calls will be forwarded to one of the Key Accounts Consultants who “cover” this three hour window using a duty rotation. At night, major customers have a dedicated 800 number to contact the company. If a customer needs help, one of the Key Accounts consultants will call them back.

Each Key Accounts Consultant has a data base of contacts that they send the number to. In advance of the summer storm season, the Key Accounts Consultants will contact their accounts and remind the customer of who the account rep is and the appropriate numbers to call.

For new or upgraded service projects, the Key Accounts Consultants will meet with the customer to understand what their needs are, and to understand their bounds. They will interface between Engineering and the customer to assure that the needs of both are met.

Technology

Key Accounts Consultants need to know about the technologies being employed by their customers in order to keep up with their practices and policies.

Key Accounts Consultants are also familiar with CenterPoint’s MV90 meter reading system for recording 15 minute demand information.

The Key Accounts group is presently working on a state mandated flagging system that will prevent an inappropriate disconnect of a certain critical loads ranging from major hospitals to traffic signals.

[1]The term “dedicated” underground at CenterPoint refers to three phase infrastructure is located entirely underground in their ducted manhole system. A dedicated network feeder does not mean that the feeder serves only a network. Rather, it refers to a feeder that is entirely underground. In fact, at CenterPoint, feeders that supply the underground network also supply radial load along the way. CenterPoint has 129 dedicated underground feeders of 1329 total feeders.

4.4.4 - Con Edison - Consolidated Edison

Design

Key Accounts

People

The Energy Service Organization at Con Edison has various subsections that interface with customers, including the Service Assessment team, Engineering, Layout, and Project Management.

Service Assessment Team

The Service Assessment Team interfaces with the customer or contractor and prepares the load letter, which details the customer work request and scope of the work. They ensure that the load letter includes critical data such as type of use, commercial or residential, information on the number of units, etc. They create a project within a computer system (Commercial Operations Reporting System — CORS) used to track each project. The request then flows to Engineering.

Project Management

Energy Services has two project manager positions — the CSR Project Manager, who manages smaller projects less than 1000 kW, and the CPM Project Manager, who manages larger projects, 1000 kW and greater.

For larger projects, the CPM Project Managers receive the layout and issue work orders to construction management (for contracted work) and electric operations to execute the project. They ensure that the customer gets service on time. They coordinate dates, check the customer’s work to make sure it makes sense, ensure that the termination points are adequate, obtain city approvals, etc.

4.4.5 - Duke Energy Florida

Design

Key Accounts

People

Duke Energy Florida assigns Large Account Managers to its larger commercial and industrial customers. The Large Account Management group is part of the Customer Service organization, reporting to a Senior Vice President. The supervisor of the Network Group maintains close communications with large account managers.

Technology

Duke Energy Florida has installed DSCADA at about 70 ATS locations (Automated Transfer Switches). At these locations, if there is an operation, an alarm would be sent to the DCC, and a text message alarm would be sent to a preselected distribution list, including the Large Account Managers. These Managers will let their customers know that there was an operation, and that they are now being serviced by the reserve feeder.

4.4.6 - Duke Energy Ohio

Design

Key Accounts

People

Duke has Key Account representatives assigned to its largest customers. These individuals back as the interface between Duke and the customer. Many of the operational issues surrounding network customers are ultimately addressed by and resolved by the two Customer Project Coordinators (CPCs)_and Project Engineer focused on the network within the Distribution Design organization.

In addition, the two CPCs act as “key contacts” for customers other than major customers. These individuals respond to customer issues, and per for scratch that and perform all distribution design work for Duke’s Cincinnati network.

The Designers are two-year degreed engineers.

4.4.7 - Energex

Design

Key Accounts

See Project Management

4.4.8 - ESB Networks

Design

Key Accounts

See Program Management

4.4.9 - Georgia Power

Design

Key Accounts

People

Georgia Power has key account managers within its Marketing group that work as a single point of contact for major customers. For these customers, all communications flow through the key account manager. It is not uncommon during the design, construction, and implementation phases for senior engineers within the Network Underground group to work directly with these key accounts, including site visits before and during construction.

Georgia Power also has Community Relations resources who interface with municipal entities.

Process

Georgia Power has developed a guideline that details the steps to be considered for any new large business project. Steps include activities early in the project life cycle such as determining the project scope, gathering load information and performing preliminary engineering; activities to design and construct the new service including completion of design drawings, securing of permits, work order approval and construction support; and activities post construction, such as documentation of as built conditions, and quality assurance. See Attachment B for an outline of project requirements to be considered.

4.4.10 - HECO - The Hawaiian Electric Company

Design

Key Accounts

People

HECO employs Account Managers within the Energy Solutions Department of the Marketing Service Division. These Account Managers routinely interface with customers. For example, they will notify customers of planned interruptions.

4.4.11 - National Grid

Design

Key Accounts

People

National Grid has a Customer Order Fulfillment group that works with customers to manage the progress of projects through their life cycle. The consumer representatives within this group are assigned geographically, and work with network new service and upgrades.

For larger “managed” accounts, including municipal accounts, National Grid has a Support Services Division (Energy Solutions) that consists of Account Executives (6) who work with these major customers.

4.4.12 - PG&E

Design

Key Accounts

People

PG&E has a position called a Service Planning Representative, whose job it is to focus on the customer interface. When a new customer, such as a high-rise building, desires connection to the PG&E network, they apply for service with the Service Planning Department. This department is responsible for gathering loading information/ They also determine whether or not the new customer load will be served by the network or by the radial system.

For the very largest customers, PG&E assigns a major account representative, responsible for all interfaces between PG&E in these major customers.

4.4.13 - Portland General Electric

Design

Key Accounts

People

The design and management of key accounts for PGE, including the network, is the responsibility of Service & Design Project Managers (SDPMs) and Key Customer Managers (KCMs). SDPMs liaise with customers, architects, and contractors to design customer facilities, while KCMs act as facilitators and work with large customers on an ongoing basis. Distribution Engineers work with SDPMs and KCMs on the technical aspects of designs. For key accounts, the Special Tester or an Infrared (IR) Thermography Technician test primary feeders and network protectors, and may provide services on secondary systems where resources permit.

Service & Design: Service & Design’s role is to work with new customers or existing customers with new projects, making it responsible for new connections, new buildings, and remodeling. The supervisor for Service & Design’s wider responsibility includes the downtown network. The supervisor reports to the Service & Design Manager, who is a peer of the Distribution Engineering and T&D Standards manager. Both positions report to the General Manager of Engineering & Design.

The Supervisor of Service & Design at the Portland Service Center (PSC) and its team undertakes capital work initiated by the customer. The “Mapper/Designer” reports to the Supervisor of Service & Design at PSC and provides the computer-aided design (CAD), geographic information system (GIS), and design service.A Field Inspectormeets with contractors. Two inspectors work for the Service & Design organization, and one specializes in the network.

Service & Design Project Managers (SDPM): Network planning associated with customer- driven projects requires regular coordination with the customer throughout the project life. PGE has a position called a Service & Design Project Manager (SDPM), who works almost exclusively with externally-driven projects, such as customer service requests. At present, two Service & Design Project Managers cover the network and oversee customer-related projects from the first contact with the customer to the completion of the project. They coordinate with customers to assure that customer-designed facilities comply with PGE specifications.

The SDPMs can be degreed engineers, electricians, service coordinators, and/or designers. Ideally, a SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. In addition, SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC) and the ability to use or learn the relevant information technology (IT) systems. PGE prefers a selection of SDPMs with a diverse range of experience and backgrounds.

SDPMs work on both CORE and non-CORE projects. This ensures that expertise is distributed and maintained across departmental and regional boundaries.

Key Customer Manager (KCM): PGE has nine KCMs reporting to Manager of the Business Group. Generally, they are geographically distributed, with three on the west side, one downtown, one in Salem, three on the east side, and one acting as a rover. The KCM responsible for downtown Portland primarily focuses on network customers. KCMs liaise with large customers and communicate their needs.

Process

QRP Customers: In 2004, PGE offered the Quality and Reliability Program (QRP) to high-value customers requiring high reliability. This program entails a high-level focus on quality and reliability, and targets 24 high-profile distribution and transmission customers [1].

QRP customers receive reliability reviews from PGE, including:

An annual walk through inspection of underground facilities, including infrared (IR) and visual inspections of equipment such as splices, connectors, transformers, and pad-mounted switches
Suggested targeted reliability improvement projects, including liaising with some major customers concerning distribution automation pilots
Power quality metering with I-Grid or PML
Tracking SEMI F47 power quality events, including momentary interruptions
Root cause analysis for any events affecting service
Meetings with account representatives, engineers, and field staff

As part of QRP, IR thermography inspections are performed on network infrastructure on a four-year cycle. This inspection includes all the primary infrastructure beginning at the substation and including the network unit. The Special Tester or an IR tech perform inspections. Where resources permit, they may also IR test secondary systems.

PGE performs other activities as appropriate to bolster the reliability of the infrastructure to key customers. One example is the use of standby generators at one major customer to improve reliability and increase capacity. At another major customer, PGE is piloting the use of bolted connections for splices instead of compressions connections, which have been traditionally used. For the purpose of this pilot and to meet customer expectations, PGE photographs each of the splices and the Standards Group tracks the performance of the bolted connections.

Customer Requests – Additional Load

Customer requests to add load can initiate through a contact with a KCM (for larger customers) or SDPM. PGE utilizes a one-note “database” to track the new or proposed construction in the downtown area. The database acts as a way to record and monitor information on different projects due to the large volume of projects across the downtown district. The database also includes some projects in the River District not serviced by the CORE network despite being downtown. Much of the proposed work is tentative; consequently, this information is tracked but not used for load forecasting. The manager of the SDPMs reviews this information to track progress and determine when anticipated projects will occur.

Once a project starts, the customer submits a “Service Coordination Request,” and the project is assigned a Maximo project number. The network KCM continues to track the proposals and follows up when the proposal becomes an almost-complete building after construction. The KCMs seek to understand the customer’s needs from a service perspective, such as what load will be anticipated. The KCM coordinates with the SDPM and the building developer, with the SDPM directly involved in the technical and electrical design alongside the building owner. The KCM hands the project to the SDPM, and continues to be involved with the building owner, developer, and manager to ensure that they are getting the service from PGE that they need. Overall, the KCM acts as a facilitator.

Maintaining Customer Details: The engineering team and KCM create and maintain a list of the major properties on the network, including vault numbers, network and feeder circuit identification, the names of the property managers, and contact information. They also note any particular issues with the vaults, such as vaults that are prone to flooding because they are below grade, or vaults that are located near dry cleaners and receive a lot of lint and therefore require periodic cleaning.

Solar Panel Installation Requests: If a network customer seeks to install solar panels, the KCM puts them in touch with PGE’s interconnection group, who will perform an analysis to determine interconnection requirements.

Explaining Customer Outages: If network customers experience an outage or reliability issue, the KCM will follow up with the customers to explain the network’s design, issue, and resolution. The KCM may engage other PGE technical experts to deliver information to customers.

In preparing these presentations, KCMs modify a set presentation designed for new customers explaining the network system. After an outage occurs, they modify the presentation with specifics about the outage. The experts explain the following:

Maintenance of the vault that is necessary by PGE
N-1 and N-2 scenarios
Possible curtailment of load scenarios and why PGE would ask for it
Particulars related to the outage or other issue

If the customer is subject to a planned outage for maintenance, the KCM is not necessarily made aware of this but will always become involved for unplanned outages. The KCM will be aware of any long-term maintenance work that PGE undertakes in a particular area so that they can respond to customer inquiries.

Civil Structure Issues: If the crews encounter a civil issue with a customer-owned vault that houses PGE network infrastructure (typical for spot network vaults), then the KCM communicates with the customer to maintain and repair the structure. For example, if crews find that the ventilation system in a vault is not working, the KCM reports this to the customer. KCMs work with building managers to coordinate annual testing of vault smoke detectors by the city fire department, as these inspections require the presence of a PGE crew. The KCM will arrange for the crews to be present when the inspections are performed.

The KCM coordinates with the building management to make sure that crews can access the vaults. On some occasions, building security considerations must be addressed in order for crews to bring tools and equipment into certain vault locations.

Substation Outreach: The KCM is involved in outreach to the customers regarding the construction of a new network substation. The KCMs deliver presentations on the project to both business owners/managers and an organization known as the Business Alliance in Portland. The KCM works with engineering to notify customers of when PGE accesses the vaults as part of the project and how the work associated with the project impacts the customer’s service.

Reliability Centers: In its Portland service territory, PGE has three reliability centers intended to serve businesses with high reliability requirements. One of these centers supplies the networks system, which is highly reliable, supplied by two substations, and designed to N-1. Notably, PGE has two additional reliability centers to supply key customers with radial designs that utilize redundancy and high-speed switching technologies to assure reliability [2].

J. Johnston. Portland General Electric’s T&D System Reliability Programs – Striving for Operational Excellence. Portland General Electric, Portland, OR: 2009. http://www.energycollection.us/Energy-Reliability/Jim-J-PGN-Reliability-Seminar.pdf (accessed November 28, 2017).
Reliability Centers. Portland General Electric, Portland, OR: 2017.https://www.portlandgeneral.com/-/media/public/business/grow-my-business/documents/reliability-centers.pdf?la=en (accessed November 28, 2017).

4.4.14 - SCL - Seattle City Light

Design

Key Accounts

People

SCL employs Customer Service Representatives who interface with customers.

Process

SCL convenes a biweekly crew coordination meeting focused on the project status of each active network project. Meeting participants include supervision and others from the network design group (engineers), civil crew representatives, electrical crew representatives (including crew leaders), and customer service representatives who interface with customers. This forum has been a highly effective project management tool for SCL in updating project status, resolving problems, and meeting project goals.

4.5 - Mapping - Recording “As-Builts”

4.5.1 - AEP - Ohio

Design

Mapping/Recording “As-Builts”

People

Mapping and documentation of the network are the responsibility of the Network Engineering group and the Network Engineering Supervisor at AEP. A Technician who reports directly to the Network Engineers maintains network maps, including recording and mapping “as-built” changes to the network into the permanent records.

Process

Maps associated with the network are maintained by a technician within the Network Engineering group in close consult with the network engineers. Existing maps are used as a basis for preparing job drawings for particular projects. Engineers prepare drawings using MicroStation and AutoCAD. Upon the completion of any construction project that alters the configuration of the network infrastructure, including vaults, substations, manholes, duct lines, etc., the crew leader will mark all as built changes on the duct and manhole one line and return to Engineering. The Network Engineers compile the as-built drawings that are returned from construction, and assign the updates to the Technician within the Engineering group to update the changes onto the electronic drawings (using MicroStation and AutoCAD), as well as update the CYME models, where appropriate. In parallel, the GIS system (Smallworld) is updated for company-wide access.

In the course of any vault, substation, or manhole inspection, personnel check the “on-the-ground” layouts and construction to make certain it matches existing records (see Vault Inspection). If any discrepancies are noted, the personnel make a note of them and forward them to the Network Engineering group for verification. If changes are required to the “as-built” records, they are forwarded to the Technician for electronic updates and exported to Smallworld.

AEP does not have a separate inspection program that audits as built conditions with designs. It is the responsibility of the crew supervisors to inspect projects to assure that construction meets design expectations, and that any as built changes to the design are properly recorded.

Technology

The network engineering group prepares and maintains various maps of the network infrastructure including:

Circuit One-Lines – These maps provide a plan view of the location of the circuit, and include the manholes and vaults on each circuit. The maps includes cable information and distance information. Circuit one-lines are used as a starting point for building circuit models within CYME.

Switch Chart Drawing – These are one-line drawings for the primary that show the electrical schematics of the spot network vaults. For grids, these maps indicate which primary circuits supply each grid. Switch chart drawings are maintained by the Engineering group and are placed on an internal website for use by the dispatchers and field crews.

Duct and Manhole One-Lines – These are drawings that indicate the duct bank configuration, and what cables are located in the ducts. These drawings are updated based on inspection. They also show the position of secondary cables on crabs. These drawings are used by field crews in performing construction or system reinforcement work in ducts and manholes (see Figure 1).

Figure 1: Sample project drawing using duct and manhole one-line as a base

Secondary Maps – AEP Ohio has recently conducted an inspection of the entire network and has created a new set of updated secondary maps that display cable and cable distance information. These maps will be maintained with information identified during periodic inspections.

4.5.2 - Ameren Missouri

Design

Mapping/Recording “As-Builts”

People

Maps and records for the Ameren Missouri network infrastructure in St. Louis are maintained by the Engineering Records Group, part of Missouri Operations within Energy Delivery Distribution Services. The Engineering Records Group is lead by a supervisor and is comprised of drafting technicians.

Process

When an estimator prepares a job, he conducts a manhole visit to verify the distribution plan within the hole, as existing maps may not accurately reflect the in service manhole configuration. Estimators visit the manholes in two person teams and photograph the manhole configuration. The estimator may then use the existing maps as a starting point for a new construction drawing by converting the existing mapping information to AutoCad drawings.

When the project is released to construction, a preliminary drawing showing the design is sent from the estimator to Engineering Records. A job drawing also accompanies the project that flows to construction.

When the job drawing goes to construction, the construction foreman indicates any changes in the “as-built” construction from the design depicted on the drawing by marking the as – built changes to a plat map and stamping the drawing as an Official Record Copy (ORC). This ORC then goes to the drafting department within Engineering Records who updates the official maps and records to reflect the as-built conditions.

For changes that affect operations – such as changes to operating one lines that impact circuit configuration or sectionalizing points - the dispatcher prepares a Map Correction / Change Request form (informally called a dispatcher note) that indicates the changes in system configuration to be modified on the maps. This form triggers the Engineering Records group to call up the preliminary drawing provided by the estimator and make any changes that affect electrical connectivity or switching to the operating (Byers) map. Engineering Records will make operating map changes within one to two days of receiving the dispatcher note.

Technology

Ameren Missouri has a good set of maps depicting their network infrastructure. Maps include:

Operating Map (Also called Byers map) – This is a map showing electrical connectivity, used for switching. Usually updated within one to two days of receiving the Dispatcher Note. This map is available to Troublemen on a laptop computer in the trucks,
Plat Maps - Detailed maps of the network area, showing all geographic facilities on a block-by-block basis. These maps are geographically correct, and show duct bank cross-sections. Usually updated within one month of receipt of the ORC from construction.
Cable Route Maps – These maps are basically feeder one lines, depicting the route of the feeder from the substation to termination. They also show all of the manhole locations. These maps contain more detail than the operating maps. Cable Route maps are updated within one to two days of receiving the Dispatcher Note.
Switching Maps - These maps are similar to the cable route maps, but also show switching devices. These maps are updated within one to two days of receiving the Dispatcher Note.

Network infrastructure is represented in a GIS – BYERS system.

Ameren Missouri is in the process of converting to a new mapping system, Gtech. At the time of the practices immersion, Ameren Missouri had not yet decided how the new mapping system would be used with network facilities.

4.5.3 - CEI - The Illuminating Company

Design

Mapping/Recording “As-Builts”

People

The CEI Maps and Records department is part of their Engineering Services Group. This department is responsible for all maps and records in the Region. The department is comprised of 11 people total, with 1-2 people focused on the underground. ¾ of an FTE resource is focused on updating records. The department employs both exempt and non exempt non bargaining employees.

In addition, the CEI UG Network Services department has an Advanced Distribution Specialist who works closely with Maps and Records, and maintains certain records information within the Underground department.

Process

The Maps and Records Department maintains maps, continuing property records and information systems, such as GIS. These systems may not contain information to the level of detail required by the Underground department. For example, some underground information, such as manhole details, is kept on manhole prints rather than company information systems. The Maps and Records department also produces a Circuit Identification book that defines labeling practices for the Illuminating Company.

When a job package arrives in the Underground department from Engineering, it may be accompanied by a CAD drawing, or may simply have a marked up map or print. Larger, engineered jobs are accompanied by a “Work Request”, which establishes the project in CEI’s computer system. Work requests for other smaller projects, such as repairing a burned out cable, will be generated by the Advanced Distribution Specialist within the UG department, and do not flow through Engineering.

On a large job, CEI will order the material prior to performing the work. On other jobs (most jobs), the material is assigned to the project after the work is complete. When the completed work package is turned in to the office, the Advanced Distribution Specialist within the UG department will review the material that was used, and then record the use of that material in the system – this will charge the material to the job and replenish the stock.

If field makes modifications to the design, the field crew will mark up the changes in red on the job print. For example, engineering will specify which duct a new cable should be pulled through. When the field crew rods the duct, they may find it blocked and choose another duct. The construction supervisor will note the change on the print and sign and date the print, acknowledging the change to the design. The changes are forwarded to the Maps and Records Department.

On average, it takes about 2 months for changes to be reflected in the mapping and records systems – one month work back log, and a month to make changes and produce an updated microfiche. For feeder prints, the Maps and Records group works closely with the Regional Dispatching Office to assure that these maps are up to date within about three days.

Technology

CEI does a thorough job in records keeping and relies heavily on manual maps and prints for their underground system records, and in performing their work. For example, manhole prints are relied on heavily to identify cables in a manhole, as CEI does not tag or label cables in the hole. If they discover a discrepancy between the records and the field, they will stop a job until they can verify.

Example prints used by CEI include:

Manhole prints, which are drawn and maintained manually or in CAD (SHL Vision – Autodesk 3D map), are used for identifying cables, as they show the position of cables in duct bank. (See Attachment - E. )

In fact, the only tag placed in the manhole is an aluminum tag placed under the lid with the manhole number. Other that this, there is no labeling in the manhole. The mapping system is a critical tool at CEI in cable identification, along with other techniques, such as using a sound coil to identify cable.

Conduit Sheets, which are also drawn and maintained manually or in CAD, are used to show the duct routing between manholes and vaults. (See Attachment F )
Feeder Maps, also drawn and maintained manually or in CAD, show the routing of an individual feeder, including vault locations. Note: CEI will also record the locations of transition joints on the feeder maps.
Customer Connection Diagrams (internally referred to a 3CD diagram), also drawn and maintained manually or in CAD, are similar to the manhole prints, and show the feeds into the transformers within the vaults.

(See Attachment - G)

CEI will scan their maps and issue a CD to the field every six months. The CD information is loaded onto lap top computers. These laptops and a small printer are used by troubleshooter crews.

Historically, records of cable installations and the work orders under which they were installed were kept manually in “cable mortality books”. The present practice is to track the cable installed date and work order number in their GIS system. Note – GIS does not include the history from the cable mortality books.

GIS also contains information about underground distribution transformers, including purchase date, installation date, company number, impedance, size, manufacturer, taps, gallons of oil, etc. Transformer test results are kept manually in a file in the underground department. Ultimately, CEI may elect to house this information in a new Cascade system they are implementing.

Oil Switch records are maintained in the Underground department in an Access data base. Oil switches are not serialized. These records include location, manufacturer, type, rating, and whether the device is remote controlled.

Network Protector information is kept in a manual file in the Underground Department. CEI has 61 network protectors.

4.5.4 - CenterPoint Energy

Design

Mapping/Recording “As-Builts”

People

CenterPoint has a GIS Mapping group that is responsible for maintaining company mapping systems. Two GIS Mapping resources (GIS Technicians) focus specifically on supporting the mapping and records needs of the Major Underground group, and are assigned to work in Major Underground, as matrix employees. Note that these technicians are contractor employees, as CenterPoint has outsourced its maps and records maintenance. The GIS Mapping resources maintain both electronic maps and hand drawn maps.

The CenterPoint employees interviewed by EPRI researchers in general feel that their maps are accurate, and kept up to date in a timely fashion. They have not experienced operating errors driven by map inaccuracies.

Process

CenterPoint’s GIS mapping resources are integrated into the work order process. When the Construction department supervisor receives the work order from Engineering, the GIS technician receives a copy also. This provides the Technician with a preliminary indication of the work to be done. This preliminary information will include project drawings prepared by the Engineering department in Microstation. For example, a vault design will include a detailed vault schematic prepared by the Vaults group within engineering.

As the construction is completed, crew leaders will request a switching order from Dispatch indicating that system configuration is changing. Copies of the completed switching orders are sent to the GIS Technician, so that he is up-to-date on the most current system configuration. He will match up the switching order with the appropriate work order in the GIS Tech files in advance of the project completion – this enables him to get started on the mapping even in advance of the job’s final completion, minimizing the mapping turnaround time at the completion of the project.

When work in the field is complete, “as built” drawings are returned to clerks in the Major Underground construction office. These clerks forward copies of the work to CenterPoint Records where copies are stored in Filenet. After being recorded, the Work Order package flows back through the GIS Technician. This work order package includes a copy of the engineering sketch, which serves as a basis for a work center drawing, which documents the construction in a new facility.

For new projects, within one week of the completion of the work, the GIS Technician will go into the field to verify what is in the field against the maps and project drawings. This verification can include wheeling measurements to confirm distances described in the design. CenterPoint’s experience is that the information on the work order is usually correct, but that sometimes in the field, conditions will change. (Crews will usually mark these changes on the work order as an “as built”).

From the “as built” work order package, the GIS Technician will prepare map drawings using Microstation. For pad mounted transformer locations, he will prepare a “Work Center” drawing See Attachment B , which shows the installation as well as some geographical information associated with the site. Work Center Drawings can include a plan view and a schematic if necessary. For dedicated^[1] underground installations, the GIS Technician will prepare a “Dedicated Map”, which shows the electrical layout, duct bank information, and some geographic information See Attachment C. Both the Work Center Drawings and Dedicated Maps are provided to field crews and kept in map books on the trucks, or are viewable through mobile work stations. . Both the Work Center Drawings and Dedicated Maps are provided to field crews and kept in map books on the trucks, or are viewable through mobile work stations.

In addition, for dedicated underground circuits, the GIS Technician creates and maintains Dedicated Underground One Line maps See Attachment - D , that shows the entire circuit from the sub out. It also indicates the work centers (such as vault locations) along the circuit path. These one line drawings are accompanied by blank switching order documents which can be used by dispatchers to create switching orders for working on the line.

The GIS Technician creates the work order Substation One Line drawings showing the underground facilities within the substation.

The GIS Technician maintains a file of manhole prints See Attachment - E , which shows the duct bank detail within manholes. These prints are created by the field crews who perform the cable installation, and show the position of feeders in the ducts on a hand drawn print. The GIS Technician is in the process of re-drawing these manhole prints in Microstation.

Finally, the GIS technician enters information into CenterPoint’s GIS system, Arc Map. This includes the location of splices, and fiber cable routes within the ducted manhole system that support the remote monitoring system. Note that CenterPoint is populating the GIS with new information, while at the same time converting existing records into GIS. The GIS system will ultimately produce maps that will replace the Dedicated Underground One Line drawings. The GIS information does serve as the foundation for the graphical switching software being used in CenterPoint’s Dispatch Center.

Center Point’s backlog for updating their mapping changes based on completed “as built” drawings is two weeks.

Technology

CenterPoint is using a GIS database by ESRI (Arc Map). They are using Microstation drawing software to generate most of the maps used by Major Underground.

Example maps / prints used by CenterPoint include:

Work Center Drawings (showing pad mount locations)
Dedicated Maps (Showing Major Underground service locations )
Dedicated Underground Onelines
Manhole Prints (Showing duct bank detail)
Vault schematics (Developed by the Vaults group, within engineering)
Substation Online Drawings

^[1] The term “dedicated” underground at CenterPoint refers to three phase infrastructure is located entirely underground in their ducted manhole system. A “dedicated” network feeder does not mean that the feeder serves only a network; rather, it refers to a feeder that is entirely underground.

4.5.5 - Con Edison - Consolidated Edison

Design

Mapping/Recording “As-Builts”

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Engineering and Planning - Responsibilities include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Mapping “As-Built” System Configuration

Con Edison creates a “before” and “after” sketch of its projects. These sketches facilitate understanding of the changes in field conditions to be made by a project. When a project job is completed in the field, the “as-built” field conditions are reflected on the electronic maps within 72 hours of energizing. On larger jobs, new transformer locations are pre – mapped to expedite the mapping process, so that maps expeditiously reflect field conditions.

Con Edison’s focus on ensuring that maps are current stands out as an important practice, as up-to-date maps are an important tool in the safe operation of the system.

Technology

Mapping Systems

Con Edison’s distribution system is mapped on three different mapping systems. Manhattan, Queens, and Westchester use one system; Brooklyn uses another; and Staten Island uses a third.

The mapping system developed as three different systems, because of the long time required to digitize the facilities. Con Edison’s long-term vision is to combine the three mapping systems into a common system.

Historically, Con Edison has developed and modified technologies with its own people, and often assigns people internally to manage these technologies, as opposed to buying technology off the shelf. Con Edison attributes this approach to the utility’s unique requirements as an all underground network, N-2 utility. “We are belt and suspenders and have to be sure we can maintain the N-2.”

4.5.6 - Duke Energy Florida

Design

Mapping - Recording “As-Builts”

People

Duke Energy Florida has a mapping group called the Geographic Mapping and Analytic Design group (GMAD). This group consists of two groups: an “analytics” group that deals with geospatial operations, including GIS, and a “design” group that deals with designing subdivisions and the associated land base. This group organizationally is part of the Engineering Construction and Planning organization.

The GMAD group is responsible for maintaining system maps and GIS. For new subdivisions, the design section of the GMAD group would perform the design associated with serving subdivisions. The GMAD group receives the subdivision land base information from the subdivision, and uses automated design software (Automated Plat Design – APD) to lay out the design. Note that this work does not apply to network design.

Within the GMAD group, the analytics side deals with creation and maintenance, including field corrections, of the maps and records. The GMAD group has a position called a GIS Technician, responsible for performing the GIS map and records updates. The GIS Technician is a job family, with the GIS Technician II typically having extensive experience with not only the GIS system but also with all Standards practices and processes in Florida, including manholes and vaults.

The staffing in the GMAD group consists of 25 resources plus about 10 contractors.

Duke Energy Florida has its entire distribution system represented in GIS, including primary, secondary, and services. The location of manholes, vaults, and primary cables associated with the network are also included in the GIS. The exception would be the position of the secondary network cables in the Clearwater network grid, and detailed information about manhole and vault configuration, which are recorded on separate, manually maintained drawings within the Network Group. In the GIS system, Duke Energy has assigned customers to transformers to support their outage management systems. For the network customers, they have attempted to assign specific customer loads to transformers though network customers are serviced by the grid.

Duke Energy Florida maintains accurate as-built manhole and vault drawings for its network facilities in both Clearwater and St. Petersburg. The manual drawings do reflect the detailed information of the underground. The field forces at both locations have high confidence in the manual drawings. PDF copies are available through links in the GIS.

At the time of the practices immersion, Duke Energy Florida had assigned a Subdivision Design Supervisor the task of updating the company’s GIS system to accurately reflect network infrastructure. This project includes incorporating network system drawings into the current GIS mapping system. Assisting in the GIS update for the Duke Energy Florida network is a full-time contractor responsible for entering the approved network maps and any corrections into the system under the guidance of the GIS Technician. This contractor is physically located with the Network Group, in Clearwater.

Process

Duke Energy Florida has seen little new construction in the network. Thus, the bulk of the mapping work has been update of the existing GIS. For new construction, the process for updating the maps begins on the back end of the project, when the as built drawing is complete.

The GMAD contractor resource who has been assigned to the Network Group, is responsible for all map updates. The as-built drawings are provided to the contractor resource, who will update both the GIS system, and separate network maps which are maintained electronically in Microstation. These documents are then converted to PDFs and placed on a shared server so that they can be accessed by employees through the GIS (see Figure 1). GIS contains links to all of the manually maintained network maps, including vault and manhole drawings, as well as Excel files of information sheets which include vault and manhole component details, such as cable sizes, cable age, etc.

Figure 1: Example of Manhole Drawing, PDF map available in GIS

If there are changes to be made to the GIS system as a result of work in the network, these updates are also handled by the contractor resource in the Network Group

If there is a field change to the design, field corrections are noted by a Network Specialist on an as built drawing. Changes in field design are normally not reviewed with the designer unless they are significant. In some cases, such as a significant change in the quantity of requested materials, the designer may be notified based on exception reporting from the work management system, designed to call out cases where the quantity of material used may exceed a pre-determined accepted variance.

While most map changes are made after the completion of construction, some field corrections flow to the GIS team ahead of construction. An example would be an addition or update of a switchable device. This type of change is pre-posted to GIS as it affects system operations and must be readily available to the DCC.

Duke Energy Florida has a backlog of as built drawings to be updated. The contractor assigned to the underground department is working to remove the backlog. The current backlog time before as-built drawings are updated on the maps is several months.

Quality Auditing

GIS Technicians perform periodic random audits, where they select random Microstation manhole drawings and make sure that the information matches the information in the GIS. This includes material lists, circuit numbering, schematic accuracy, etc. When updating maps, if the mapping group has questions, they will send it back to the Network Group for clarification.

On occasion, Network Specialists will enter manholes and redraw the manhole interior to assure its accuracy.

Equipment information, such as the location of splices, work order information, cable sizes, voltage class, duct position, and equipment serial numbers, is kept in the as-built manhole and vault drawings. These are contained in the Excel spreadsheet links on the GIS maps (see Attachment E for a sample of a manhole records sheet). Whenever a drawing is updated, the Excel spreadsheet is also updated. More detailed part information is tied by serial number into the online work management system.

Network Mapping Update Initiative

In late 2015, the company began a new initiative to update network drawings. A full-time contractor (KCI) based in the Network Group was hired to assist in the project. The first step was to match the GIS network maps with the manhole drawings maintained by the Network Group (see Figure 2). Note that the field crews maintain and use manually updated maps, which they feel very confident about. The challenge is to assure that the updated GIS accurately reflects conditions in the manholes, and to assure that any changes in the field are posted in a timely manner in the GIS.

Figure 2: Excerpt from network primary feeder map, maintained by the Network Group

Within the updated GIS there are three layers: the paper-to-electronically converted map, standardized symbols on the GIS maps that represent components and electrical connections, and a third layer of links embedded within these symbols that bring up PDF/Excel information. One problem in the past has been standardizing the symbols and making certain that GIS operators use the appropriate symbol for linking to the correct underlying PDF/Excel files.

To assist in any ongoing changes (beyond reconciling hard-copy maps with GIS), the company is moving to GE’s Smallworld system (replacing Intergraph) and is considering software called Fusion, a version documentation program that will assist in assuring that the map update process is tracked. Using this combination, the company will have version-control over map revisions; any change, who made the changes, and when changes were made then will be in the system. In turn, these can also be exported to PDF and Excel files for inclusion into the GIS system. For this system to operate efficiently, any changes made in the field must be sent immediately to the GMAD group to be fed back into the system.

The company is also looking at a Web-based compliment to Smallworld called Myworld. The application overlays all major systems within Smallworld (cable runs, manholes, easements) onto a satellite-based map.

Technology

The GMAD group uses G/Technology, an Intergraph system, as its GIS system. At the time of the practices immersion, Duke Energy Florida had embarked upon a transition to a new GIS system, GE Smallworld.

Detailed maps, finalized design plans, and material and component lists are generated on Microstation and then fed into the GIS system in the form of PDF files (maps) and Excel spreadsheets (material and component lists).

Dispatchers use the GIS PDF files, but for detailed electrical schematics they use a static, web-based system called Map Board, which they find easier to uses than the OMS.

All field crews are connected via mobile devices, typically laptops. Most trucks are also outfitted with printers to get hardcopies of the PDF maps on the job site.

Duke Energy Florida does not keep photographs of manhole and vault interiors as part of its permanent record.

4.5.7 - Duke Energy Ohio

Design

Mapping/Recording “As-Builts”

People

Duke Energy Ohio has a maps and records group located in downtown Cincinnati.

The Maps and Records department is comprised of technicians who maintain the maps and records for Duke Energy Ohio. All completed construction drawings, and most map changes flow through this department.

For example, changes to the Cable and Conduit (C & C) drawings for the downtown network, usually come from the design organization. These drawings, showing details of manhole locations and the duct positions of cable within network manholes, are manually marked up showing changes in configuration by the Customer Project Coordinators (CPCs) within the Design organization. These changes typically flow through the Network Planning engineer, and then to Maps and Records for permanent update.

Process

Designers (CPCs) will create construction drawings. Often times, existing CAD drawings will be used as a starting point, with the changes marked on top of the existing drawing. This is typically done in either Microstation, or in Expert Designer.^[1]

For emergency work such as rerouting a feeder in an emergency, field crews will work with the planning engineer, network engineer, or construction supervisor to prepare a hand drawn sketch of the new route. This drawing is then used to drive changes to the permanent mapping systems.

When a project is completed, the crew foreman or supervisor submits via fax or e-mail the completed construction drawings to the maps and records group, who are responsible for updating the permanent maps and records.

When a construction crew deviates from the design drawings, they will note their changes by redlining the construction drawings. These red line drawings are then sent to maps and records at the job conclusion for permanent map update.

Duke Energy Ohio has several processes in place to assure the integrity of the maps.

Periodically, they will send mapping personnel into the field to perform an audit of what they find in the field against the mapping system.

Also, a check of the maps is included in the manhole inspections. Inspectors will “red line" to cable and conduit (C&C) drawings, indicating changes to be made to the maps so that they accurately represent field conditions. The changes are then made to the permanent C&C drawing by the Maps and Records department.

Duke personnel noted that there is no formal audit process comparing as built construction to design drawings on a job or job basis. They rely on a constant strong relationship between engineering, construction, and the maps and records group. Duke Energy Ohio crews will have a copy of the manhole drawing with them when they enter a manhole.

For mainline feeder work, maps of the completed construction are created in advance, so that when the system configurations are made in the field, the maps are prepared for a quick update.

Duke personnel noted that the turnaround of map changes is improved over years past. This is in part driven by the fact that certain records, such as Duke’s GIS records, drive the outage management system. Duke personnel reported their mapping systems are fairly accurate.

Technology

For Network Systems, Duke Energy Ohio is utilizing various types of maps.

A conduit and cable (C & C) map, detailed map showing physical manhole locations, manhole conduct positions, etc. See Attachment A for sample C&C Map
Network Feeder maps, which show the circuit route and the location of Transformers. See Attachment B for sample Network Feeder Map
Secondary main sheets, showing the secondary system for an entire network. See Attachment C for sample Secondary Main sheet

Duke Energy Ohio is using the Small World GIS system to represent the radial portions of their distribution system. Note that the network system is not modeled in Small World.

^[1] Expert Designer was being implemented at Duke Energy Ohio at the time of this practices immersion.

4.5.8 - Energex

Design

Mapping/Recording “As-Builts”

People

Mapping is the responsibility of Data Services and Demand Management group, part of Asset Management, led by a Group Manager. The Data Services area is broken up into two teams.

One is the operational and transactional data team, which is responsible for entering information from the field into the company data systems, including maps. The other is the strategic data team, which is responsible for leveraging the information in the systems for the betterment of the company.

One of the systems maintained by this group is the enterprise asset management system, which is a 30 year old in-house developed Oracle database that services as an asset register. Energex also uses an ESRI GIS system, which is linked to their asset register.

Process

Energex has recorded the CBD infrastructure in their Asset Management and GIS systems and produces various map products out of these systems, including UG duct maps, primary feeder maps, and low-voltage system maps. Maps show the location of joints. Maps are available to employees via on line systems, but are not available to the field force through their mobile data application.

At the time of the immersion, this group was looking at developing a transition plan to replace the system with a commercially available product, as the existing system has many interfaces with other systems and is thus, unwieldy to update. Along with this, Energex wants to replace its GIS system.

In the hub locations, Energex maintains hard copies of the UG maps. Noncritical changes in field conditions are updated in the hub locations on these manual maps, which are updated on the permanent maps by the mapping group once a fortnight. For higher priority updates, Energex responds according to requirements. For example, their Distribution Management System (DMS), Power On, is updated to reflect switch position changes, real time (done by control room operators).

The company has established metrics for map updates. Field crews have a target of 10 days after work is complete to sign off on the as built drawings and return them to the mapping group. The mapping department has a target of 10 days to complete the map update upon receipt of the “as built.” Performance against these metrics is included in the company performance management system, which affects bonus payments.

Historically at Energex, about 15 percent of the “as built” jobs were completed differently than designed.

Energex has implemented a monthly audit process within the mapping group to assess the following:

Quality of the data entry by the entry team.
Quality of the data in the system
Field checks on the work.

Energex samples about 10 percent of the work for the purposes of performing these audits. The company has two resources that focus on comparing what is built in the field with what has been reported on “as built.” If these resources uncover systemic problems, Energex feeds it back to the appropriate groups, such as Procurement or Standards.

Technology

Energex uses an Enterprise Asset management system based on an Oracle database, developed in-house, that serves as an asset register. Energex also uses an ESRI GIS system, which is linked to their asset register.

4.5.9 - ESB Networks

Design

Mapping/Recording “As-Builts”

People

ESB Networks has a centralized mapping organization (Central Site) for maintaining maps and records of their MV and LV systems in Dublin. The Central Site is responsible for maintaining the facilities management system, DFIS. This organization is led by an Engineering Officer.

The LV maps for the city of Dublin are very detailed and meticulously maintained, as field crews depend on these maps to find junction points within the secondary system to perform sectionalizing. Many of the junction points and “T’d” services are buried, with no aboveground indication of their presence. (The city of Dublin prevents ESB Networks from using aboveground mini pillars.)

Process

ESB Networks Network designers (Engineering officers) use a system called GeoDart – an Intergraph drawing tool – to prepare design drawings, such as a design for connection to a new customer. This system is integrated with the DFIS system, so that a copy of the design drawing is maintained in DFIS. When construction is completed, the construction group sends an “as built” drawing back to the central mapping group. The central mapping group updates the design drawing to reflect the as built conditions, and the GeoDart drawing updates the permanent record in DFIS.

All staff are encouraged to ‘mail in’ corrections if they identify map errors. Corrections are mailed to Central Site, who are responsible for the map integrity, and will accept a correction drawing in any format, including freehand sketches.

ESB Networks performs periodic quality audits, in which a supervisor performs a field assessment of a completed job, examining the quality of construction against both the design and against ESB Networks’ construction standards. Supervisors in each area are required to perform a number of these audits each year.

ESB Networks also performs periodic design audits, in which the design is compared to standard design practices. These audits are implemented by the central design organization.

Technology

ESB Networks uses a geographic facilities information system called DFIS – an Intergraph product. This system is used to record all distribution facilities information, including the LV, MV and 38-kV sub-transmission systems. DFIS serves as the real-time asset register.

ESB Networks also uses a system called GeoDart – an Intergraph drawing tool that is integrated with the DFIS.

The DFIS representation of the system also feeds into the ESB Networks OMS model, which is used to manage the response to outages and to reflect real-time conditions of the system as it is operated, through an overnight update. Note that the OMS system at ESB Networks is integrated with SCADA, such that breaker operations are reflected in OMS. MV maps from the OMS are displayed on the dispatcher console. The LV network is not.

Network Technicians have copies of the MV DFIS maps on their trucks. LV maps are not kept on the trucks.

ESB Networks is in the process of implementing a new mapping system that will include the LV network (see Figure 1 and Figure 2). Note that the LV system has been digitized, but has not been loaded into the existing DFIS.

Figure 1: LV map

Figure 2: Book of hand drawn detail sketches of the LV system – supplements the maps

4.5.10 - Georgia Power

Design

Mapping/Recording “As-Builts”

People

Mapping and documentation of the network are the responsibility of the Network Engineering group. Organizationally, the Network Engineering group is part of Network Underground. Organizationally, the Network Underground group is a separate entity, led by the Network Underground Manager, and consisting of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure, including the development of standards for network equipment.

Management of the maps and records associated with network infrastructure is performed by Network Underground Engineering group, led by a manager, and comprised of Engineers (Electrical and Civil) and GIS Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while GIS Technicians have a combination of years of experience and formal education, including two-year and four-year degrees. Design engineers, GIS technicians, field inspectors, and field force all contribute to the timely and accurate mapping and recording of facilities associated with the network grid.

Process

Georgia Power uses a graphical information system to store its network and “as-built” maps. They also use software called Distribution Viewer, or DistView – a module of NaviGate by Gatekeeper Systems – to display its information and lt” maps. Within DistView, designers and engineers can view information from GIS (ArcFM) and other systems, including underground “layers” showing information such as primary facilities or secondary facilities, and call up manhole and vault detailed views. The DistView system indicates the locations on the secondary networks where customer services are provided. Using an event button, engineers can click on inspection and maintenance histories as well, with detail such as the dates of inspections and the names of the personnel who performed the inspection, including what their findings and recommendations were.

DistView can be accessed anywhere through Georgia Power. The system has a Notes feature that enables an engineer, for example, to enter notes from a remote location into the system by a laptop connected to the intranet. This connectivity this helps insure that field engineers and inspectors capture information as quickly as possible. Georgia Power assigns an engineer or engineering assistant to look at the notes that have been created in the system every Monday morning and look for open jobs. Notes are removed once they are addressed.

Within GA Power’s records, network locations are numbered by manhole, and every location has a network location number and GPS coordinates. Primary and secondary feeders are included in the map. Splices locations are also shown on the maps.

Engineers can import AutoCAD design drawings into Dist View. Importing background information for new designs facilitates the design process, eliminating the need for drafters to layout the background of the entire system.

Georgia Power still maintains drawings in its GIS system, however. Some of the older maps had been directly scanned into the GIS system, and the information has not yet been ported over into DistView. It is often easier for engineers to use DistView if they want a quick look at a site, but GIS may contain more detailed information that is not yet populated in DistView (See Figure 1.).

Figure 1: DistView mapping system for Georgia Power

Even with DistView and GIS systems, Georgia Power keeps the old hard-copy drawings. In . Questions often arise about the location and dimensions of original facilities, even if those facilities have been modified or abandoned in place,

To date over 30,000 files in total, some digital and some of them scanned, have been imported into the system. Contractors were called in to open drawings and populate tables.

An open question for Georgia Power is relying on electronic file formats for archiving. Among the questions they’ve had to raise is how long will these electronic file formats be viable? Past attempts to digitize old drawings have relied on software that has since become obsolete. As of now, the maps are stored in PDF format, and they do keep hard copies in the file room. An additional layer of protection for its mapping system is a backup of the map files to an off-site disaster recovery center. Southern Company backs up all data stored on its network daily. The need for this was reaffirmed a few years ago when a tornado hit downtown Atlanta, fortunately missing the Georgia Power facility.

Georgia Power is focused on records data integrity, and has worked to make map and GIS update part of the overall job completion process. Milestones are tracked from the date of work order approval through completion and posting of records information. Milestones are tracked in Georgia Power’s JETS (job estimating and tracking) system.

When a job is complete in the field, the project foreman signs off on the work drawings, indicating any changes in the as built design, and returns the project to engineers within the Network UG Engineering group. The entry of the construction complete date by either the foreman or engineer triggers the close out process.

Within Network Underground Engineering, one of the GIS Technicians serves as a GIS coordinator, who prepares the posting package by pulling together all of the job completion information required to update maps and records. Georgia Power targets one week for update of maps and records to reflect field changes.

Technology

DistView software is used by engineers and planners for fast and accurate maps of nearly the entire Georgia Power underground network. The GIS system contains, to date, more complete mapping, including older, scanned maps. The map room is maintained as a backup and a check of what is stored electronically. Finally, the GIS and DistView maps are backed up to an off-site DR facility 24x7 in case a disaster takes out the computing systems at Georgia Power. The Job Estimating and Tracking System (JETS) is used to estimate projects and track costs.

4.5.11 - HECO - The Hawaiian Electric Company

Design

Mapping/Recording “As-Builts”

People

The HECO Maps and Records are maintained by of the Operating Engineering Division of the System Operations Department. The department is comprised of 5 people - 2 senior level people and 3 junior level people. The group is responsible for maintaining maps and facility records for HECO.^[1]

Process

The Maps and Records group maintains maps, continuing property records, electronic facilities maintenance systems (EDMS) and other information systems, such as GIS.

The group is responsible for creating and maintaining Switching Diagrams which

(See Attachment C, are manually drawn (using Microstation) single line diagrams used by switching coordinators within System Operations to plan and execute switching. These diagrams are updated as a priority and are provided to the dispatcher on a daily basis. Others at HECO who required copies of switching diagrams receive updates every six months. , are manually drawn (using Microstation) single line diagrams used by switching coordinators within System Operations to plan and execute switching. These diagrams are updated as a priority and are provided to the dispatcher on a daily basis. Others at HECO who required copies of switching diagrams receive updates every six months.

HECO has implemented a GIS system that represents their distribution system, with the exception of secondary, services, and network vaults. Outside the network, all vaults, manholes, and underground facilities are represented in GIS. HECO does plan to record network vault information in their GIS system in the future. The GIS information is being used as a foundation for HECO’s Outage Management System (OMS).

HECO is not recording the location of underground splices within their GIS system. Other underground asset information is being recorded. Not all of this information is being captured spatially; that is, information about some assets is being recorded, but may not appear on GIS produced maps. HECO is not producing and maintaining detailed manhole drawings that detail the duct bank configuration within each manhole. Field crews do not rely on maps for circuit identification – they rely on testing and field circuit labeling.

When a change to the maps and records is required, the change is noted on a form known as a Mapping Revision Order (MRO). See Attachment - D . Priority changes are made to the maps and records within 24 hours. Priority changes are those that can impact day to day system operations and include things like switch replacements, changing switch numbers, installation of new transformers, etc. Non – priority changes are completed within a three week time frame. HECO has no mapping backlog older than three weeks. HECO is utilizing an MRO Checklist (See Attachment - E , to track the progress of an MRO.

The HECO Maps and Records group is responsible for maintaining the Wallboard in the Dispatch center. The Dispatch wall board is electronic, and changes mare made by the maps and records group to the software that drives the electronic display, and to the manually updated switching diagrams.

In performing their updates of the records, maps and records personnel rarely go into the field. If a field check is required, they will normally ask one of the Primary Trouble Men (PTM’s) to perform the field check and report field conditions to them.

The field crew is responsible for notifying the Dispatcher verbally of any changes from the design of the “as – built ” construction. The Dispatcher documents these changes and forwards the changes to the Maps and Records Department via a Mapping Revision Order (MRO). HECO is not performing routine post construction audits to assess the adherence of construction to design, and accuracy of the mapping system. They believe their records to be about 80% accurate.

Technology

HECO is using G/Technology by Intergraph as their GIS system. Their future plans are to tie their design system in with the GIS so that job designs feed the maps.

HECO has created a database for creating and tracking a computerized MRO. This has not yet been implemented.

^[1] HECO does have a small mapping group that is part of System Operations.

4.5.12 - National Grid

Design

Mapping/Recording “As-Builts”

People

Mapping systems at National Grid are maintained by a mapping group located in Syracuse. For network systems infrastructure, master archival copies of underground conduit maps are kept in Syracuse, with working copies kept at the Albany office.

Post-construction audits are organized by National Grid’s Distribution Engineering Services group for the purpose of identifying opportunities for improvement in both design and construction. The Director of Distribution Engineering Services (DES) determines the number of required audits for Transmission, Distribution, and Underground construction and maintenance jobs, based on National Grid’s objectives for each fiscal year. The Director is responsible for selecting criteria for audits, and presenting audit findings to the executive management team.

Work Method Coordinators typically perform the audits. They select jobs for audit based on criteria established by the Director of DES, review the jobs prior to performing field visits, conduct the field visits and record findings, prepare reports, and review audit findings with the field. They also finalize the audit reports and participate in assessment.

Process

National Grid has implemented a GIS system. However, like many companies, the GIS and associated map products do not lend themselves readily to network systems. Consequently National Grid Albany will sometimes refer to archived underground maps of the network system kept at the Albany office. However, these maps have not been maintained. Because these archive maps are not accurate, the UG group will often perform field surveys of manholes and vaults to verify existing infrastructure and configuration prior to performing work.

Part of the work flow associated with the design of a new project is the performance of a “constructability review. “ After the design is drawn up, it is forward to a construction supervisor (Underground Field Supervisor) who meets with the designer and reviews the project to assure that it can be built as designed.

In addition, after the construction is completed, any as built changes are documented by the UG Field Supervisor and recorded so that they are reflected in the maps and records systems.

Random post-construction audits on construction and maintenance jobs take place to evaluate compliance with construction standards and assist National Grid to meet its vision of delivering unparalleled safety, efficiency and reliability.

Each fiscal year, the Work Methods Coordinators of Underground and Overhead Lines deliver a list of completed jobs that are eligible for audit based on the DES Director’s criteria. These jobs are selected from both National Grid in-house and contractor work - both maintenance and new construction. Each work order is considered a separate job for the purposes of audit, and audits are selected to try to span the division as best possible.

The first step in an audit is to review work requests and associated construction drawings for standards compliance and to become familiar with the job. If there are problems with the existing construction drawings, these are discussed with managers and the work crews. Any as-built drawings are also reviewed for changes from the construction drawings, and these are entered into the computer system to ensure the changes are properly documented.

The coordinators then go into the field with an audit checklist to inspect and take photographs. Field notes and pictures are used to build an audit report using a template provided by Distribution Engineering Services. Major and minor findings are documented, along with an overall summary of the audit.

Work Methods Coordinators meet with the field staff to discuss any extenuating circumstances or material issues that might have prevented the job from being constructed as designed. If necessary the designer is brought into this discussion. The audit report is then updated with any additional findings from this meeting.

Work Methods Coordinators meet to discuss the audit findings and assign the audit report a grade based on a grading standard on the DES information network. All audit reports are combined into a consolidated report with an executive summary of audit findings for the fiscal year.

Technology

Maps used for underground work include an index operating map, a single line operating map for each feeder showing the sectionalizing points including high side switches and NP’s in each vault on the feeder.

Maps also include UG conduit drawings, showing the duct back configurations and circuit routing in each vault and manhole.

National Grid also has secondary prints, showing the location, size and type of the secondary cable system components. Small service jobs are drawn up in GIS. Larger jobs are prepared in Microstation.

At the time of the EPRI Immersion, National Grid had embarked on a company-wide mapping project to reduce the number of different mapping products used at National Grid. A Distribution Standards representative is part of the project.

4.5.13 - PG&E

Design

Mapping/Recording “As-Builts”

People

Network maps are maintained by the Division Mapping group. Each division has its own mapping group; that is, there is a mapping group for San Francisco and another for Oakland. Organizationally, these groups report to the Distribution Engineering and Mapping organization, led by a Director. Within the Division Mapping group, PG&E has a senior mapping person working with the primary system, and another mapper working with the secondary system.

PG&E also has mappers who work within Division Operations (DO Mappers). These mappers are responsible for maintaining the circuit maps that depict the network within the operations center.

Process

Changes to the maps of the network infrastructure are driven by the planning engineer in most cases, as Planning initiates and performs the design of most changes to the network. Even changes to the maps driven by emergencies will flow through Planning, as crews will often involve planning in the developing the solution to the problem.

PG&E has an up-to-date documented procedure for maintaining network maps. (See Attachment C .)

One network map used at PG&E is the Circuit Map. The circuit map is a semi-schematic type of map that shows sectionalizing points and transformer locations for network primary circuits. Circuit maps are drawn and maintained by the Division Operations (DO) mappers using a CAD system.

Projects that go to construction are accompanied by job drawings, which may be a section of a circuit map marked up with the changes. At the conclusion of a job, the crews prepare a circuit drawing showing the network changes. This circuit drawing can either be hand drawn or assembled by cut and pasting copies of the circuit drawings provided with the project. The drawing indicates both the former circuit configuration and the present (post construction) circuit configuration.

These circuit drawings, indicating the field changes, are sent through Division Operations, where DO mappers update the Division Group Maps, which are displayed on the Operations center wall. These changes are made within 1 – 3 days of the when the change is received.

The changes then flow to Division Mapping, who makes the changes to all other maps and records maintained by PG&E for network infrastructure, including circuit maps, block maps, route sheets, and the update of the SAP Asset Register for certain network equipment changes. Division Mapping also updates maps in the Division Emergency Center (DEC). These maps and records changes affecting the primary system are made from within 1 to 5 days of receiving the changes in Division Mapping.

Another source of maps and records changes are corrections to the maps received from the Compliance group. In performing their work, the Compliance group may encounter maps and records discrepancies. Copies of the network transformer and network protector maintenance inspection checklists are sent to Division Mapping noting the changes to be made to the maps and records.

PG&E does not have a formal process for performing post construction audits of network projects.

Technology

For Network Systems, PG&E is utilizing various types of maps.

A Circuit Map, which is a CAD drawn, semi – schematic map showing primary feeders, sectionalizing points, and transformer locations. See Attachment D for sample Circuit Map
Distribution Map (Block Map), which shows all the network facilities (primary and secondary) in a given geographic area (usually a city block). These maps include a “Duct Side Drawing” which shows a plan view layout including duct bank configuration in each manhole. Note that the block maps show taps, but not inline splice locations. See Attachment E for a sample block map. These maps were originally hand drawn and maintained, and are now updated in CAD.
Route Sheet, which is a tool for physically (geographically) going from one vault to another, to facilitate performing switching to establish a clearance on network feeder. When division mapping updates SAP, they will also update the route she is the change to the system affects the route sheet itself.

PG&E has an in house GIS system called DART that models the radial system. However their network facilities beyond the network feeder circuit breakers are not represented in GIS.

When the system change involves a new network transformer, the Planning engineer is notified of the change so that he can provide division mapping with a new network bus number and specify what customers should be assigned to this new bus. Division Mapping then creates this new network bus within the DART system and reassigns customers to the new bus. This information is used for load modeling by the Planning engineer.

SAP serves as the asset register for network equipment. Division Mapping will update SAP to reflect system changes. When they update SAP, Division Mapping will also update the route sheet if affected by the system change.

PG&E has implemented wireless laptops on trucks to access the mapping information real time.

4.5.14 - Portland General Electric

Design

Mapping/Recording “As-Builts”

People

The “Mapper/Designer” working for the Service & Design group at the Portland Service Center (PSC) is responsible for recording “as-builts" associated with network projects.

The “Mapper/Designer” reports to the Supervisor of Service & Design at PSC and provides the computer-aided design (CAD), geographic information system (GIS), and design service. Mapping facilities also involves PGE’s GIS department, which verifies that any designs have electrical connectivity and ensure that ArcFM GIS contains the latest design.

Process

When designing a system, designers produce an electrical map used by the construction crews to mark up as-built field changes.

The Mapper maps everything in ArcFM GIS. When the field job is completed, it comes back to Service & Design to develop the “as-built” model and document the as-built. Once everything has been set up in design draft version on the GIS, the final post is entered on the GIS. The GIS holds the electrical drawings and conduit plans, while vault details stand alone.

Following the “as-built” finalization, the GIS Department sees the work order in Maximo and the design in “draft version” within ArcFM. The GIS Department performs some quality assurance/quality control (QA/QC) to make sure that there is electrical connectivity in the plan/design. This ensures that the required attributes are in the system, such as operating voltage, cable type, etc. The department also runs a reconciliation process to determine that nothing was missed due to other builds in the area, again ensuring electrical connectivity. This process ensures that the GIS contains the latest design.

After the structure has been built, the conduits used are marked on the field drawing and then noted in the GIS. PGE is starting to take pictures/images of vaults that can be included as part of the package. The design package and vault details are created for new construction but updated to reflect the in-vault conditions identified by the field force that differs from the records. Discrepancies are sent back to mapping and design for correction.

Butterfly Maps/Conduit Plans: PGE has butterfly maps for Class A vaults used to facilitate customer discussions, as they include information about customer requirements. The butterfly map does not show the locations of moles, splices, or cable limiters.For a vault, the conduit plan may warrant its own sheet and plan if it is particularly complex. The city requires permits; thus, for any construction on the network, PGE draws up a separate conduit plan.

Paper Maps: PGE migrated from Frame Intergraph and a CAD database to ArcFM. However, the new mapping is not yet updated and many paper maps that are not particularly accurate still exist. The secondary side of the network was never mapped but all recorded on paper, so there still is a backlog, which is migrating over to electronic format. PGE has faced challenges in how to view some of the diagrams/maps in the new ArcFM for the network. The feeders are clustered together, making it difficult for workers to view and understand the layout.

GIS Strategy & Roadmap Project: PGE is presently undertaking a GIS strategy and roadmap project to look at areas for improvement and develop a strategy. The company is identifying performance issues, functionality, usability, and resources. Similarly, it has embarked on an effort to improve the overall mapping accuracy in the network. Accordingly, PGE is gathering and consolidating documentation about the CORE network system, including the “butterfly” drawings for each vault and manhole.

Technology

Geographic Information System (GIS) – ArcFM/ ArcGIS

To support planning, engineers use ArcFM, which is built upon ESRI’s ArcGIS system. Users can access ArcGIS mapping software via a browser, desktop application, or mobile device, and organizations can share maps and data. ESRI’s system allows users to capture, analyze, and display geographical information, enabling display of maps, reports, and charts.

GIS is used to map assets and circuits, and can be linked to the customer information system and other enterprise applications. The maps provided with ArcGIS include facility maps, circuit maps, main line switching diagrams, and a service territory map [1,2].Operators can use ArcGIS to schedule work and dispatch crews, and they can also locate crews and view work status and progress [3].

With ArcGIS, operators and crews can locate assets and infrastructure, as well as determine how they are connected. The view of the electrical system includes connectivity, service points, and underground assets. Crews can follow how current flows through the interconnected network and determine upstream and downstream protective devices. The GIS allows users to overlay external data, including images, county maps, and CAD files onto the map view.

The GIS includes the ArcMap and ArcFM viewer, which allows designers to use compatible work units and send these to the Maximo system. In 2017/2018, PGE will investigate processes for transferring Arc GIS information into CYME, which will require a software development from the vendor, Schneider Electric. ArcFM will be built on top of ArcGIS, and the system will allow engineers to use CYME, which is presently used on the radial system, for the network.

ArcFM GIS software will help engineers design network layouts and create a package with details for relevant personnel. Schneider’s software is a map-focused GIS solution that allows users to model, design, maintain, and manage systems, displayed graphically alongside geographical information. ArcFM uses open-source and component object model (COM) architecture to support scalability, user-configurability, and a geographical database.

ArcGIS Solutions. “Electric Facility Maps.” Solutions.ArcGIS.com.http://solutions.arcgis.com/utilities/electric/help/electric-facility-maps/ (accessed November 28, 2017).
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).
GIS for Electric Distribution. ESRI, Redlands, CA: 2010. http://www.esri.com/library/brochures/pdfs/gis-for-electric-distribution.pdf (accessed November 28, 2017).

4.5.15 - SCL - Seattle City Light

Design

Mapping/Recording “As-Builts”

Process

Network Maps and Asset Records

SCL utilizes a home-developed system called NetGIS as their repository for network

asset records, and to produce network maps. NetGIS enables SCL to produce CAD maps, and to maintain records associated with each network vault.

SCL personnel can obtain maps from the system, and can click onto a vault to

obtain a description of the equipment contained in the vault including:

Splice type and information
Ductbank configuration
Civil information
Ground points
Bus bar

When a change is made to the network, the GIS section updates the network feeder maps in NetGIS.

Technology

SCL utilizes a home-developed system called NetGIS. NetGIS is their repository for network asset records, and also the product they use to produce network maps. NetGIS is not a full, graphical geographic information system (GIS) system with electric connectivity. Rather, it enables SCL to produce CAD maps, and to maintain records associated with each network vault.

Note that their load flow analysis product is not tied in with NetGIS.

4.6 - Network Area Substation Design

4.6.1 - AEP - Ohio

Design

Network Substation Design

People

The specification for network substation design used in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineering group. This group, led by the Network Engineering Supervisor has direct responsibility for all aspects of network design for AEP Ohio, and provides a consultative support role to the other AE operating companies. Organizationally, the Network Engineering group is part of the corporate Distribution services organization, geographically based in downtown Columbus at AEP Ohio’s Riverside offices, and ultimately reporting to the AEP Vice President of Customer Services, Marketing and Distribution Services. Distribution Services supports all AEP network designs throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Network substation design issues are discussed and recommendations made through this committee.

Process

AEP Ohio has network systems in both Columbus and Canton, Ohio. Each Columbus network is built to N-2 reliability. The Columbus urban area has four separate networks – North, South, Vine, and West – supplied from three substations. Each network is supplied from 138 kV/13.8 kV Δ -Y network transformers. All four networks, about 30 MVA each, are served by six dedicated network feeders at 13.8 kV, with each group of six originating from a single substation. There is no overlap in these networks. This is a preferred design in that the network feeders are sourced at the same voltage, which minimizes the possibility of problems with network protectors pumping or cycling. AEP reports few problems with protectors pumping, cycling, or opening under light network loading.

Substations supplying the network utilize a ring bus design, and consist of multiple substation transformers, with one used as a ready reserve hot spare unit. The substation transformer secondary (medium voltage) buses are connected in a complete ring with closed tie circuit breakers between all buses. Network feeders supplying any one network emanate from at least three secondary bus sections, with no more than two network feeders originating from any one bus section. Multiple station transformers are connected so that a minimum of two transformers operate in parallel during normal operation. Circuit breakers are then used to automatically remove any faulted bus sections from service without impacting normal operations. This provides N-2 service to all existing customers in the downtown region. All stations have a minimum of three transformers, with some having as many as five or six.

In Columbus, the Vine network primarily serves spot networks in a high-rise area of downtown (Vine station), with some mini-grids at 480 V. The other three networks (North, South, and West) serve a mix of grid (216 V) and spot loads.

Canton has one network supplied at 23 kV. The station that supplies Canton is designed to N-1, though networks themselves are also designed to N-2.

Technology

AEP has SCADA monitoring and control of its network feeders.

The Network Engineering group is responsible for maintenance and upgrades to the network substation designs. The group has sponsored various projects to enhance network substation functionality, including replacing all electro mechanical relays with microprocessor-controlled relays, modernizing the control house building and performing manhole repairs at station exit locations.

AEP is installing a master trip and close system that will enable the dispatcher to drop or pick up an entire network as a group, or be to enable or disable selected circuits to be operated.

At the time of the practices immersion, AEP is installing a significant upgrade in its network remote monitoring and control system. (See Remote Monitoring System )

4.6.2 - Ameren Missouri

Design

Network Substation Design

People

Distribution planning of the network at Ameren Missouri, including the planning of the substations that supply the networks, is performed by resources in several groups.

Area planning for the distribution system is the responsibility of Distribution Planning and Asset Performance. This group, led by a manager, is staffed with four-year degreed engineers, and includes the Standards Group as well as a planning engineering Group. Organizationally, Distribution Planning and Asset Performance is part of Energy Delivery Technical Services, reporting to a vice president.

Local distribution planning of both the network and non-network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division. This division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues. The engineers are four-year degree positions. Energy Services Consultants have a combination of years of experience and formal education, including two year and four year degrees. The engineers are nonunion employees; the estimators are in the union. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP.

Finally, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network. At the time of the practices immersion, the revitalization team had developed a series of planning criteria documents, including criteria for loading, route diversity, sectionalizing, and application of automation. In addition, they had developed recommended requirements for cable replacement, and conduit system design and replacement. This group is also performing area planning for the network, including the planning of new substations to supply the networks.

Organizationally, the Underground Revitalization Department is part of the Underground Division.

Process

The design of the distribution network system serving St. Louis consists of four distinct secondary network grids each supplied by a separate substation.

Together, the four network substations supply about 205 MVA of load. Three of the stations are sourced at 138 kV from overhead supplies, while one is served at 35 kV from an underground supply. Two of the substations are relatively new, and two are more than 50 years old.

Of the four substations, three of them have three transformer units each. In one of those three stations, two of the units are online, with one held in reserve. In the other two stations, all three units are in service. The fourth station is a two unit station.

At the time of the practices immersion, Ameren Missouri, through its downtown revitalization project, was developing plans to replace the oldest substation (the one with the 35kV supply), with a new station in a different location, as the oldest station is also out of phase with the other three.

Ameren Missouri’s substation design uses a ring bus with no more than two network feeders fed off of the same bus section at the station. A given bus section may serve both radial and network feeders. Network feeders are fed directly off of the substation bus (as opposed to radial feeders which feed through reactors to limit fault levels).

Technology

The network substations are each equipped with SCADA, monitoring and controlling network feeders and monitoring network equipment. The communications backbone is optic fiber, with two way communications to each network vault.

4.6.3 - CEI - The Illuminating Company

Design

Network Area Substation Design

People

Substation Design is the responsibility of the Transmission and Substation Design group, a corporate function at FirstEnergy responsible for the entire FirstEnergy system.

Process

As the load in downtown Cleveland has been on the decline, the existing network infrastructure has adequate capacity to carry the load, and in fact, has excess capacity. Consequently, CEI is not planning any new network substations or any expansions or modifications to the network substation serving the downtown network.

Hamilton Sub supplies the Network as well as other downtown load. It is supplied by two 138 kV sources (1957 vintage oil filled pipe type cables) feeding four substation transformers with dual secondary windings, supplying 12 isolated 11kv bus sections with manual ties. The network feeders and load are staggered among the bus sections / transformers to maintain N-1 reliability.

For new substation installations, FirstEnergy’s general philosophy is to utilize smaller modular substations “mod subs” with smaller transformers and minimal feeders emanating from each substation. These mod sub installations would be replicated to meet the load requirements in normal and contingency situations. In dense urban situations, alternative substation designs may be required.

Technology

The 138 kV oil filled pipe type cable system has been highly reliable for CEI. The CEI Underground department is responsible for the maintenance of this cable. The department manager acknowledged that if he had a problem with this cable, he may have to bring in outside help to aid him in resolving the problem as he may not have the expertise in house.

4.6.4 - CenterPoint Energy

Design

Network Area Substation Design

People

Substation Design is the responsibility of Substation Engineering, not part of Major Underground. Substation engineering at CenterPoint balances workload between internal and contract resources. Substation construction is contracted.

Process

CenterPoint supplies its network systems from three dedicated substations. These substations are supplied by a primarily overhead 138kV transmission system.

Distribution voltages supplied by these subs are 12 kV and 34.5 kV. The 35kV station uses 2 or 3 100 mVA units, designed to N-1. The 12.5 kV stations use 2 or 3 50 mVA units, also designed to N-1.

For contingency planning purposes, CenterPoint plans for the loss of the highest firm rated substation transformer.

As part of a risk mitigation strategy, CenterPoint recently implemented contingency plans for the loss of the entire station that supplies the 34.5 kV major underground system. This system serves critical loads, such as major hospitals and universities. CenterPoint extended feeders from other stations and built overhead tie points to be able to back up the load even in the event of the catastrophic loss of the entire station. In addition, CenterPoint maintains spare substation transformers.

4.6.5 - Con Edison - Consolidated Edison

Design

Network Area Substation Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Engineering and Planning - Responsibilities include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Substations in Manhattan and central Brooklyn are designed with a second contingency. Other Con Edison substations are designed for a first contingency.

Area Substation design (N-2) calls for five substation transformers (normally 65 MVA units) — four connected, and one spare that is energized but not connected.

Substations are designed with a double synchronous bus (Syn Bus), and major and minor bus sections (32 primary feeder positions at 13.8 kV). Area substations are designed to source two networks.

Network feeders are fed off of the minor bus sections. Diversity is built into the bus arrangement. More specifically, feeders are arranged so that if Con Edison loses a minor bus section, each circuit fed by that bus section doesn’t service the same area. In other words, if a pair of primary feeders is supplying a particular area, those feeders are supplied from different minor bus sections.

(See Attachment B ) . This attachment is not an actual Con Edison substation operating diagram, but is a representative diagram for a substantially established substation. A completely built-out substation might have four circuit breakers on many busses and have many feeders bifurcated (see 12E & 41W).

Some area substations are located in the bottom floors of buildings, with a multilevel design. For example, in one location, the substation transformers (138 kV: 13.8 kV) were located on the ground floor of a building. The syn bus, minor busses, circuit breakers, and a small control room were located on the third floor. This particular substation also housed a small Control Room, manned on day shift. The primary feeders fed down to the floor below the sub-transformers to source the network.

Primary feeders sourcing the networks either feed right into the networks, or are spliced if the bending radius or other factors prevent a direct pull. The Underground Group (Splicers) is responsible for making the terminations at the substation transformer secondary (13.8 or 27 kV).

4.6.6 - Duke Energy Florida

Design

Network Area Substation Design

Technology

In Clearwater, Duke Energy Florida has a true low voltage meshed secondary network. This network, a 125/216V grid, is supplied by three medium-voltage (7200/12470V) wye connected primary network feeders fed out of one substation. The substation that supplies the network is a large four-transformer station that supplies non-network loading as well. While all three network feeders are fed out of the same substation, the feeders are supplied from separate bus sections at the sub (open bus ties to manage fault currents – not using phase reactors), sourced by separate transformers. Because the feeders are supplied by three sources and have different loads, and because the network is very lightly loaded, Duke Energy Florida has experienced issues with open and frequently operating network protectors on their Clearwater system. Duke Energy Florida expects this situation to improve as the remaining non network load is removed from the feeders, and as planned new loading is added to the system.

St. Petersburg underground infrastructure is fed by 12 different feeders supplied from three different substations. The company moved away from a network grid system in St. Petersburg years ago, with eight two-feeder 277/480V spot network locations remaining in the system. The two feeders supplying any one spot network location are sourced from the same station. Most of the infrastructure in St. Petersburg is supplied by a primary and reserve feeder loop scheme, with automated transfer switches (ATS). The ATSs are tied in with SCADA and can be monitored and controlled from the DCC.

4.6.7 - Duke Energy Ohio

Design

Network Area Substation Design

People

Network area planning, including planning of the substations that supply the network, is the responsibility of the Distribution Planning group, within the Asset Management organization. Network Substation design, including modifications to the existing substations that supply the network, is the responsibility of a substation design engineer within the Transmission Planning organization. This engineer will involve the distribution planning engineer on the distribution part of the substation design.

Process

The design of the distribution network system serving Cincinnati consists of two network substations supplying four distinct secondary networks (two networks supplied by each substation). Three of the four networks in downtown Cincinnati are supplied by eight feeders, each, and the fourth network, by four feeders.

The two network substations are located close to one another, and are sourced at 138 KV. Parallel 138 kV feeders join the two substations.

One station has four 67MVA transformers, and the other, three 90 MVA units and one 67 MVA unit. Each station uses a ring bus arrangement on the secondary, with network feeders supplying a given network sourced from separate buses within the substation.

Each substation is visited at least weekly by night time mobile operators who perform inspections and network protector drop tests. Mobile Operators are responsible for performing switching and tagging within the substations.

Technology

The network substations are each equipped with electronic keying, and video monitoring.

One of the substation houses permanently stationed fault location equipment (Thumpers) as it is a multiple level station. The other station is located on the ground level, and can be accessed with a thumper van.

Power quality monitors are also positioned in each of the substations, measuring current and voltage coming off the transformers, supplying each network feeder.

4.6.8 - Energex

Design

Substation Design

People

Zone Substation Design

The Systems Engineering group, led by a group manager, and part of the Asset Management organization is responsible for Zone Substation Design Standards. This group is responsible for establishing the design standards for zone substations. Energex also has a Design organization within its Service Delivery organization, also led by a group manager, and responsible for performing designs of specific projects, including new construction and system reinforcement projects. The Design group is comprised of four year degree qualified engineers and engineering associates. Project engineers apply the appropriate, approved Zone Station Design standards and lay out the projects using the Energex design tools, such as Microstation and AutoCAD.

(See the Standards section of this report.)

Medium-Voltage Substation Building Vault Design

The Systems Engineering group, led by a group manager, and part of the Asset Management organization is responsible for medium-voltage substation building vault design. The Design group is comprised of four year degree qualified engineers. Project engineers apply the appropriate, approved medium-voltage substation building vault design standards and lay out the projects using the Energex design tools, such as AutoCAD.

Process

Medium-Voltage Substation Building Vault Design

Medium-voltage substations in the CBD are usually located within building vaults. The medium-voltage stations consist of primary (11 kV) switches protected by bus differential relaying, transformers, and secondary switchgear which supplies both the building load and feeds into the low-voltage network serving the CBD.

Figure 1: Energex Employee giving safety briefing before entering a C/I substation, located in a building vault

Figure 2: Dry type transformer supplied by the three feeder mesh

Figure 3: Primary terminations (PILC) on dry type transformer

Figure 4: Multiple dry type transformers

Figure 5: Circuit breakers with bus differential relaying

Figure 6: Low-voltage switchboard, with feeds to the customer

At some locations, Energex may “Tee” off the primary feeder with a substation consisting of an SF6 gas insulated ring main unit (the primary switch gear current design) with an “in” switch, an “out” switch, and a fused, switched tap leading to the transformer. The use of a packaged substation with a ring main unit is a common design outside of the CBD.

In URD applications, Energex uses a similarly designed “packaged” substation (see Figure 7), which is a pad-mounted unit consisting of the ring main unit (“in” switch, an “out” switch, and a fused, switched tap leading to the transformer), the transformer, and the low-voltage switchboard supplying the low-voltage network feeding the development (see Figure 8). Note that URD developments are fed by an extensive low-voltage network feeding through mini-pillars. Services are tapped from these mini-pillars to serve customers (see Figure 9).

Figure 7: Typical pad-mounted 'packaged' substation supplying UG development (another view). Note mini pillar to the right of the sub

Figure 8: Low-voltage switchboard supplying the LV network feeding the development

Figure 9: Typical Home, note mini pillar in the foreground supplying the customer

Energex has SCADA at the substation, and some remotely monitored and controlled normally open tie points between 11 kV feeders out on the system, but in general, Energex has little SCADA beyond the substation. Energex is currently installing a power quality (PQ) meter on the low-voltage side of all distribution transformers greater than or equal to 300 kVA, three phase.

Technology

Zone Substation Design

The 11 kV distribution network supplying the central business district (CBD) in Brisbane is supplied by four zone substations. These zone substations are fed by 110-kV transmission via both underground and overhead transmission feeders and supply the network through 110-kV:11 kV transformers (see Figures 10 through Figures 11).

Typical transformer sizes are 60 or 80 MVA Wye-Delta units. In order to provide an earth reference for the 11 kV network, an earthing (grounding) transformer is connected to the 11 kV output of the main transformer (see Figures 12 and 13). All of the zone substation transformers have dual windings supplying the 11 kV bus. They regulate voltage at the stations with a combination of tap changers and capacitors.

A typical zone substation may supply 6 or 7 feeders from an 11 kV ring bus. All bulk and zone subs have full SCADA. However, Energex has deployed very little SCADA or automation beyond the substations.

Figure 10: Gas insulated switchgear at Energex. 110:11 kV zone substation

Figure 11: 11 kV cables emanating from zone substation transformer secondary side

Figure 12: Earthing transformer at zone substation

Figure 13: Cables exiting zone substation

Figure 14: Cables exiting zone substation

Medium-Voltage Substation Building Vault Design

At the time of the immersion, Energex was in the process of implementing the PowerOn Distribution Management Product from GE, which provides electronic displays of the distribution networks, both medium voltage and low voltage.

4.6.9 - ESB Networks

Design

Network Substation Design

(Network Substation and MV Substation Design)

People

The design of the substation infrastructure is performed by designers located within the Network Investment Management groups for larger designs, and within the ESB Networks Regions for the smaller designs. The Network Investment Management groups (North and South) are part of the Asset Investment group, within Asset Management. The Regions are organizationally part of the Operations Management Group, also part of the Asset Management organization.

Most designs are performed by an Engineering Officer – the designer position at ESB Networks.

The development and maintenance of guidelines for performing network substation design are the responsibility of the Specification Management group, part of the Asset Investment group, also part of the Asset Management organization at ESB Networks.

The Specifications Management group has developed thorough guidelines for the design of substations. This guideline includes specific direction for optimizing designs.

Note that in addition to the Operations Management and Asset Investment groups, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Assets & Procurement, and Finance & Regulation. These groups work closely together to manage the asset infrastructure at ESB Networks.

Technology

Network Substation Design

In Dublin, ESB Networks uses a meshed 38-kV substation design. ESB Networks has six 38-kV meshes in the Dublin area, two North, and four South. (Outside of Dublin, the 38-kV system is either radial or looped.) The mesh is a closed loop system supplied by transformers at either end supplied from different substations. The system is protected by impedance and differential relays, and can isolate interruptions in milliseconds.

The system provides high reliability, providing n-1 even with the loss of a feeder section. In the loss of any circuit section - the remaining transformers don’t see a loss of supply. In the loss of a sub transformer, the load is supplied from the remaining transformers. For planned work, ESB Networks may couple mesh systems to maintain security of supply.

Note that if ESB Networks takes out a 38-kV cable for service, it also may take out one of the substation banks because of the short circuit duty.

To prevent circulation among the substation transformers that comprise the mesh system, the transformers are interconnected with communications with one transformer considered the master, and as its voltage varies, the other units (slave units) follow suit by changing taps to match the master. In an abnormal operation, if a cable is taken out, for example, ESB Networks has the ability to access a screen within their SCADA, and regroup the transformer master/slaves relationships to reflect the abnormal configuration.

In its 38-kV system at ESB Networks, the neutral is arc suppressed using an arc suppression coil to counter the capacitive effects of the cable.

ESB Networks’ MV system is fed by radial cables. In Dublin, the MV system is a 10-kV system. In most of the rest of Ireland, ESB Networks has converted much of the 10 kV to 20 kV.

MV Substation Design

ESB Networks uses a standardized MV “packaged substation” consisting of an SF6 gas insulated ring main unit, the MV transformer (in Dublin, typically a 10-kVA primary to a 430-V secondary), and the secondary bus and protection that feed the secondary “mains” that supply the LV system in downtown Dublin.

The current design of the primary switch is an SF6 gas insulated ring main unit device (see Figure 1), with an “in” switch, an “out” switch, and a fused, switched tap leading to the transformer (kkt). The company describes these units as “maintenance free,” and obtains them from a supplier through a lease arrangement. ESB Networks does have older oil insulated devices installed on its system as well. These devices must be manually operated from within the indoor room. ESB Networks has not implemented automated control of these devices.

Figure 1: SF6 gas insulated ring main unit

ESB Networks’ design is to loop its 10-kV MV feeders in and out of these switches, designing normally open tie points between feeders. This provides them the ability to sectionalize to isolate outage sections and to feed each MV transformer from either direction. Note that ESB Networks does utilize faulted circuit indicators. These are not remotely monitored, as ESB Networks engineers have determined that it is not economical to remotely monitor fault indicators unless remote switching capability is also implemented.

ESB Networks’ standard primary switchgear (ring main unit) is a “load make,” but not a “load break” device. The switch is designed with an anti-reflex handle that prevents an operator from inadvertently and reflexively opening the switch if the operator happens to close into a fault, as the device cannot break load. If the operator does close into a fault, ESB Networks relies on the tripping of the breaker that sources the 10-kV feeder.

The primary cable that runs from the primary switchgear to the transformer is laid in a cable tray (duct), easily accessible by removable duct covers either made of wooden blocks, or a glass reinforced polyester material.

Standard transformer sizes are 200, 400 and 630 kVA, with the 630-kVA unit being the most prevalent. Most customers in Dublin are served from the secondary system, but Dublin does have about 170 customers that take primary service at 10 kV - packaged substation. ESB Networks’ standard transformer is a dual-voltage unit, as most of its service territory outside of Dublin is served at 20 kV, while the feeders supplying downtown Dublin Park are 10 kV (see Figure 2 and Figure 3). ESB Networks describes these transformers as sealed units that do not require routine oil testing.

Figure 2 and 3: Transformer

Secondary mains emanate from a secondary cabinet mounted adjacent to the transformer. The secondary mains are fused (see Figure 4 and Figure 5).

Figure 4: Secondary mains – fuse cabinet

Figure 5: Secondary fuse

ESB Networks’ standard switch unit can be motorized. ESB Networks can use these motorized switches to implement some urban automation. ESB Networks installs remote control in the MV switchgear, and plans to use this at stations that serve government buildings.

4.6.10 - Georgia Power

Design

Network Substation Design

People

Network standards, including the standard for network underground substation design, are the responsibility of the Standards Group and the Network Underground design engineers. These engineers are part of the Network Engineering Group, or principal engineers that report directly to the Network Underground Manager.

Organizationally, the Network Underground group is a separate entity, led by the Network Underground Manager, and consisting of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure, including the development of standards for network equipment.

Network design is performed by the Network Underground Engineering group, led by a manager, and comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees.

Area Planners are responsible for performing studies to assure adequate transformer capacity. While part of a central organization, area planners are located throughout the Georgia Power territory. For example, an Area planner located in the Metro East region is responsible for planning of substations that supply the Atlanta network.

Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. It is a living document, and the responsibility of the Standards Group comprised of senior engineers in the Network Underground group. Standards are available in both an online and printed book format.

Process

Georgia Power supplies 35 separate networks in Atlanta, with most being five-feeder networks, supplied at 20 kV. Secondary grids are supplied primarily at 120/208 V. Georgia Power also has many spot networks, supplied at 480 V.

Georgia Power supplies the downtown networks from multiple substations. Some substations supply only network load, while others supply both network and non – network loads. However, even at these mixed stations, Georgia Power uses “network only” transformers within the substation. These units supply bus sections that supply only network feeders. All feeders supplying any one network are fed off of the same substation bus.

Area Planners design the stations so that there is always capacity at the station to back up network feeders, as network feeders at Georgia Power have historically been designed without tie points outside the station. (Note - at the time of the immersion, GA Power was beginning to put normally open ties between network feeders at selected locations). For example, at a three-station bank, where one transformer is dedicated to supplying network load, and the other two-supply non-network load, the units that supply the non-network load would be sized with reserve capacity to back up the network load in the case of the loss of the network transformer (N-1).

There are two exceptions to the network-only feeders from substations:

in an emergency and there are no alternate network feeders to take up the capacity from a lost network transformer [an N-2 situation]
the MARTA rapid transit system. Georgia Power has made an exception in the case of the transit line because its entire system is in duct line and well protected from any possible damage.

Georgia Power uses LTC transformers to regulate voltage of the bus that supplies network voltages. This assures that all network feeders supplied by the bus are supplied at the same voltage, yielding good performance of the network system. (Georgia Power reports no problems with protectors cycling or pumping, for example). This approach to voltage regulation differs from the approach used in the non-network distribution system outside of Atlanta, where single phase regulation is the standard.

In Atlanta, Georgia Power typically limits its network size to 40MVA, although they do have some 50MVA networks (about 10MVA per feeder). Any customer asking for service is supplied by this network bus standard because Georgia Power’s Underground Network group feels it is more reliable and uniform, making on-going expansion and maintenance easier.

The company currently does not have a lot of room in the downtown Atlanta area for new substations.

Typically Georgia Power prefers to keep loads in the 70 to 90 percent range, and any transformer or network segment exceeding 90 percent loading is prioritized and tagged for the Area Planner and engineering for analysis, to add more capacity through additional transformation, off-loading service to another network grid, or by adding substations.

One unique aspect of the Georgia Power transformer operations is the use of re-rating of transformers for reserve contingency. By examining test criteria on a given transformer, Georgia Power may find the transformer capable of 115 to 130 percent of nameplate ratings through objective tests. The company then knows they have that reserve capacity in an emergency. High-priority (24x7 operations) and high-capacity customers are never put on re-rated transformers.

Duct bank configuration is standardized, as is racking within manholes. Primary feeders are in duct line at the bottom positions, with secondary feeders at the top. Configurations can vary according to the duty needed, and may be 2X4, 2X6, etc. Georgia Power is specifying six-inch duct line wherever possible to accommodate EPR and PILC cables greater than 750 MCM. Its older network sections, primarily in downtown Atlanta, have 4 inch conduits. As a result, Atlanta uses mainly lead cable in these constrained spaces. They are committed to keeping lead cable, as Georgia Power has found it to be very reliable and easily contained in the older four-inch conduits where cable size is limited.

Figure 1: 2 x 6 duct bank

A notable practice in cable racking in vaults and manholes is the use of the Georgia Power Peachtree racking system. Primary feeders are racked on the bottom, secondary are racked on the top, and the neutral on is on the very top. The Peachtree racking design allows for future expansion. Engineers may not need all four directions; but designers believe they have to put feeders in the right place for easier expansion. Feeders are numbered as well, from 1-6, also to more easily accommodate expansion and maintenance.

In cases of customer premise - based transformers, such as a spot network vault, Georgia Power supplies customers with detailed vault construction reference drawings. It is up to the customer to build and maintain the vault structure. Before installation of transformers and during vault construction, Georgia Power inspects the vault to make certain it meets with their standards. It is common practice for Underground Network group engineers to inspect the customer site before making vault recommendations (See Figure 2).

Figure 2: Spot Network Vault

Technology

Georgia Power has recently acquired CYMDIST to model the entire secondary and primary grid. The program is designed for planning studies and simulating the behavior of electrical distribution networks under different operating conditions and scenarios. It includes several built-in functions that are required for distribution network planning, operation and analysis. The model Georgia Power has developed is extremely accurate including cable systems, cable ratings, cable capacities and specifications.

The Area Planner keeps detailed spreadsheets, continually updated, on upcoming and ongoing projects that may require new substations or spot networks.

The Georgia Power GIS system also tracks network statistics, so that if a particular network segment reaches a threshold, it is tagged for the area planner and network design group.

The Operations and Reliability Group monitors network performance continually, and offers significant objective feedback for future network plans based on its remote monitoring data.

4.6.11 - HECO - The Hawaiian Electric Company

Design

Network Area Substation Design

(15kV Distribution Substation Design)

People

15kV Distribution Substation Design is the responsibility of the Substation and Telecommunications Division of the Engineering department.

Process

HECO’s 15kV substation design philosophy is to use small, repeatable, consistently designed substations. A typical 15kV substation is comprised of a 10 MVA unit, with two circuits fed out of the substation. As loads require, this “modular” concept is repeated as required to meet the load requirements. Most 15kV substations are sourced by HECO’s 46kV transmission system.

Note that HECO also has 25kV distribution supplied through 2 substations sourced by 138kV. At these stations, HECO is using 50 MVA units.

Technology

HECO has over 250 10 MVA stations on their system. They have two mobile subs, a 5 and a 10 MVA unit, and have 3 10 MVA spares on the island.

4.6.12 - National Grid

Design

Network Area Substation Design

People

Network substation design, including modifications to the existing substations that supply the network, is the responsibility of the Substation Engineering Services group, part of the Engineering organization within Distribution Asset Management.

Process

The downtown network in Albany is fed by two substations. The Albany network is supplied by ten dedicated network feeders – three from one substation and seven from the other substation.

National Grid’s Albany network system is designed to n-2. That is, the system is designed to ride through the failure of any two components (primary and secondary cables, transformers, network protectors, and ancillary equipment) during a system peak, with only minor overloads to transformers, primary feeders and secondary mains.

Figure 1: Network Unit - Protector

National Grid also has a separate 277/480 V spot network system supplied by five 34.5KV feeders and serving fourteen spot network locations. Two additional customers are dual fed primary voltage customers off of these 34.5kV feeders. There are also ten customers fed from eleven spot networks off of the 13.2kV general network feeders. Three of these are 125/216v, the rest 277/480v. Additionally, there is one customer fed off of two of these 13.2kV feeders through a padmounted PMH-9 switchgear. These spot network locations are designed to n-1.

Network substations are designed with a minimum of two high voltage supply circuits and two power transformers so that the failure of any transformer or supply circuit will not affect the network supply.

Technology

The network substations are each equipped with SCADA, monitoring and controlling network feeder breakers. National Grid does not have SCADA monitoring or control installed in their network beyond the substation. (Note: National Grid is piloting the application of remote monitoring in their Buffalo, NY network.)

4.6.13 - PG&E

Design

Network Area Substation Design

People

Network area planning, including planning of the substations that supply the network, is the responsibility of the network planning engineers within the Planning and Reliability Department. This department is led by Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system. For network systems, the two planning engineers are responsible for both network planning and network design.

Network substation design, including modifications to the existing substations that supply the network, is the responsibility of the Substation Engineering Department. This group involves the distribution planning engineer on the distribution part of the substation design.

Process

PG&E has secondary networks in both San Francisco and Oakland.

Secondary network grids are 120/208V. Secondary network spots are at 120/208V and at 277/ 480V.

The downtown networks in San Francisco are fed by four substations, and the Oakland networks are fed by two substations. They have 12 total networks, 10 being supplied by 12kV feeders and the other two, 34.5kV feeders. Each individual network system sourced at 12 kV is fed by 6 dedicated network feeders. Of the two 34.5kV sourced networks, one is fed by 4 feeders and the other, by 5 feeders. 12 kV primary feeders supplying the networks are typically PILC, and the 35kV are XLPE.

Each network is served by feeders supplied from a single substation. However, some feeders supplying a given network are fed from separate transformers at the station. In some cases, PG&E has experienced some challenges with circulating currents, such as unintended network protector operations. At the time of the immersion, PG&E was implementing changes to resolve this issue, such as redesigning the substation configuration to supply all feeders to a particular network from the same substation transformer.

Technology

The network substations are each equipped with SCADA, monitoring and controlling network feeders and monitoring network equipment. The communications backbone is optic fiber, with two way communications to each network vault. Within the substation, communications are transmitted over copper, and then from substations back to the operations center, PG&E’s fiber based communications infrastructure.

4.6.14 - SCL - Seattle City Light

Design

Network Area Substation Design

Process

SCL has a network design that breaks the network load into small, isolated sub-networks to limit the number of customers exposed to an outage in the event of loss of any one sub-network. Each sub-network is sourced by six primary feeders (at either 13.8 or 26.4 kV), and is designed to N-1.

All primary feeders that source a given sub-network are sourced from the same substation. This minimizes the potential for circulating currents on the secondary system due to load imbalances between two substation sources. SCL has 15 distinct sub-networks. SCL currently has no ties between the sub-networks, nor have they applied any distribution automation (remote operation) to the network feeders beyond the substation breaker.

4.6.15 - References

EPRI Unde rground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.3 - Network Substation Design

EPRI Low-Voltage Training Material

Network Substation Configurations

4.7 - Network Design

4.7.1 - AEP - Ohio

Design

Network Design

People

Design of the networks serving Columbus and Canton Ohio, the two areas of focus for this urban underground network immersion study, is performed in Columbus by the AEP Network Engineering group, which is organizationally part of the AEP parent company. Within the Network Engineering group, the company employs two Principal Engineers and one Associate Engineer who are responsible for network design for AEP Ohio. These planners are geographically based in downtown Columbus at its AEP Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is organizationally part of the Distribution Services organization, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. In addition to responsibility for designs of the AEP Ohio networks, the Network Engineering group also provides consultative support services to the other AEP operating companies.

Two Principal Network Engineers primarily oversee the designs for Columbus networks; one Associate Network Engineer primarily oversees Canton, but often helps with Columbus-based projects. The Network Engineers are responsible for all aspects of the network design, from inception to implementation, including the preparation of work orders, material acquisition, site inspections, and project completion.

AEP Ohio also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues.

AEP Network Engineers design the network system in Columbus to a full N-2 resiliency, including the substations and spot network locations. This N-2 reliability is notable, as most urban underground network systems operate at an N-1 level. N-2 insures that if any system components fail, the remaining facilities can carry the load and maintain service. For example, all spot network locations are designed with at least three transformers, with any one transformer able to carry the peak spot network load. The AEP Network engineers will also perform radial (non-network) designs for customers who locate within the city centers, and who do not opt for or require network service.

AEP network engineers perform all designs associated with the network, including new service projects and system reinforcement projects. The Engineers perform all aspects of design including network unit design, equipment sizing, performing load flow analyses, and preparing project drawings that describe the designs for construction.

Two Technicians assist the engineers with the preparation of drawings in MicroStation and AutoCAD. This is a full-time position and is assigned to the Network Engineering department.

All civil design for network projects, including manholes, vaults and duct lines, is also the responsibility of the Network engineers, though much of the civil design work is outsourced to a civil engineering firm. The primary Civil Engineer at that firm is a retired AEP Ohio employee who has many years of experience working with AEP Ohio underground networks.

The AEP Network Engineer responsible for customer designs works closely with the AEP Customer Service Representatives and the customer to insure designs for customer service meet all AEP as well as customer specifications.

Process

AEP Ohio has network systems in both Columbus and Canton, Ohio. The Columbus urban area has four separate networks – North, South, Vine, and West – supplied from three substations. Each network is supplied from 138 kV/13.8 kV Δ -Y network transformers. All four networks, about 30 MVA each, are served by six dedicated network feeders at 13.8 kV, with each group of six originating from a single substation. There is no overlap in these networks. This is a preferred design in that the network feeders are sourced at the same voltage, which minimizes the possibility of problems with network protectors pumping or cycling. AEP reports few problems with protectors pumping, cycling, or opening under light network loading.

Each Columbus network is built to N-2 reliability. In Columbus, the Vine network primarily serves spot networks in a high-rise area of downtown (Vine station), with some mini-grids at 480 V. The other three networks (North, South, and West) serve a mix of grid (216 V) and spot loads.

Canton has one network supplied at 23 kV.

The substations that supply Columbus are also designed to N-2, using at least three transformers, with one serving as a ready reserve hot spare. The stations that supply Canton are designed to N-1. The AEP Ohio stations use a ring bus design, with two circuits emanating from each bus section. Other substation bus configurations are used at other AEP operating companies.

AEP designs call for precast manholes and vaults, though the company will pour in place in certain situations. For example, in repairing a deteriorated manhole, personnel may pour the bottom and precast the middle and top section. New manholes and vaults are designed with two ground rods at opposite corners and a ground ring, typically 4/0 cu. AEP is not tying the grounding with the manhole or vault rebar.

AEP duct banks are open cut, concrete encased. Many existing ducts are fiber (Orangeburg pipe). The new construction standard utilizes 5 inch PVC conduits. Typical duct back arrangement is a 4/3 duct bank with primary feeders occupying the lower positions in the duct bank.

For network circuits, AEP uses 500 Cu Flat strap EPR cable with a thin jacket to fit in 3 or 3 1/2 inch duct (See Figure 1) ). AEP also uses 750 Cu or Al cable for station exits for network feeders. For secondary, AEP has standardized on 750 Cu EAM insulated cables as this is the largest size that can fit in the 3 1/2 inch duct. As the ducts are expensive, AEP’s philosophy is to maximize the use of the ducts. In its typical designs, AEP leaves ducts open for communications.

Figure 1: AEP Ohio PVC duct lines encased in concrete

All new network service designs reference the AEP parent company Network Design Criteria guide, which outlines both Single Contingency (N-1) and Double Contingency (N-2) Operations. Using this Design Criteria, the Network Engineer responsible for designing new service performs circuit analysis using CYMCAP and CYME SNA to determine the design needs to meet expected service requirements. Line drawings of the circuits and feeders are then drawn in MicroStation and AutoCAD by two Technicians within the Network Engineering group.

The Network Engineer then specifies the space and duct requirements for the service (vault, duct lines needed, etc.) in AutoCAD drawings and turns the requirements over to a Civil Engineer contractor to prepare the civil designs.

AEP Ohio PVC duct lines encased in concrete

AEP’s network unit design calls for a wall-mounted solid dielectric vacuum switch that is separate from the transformer, a submersible network transformer that can accept ESNA style (elbows or T bodies) connections, and a transformer mounted network protector (see Figures 2 and 3). All new AEP Ohio designs utilize Eaton CM52 network protectors and fiber-optic connections from the protector to the Operations Center for control and monitoring (see Figures 4 and 5).

Figure 2: Primary transformer connection – T bodies

Figure 3: Primary transformer connection – T bodies

Figure 4: Network transformer. Note that the transformer does not have a primary switch compartment

Figure 5: Network protector mounted on network transformer

AEP Ohio uses cable limiters on all its 480 secondary networks, at both ends of the mains (see Figure 6). The company also uses limiters in 216 V networks on cables sizes 250 MCM and above (though faults at 216 V will self-clear). Cable limiter application approach is documented in the AEP Guide to the Installation of Cable Limiters on Network Secondary and Service Cables. AEP uses the “Bussman” type cable limiters.

Figure 6: Cable limiter used by AEP Ohio

Once final electrical and civil designs are completed, the Network Engineer secures permits, writes work orders, and oversees the construction of the service site, including on-site inspections and final commissioning.

Technology

Network Engineers follow the printed and online Network Design Criteria published by the parent company. CYME SNA and CYMCAP are used for circuit and load calculations and network maps. Line drawings are developed in MicroStation and AutoCAD before turning them over to a Civil Engineer contractor.

Design specifications include the following information:

Civil construction specifications, including vault or substation dimensions
Full electrical components, and their specifications, including N-2 design criteria for transformers and feeders
Manhole and duct line specifications, including grounding
Network protectors and Operation Center communications

The STORMS system is a design system that is used to prepare work orders and estimate projects. It utilizes compatible units with predetermined materials, costs, and labor hours associated to each unit. The use of this system for network design is relatively new to AEP.

4.7.2 - Ameren Missouri

Design

Network Design

People

Design of the urban underground infrastructure supplying St. Louis, both network and non- network, is the responsibility of the engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The Underground Division, led by manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including network and non network vaults and manholes, size equipment, perform load flow analyses, and prepare line drawings that describe the designs. All of the engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

The Energy Services Consultants (Estimators) take the designs developed by the engineers and complete the design package, including all the physical elements of the design. Estimators have a combination of years of experience and formal education, including two year and four year degrees, and are part of the union, IBEW.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis.

Ameren Missouri has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both online and printed book format.

Process

The design of the distribution network system serving St. Louis consists of four distinct secondary network grids each supplied by a separate substation.

Each of the four network substations supplies about 205 MVA of load. Three of the stations are sourced at 138 kV from overhead supplies, while one is served at 35 kV from an underground supply. Two of the substations are relatively new, and two are more than 50 years old. At the time of the practices immersion, Ameren Missouri, through its downtown revitalization project, was developing plans to eliminate the oldest substation and add a new switching station in a different location, as the oldest station is also out of phase with the other three.

The secondary network grids supplying downtown St. Louis are 120/240 V volt grids, each served from one of the four substations. Ameren Missouri does not utilize 277/480 V secondary grids. However, most spot network locations are 277/480 V secondary spots.

Two of the 120/208 V secondary network grids are supplied with eight feeders each at 13.8kV. One of the secondary network grids is supplied by seven feeders at 13.8 kV, and the remaining network is supplied by six feeders at 13.8kV.

Ameren Missouri uses dedicated network feeders; that is, they do not supply radial load from feeders that supply the secondary network grids. Their protection settings for network feeders are “one shot to lock out”.

While Ameren Missouri uses neutral grounding reactors to reduce the fault duty for ground faults for radial feeders, they do not use them for network feeders.

Ameren Missouri designs their system to N-1. That is, the system is designed to ride through the failure of any one component during a system peak with only minor overloads to transformers, primary feeders, and second mains. Note that in some cases, Ameren Missouri provides N -2 in that they plan their system to be able to withstand a bus outage. They utilize a ring bus design with bus sections serving two feeders. Consequently the loss of a bus section may result in the loss of two feeders. In these situations the system design really provides N-2.

Until recently, Ameren Missouri did not have a design criterion which limited the number of primary feeders in a duct line. However, as part of the downtown St. Louis revitalization effort, Ameren Missouri is working on planning criteria that will dictate how many circuits may reside in a given duct. They propose that no more than two network circuits originating from the same station may reside in any one duct.

Up until the late 1980s, PILC cables were standard Ameren Missouri. The current standard for primary cables is EPR insulated cables; however, much PILC remains installed.

While their current duct standard calls for PVC duct, Ameren Missouri has considerable clay tile and fiber duct installed. Because of the small size of these ducts Ameren Missouri participated in the development of and is using a thinner wall EPR insulated primary cable which enables them to take advantage of the existing smaller duct system. The thinner wall cable allows Ameren Missouri to install this cable in their smaller sized conduit system.

Technology

Ameren Missouri has a good set of maps depicting their network infrastructure. Maps include:

Operating Map (Also called Byers Map) – this map showing electrical conductivity is used for switching.
Plat Maps, a detailed map of the network area, showing all geographic facilities on a block by block basis. These maps are geographically correct and show duct bank cross-sections.
Cable Route Maps – these maps are basically feeder one lines, depicting the route of the feeder from the substation to termination. They also show all manhole locations. These maps contain more detail than the operating maps.
Switching Maps - These maps are similar to the cable route maps, but also show switching devices.

Network infrastructure is represented in a GIS – BYERS system.

Ameren Missouri is in the process of converting to a new mapping system, Gtech. At the time of the practices immersion, Ameren Missouri had not yet decided how the new mapping system would be used with network facilities.

Estimators use a system called the Distribution Operational Job Management (DOJM) to prepare job estimates. This system enables an estimator to build the job using compatible units that represent certain construction standards and are accompanied by estimates of labor hours to install and materials and their associated costs. The DOJM system is based off of a Severn Trent product.

4.7.3 - CEI - The Illuminating Company

Design

Network Design

People

The design of the network is performed by the CEI Underground / LCI group (Design Group), part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

The group is comprised of Engineers (5) and Design Technicians (3). The department currently includes two younger employees brought into the department in anticipation of retirements, so that departmental knowledge is preserved.

The majority of the design of both the network and non-network systems is done in house. Underground network / non- network design is seldom outsourced at CEI.

The group’s responsibilities include network system and non – network system designs and the development of standards for the ducted manhole system including vault and manhole design standards and customer design standards^[1] . The group prepares construction drawings for the conduit system, vaults and manholes.

The group is responsible for preparing designs for serving and interfacing with larger C&I customers.

The group is also responsible for preparing civil designs.

Process

The network serving downtown Cleveland (the Network) is a small part of the overall ducted manhole underground system serving the Cleveland Area. The bulk of the underground system is served through radial designs.

The Network serves about 399 customers. It consists of one 120 / 208V network grid supplied by five 11kV feeders (PILC, EPR and XLP) fed out of the Hamilton substation, and two spot networks. The network is lightly loaded (about 30% loaded, or about 8-10 MVA of network load), and serves mainly smaller customers. The system is designed to N-1, meaning that service continuity can be maintained with the loss of any one device.

The Network is made up of approximately 57 vaults, and includes 61 network transformers (500, 750, and 1000 kVA transformers). Network protector sizes range from 1600 – 3000 A. The secondary is made up of 500 cu cables (XLP) with cable limiters.

Hamilton Sub supplies the Network as well as other downtown load. It is supplied by two 138 kV sources to four substation transformers with dual secondary windings, supplying 12 11kv bus sections. The network feeders and load are staggered among the bus sections / transformers to maintain N-1 reliability.

CEI’s network feeders utilize separate duct banks and different routes wherever practical in order to reduce the probability of a multiple contingency situation. However, they do have certain instances, where multiple feeders share the same routes.

CEI limits the number of feeders entering a transformer vault to the one serving the transformer by serving all transformer vaults from taps fed off of the main duct run.

CEI does not using fire proofing or arc proofing tape, even in facilities that contain multiple primary feeders, or both primaries and secondaries. If they are working in a hole with old asbestos tapes or other materials, they remove the asbestos from all facilities in the hole before commencing the work.

CEI’s goal is to not increase the loading on the network, as they are unsure of the condition of secondary cables and thus the current carrying capability of the secondary. CEI does not add large loads to the network – most large loads are served either by multiple feeders from the 11kV sub- transmission system (see Non-Network design - Process ), or by CEI’s 33kV subtransmission system. Small loads will be added to the network.

When CEI receives an application for a new service in an area served by the network, they may involve the Planning engineers to see if they can carry the load on the network from a particular transformer or mole. Typically a new load of less than 400kW will be connected to the network. Larger loads are normally served from either the 4kV or 11kV radial systems.

If the project involves just a tap, the design will be performed by the engineers within the Design Group who focus on serving customers (the LCI ).

If the project involves a cable line extension, both a cable engineer, and an LCI engineer are usually involved in the design. The cable engineer would design the conduit system up to the point of the customer interface, and the LCI engineer would develop the service interface, including the transformation and switchgear.

Technology

Engineers will prepare the required construction drawings that show the duct configurations, shows the manhole design, references standards pages, etc. Wherever possible, they will use the GIS system as a foundation for a drawing. They may show a portion of an existing vault drawing if the project involves a revision. In general, the prints they produce are very clear and well received by the Underground Group.

^[1] FirstEnergy has a corporate Standards group, but system wide standards for ducted manhole and network systems are not fully developed, as FirstEnergy companies “grew up” with different standards / equipment / approaches. Consequently, the CEI Underground / LCI group develops and maintains standards for the ducted manhole system serving the Cleveland area (network and non-network). FirstEnergy has formed a system wide users group focused on addressing and standardizing network issues across their system.

4.7.4 - CenterPoint Energy

Design

Network Design

People

Network design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group deals with the design of three phase pad mounted transformer installations, including looped commercial developments. This group, the Padmounts group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is not typically involved in network design.

Another sub group focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. This group, called the Vaults group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. Note this group designs submersible network vaults as well as building vaults.

The final subgroup is one focused on distribution feeder design. This group, the Feeders group, focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

CenterPoint has five 120/208 V secondary networks served by from 6 – 10 primary feeders each. Three different substations supply the networks, with two substations supplying two different networks each, and the remaining sub supplying one network. These networks serve customers in both downtown Houston and in areas outside central Houston. CenterPoint does not have a 480V network street grid.

The 120/208V network secondary grids are fed by 12.47 kV primary feeders

but the feeders are not exclusively dedicated to serving the network; they do supply some radial load.

The street grids are fed from both 208V subway vaults and from 208 “dry vaults” which are building vaults that supply both the local building and the street grid.

Figure 1: Picture of feed from a customer network vault out to the street grid

CenterPoint also provides spot network service to customers at 12kV with a 120/208 V and 480V secondary.

Note that in their network unit design, CenterPoint has made the decision to physically separate the transformer primary disconnect (into the transformer) from the unit itself. Similarly, CenterPoint physically separates the network protectors from the transformers as well. The decision to separate the components of the network unit was made for safety, so that an explosion or fire in one component does not impact the other component. See Network Unit Design - Process for more information.

Technology

Engineers will prepare the required construction drawings that show the duct configurations, the manhole or vault design, references standards pages, etc. using MicroStation CAD software. The Major Underground group also uses LD Pro by Itron to identify and cost estimate the material requirements for the project. Engineers will supplement these estimates with anticipated labor costs and estimated civil construction costs. (Note that CenterPoint has developed assembly units for selected construction types that contain a resource and cost estimate to perform the work associated with that construction type. However, most of these assembly units have been developed for overhead construction standards. Consequently, underground design involves a fair bit of manual intervention to develop cost estimates.

Estimates developed using LD Pro feed into CenterPoint’s SAP system which is used to establish an order to capture all of the costs associated with the project, including the costs of preconstruction activities. This SAP order is created in the initial stages of a project.

4.7.5 - Con Edison - Consolidated Edison

Design

Network Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Engineering and Planning - Responsibilities include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Network Design Criteria

Con Edison’s design criteria calls for no more than two feeders in any one duct bank that services the same areas. Also, feeders supplying any one area are sourced from different minor bus sections at the station so that the loss of a minor bus section won’t jeopardize any one area. Con Edison’s design criteria calls for no more than two feeders in any one manhole.

In the network system design used in Manhattan, four feeders typically run down the avenues (the main north-south thoroughfares on Manhattan). Two feeders run down one side of the street, and two run down the other side.

4.7.6 - Duke Energy Florida

Design

Network Design

People

Network design is performed by the Distribution Design Engineering group for Duke Energy Florida, which works out of offices in both downtown St. Petersburg and downtown Clearwater. The groups are responsible for designing new and refurbished network designs, as well as underground radial and looped distribution designs. The Distribution Design Engineering groups in Clearwater and St. Petersburg are led by a Manager, Distribution Design Engineering, and are organizationally part of a Distribution Design Engineering Group responsible for Duke Energy Florida’s Coastal region, led by a Director.

The Design Engineering group is comprised of two sub-groups: an Engineering group, comprised of degreed engineers, and a Technologists group, comprised of non-four year degreed Network Technologists. Work within the Design Engineering group, both in Clearwater and St. Petersburg, is assigned geographically, such that a designer (either an Engineer or a Technologist) is responsible for both network and non-network designs within an assigned geographical area. Some designers focus on commercial customers, while others focus on residential customers. For example, the St. Petersburg design group has two engineers that focus on commercial designs – both engineers have four-year engineering degrees.

The criteria for choosing non-degreed Technologists may include years of experience, and for new job postings, at least a two-year degree in electrical technology. The existing group has individuals with varied experience, including distribution operations, control and transmission.

The Design group is experiencing a large turnover in its Engineering staff, as a number of employees with many years of experience are retiring. A challenge for the group as positions turnover will be acquiring new resources with design experience.

The design of the network is also based on input from the Network Planning group. Network Planning at Duke Energy Florida is organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I), which is led by a Director of PQR&I for Duke Energy Florida.

To perform planning work, the Network Planning group divides the Duke Energy Florida territory into four separate zones. The cities of Clearwater and St. Petersburg, part of the South Coastal Region, are included in one of the four zones. Every zone is assigned a Lead Planning Engineer and Senior Planning Engineer, who are responsible for all distribution planning activities within the zone. This work includes recommending enhancements to meet anticipated capacity requirements. All Planners have four-year degrees in Electrical Engineering, a requirement for the position.

The design of the network is also influenced by the Duke Energy Florida Standards group, which Group oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family. The Standards engineer has developed a Distribution Engineering Manual section on Secondary Networks, which provides good background information on network component design considerations including cable limiter placement and coordination, protector operation, and manhole and vault considerations. See Attachment C .

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies.

Duke Energy Florida has developed network design standards, which are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D .)

The Design engineers are engaged in a Duke Energy corporate-wide process to consolidate design standards for network systems among the various Duke operating companies, due to be finalized in 2017. A challenge will be to integrate historic design differences into the new guidelines. For example, historic cable limiter application approaches have differed among Duke Energy operating companies. The new standards will need to reflect these differences and include appropriate going forward standards.

Process

In Clearwater, Duke Energy Florida has a true low voltage meshed secondary network. This network, a 125/216V grid, is supplied by three medium voltage (7200/12470V) wye-connected primary network feeders fed out of one substation. The three feeders are targeted to be dedicated network – they historically had supplied both network and non-network load, but Duke Energy is nearing completion of a project to remove all non- network load so that the three feeders supplying the network grid are true dedicated network feeders.

The substation that supplies the network feeders is a large four-transformer station that supplies non-network loading as well. While all three network feeders are fed out of the same substation, the feeders are supplied from separate bus sections at the sub (open bus ties to manage fault currents), sourced by separate transformers. Because the feeders are supplied by three sources and have different loads, and because the network is very lightly loaded, Duke Energy Florida has experienced issues with open and frequently operating network protectors on their Clearwater system. Duke Energy Florida expects this situation to improve as the remaining non-network load is removed from the feeders, and as planned new loading is added to the system.

Duke Energy Florida has designed its network feeders with primary sectionalizing switches. They have historically used three-way (feeder in, feeder out, and alternate feeder) oil switches that can be used to sectionalize, transfer loading from circuit to another, or tie feeders together. Devices can be opened, closed, or put in the ground position. The older devices, locally referred to as “RA” switches (Rocker Arm), are motor operated, and can be operated from outside of the vault or manhole using a tethered control, or from SCADA. Part of the normal process for troubleshooting a network feeder is to sectionalize and restore service to the non-affected part of the network feeder.

Duke Energy Florida is in the process of replacing the oil-filled sectionalizing devices used on the Clearwater network feeders with solid dielectric vacuum switches. The oil devices are near end of life, and it is becoming more difficult to obtain parts. In addition, the move away from an oil insulated device is part of an effort by the Duke Corporation to move away from oil or gas insulated switchgear. As Duke Energy Florida pursues a permanent replacement for the RA switch, they are seeking a device that provides a visible open.

The replacement solid dielectric vacuum devices, under design specification at the time of the practice immersion, are slightly larger than the oil-filled devices and will be placed in sidewalk vaults. These devices, which do not have fault interruption capability, will be equipped with remote reporting faulted circuit indicators (FCIs) that communicate via SCADA to the DCC. The devices will provide a visible open through an interlinked system where the vacuum bottle must be open before you can open the visible break. The new devices will be placed on an angled stand so that the switch faces the vault exit and can be easily operated with a hot stick from outside the hole. The switches will also have the ability to be operated from above ground using a hand held pendant control that is hardwired to the switch. The decision to proactively replace the older oil gear with the new solid dielectric switches was collaborative involving the component engineer within the PQR&I group, the Standards engineer and the Network Group.

In St. Petersburg, the company moved away from a network grid system years ago, with eight spot network locations remaining in the system. Duke Energy Florida is not planning on reintroducing a network infrastructure in downtown St. Petersburg. Most of the infrastructure in St. Petersburg is supplied by a primary and reserve feeder loop scheme, with automated transfer switches (ATS). Outside the network, the primary and reserve looped feeder scheme is used in Clearwater as well. The ATSs are motor operated and most are tied in with SCADA and can be monitored and controlled from the DCC via a 900 MHz radio communications system. When ordered, the dispatcher can remotely open a feeder switch if it is equipped with communications. For those switches that have yet to be upgraded with SCADA, Network Specialists must manually operate them. Note that at the time of the practices immersion, Duke Energy Florida is in the process of upgrading switchgear communications infrastructure from 900 MHz radio to secure cellular.

St. Petersburg underground infrastructure is fed by 12 different feeders supplied from three different substations. Many of the in-service ATSs are oil-filled devices, with two oil-filled tanks with a bus tie between them. Duke Energy has prioritized ATSs with two oil-filled tanks located in building vaults for replacement. The replacement design utilizes two three phase solid dielectric vacuum switchers (MVS) looped together (jumpered from one to the other), with the transformers supplied radially off of the T bodies using load reducing 200 amp taps (see Figure 1).

Figure 1: Solid dielectric design for a three-way 3Φ switch utilizing Elastimold MVS switches. This switch can be used as the high side disconnect for a network transformer, with the 200 A interface on the back of the 600 A T bodies (left side) used to supply the transformer

Duke Energy Florida does use cable limiters in its network design. Cable limiters are installed at each secondary junction on the secondary mains on the outgoing secondary cable. In addition, cable limiters are installed at all service connections. Duke Energy Florida uses full section limiters on the street main secondary grid. Half section limiters are used on service connection junction points and are sized to match the conductor size. This is to ensure a service conductor fault will be isolated before damaging the secondary main and associated limiters. Limiters are sized such that when a primary fault occurs, the primary protection should clear before any limiters blow. For a secondary fault, the limiters should clear the fault before the network protector fuse opens. Based on past experience, the limiters behave as anticipated.

Duke Energy Florida uses T-body joints for connecting cable sections, and elbow joint connections to the transformer.

The network unit supplying the network grid consists of a separate wall mounted primary switch, a network transformer, and transformer secondary mounted network protector (see Figures 2 and 3)

Figure 2: Wall mounted primary switch supplying network transformer

Figure 3: Transformer secondary mounted network protector

Technology

At 125/216V, Duke Energy Florida has standardized on the CM22 with internal NP fuses. At 277/480V, they have standardized on the CM52, a fully submersible protector with a dead front design. Duke Energy Florida’s network protector specification also calls for features such as:

External disconnects, which are used to separate the protector from the secondary collector bus. These disconnects are a safety feature used in a 480V design to mitigate arc flash risks. On this network protector, the NP fuses are internal and link style, as Duke Energy Florida is able to create the visible break between the NP and the secondary bus using the disconnects. Note that the disconnects can only be opened with keys which can only be accessed when the NP handle is in the open position because of an interlock system.

Wall-mounted ARMS (Arc Flash Reduction Maintenance System) modules, which enable a worker entering the vault to change the protection settings in the protector to reduce the fault clearing time and thus the arc energy in the event of a fault.

A submersible Stacklight, which is an annunciator system that indicates network protector status through a series of different colored lights.

Duke Energy Florida also uses a remote monitoring system. The company uses the Eaton VaultGard communication platform for recording and aggregating data from the network protector and vault. This information is communicated through a Sensus cellular monitoring system to a central server every half hour. Within the Network Group, information from Sensus, such as secondary loading, is monitored daily. Note that the Sensus system is read only, with the functionality to remotely control equipment being disabled for security purposes.

Duke Energy Florida is in the process of replacing the oil filled sectionalizing devices (RA switches) used on the Clearwater network feeders with a new solid dielectric vacuum switch design. Drivers for this replacement effort include the fact that the in service devices are a 1980s vintage device and are near their end of life, and it is becoming more difficult to obtain parts. In addition, the replacement is part of an effort by the Duke Corporation to move away from oil or gas insulated switchgear. As Duke Energy Florida pursues a permanent replacement for the RA switch, they are seeking a device that provides a visible open (see Figures 4 through 7).

Figure 4: Network Feeder primary sectionalizing switch (RA) switch

Figure 5: Network Feeder primary sectionalizing switch (RA) switch

Figure 6: Control Box for network feeder primary sectionalizing switch

Figure 7: Example of an RA switch replacement considered by Duke Energy Florida. The switch depicted is a vacuum switch with the breaker under oil. Duke Energy Florida is planning to move to a solid dielectric vacuum switch

4.7.7 - Duke Energy Ohio

Design

Network Design

People

Network design is performed by a Network Project Engineer and two Designers who are part of the Distribution Design organization. This organization is focused on all distribution design work for Duke’s Ohio and Kentucky utilities, including network design.

Theses resources work closely with one another and with the Planning Engineer focused on the network to design modifications to the network.

Process

The design of the distribution network system serving Cincinnati consists of two network substations supplying four distinct secondary networks (two networks supplied by each substation). Three of the four networks in downtown Cincinnati are supplied by eight feeders, each, and the fourth network, by four feeders. The primary voltage of network feeders is 13.2kV.

Duke Energy Ohio’s cable standard for the network primary is a 750 cu EPR flat strapped neutral cable or a 4/0 cu EPR cable (without flap strapped neutral). They chose the EPR cable with flat strapped neutral design because much of their old duct system consists of 3 1/2 inch square duct. Note that Duke Energy Ohio will pull three conductors bundled together through a single duct.

Duke Energy Ohio narrows their network to a specific geographic area. If there is new load being added to this geographic area, Duke will consider in adding the load to the secondary network. They have no plans to actively de-load the network. In some cases, Duke Energy Ohio has elected not to add new load to the network based on project specific factors.

New vaults that are designed to serve new load are designed above ground. Customers must provide all equipment and access points within their building. The City of Cincinnati does not provide a right of way space for underground vaults. Note that Duke Energy Ohio does have a significant number of submersible faults already built.

4.7.8 - Energex

Design

Network Design

Note: Energex does not utilize a low voltage meshed secondary “network” in its CBD. This section discusses their design approach in serving the Brisbane Central Business District.

People

Energex has a Systems Engineering group, led by a group manager, and part of the Asset Management organization. This group is responsible for establishing the design standards for the distribution network. Energex also has a Design organization within its Service Delivery organization, also led by a group manager, and responsible for performing designs of specific projects, including new construction and system reinforcement projects. The Design group is comprised of four-year degree qualified engineers and engineering associates.

Process

To serve the downtown Brisbane central business district (or CBD), Energex is using an 11kV primary system, and supplies loads using single feeder supplies, or - in the Central Business District - using two and three feeder meshed 11kV systems.

There are four major substations that supply the load in downtown Brisbane. These substations are sourced at 110 kV by a combination of overhead and UG feeders. Within the stations are multiple 110 kV: 11kV dual winding transformers supplying the 11kV bus that sources the 11kV distribution system.

Energex runs multiple primary feeders at 11 kV out of these stations as part of a meshed system. Most of the feeders supplying the CBD are part of a three feeder mesh, where each of the feeders is fed out of the same substation, and are normally tied together at a “mesh point” located at a medium-voltage substation location. The feeders supply medium-voltage substations containing transformers (typically, either 1000 or 1500 KVA units), that supply the low-voltage system that supplies the down town load. Energex designs the mesh with sectionalizing points (circuit breakers or CBs), normally SF6 or oil (older design) switches located at various points along the feeder, protected with bus differential relaying, and a pilot wire scheme, so that devices operate simultaneously. These sectionalizing points may be designed on either side of a medium-voltage station, or separating multiple units within a medium-voltage substation, such that even with the loss of any one feeder section, customers can be supplied from the remaining mesh after performing some switching. Note that Energex does not use any automatic switching schemes, or remote control of these switches. Energex does install basic alarming in their medium-voltage stations, such as alarms for an open breaker, and general alarms (battery charge, sump pump). Alarms communicate by wire to an RTU at the substation supplying the primary feeder, and then through a WAN back to their SCADA.

For example, some high rise facilities may be supplied by Energex via multiple transformers separated by a switch on the primary. In the case of a fault on one feeder section, the bus differential relays isolate the section, resulting in a loss of supply to one of the transformers supplying the customer, and thus a partial loss of service to the customer. However, the customer may have the ability to perform switching on his side to energize the de-energized secondary bus by closing a secondary bus tie, after decoupling the secondary bus from the Energex transformer (using an interlock system that would prevent him from closing the bus tie until after it has separated itself from the Energex transformer). In this scenario, the customer load is restored, being supplied by the remaining in-service transformer.

The primary feeders also have bus over current protection at the source and at the mesh point. As UG feeders supplying the CBD, the primary feeders do not employ automatic reclosing and, upon sensing a fault, trip and lock out immediately. At the supply substation (110 kV: 11 kV), Energex has automatic changeover of the buses, so that the bus remains energized even with the loss of any one substation transformer. CBD has transformers operating in parallel so there is no auto changeover required on CBD substation busses.

Characteristics of a Three-Feeder Mesh Network

(from the Energex Standard Network Building Blocks document, Feeders BMS 03929, Updated: 13/12/2012, see Figure 1).

The layout of a developed three-feeder mesh network is shown in Figure

The network has the following characteristics:

Any two of the three feeders of the mesh ideally must be capable of supplying the total load of the mesh.

Distribution substations are installed generally in each major building.

Local low-voltage (LV) supply may be run onto the street from a distribution substation in a building in order to supply other customers on the street.

A fault in any of the 11 kV cables within the mesh results in the faulted cable being isolated by the circuit breakers (CB) at each end of it. Supply is maintained to the majority of the load supplied by the mesh.

Where the 11 kV bus in a distribution substation has a single CB for two transformers (e.g., Distribution Substation ‘A’), a fault in either 11 kV cable connected to the substation results in loss of supply to one transformer and partial loss of supply to the building. The building generally would have a transfer scheme on the LV side, a standby generator, or both.

If an 11 kV cable that has a teed connection to a load fails, the teed load loses 11 kV supply until the cable is repaired. Teed connections should not be installed in three-feeder mesh systems.

Individual distribution transformers are protected generally by fused units, sometimes by CBs.

A large CBD area may have many three-feeder mesh networks supplying it.

A three-feeder mesh may have a further backup connection to another three-feeder mesh, and other variations depending on the situation.

A CB may feed more than one mesh as shown, and protection must be arranged to suit (see Figure 1).

Figure 1: Energex 11 kV CBD Feeder Diagram

Technology

Medium-voltage substations in the CBD are usually located within building vaults. The medium-voltage stations consist of primary (11 kV) switches protected by bus differential relaying, transformers, and secondary switchgear that supplies both the building load (see Figure 7) and feeds into the low-voltage network serving the CBD (see Figures 2 to 6 and Figure 8).

Figure 2: Energex employee giving safety briefing before entering a C/I substation, locating in a building vault

Figure 3: Dry type transformer supplied by the three feeder mesh

Figure 4: Primary terminations (PILC) on dry type transformer

Figure 5: Multiple dry type transformers

Figure 6: Circuit breakers with bus differential relaying

Figure 7: Low-voltage switchboard, with feeds to the customer

At some locations, Energex may “Tee” off the primary feeder with a substation consisting of an SF6 gas insulated ring main unit (the primary switch gear current design) with an “in” switch, an “out” switch, and a fused, switched tap leading to the transformer. The use of a packaged substation with a ring main unit is a common design outside of the CBD.

Figure 8: Typical building vault substation with ring main unit (foreground) and transformer (background)

In URD applications, Energex uses a similarly designed “packaged” substation, a pad-mounted unit consisting of the ring main unit ( “in” switch, an “out” switch, and a fused, switched tap leading to the transformer), the transformer, and the low-voltage switchboard supplying the low-voltage network feeding the development (see Figures 8, 9 and 11). Note that URD developments are fed by an extensive low-voltage network feeding through mini pillars (see Figure 10). Services are tapped from these mini-pillars to serve customers (see Figure 12).

Figure 9: Typical pad-mounted 'packaged' substation supplying UG development. High-voltage switches (ring main unit) in the front, transformer in the middle, and low-voltage switchboard in the back

Figure 10: Typical pad-mounted 'packaged' substation supplying UG development (another view). Note mini pillar to the right of the substation

Figure 11: Low-voltage switchboard supplying the LV network feeding the development

Figure 12: Typical home, note mini-pillar in the foreground supplying the customer

Energex has SCADA at the substation, and some remotely monitored and controlled normally open tie points between 11kV feeders out on the system, but in general, they have little SCADA beyond the substation.

Energex is currently installing a PQ meter on the low-voltage side of all distribution transformers greater than or equal to 200 kVA, three phase.

At the time of the immersion, Energex was in the process of implementing the Power On DMS product, which provides electronic displays of the distribution networks, both medium voltage and low voltage.

4.7.9 - ESB Networks

Design

Network Design

Note: ESB Networks does not utilize a low voltage meshed secondary “network” system. This section discusses their design approach in serving Dublin. See Non-Network Design for more information.

People

Network design at ESB Networks is performed by engineers within the Network Investment groups – two groups responsible for planning network investments in the North and South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Network designs and design specifications are developed by engineers and by “Technologists,” who have developed their expertise through field experience.

ESB Networks may receive engineering consulting support from ESB Networks International (ESB NetworksI) for larger designs.

Network design standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Technology

In central Dublin, the network operates at 10 kV, all of which is underground. Within Dublin there are 38 HV stations. Thirty-one are 38 kV:10 kV and seven are 110 kV: 10 kV. There are 2040 MV substations that consist of switchgear as part of the ring main unit, a transformer, and a secondary, all in one package. This provides 200, 400 and 630 kV in one packaged substation. The Dublin system is an N-1 design with forward feed and standby feed capacity. Dublin has 170 customers that take voltage at 10 kV; these customers are primary metered customers.

4.7.10 - Georgia Power

Design

Network Design

People

Design of the urban underground infrastructures supplying metropolitan areas in Georgia is the responsibility of the engineering group within the Network Underground group. The Network Underground group, led by the Network Underground Manager, consists of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure at Georgia Power. It is a centralized organization, responsible for all Georgia Power network infrastructures.

The Network Engineering group, led by the Network Underground Engineering Manager, is comprised of Engineers (Electrical and Civil) and Engineering Representatives concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Engineering Reps have a combination of years of experience and formal education, including two-year and four-year degrees. Engineers are not represented by a collective bargaining agreement.

In addition to the engineers with in the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also deal with issues of network design.

Engineers design the system, including vault designs, network unit designs, equipment sizing, perform load flow analyses, and prepare one-line drawings that describe the designs. The design is then turned over to draftsmen who do final CAD drawings that detail all the specifications, both civil construction and electrical component, and input them into the GIS system. There are 12 design engineers and 5 draftsmen (called “GIS Technicians).

Georgia Power has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. Standards are available in both an online and printed book format. Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. It is a living document, and the responsibility of the Standards Group comprised of the Principal Engineers in the Network Underground group. The standards are divided into two main sections: civil construction and network specifications and design.

Process

Georgia Power, as of the time of this immersion study, has 35 networks in the metro Atlanta area. The company tries to limit network sizes to 40 MVA but has a few 50 MVA networks in place there. Each network group is typically fed by 5 network feeders, though they do have some six feeder networks. The system is designed to n-1.

Network feeders are supplied from a network bus at the substation supplied by a substation transformer that feeds only network load. No non – network feeders will be fed off of the network bus. Feeders supplying any one network are sourced from the same substation. Georgia Power uses bus voltage regulation at the station.

Network feeders are dedicated, with no sectionalizing devices or tie points, though at the time of the immersion, Georgia Power was investigation the use of tie points for network feeders. (Note, Georgia power does have primary sectionalizing on network feeders supplying the airport for added reliability).

Typical duct bank configurations are two-wide by six high. Vaults/manholes have bay forms built into the corners to take the bend out of the cable in the manhole. Therefore, the cables can maintain the appropriate bending radius and still be near the wall in the corners. Single driven ground rods are used in the manholes.

Figure 1: View of manhole corner (bay forms used to create corner)

Another notable aspect of Georgia Power’s network design is the use of what they call “Peachtree racking.” This standard calls for consistent racking approach that consists of primary cables racked on the bottom, with secondary cable pairs racked above (See Figure 2.). The racking system is clearly marked, and facilitates future expansion out of the manhole. Georgia Power has found this is a tremendous benefit in standardizing design, streamlining maintenance, and providing greater worker safety (See Figure 3.).

Figure 2: GA Power employee explaining benefits of Peachtree racking within a training manhole

Figure 3: Desktop training aid showing Peachtree racking approach

Georgia Power uses both Eaton and Richards dual-voltage network protectors. There are current-limiting fuses external to each protector (Figure 4), and newer protectors have external fuse boxes. This is to provide better arc flash protection by only uncovering one fuse at a time. They are in the process of converting older units that utilize electromechanical relays to units that use solid state relays. At the time of the immersion, they were evaluating new protector designs. Georgia Power’s current standard calls for network protectors to be fully submersible, and mounted on the network transformer.

Figure 4: Current limiting fuses (covered with fire proof tape) positioned between collector bus and protector

Georgia Power has remote monitoring and control of all network protectors. They are tied to the Network Operations center either through radio, or through a fiber system that aggregates information from multiple vaults. Georgia Power has used SCADA for protectors for approximately 15 years.

Georgia Power’s standard for network transformers conforms to IEEE C57.12.40 ( IEEE Standard for Network, Three-Phase Transformers, 2500kVA and Smaller). GA Power also specifies units with the following minor modifications: 1) transformers are welded onto metal rails to keep them off the vault floors and make them easier to pick up with a fork lift (See Figure 5); and 2) every transformer has phasing tubes on top to identify phasing in the transformer (See Figure 6.). The phasing tubes provide a simple and foolproof way for tracing voltage. On the transformer end, field personnel can insert a probe into the phasing tube on a de-energized unit, and put a signal on the cable. On the joint end, crews can trace the connection to phase from this signal. They can then repeat the procedure for the remaining phases.

Figure 5: New transformer – note rails welded to transformer bottom

Figure 6: Transformer – phasing tubes

Georgia Power rarely uses cable limiters on its secondary network grid system in Atlanta.

Georgia Power will use sand type current limiting fuses between the secondary collector bus and the customer service, mainly to protect its network bus from customer faults. Georgia Power does not openly advertise the use of these limiters, and it expects the service itself to be fused on the customer end.

There are many secondary spot networks in the Georgia Power system, mainly 480 V, particularly in Atlanta. Georgia Power refers to a true spot network supplied by network feeders as a network vault service. Common network transformer sizes for spot networks are 1000 kVA and 2000 kVA. Note that GA Power may also use the term “overhead spot network” to describe some locations where they have a network supplied by two overhead systems. This is an exception rather than a rule.

Another notable feature in the Georgia Power network is the use of full rubber insulation on its bus conductor (See Figure 7 and Figure 8). This may be more costly than designs seen in other networks, but Georgia Power is satisfied that it adds another layer of protection and reliability to the system and to its customers, while enhancing employee safety by reducing exposure to shock and flash.

Figure 7: Secondary collector bus with EPR insulation

Figure 8: Secondary collector bus with 600 volt EPR insulation, cross section

Technology

Georgia Power uses its GIS system (ESRI) to keep extensive and detailed maps of all underground networks. Network maps are now drawn up in a CAD system by design engineers and draftsmen, which augment original maps that have been imported from the past and converted to raster drawings. CAD maps are fed into GIS. Network maps include the following information:

Civil construction specifications, including vault or substation dimensions
Full electrical components, and their specifications and placement
Manhole and duct line specifications

In addition, design engineers refer to the Standards Group online or hard copy book for standard designs and acceptable variations.

4.7.11 - HECO - The Hawaiian Electric Company

Design

Network Design

People

Underground network design is performed by the HECO T&D Division. This group is part of the Engineering Department. The group works closely with the Planning Division in network designs.

The group is comprised of 2 lead engineers, 13 design engineers and a supervisor. All are four year degreed engineers with about half the group having their PE license.

Process

The network serving Honolulu is a relatively small part of the overall ducted manhole underground system. The bulk of the underground system is served through radial designs.

The Network serves about 1600 customers. It consists of seven 120 / 208V network grid supplied by 8 11.5kV feeders (PILC, EPR and XLP), and 27 spot networks with 480y/277 V secondaries.

The Network is made up of approximately 140 network distribution transformers. The network system consists of about 181000 feet of primary and 44000 feet of secondary cable.

The system is designed to N-1, meaning that service continuity can be maintained with the loss of any one device.

An area substation supplies the Network as well as other downtown load. It is supplied by two 138 kV sources to three 50 MVA (138kV / 11.5kV) delta zig-zag substation transformers connected in a breaker and a half scheme on the 138 kV side, and a ring bus on the 11.5kV side.

HECO has no plans to increase the size or capacity of its secondary network systems.

Technology

HECO is using Siemens PTI PSSE, version 29.5 to perform load flow analysis in the network.

4.7.12 - National Grid

Design

Network Design

People

There are two designers who perform network designs for the National Grid Albany network.

One designer (a Design Investigator) focuses on designing smaller new services connections to the network, 800 amps and below. This individual has a two year degree, though the degree is not mandatory for the position. This designer has field experience as both a cable splicer and maintenance mechanic. This designer also performs some non- network UG and overhead service designs.

The other designer (a Designer C) performs all larger and more complicated network designs, including network reinforcements, large new services projects greater than 800 A, and vault designs. This individual has a two-year degree, a requirement for the position. This designer also performs non – network UG designs.

Organizationally, both designers are part of the Distribution Design organization, led by a manager, and part of the Engineering organization at National Grid. This organization is structured centrally, with resources assigned to and in some cases physically located at the regional locations. The designers who support the Albany network are both physically located at the NYE building in Albany.

Both designers are represented by a collective bargaining agreement. The Design Investigator and Designer classifications are two different classifications with different progressions.

Both designers work very closely with the field engineer, part of Distribution Planning, assigned to the underground department to support the Albany network.

National Grid will determine the appropriate service type for a customer based on their load, criticality and location. There have been times where they have asked a customer to accept network service (a sports arena, for example). National Grid Albany does not use a separate rate for network customers.

Process

The design of the distribution network system serving Albany consists of two network substations supplying one distinct 208Y/120 V secondary network system. The secondary network grid is supplied by ten dedicated network feeders – three from one substation and seven from the other substation.

National Grid’s Albany network system is designed to n-2. That is, the system is designed to ride through the failure of any two components (primary and secondary cables, transformers, network protectors, and ancillary equipment) during a system peak, with only minor overloads to transformers, primary feeders and secondary mains. For example, for a network with four primary cables, the design shall be such that the network system can withstand the failure of a primary cable with one cable out of service for other reasons.

Transformers are sized such that under single contingency conditions (n-1), loads on any transformer shall not exceed 120% of nameplate rating. Under double contingency conditions (n-2), loads shall not exceed 140% of nameplate rating. Under all conditions, loads shall not blow protector fuses.

National Grid also has a separate 277/480 V spot network system supplied by five 34.5KV feeders and serving fourteen spot network locations. Two additional large customers are dual fed primary voltage customers off of these 34.5kV feeders. There are also ten customers fed from 11 spot networks off of the 13.2kV general network feeders. Three of these are 125/216v, the rest 277/480v. Additionally, there is one customer fed off of two of these 13.2kV feeders through a padmount (PMH-9) switchgear. These spot network locations are designed to n-1.

Network substations are designed with a minimum of two high voltage supply circuits and two power transformers so that the failure of any transformer or supply circuit will not affect the network supply.

National Grid’s design calls diversified duct line routes for primary feeders to minimize the number of feeders in a given duct line. National Grid uses arc proof taping of cables. All duct lines are concrete encased, including primary cable ducts, and secondary cable duct. .

Much of the existing primary and secondary system is built with PILC cables. National Grid’s current standard calls for EPR insulated primary cables. The secondary cable standard calls for EPR insulated cables with a Hypalon (low smoke) jacket. National Grid does use cable limiters.

National Grid uses submersible transformers with throat mounted submersible type network protectors. Transformers are equipped with a primary disconnect and grounding switch.

Technology

National Grid has several maps depicting their network infrastructure. Maps include:

Index Operating Map, an 11x17 map showing a single line of network feeders.
UG Conduit Drawings, showing duct bank configuration and circuit routing.
Secondary prints, showing locations, type and size of secondary cable system components.

4.7.13 - PG&E

Design

Network Design

People

Network design at PG&E is performed by the planning engineers within the Planning and Reliability Department. This department is led by a Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems, and is also responsible for network design. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution design.

Both network planning engineers are four year degreed engineers. The planning engineers are represented by a collective bargaining agreement (Engineers and Scientists of California).

The planning engineers work closely with project estimators (Estimators or Senior Estimators) who develop cost estimates and perform field checks to see if the design laid out by the planning engineer is workable in the field. The estimators also prepare the job packet for construction. PG&E has project estimators located in local offices to work with smaller projects, and estimators located in their Resource Management Centers, who work with larger projects. The estimators that work on network design projects are located in the San Francisco division.

Planning engineers and Estimators are represented by collective bargaining, Engineers and Scientists of California (ESC).

Process

The design of the distribution network system serving San Francisco consists of three network substations supplying 10 distinct secondary networks. The Oakland network is fed by one station supplying two network groups. Of the 12 total network groups, 10 are supplied by 12 kV feeders. At 12kV, the individual network groups are each supplied by six dedicated network feeders. Two network groups are supplied at 34.5 kV. One of these network groups is supplied by four feeders, and the other five.

PG&E’s design calls for no more than two feeders from the same network group in a given duct line. All duct lines are concrete encased, including primary cable ducts, secondary cable ducts and fiber ducts ^[1] .

The 12kV system is designed with PILC cables. 750 cu EPR with a flat strapped neutral is sometimes used as replacement for PILC cable where duct size is limited.

Each network is served by feeders supplied from a single substation. However, some feeders supplying a given network are fed from separate transformers at the station. In some cases, PG&E has experienced some challenges with circulating currents, such as unintended network protector operations. At the time of the immersion, PG&E was implementing changes to resolve this issue, such as redesigning the substation configuration to supply all feeders to a particular network from the same substation transformer bus section.

PG&E supplies 120/208V secondary network grids, and both 120/208V and 277/480V spot networks.

PG&E’s network system is designed to n-1. That is, the system is designed to ride through the failure of any one component during a system peak, with only minor overloads to transformers, primary feeders and secondary mains during peak periods.

PG&E is not planning to build any new networks, but they will add loads to the existing networks, particularly in San Francisco. In Oakland, PG&E tends to serve new loads from the radial system. Non-network customers are served from the radial system. If customers want a second supply for backup, they must pay for the costs of installation, ownership and reserved capacity per the applicable PG&E tariffs.

Within San Francisco, PG&E uses primary sectionalizing devices on network feeders (historically, the G&W T Ram). San Francisco’s experience is that when they open a network feeder, they often have network protectors that “hang up”; that is, do not open properly. Their primary feeder design with switches gives them the ability to isolate the section of the feeder where the bad protector is located, enabling them to complete their work on the fully de-energized section. This design also facilitates obtaining clearances and troubleshooting.

PG&E has been moving from using oil switches as network feeder sectionalizing switches to a solid dielectric switch. One driver for this change is a concern over the failure of the switch and the environmental and other hazards associated with oilfield gear. One challenge faced by PGE in the network application is that the fault duty in the network may exceed the rating of the dielectric switch. PG&E is currently working on ways to reduce the fault duty of their networks to be able to apply these devices.

When a new customer, such as a high-rise building, desires to connect to the PG&E network system, they will put in an application for service to the Service Planning department. The Service Planning department is responsible for gathering loading information. They are also familiar with the electrical system, and can determine whether or not the new customer can be served by the network or by the radial system. In ascertaining the customers expected load, PG&E will look at similar buildings to understand demand patterns. Planning engineers will also perform a low flow analysis to understand the impact on the system, running both the normal case and the n -1 case.

Typically, small to medium loads 500kVA and less requiring 120/208V service will be connected to the network grid. Loads from 500kVA to 1MW will get a 120/208Vspot. Loads greater than 1 MW will typically receive a 277/480 V spot network service.

The PG&E network grid load is growing slightly. Presently, PG&E has many high rises in their network that were formerly commercial locations that now serve residential customers. This has resulted in a changing load factor.

PG&E services spot networks using UG vault type transformers. Most times, the buildings will put their spot network vault underground, accessible from both the building and the sidewalk. Customers provide the space, lighting and ventilation.

PG&E’s design calls for no more than two transformers in a vault without some sort of fire isolation.

Technology

PG&E has a good set of maps depicting their network infrastructure. Maps include:

Circuit Maps, a semi- schematic map showing the circuits and sectionalizing points,
Distribution Maps (Block maps) showing all facilities in a certain geographic area
Duct Maps, showing duct positions in the network vaults and manholes. (Duct side drawing may be part of the distribution maps).

^[1] PG&E will allow third party fiber in their ducts. For example, San Francisco 911.

4.7.14 - Portland General Electric

Design

Network Design

People

PGE has several different groups who share responsibility for network design.

Distribution/Network Engineers: Three Distribution Engineers cover and design the underground network, as well as work with customers to design customer-owned facilities, such as vaults, which may house network equipment. The Distribution Engineers are not based in the Portland Service Center (PSC) or CORE group but have direct responsibility for the network and work closely with the CORE. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to support them with civil designs.

The Distribution Engineers develop the network and maintain its standards, which are forwarded to the Standards Department for inclusion in company standards documents. Distribution Engineers assume responsibility for network standards as they have the expertise specific to network equipment.

Distribution Engineers also provide the loading information that the Planning Department uses to create CYME and PSSE models.

Standards Department: The Manager of Distribution Engineering and T&D Standards oversees the Standards Department. This group consists of four standards engineers and one technical writer. This group is responsible for company standards, and works closely with the Distribution Engineers responsible for the network to assure that network standards are up to date.

Service & Design at PSC: Service & Design’s role is to work with customer projects, making it responsible for customer requests for new connections, and customer-generated system upgrades, such as a building remodeling. The supervisor for Service & Design’s wider responsibility includes the downtown network. The supervisor reports to the Service & Design Manager, who is a peer of the Distribution Engineering and T&D Standards manager. Both of these positions report to the General Manager of Engineering & Design and directly to the vice president.

The Supervisor of Service & Design at PSC and its group undertakes capital work if it is initiated by the customer. The “Mapper/Designer” reports to the Supervisor of Service & Design at PSC and provides the computer-aided design (CAD), geographic information system (GIS), and design service. A Field Inspector meets with customers/customer contractors. Two inspectors work for the Service & Design organization, with one specializing in the network.

Service & Design Project Managers (SDPM): Network planning associated with customer-driven projects requires regular coordination with the customer throughout the project life. PGE has a position called a Service & Design Project Manager (SDPM), who works almost exclusively with externally-driven projects, such as customer service requests. At present, two Service & Design Project Managers cover the network and oversee customer-related projects from the first contact with the customer to the completion of the project. They coordinate with customers to assure that customer-designed facilities comply with PGE specifications.

The SDPMs can be degreed engineers, electricians, service coordinators, and/or designers. Ideally, a SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. In addition, SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC) as well as the ability to use or learn the relevant information technology (IT) systems. PGE prefers a selection of SDPMs with a diverse range of experience and backgrounds.

SDPMs work on both CORE and non-CORE projects. This ensures that expertise is distributed and maintained across departmental and regional boundaries.

Key Customer Manager (KCM): PGE has nine KCMs reporting to Manager of the Business Group. Generally, they are geographically distributed, with three on the west side, one downtown, one in Salem, three on the east side, and one acting as a rover. KCMs liaise with large customers and communicate their needs.

Process

Design Process

When a new building is constructed and ready to connect to the network, PGE follows a specific process/flow, which does not significantly differ for spot or grid networks. The process begins when a customer contacts the service coordination desk and receives a work order number, which tracks the process in the system. The customer is assigned to one of the SDPMs, who will discuss the project with the customer and determine what information has been provided, what is still needed, and a timeline for any scheduled visits.

The SDPM coordinates with the distribution engineering team to determine exactly what is needed. Every new load is analyzed using PSSE, under the direct supervision of Distribution Engineers. The Distribution Engineers determine the electrical design needed to service the new load.

Distribution engineering sends the distribution design to the SDPM, who determines the route that the conduit(s) must follow and where to install them. For example, if a distribution engineer specifies that they need to run two 500 MCM copper cables from a particular manhole to the building panel, the SDPM determines exactly how to accomplish it. Once the design layout is complete, the Distribution Engineers confirm the electrical layout. The SDPM also works with the building architect(s) on the design/construction of any new vaults to assure that the designs meet PGE specifications.

PGE also uses Field Inspectors, who meet periodically with the customer/customer contractors throughout the project construction. KCMs may also liaise with large customers about the project.

Customer Requests - Additional Load

Customer requests for additional load may flow through the KCMs or SDPMs. PGE has created a one-note “database” containing all of the new or proposed construction in the downtown area. The database acts as a way to record and monitor information on different projects due to the large volume of projects across the downtown district. The database also includes some projects in the River District that the CORE network does not service despite being downtown.

The manager of the SDPMs reviews this information on an informal basis to track progress and check that the anticipated projects will actually occur. Much of the proposed work in the database is tentative, so PGE does not utilize this information for load forecasting.

Once a project actually starts, the customer submits a “Service Coordination Request,” and the project is assigned a Maximo project number. The network KCM, who may be involved upfront in understanding the customer’s service requirements, coordinates with the SDPM and the building developer. The SDPM is directly involved in the technical and electrical design.

The KCM will continue to track the project and follows up when the proposal becomes an almost-complete building after construction. Overall, the KCM acts as a facilitator.

Network Equipment

PGE’s network infrastructure consists of five separate network systems supplied from two different substations. One substation supplies three networks, with four primary 12.4-kV feeders supplying each network. Of these three networks, one consists of all spot network locations while the other two include both spot and grid networks. The other substation supplies two networks, with four primary 11-kV feeders supplying each network. These two networks consist of both spot and grid networks. PGE uses a conventional network design with dedicated network feeders, supplying only network load. For reliability, different bus sections at the substation supply feeders that supply any one network.

The typical network unit consists of an integrated three-position disconnect and grounding switch, a network transformer connected in delta-wye, and a throat-mounted network protector. PGE uses straight Energy Services Network Association (ESNA) receptacles in the transformer. Note that PGE does have locations that differ from this typical design, including locations that utilized banked single-phase transformers, as well as separately mounted switches and network protectors.

The typical transformer sizes on the grid networks are 500 kVA or 750 KVA. For spot networks, transformers can be 500, 750, 1000, or 1500 kVA, depending on the spot network load requirements. All equipment is submersible.

For spot network locations, the vaults are typically customer-owned and located below grade. PGE does have some spot locations above grade and a few older installations with spot networks on the roof.

The primary cable system is a combination of lead cables and EPR insulated cables. PGE replaces lead cables with EPR cables as opportunities arise. They use transition, cold shrink, and heat shrink joints. Splices are “pressed,” as field crews have more confidence in compression connections than in shear bolt technology. Note that with the EPR cable systems, PGE is trialing the use of bolted ESNA-style connections, such as Y and H connections.

The secondary system uses both lead and EPR cables. PGE does not have a secondary cable replacement program underway.

In most of its spot network vaults, PGE has installed a ground fault relay scheme that measures the neutral and ground current through a current transformer (CT). If the current exceeds a threshold, it trips all of the network protectors supplying the spot and locks them into the open position. Once this system activates, the protectors can only close with manual intervention. PGE installed this scheme because the primary protection scheme will not see through to a fault on the downstream side of the protector prior to the collector bus. PGE has experienced incidents in which the customer bus in front of (upstream of) the switchgear faulted, and the ground fault protection scheme worked as intended.

For the protective system to function correctly, PGE requires that the customer-side ground and neutral not be grounded on the customer side, but instead be isolated, and that it be tied in with the ground fault scheme on the vault secondary side.

In addition, most vaults also have a trip scheme tied in with thermal sensors located above the collector bus and transformers. This scheme also trips all of the protectors supplying the spot.

Technology

PGE engineers use PSSE to analyze new customer loads on the network, model the impacts, and determine the required system reinforcements. PSSE can not only model power flows and system dynamics but also test contingencies, optimal power flows, and voltage stability. As a relatively antiquated system, presently PSSE can only model three-phase loads, not single phase. PGE is transitioning to CYME software and intends to add the secondary network module. Thus, PGE will use ArcGIS to model and display loops. PSSE cannot show loops and creates errors when modeling the secondary network, which has prevented accurate models from developing. PGE currently uses CYME for modeling on the radial system.

PGE uses ArcFM GIS software for designing network layouts and creating a package with details for relevant personnel. ArcFM builds upon ESRI’s ArcGIS. Schneider Electric’s software is a map-focused GIS solution that allows users to model, design, maintain, and manage systems, displayed graphically alongside geographical information. ArcFM uses open-source and component object model (COM) architecture to support scalability, user-configurability, and a geographical database.

PGE uses ArcFM with Maximo for Utilities 7.5, which creates work orders and reference numbers when customers confirm a project. After creating a design in ArcFM, designers send it to Maximo in which compatible units (CUs) can calculate the work details and scheduling.

4.7.15 - SCL - Seattle City Light

Design

Network Design

People

Organization

Network Design at SCL is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A . The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Process

Network Design

SCL has a network design that breaks the network load into small, isolated “sub-networks” to limit the number of customers exposed to an outage in the event of loss of any one sub-network. Each sub-network is sourced by six primary feeders (at either 13.8 or 26.4 kV), and is designed to N-1. All primary feeders that source a given sub-network are sourced from the same substation. This minimizes the potential for circulating currents on the secondary system due to load imbalances between two substation sources. SCL has 15 distinct sub-networks. SCL currently has no ties between the sub-networks, nor have they applied any distribution automation (remote operation) to the network feeders beyond the substation breaker.

Network Secondary

SCL has existing 208 and 480 V secondary networks. SCL will not expand the 480 V network, because of the potential for having a sustained arc at 480 V.

Spot network services to new large load buildings are normally supplied at 480 V.

SCL has high fault duty in their downtown area (100000 A).

Load Flow

SCL conducts a master load flow analysis twice per year using “extracts” from their monitored loading data after the summer and winter of each year. This master load flow analysis is performed on all network feeders. The analysis is performed by the Load Flow Engineer within the Network Design Department. This process is one of the drivers of reconductoring projects.

(Note: many feeders are analyzed more than twice per year because of load increases – see feeder assignment process discussion in next paragraph.)

SCL also performs a feeder load analysis as part of their Feeder Assignment process in response to anticipated new load. The term “Feeder Assignment” means determining which feeder or feeders will serve a new network load. A Network Services engineer requests the feeder assignment based on a new or supplemental load need. The System Engineer within the Network Design department performs an analysis to determine the best scenario for serving the new load. This analysis includes ensuring that the network design criteria are met, and that any feeder imbalance is restricted to less than 20%. (Note that about 80% of new load is served as a spot network, rather than tapping the existing network secondary.) See Attachment B , for a flow diagram of the Feeder Assignment Process.

When SCL performs a load flow analysis, they start off with the worst case (no accounting for diversity). They then re-run the case after applying a diversity factor.

Technology

Fire Protection

SCL uses both fire protection heat sensors and temperature sensors in vault design.

The fire protection heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225 ˚ F. SCL has installed fire protection heat sensors in 95% of its building vaults. These sensors are not utilized in “street” vaults.

The temperature sensors, part of the DigitalGrid (Hazeltine) system, send an alarm to the dispatcher at 40 ˚ C – well before the network protector trip threshold is reached. SCL currently has completed installation of these sensors in about 20% of their vaults. They plan to install these sensors in all of their network vaults (both in building vaults and in “street” vaults).

Cable Cooling System

SCL has designed and installed a novel chilled-water heat-removal system to increase the ampacity of cables at a certain location that was identified as a thermal bottleneck due to the number of adjacent network primary feeders, depth of burial, and other factors.

They have been successful in increasing the ampacity of these cables by 40% through the installation of this water-cooling system.

4.7.16 - References

EPRI Low-Voltage Training Material

Low Voltage Network Overview

EPRI Low-Voltage Training Material

Design Considerations for secondary networks

4.7.17 - Survey Results

Survey Results

Design

Network Design

Survey Questions taken from 2015 survey results - Summary Physical/General and Design (Question 72)

Question 17 : What is average number of feeders supplying a conventional network (street grid)?

Question 25 : What is the typical number of feeders required to supply your spot networks?

Question 72 : What type of secondary connection technology is used on your networks?

Survey Questions taken from 2012 survey results - Summary Physical/General and Design (Question 4.21)

Question 2.4 : How many feeders make up the network feeder group?

Question 2.7 : How many feeders (minimum) supply your spot networks?

Question 2.8 : Network primary operating voltages(s)?

Question 4.21 : What type of secondary connection technology is used on your networks?

Survey Questions taken from 2009 survey results - Summary Physical/General

Question 2.4 : Network primary operating voltages(s)? (this question is 2.8 in the 2012 survey)

4.8 - Network Protector Design

4.8.1 - AEP - Ohio

Design

Network Protector Design

People

Establishing specifications for the network unit, including transformers, network protectors and the primary switch design used in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineers in collaboration with the Network Engineering Supervisor. These personnel are geographically based in downtown Columbus at AEP Ohio’s Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is part of the Distribution services group at AEP, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Distribution Services group, including the Network Engineering Supervisor supports all AEP network design issues throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Network protector designs used throughout the AEP service areas are regularly studied and recommendations are made through this committee.

Process

AEP Ohio has standardized on Eaton CM52 network protectors, though the company has various in-service styles of both Eaton and Richards network protectors. Key drivers of AEP Ohio’s decision to standardize on the CM52 include its submersible, dead front design, which minimizes inadvertent contact with energized parts within the protector and enables quick and safe testing, and built in diagnostics which can be relayed through AEP’s SCADA system to network monitoring stations.

AEP is in the process of replacing older network protectors with Eaton CM52 network protectors. These replacement protectors use microprocessor relays and supplant mechanical and analog designs of previous network protectors in the AEP system. AEP Ohio is also contemplating the use of Eaton NP Serve, a network protector monitoring and control module, for better real-time data monitoring and control, including the ability to retrieve data from downstream devices, and perform applications such as secondary fault diagnostics.

Technology

AEP uses Eaton CM52 network protectors, a fully submersible protector with a dead front design (see Figure 1).

Figure 1: AEP Network Engineering Supervisor Roy Middleton demonstrating dead-front enclosure network protector cabinet

AEP’s network protector specification also calls for other features that can be purchased with the CM52 including:

External disconnects are used to separate the protector from the secondary collector bus. These disconnects are a safety feature used in a 480-V design to mitigate arc flash risks (see Figure 2). On this network protector, the NP fuses are internal and link style, as AEP is able to create the visible break between the NP and the secondary bus using the disconnects. Note that the disconnects can only be opened with keys which can only be accessed when the NP handle is in the open position because of an interlock system.
ARMS (Arc Flash Reduction Maintenance System) modules enable a worker entering the vault to change the protection settings in the protector to reduce the fault clearing time and thus the arc energy in the event of a fault.
A remote racking system (RemRack) enables the Network Protector breaker to be racked out remotely from outside the vault while the door of the network protector remains closed. This feature prevents the worker from being exposed to an arc flash while racking out the breaker.
A submersible stacklight is an annunciator system offered by Eaton that indicates network protector status through a series of different colored lights (see Figure 3).

Figure 2: Keys for protector top disconnects interlocked with NP handle position

Figure 3: Externally mounted disconnect handles. Note 'stacklight' annunciator system on the left side

AEP Ohio also has an installed remote monitoring system. The company uses the Eaton VaultGard communication platform for recording and communicating data from the network protector to monitoring stations (see Figure 4). In addition, AEP Ohio is in the process of refurbishing its network monitoring system with dual looped, redundant fiber-optic communications network that will relay information to AEP Ohio monitoring stations (see Remote Monitoring System). This system uses optical cabling that ties in with the CM52 microprocessor-controlled relay to provide monitoring and control of the protector. The new system will offer a wider range of information than was available on protectors the company used in the past. AEP Ohio is considering moving to a new NP Serve product from Eaton which will provide more real-time data to its Operations Center over its fiber-optic network.

Figure 4: VaultGard data communications link for network protectors

4.8.2 - Ameren Missouri

Design

Network Protector Design

People

Network standards, including the standard design for the network unit, including the network protector design, are the responsibility of the Standards Group.

This group develops both construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both an online and printed book format. Updated versions of the book format version are issued every 2-3 years.

Organizationally, the Standards Group is led by a Managing Supervisor, and is part of the Distribution Planning and Asset Performance Department, part of Energy Delivery Technical Services. The group is staffed with engineers.

For the network unit standard, Standards engineers work closely with the organization responsible for network equipment testing and maintenance – the Service Test group. Ameren Missouri has an up to date material specification for the network unit; however, the construction standard for this installation is maintained separately, and is not part of the Construction Standards Book. Ameren Missouri plans to incorporate the standard for the network unit into its Construction Standards Book.

Process

Ameren Missouri uses submersible throat-mounted network protectors with microprocessor controlled relays.

Ameren Missouri has a network protector maintenance and repair shop located in St. Louis. They maintain an inventory of protectors which are tested and ready for installation.

Network Protectors are maintained on a two year cycle. (See Network Protector Maintenance for more information. ) Ameren Missouri does not do periodic network protector drop testing. for more information.) Ameren Missouri does not do periodic network protector drop testing.

Technology

Ameren Missouri has about 265 network protectors on their system. Their current standard is for the network protector to be throat mounted to the transformer secondary. Standard network protector sizes are 1875, 2000, 2250, 2825, and 3000 amp units.

Ameren Missouri uses protectors from both Eaton and Richards. At the time of the practices immersion, Ameren Missouri was in the process of moving to the CM52 network protector. This decision was based on an analysis performed by Ameren Missouri, and driven by certain attributes of the CM52, including the dead front design, modular replacement, and remote racking capability, which enables them to rack the breaker out of the bus with the NP door closed.

Ameren Missouri uses the ETI electronic relay as part of its remote monitoring system. Using this system, they are monitoring various points including voltage by phase, amps by phase, protector status, transformer oil top temp and water level in the vault. The monitoring points are aggregated at a box mounted on the vault wall that communicates via wireless.

Figure 1: Transformer mounted network protector

Figure 2: Transformer mounted network protector secondaries

Figure 3: Transformer mounted network protector secondaries

Figure 4: Remote monitoring control box mounted on vault wall

4.8.3 - CEI - The Illuminating Company

Design

Network Protector Design

People

The design of the network protectors is performed by the CEI Underground / LCI group, part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

Technology

The Network is made up of approximately 57 vaults, and includes 61 network transformers with protectors. Network protector sizes range from 1600 – 3000 A.

Network Protector information is kept in a manual file in the Underground Department.

4.8.4 - CenterPoint Energy

Design

Network Protector Design

People

The design of network vaults, including the use of network protectors is performed by the Vaults group within the Major Underground Engineering Department. The Vault design group is led by a Lead Engineering Specialist. The Engineering department is led by a Manager and is comprised of four main sub groups, including the Vaults group.

Process

For new designs, CenterPoint physically separates the network protectors from the transformer units, where they can. The driver for this change was to keep a fire in the network protector from spreading to the transformer.

Technology

About ten years ago, CenterPoint decided to rehabilitate their network infrastructure, including replacing all of their network protectors. They did some investigation of network protector types and elected to standardize on the CMD type protector.

They chose to standardize on the CMD because they believe that the dead-front, draw-out, spring-closed breaker mechanism and the externally mounted fuses make this is a safer design than some other network protector styles. They acknowledge that the CMD units are larger than some other styles.

4.8.5 - Con Edison - Consolidated Edison

Design

Network Protector Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Employee Depelopment

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Network Protector Design

Con Edison uses a mix of Eaton and Richards network protectors. At 120/208, Con Edison mounts the network protector directly on the transformer secondary. At 265/460, Con Edison’s design standard calls for the protectors to be mounted separately from the transformer, normally in a separate vault enclosure.

Depending on the application, Con Edison’s network protectors are either built with a submersible enclosure, built with a non-submersible (ventilated) enclosure, or mounted on an open frame.

The use of submersible network protectors is limited to those places where the units will likely be in water. Con Edison has divided its territory into hurricane flood zones, and is in the process of installing submersible network protectors in vaults located in the zones most susceptible to flooding. All new installations in these zones are submersible.

Con Edison does have plans to retrofit existing installations that have non-submersible units with submersible ones, but they face a challenge in that the submersible units take up more space.

In vaults with non-submersible (ventilated) network protector units, Con Edison installs a high water alarm to indicate when a sump pump may overflow and respective equipment integrity is in question.

In locations where the protector will be located in a compartment (for example, in a building), the protector is mounted on an open frame.

4.8.6 - Duke Energy Florida

Design

Network Protector Design

People

Standards for network design, including the network protector, are the responsibility of the Duke Energy Florida Standards group, which oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies. The Design Engineers are engaged in a Duke Energy corporate-wide process to consolidate design standards for network systems among the various Duke operating companies, due to be finalized in 2017.

Duke Energy Florida has developed network design standards, which are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D.)

Process

The Standards engineers who focuses on network infrastructure works very closely with experts within the Network Group, including the department manager and senior network specialists. Network standards for infrastructure in Clearwater and St. Petersburg are the result of the collaboration between the Standards group and Network Group.

Technology

Clearwater

At 125/216V, Duke Energy Florida has standardized on the CM22, with internal NP fuses (see Figures 1 and 2). Duke Energy Florida uses a remote monitoring system in its network vaults in Clearwater. The company uses the Eaton VaultGard communication platform for recording and aggregating data from the network protector MPCV relay and from other vault sensors (Qualitrol). This information is communicated through a Sensus cellular monitoring system to a central server every half hour. Within the Network Group, information from Sensus, such as secondary loading, is monitored daily. Note that the Sensus system is read only, with the functionality to remotely control equipment being disabled for security purposes.

Figure 1: CM22, spare unit, in case"

Figure 2: CM22, spare unit

The network mains are supplied with four sets of cables using stud moles on the protector. Their vault design calls for the use of a separate uni-strut rack with insulated cable clamps that is mounted into the vault wall to support weight of the secondary cables.

Limiters are installed at each secondary junction on the secondary mains on the outgoing secondary cable.

St. Petersburg

At 277/480V spot network locations, Duke Energy Florida has standardized on the CM52, a fully submersible protector with a dead front design (see Figures 3 and 4). Duke Energy Florida’s network protector specification also calls for features such as:

External disconnects, which are used to separate the protector from the secondary collector bus. These disconnects are a safety feature used in a 480V design to mitigate arc flash risks. On this network protector, the NP fuses are internal and link style, as Duke Energy Florida is able to create the visible break between the NP and the secondary bus using the disconnects. Note that the disconnects can only be opened with keys which can only be accessed when the NP handle is in the open position because of an interlock system.
Wall-mounted ARMS (Arc Flash Reduction Maintenance System) modules, which enable a worker entering the vault to change the protection settings in the protector to reduce the fault clearing time and thus the arc energy in the event of a fault.
A submersible Stacklight, which is an annunciator system that indicates network protector status through a series of different colored lights.

Note that Duke Energy Florida has not installed the Sensus remote monitoring system in spot network protector vaults, in St. Petersburg.

Figure 3: Spot network vault with CM52. Note uni-strut cable support racks

Figure 4: note the external disconnects, stack light, and stud models atop the protector

4.8.7 - Duke Energy Ohio

Design

Network Protector Design

People

Network standards are the responsibility of the collaboration of the network engineer, the planning engineer, and the Dana Avenue supervision. This group uses the old Cincinnati gas and electric construction manual as a guide. Ultimately, Duke Energy will develop a common network standard across the system.

Process

Duke Energy Ohio has its own network protector refurbishment facility at Dana Avenue. They maintain an inventory of about 30 units, which are tested and ready for installation.

Technology

Duke Energy Ohio has about 410 network protectors on their system. Their current standard is for the network protector to be mounted to the transformer secondary; however, they have many existing freestanding network protectors on the system.

Duke Energy Ohio’s current standard is to use the CM52’s with communication enabled MCDV relays^[1] . Note that Duke Energy Ohio is in the process of changing out old network protectors, replacing about 35 units per year, and selecting units for replacement based on vintage and condition.

Standard network protector sizes are 2000 and 2825 amp units at 208 V and 3500 amp units at 480 V. Duke’s network protector installations use external mounted, busman style fuses. (Although Duke has many existing installations with internal NP fuses installed.)

Network protector installations are designed with a shroud (blast hood) over them.

Figure 1: Transformer Mounted Network Protector with external fuses

Figure 2: Transformer Mounted Network Protector with external fuses

^[1] Duke Energy Ohio is in the process of installing remote monitoring in their network.

4.8.8 - Energex

Design

Network Protector Design

Process

Energex does not require network protectors as its secondary is not meshed.

4.8.9 - ESB Networks

Design

Network Protector Design

Process

ESB Networks does not require network protectors as its secondary is not meshed. For its MV substations, ESB Networks uses overcurrent protection at the feeder source. Single-phase spurs are fused from the main line.

4.8.10 - Georgia Power

Design

Network Protector Design

People

Establishing standards for network protectors at Georgia Power is the joint responsibility of the Standards Group, comprised of senior network underground engineers from the Network Underground Engineering group and Principal Engineers who report to the Network UG Manager, and the Network Operations and Reliability group. Both the Network Underground Engineering group and the Network Operations and Reliability group are part of Network Underground.

The Network Underground Engineering group, led by a manager, is comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees.

The Network Operations and Reliability group, led by a manager, is comprised of Test Engineers, Test Technicians and other resources who perform system operations and maintenance activities. The Test Engineers are four year degreed positions, and are not part of the union. Together, the engineers develop standards for the use and type of network protectors on all of Georgia Power network underground systems, statewide.

Standards were first documented and codified in the 1970s, and they include what was already in place on the network from the 1940s and any new standards developed since then. Standards are available in both an online and printed book format.

Process

For network protectors, Georgia Power uses both Richards and Eaton protectors. Engineers have standardized on submersible protectors with dual ratings (208V or 480V). They deploy mainly Eaton CM 22 and Richards 313 and 314s. Engineering has bought and installed a few CM 52s for trial, but are concerned with stored energy in the unit spring. Once that issue is resolved, Georgia Power may move to this model or some other model with purely electronic relays.

While some older protectors have internal fuses, Georgia Power is moving to protectors with outside fuse boxes mounted on the top of the protectors (See Figure 1 and Figure 2.). These Class L current-limiting fuses provide backup protection if a protector fails to open for a primary fault. They also protect the GPC bus during faults on customer-owned service equipment. They also reduce the arc flash exposure for persons working inside the protector.

Figure 1: New network protector: note fuse boxes on top of the protector

Figure 2: Older network protector, being rehabbed

For network feeders, protective devices include the feeder breaker, network protectors and fuses installed on the secondary between the network and the customer. Current limiting fuses are used at the junction between the Georgia Power system and the customer’s facility.

Maintenance and Upgrades

Georgia Power is in the process of replacing older network protectors with either new units or refurbishing protectors in the field by replacing electromechanical relays with microprocessor based controls. The network protector replacement initiative is being performed in tandem with the Georgia Power three-year network protector inspection cycle performed by Test Technicians, part of Network Operations and Reliability. When the inspection team finds a protector that is old or needs to be upgraded with a microprocessor relay, they perform the upgrade during the field inspection whenever possible. Although this may slow the inspection crews down in their maintenance schedule, Georgia Power has stayed on track in its inspections and has found this practice the most cost-effective and expedient means for performing the upgrades and replacements.

Technology

All network protectors are connected to the Network Operations center by a SCADA system that runs on DSL, radio frequency, or fiber network connection to the Network Operations center. Protector monitoring and opening/closing of protectors can be performed remotely by operators within the Network Operations Center. Remote monitoring and control of protectors has been in place at Georgia Power for about 15 years (See Figure 3 and Figure 4.).

Figure 3: Image from GA Power Network Control Room

Figure 4: Image from GA Power Network Control Room showing NP status (CL – closed)

4.8.11 - HECO - The Hawaiian Electric Company

Design

Network Protector Design

People

Network protectors are sized by the Planning Division. The relay settings are determined by the Protection Division. The design of a network protector installation is performed by the T&D Division of the Engineering Department.

Technology

The Network includes approximately 140 network transformers with protectors (Network Units). Network protector sizes range from 1200 – 3000 A at 125/216V, and from 800 – 3000 A for 277/480 V spots.

HECO has remote monitoring of network protector status (Open / Close) at its dispatch center.

4.8.12 - National Grid

Design

Network Protector Design

People

Network standards, including the standard design for the network protector, are the responsibility of the Distribution Standards department, part of Distribution Engineering Services. Distribution Engineering Services is part of the Engineering organization, which is part of the Asset Management organization at National Grid. Within the Standards group, National Grid has two engineers that focus on underground standards.

National Grid has up to date standards and material specifications for network equipment, including the network transformer primary switch, network transformer and network protector. Network material specifications are updated annually. Standards are updated on a five-year cycle.

Note that because National Grid’s system is comprised of multiple network systems of different designs in both New York and New England, the standards book is organized with a common standards section that represents the whole company, and then individual sections that specify standards appropriate to the individual network systems that comprise their overall infrastructure.

Process

National Grid has a network protector maintenance and repair shop located in the NY East Division building in Albany – the same location as the UG Department headquarters. This shop receives new units, mounts them on the transformer, and performs operational checks. The shop maintains an inventory of protectors which are tested and ready for installation.

Figure 1 and 2: Network protector maintenance

National Grid performs network protector inspections annually, and performs network protector diagnostic testing on a five year cycle. (Note that diagnostic testing of CMD style protectors is performed on a two-year cycle, as National Grid has experienced some performance issues with these units.)

National Grid performs network protector drop testing annually.

Technology

National Grid has about 250 network protectors on their Albany network system. Their current standard is for the network protector to be throat mounted to the transformer secondary. Protectors are either rated 216Y/125V or 480Y/277V.

Figure 3: Transformer mounted network protector

Network protectors are sized to 140% of the transformer rating standard network protector sizes at 216Y/125V are 1200, 1875, 2825 and 3500 amp units. Sizes of units rated 480Y/277 include 800, 1200, 1875, 2825, 3500 and 4500 amp units. National Grid network protector installations may use either internally or externally mounted fuses.

National Grid uses network protectors from both Eaton and Richards Manufacturing. All new protectors are equipped by the NP repair shop with communication enabled relaying. National Grid has completed changing out all old network protector electromechanical relays with microprocessor controlled relays in NY East.

Spot network vaults are equipped with a ground fault protection system designed to trip (open) all of the network protectors in the vault in the event of a ground fault. The customer is required to buy, install, and wire the National Grid approved ground fault protection system. Ground fault protection system equipment is installed in the customer’s electric room. However, a current transformer required to monitor neutral currents is installed in National Grid’s transformer vault.

Figure 4: Network Protector Note: CT for ground fault protection scheme

Figure 5: Network Protector Note: conduit for ground fault protection scheme control wiring

4.8.13 - PG&E

Design

Network Protector Design

People

PG&E has effectively implemented an asset management process for network equipment. They have assigned a specific person as the “Manager of Networks”, part of the Distribution Engineering and Mapping organization. This asset manager is responsible for determining the investment, maintenance and replacement strategies for network assets including network protectors.

The manager of networks is both an electrical engineer, and an attorney. He collaborates closely with the network planning engineer (Reliability and Planning), cable experts within Standards, and the Maintenance and Construction Electric Network group, the organization responsible for the execution of the asset strategies developed by the manager of networks. Note that within the M&C Electric Network Group, PG&E has a network protector maintenance and repair shop led by an experienced supervisor who is a network protector expert.

EPRI observed strong working relationships between the manager of networks, and other key PG&E resources focused on network management. The manager of networks was visible and known to the field force, periodically meeting with field crews to review topics of interest.

The manager of networks has a well documented asset strategy for managing network assets. ( See Attachment A ..) PG&E also has standards for network protector requirements and ratings.

Process

PG&E uses throat-mounted network protectors. PG&E assumes a similar life expectancy to that of the network transformer. Consequently, when the transformer is replaced, they will replace the network protector as well. Note that many of their installed units were placed in the 1950s.

PG&E has a network protector maintenance and repair shop located in San Francisco. This shop is led by a network protector expert, and supplemented periodically by a cable splicer from the Oakland division (for training purposes). They maintain an inventory of protectors which are tested and ready for installation.

Network Protectors are maintained on a three year cycle. See Network Protector Maintenance for more information.

Technology

PG&E has about 1400 network protectors on their system. Their current standard is for the network protector to be throat mounted to the transformer secondary. Standard network protector sizes are 1875, 2825 and 3500 amp units. PG&E network protector installations use externally mounted fuses.

PG&E’s uses network protectors from both Eaton (CM52, CM22 models and Richards Manufacturing (137NP, 313NP models.) They do have some Eaton CMD units installed as well. All protectors are equipped by the NP repair shop with communication enabled relaying (MPCV).

PG&E is in the process of changing out old network protectors, replacing units as part of their transformer replacement program.

Figure 1: Transformer Mounted Network Protector with external fuses (top of protector)

Figure 2: Transformer Mounted Network Protector with external fuses and CT’s for remote monitoring

4.8.14 - SCL - Seattle City Light

Design

Network Protector Design

People

The design of the network protectors is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A. The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Technology

The Network is made up of approximately 1200 network transformers with protectors. Network protector sizes range from 1875 – 4500 amp.

See the pictures below for a photograph and schematic of a typical spot network vault at SCL.

4.8.15 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.15 - Network Protector Designs

4.9 - Network Rehabilitation

4.9.1 - AEP - Ohio

Design

Network Rehabilitation

(Network Revitalization)

People

Network revitalization, improvements, and refurbishment are planned by the AEP Ohio Network Engineering group in tight collaboration with its parent company. The company employs two Principal Engineers and one Associate Engineer to perform all network design and planning activities for the Columbus and Ohio urban underground networks. These engineers are geographically based in downtown Columbus at its AEP Riverside offices, and organizationally part of the parent company Distribution Services organization. The Network Engineering group reports to the AEP Network Engineering Supervisor, who ultimately reports the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues. This committee can and does recommend system revitalization, improvements, and refurbishments for the AEP Ohio networks to the parent company. After approval from the AEP parent company, AEP Ohio Network Engineering and the AEP Network Engineering Supervisor plan the revitalization projects and oversee their completion.

Process

AEP Ohio has a number of on-going network revitalization and refurbishment projects in the works, including the following:

Replacement of Secondary Cable

After incidents involving fire in manholes caused by faulty secondary cables in 2014, the parent company, AEP, determined that an investigation team should look into the incident and report its findings. The investigation included the following:

On-the-ground inspection of cables in duct lines by camera
Scientific modelling of the existing secondary cable and its loads
Load flow models to identify cables that are overloaded or nearly fully loaded
Examination of failed secondary cable at AEP Ohio, as well as outside testing by a third party consultant.

The summary report of these investigations determined that the secondary styrene butyl cable was the cause of the fire due to cracked insulation. Network engineering analysis found that its insulation breaks down due to overheating and may produce combustible gases. Network Engineering has performed load analyses that have identified the cable runs most at risk and are a priority in the replacement process.

The summary report in AEP Ohio served as a basis for examination of all network grid systems in the AEP operating companies. It was found that other locations may need to rehabilitate secondary cabling as well.

In response, AEP formed a Project Management Team to initiate and lead a program to inspect and replace selected secondary cables throughout the AEP system.

AEP Ohio and all AEP network operating groups have prioritized the secondary cable replacement according to conditions (see Figure 1).

Figure 1: AEP mitigation and prioritization strategy for secondary cable replacement

The cable replacement project, totaling $300 million for all of AEP, will result in replacement of nearly 202,600 circuit feet of secondary cable in AEP Ohio. System-wide, AEP will replace in excess of 900,700 circuit feet of secondary cable. This massive undertaking also led AEP to reinforce its existing network inspections to aggressively perform the following throughout the AEP operating companies:

Visually inspect every manhole and vault
Note not only secondary cable conditions, but also note conditions of every other network component in the manhole and vault, including transformers, switches, primary cables, etc.
Record all inspections of manholes and vaults into the system-wide asset tracking database called NEEDS (Network Electrical Equipment Database System)

To help drive the system-wide inspections and spur replacements and repairs, a Gantt chart and a system dashboard were put in place and updated weekly to track the progress of the inspections and replacements program (see Table 1 and Figure 2).

Table 1: Portion of weekly dashboard report on secondary network inspections

Figure 2: Sample of Gantt chart for AEP Operating Companies’ inspection and rehabilitation schedule

Secondary butyl and other cable (such as cloth PILC and older durasheath XPLE) are being replaced with 750 EAM insulated cable. The 750 EAM cable was chosen by the engineers because it fits in the current duct lines and has the capacity and thermal rating required by the network. The older butyl cable was rated at 70 degrees C, whereas the 750 EAM is rated at 90 degrees C (see Figure 3).

Figure 3: 750 EAM secondary replacement cable rated at 90 degrees C

In addition, AEP Ohio has found that secondary lead cable in its system, when hot, can cause fires that threaten other cables in the duct lines. Therefore, lead cables are also scheduled for replacement under this revitalization and refurbishment project (see Cable Replacement).

Network Protectors

All 480 volt network protectors in AEP Ohio are scheduled for upgrades to Eaton model CM52 protectors as well as older 216 volt units. Many have already been installed. The CM52 offers greater safety, flexibility, and data collection and operation via the new fiber-optic SCADA system, also under deployment (see Design-Network Protector Design). All network protectors have microprocessor based relays.

Fire Protection

Eaton High Thermal Event Systems are being deployed on high value 480 volt spot networks located in building vaults. If a fire is detected, the system automatically trips, isolating the affected transformer or bus before fire can spread.

SCADA Fiber-Optic Cables

The entire SCADA communications network is being upgraded to a double-loop, fully-redundant fiber-optic cable network. The new SCADA network cable is fast, lightweight, and fault tolerant (see Remote Monitoring).

Network Transformers

AEP Ohio is updating all its transformers to units without an integrated primary switch as older systems come out of service. These newer transformers will require less maintenance for AEP Ohio. The network unit will include a wall-mounted solid dielectric vacuum switch to separate the transformer from the primary

Technology

AEP Ohio uses CYMCAP and CYME SNA modules for its cable ratings, load analyses, and network circuit modelling. Its NEED database tracks all system serialized assets and their conditions as recorded by inspections. NEED also includes civil asset information such as underground vault and manhole structures.

4.9.2 - Ameren Missouri

Design

Network Revitalization

People

Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. This group’s role includes addressing issues such as the development and update of planning criteria for the network, development of both cable and transformer replacement strategies, development of a network transformer replacement strategy, development of route diversity criteria, development of the criteria for manhole covers, and criteria for conduit system replacement.

Background

The city of St. Louis underwent periods of growth during 1910 -1920 as well as during the 1950s and 60s. These times saw Union Electric (now part of Ameren Missouri) install much of its underground network, which is now of a vintage where it is starting to deteriorate. As the city undergoes a period of redevelopment designed to encourage residential and commercial growth, Ameren Missouri understands that these old systems must be revitalized to handle increasing consumer demand.

For example, the St. Louis area has new apartments and hotels, a development at Ballpark Village, the Lumiere Place Casino and Hotel, the Scottrade Center, Edward Jones Dome, and the Busch Stadium. All of these require reliable energy supply that the old system may not be able provide without rehabilitation. Note that most of these are serviced by Ameren Missouri’s radial system.

This urban rejuvenation project provides the perfect opportunity for Ameren Missouri to instigate a complete re-examination of its system, and harden it against outages by both increasing reliability and incorporating Smart Grid initiatives.

Ameren Missouri’s current underground system serving St. Louis has four substations, 28 radial circuits, and 29 network circuits providing 200 MVA of demand within a two square mile area. High population density makes upgrading old systems difficult; therefore, any revitalization projects must be designed to last well into the future, minimizing future disruption and ongoing maintenance costs.

Ameren Missouri has set up a group, the “Underground Revitalization Department”, to research present and future needs, and to create a plan for upgrading and extending the system to account for increasing loads and usage patterns. The planning phase is currently underway, and the construction is intended to start in 2012, spread over 8 – 12 years.

The Underground Revitalization Department team is a multidisciplinary group of Ameren Missouri experts assembled to oversee the work, and to look at every single aspect in creating a holistic revitalization approach. Currently, Ameren Missouri has nine active strategy teams and one lead team, utilizing a total of 26 employees.

Project Team: This five-person team has been given the directive of establishing the plan for upgrading the underground network in St. Louis. It is looking at where problems arise with the infrastructure, and using this to create a strategy for revitalizing the system while balancing cost, practicality, reliability, and capacity.

The Project Team ensures that there are open lines of communication between the revitalization strategy group and the company directors, making sure that the project fits with corporate strategies. This group is headed by a Project Team Leader, and reports to the Manager of Distribution Operations.

Strategy Lead Team: This team contains the team leaders from the nine project subgroups, and works to ensure that all of the elements of the project blend together seamlessly. Some of the engineers are members of multiple project sub group teams, further ensuring that the approach to revitalization is fully integrated.

Strategy Teams: The nine strategy teams cover the following areas:

Route Diversity
Distribution Automation and SCADA
Sectionalizing
Inspection and Maintenance
Cable Diagnostics
Manhole Covers
Conduit Systems
Cable Replacement
Transformer Replacement

Two further groups will be added in the future as the project enters the implementation phase:

Reducing Collateral Damage
MLK (new substation) Cutover Strategy

The teams are developing strategies, as well as detailed plans for applying those strategies to the downtown infrastructure.

Process

The Underground Revitalization Department team formation was driven by the need to invest in modernizing distribution infrastructure to meet the higher loads and changing needs of consumers in urban St. Louis and address the fact that older underground systems require a significant maintenance expense.

See Asset Management

At the time of the practices immersion, all but two of the strategy teams had drafted their strategies, helping the underground group decide exactly what is required and exactly what improvements need to be made to the network. The improvements and upgrades to the system are expected to span ten years, but Ameren Missouri believes in developing all of the strategies at the outset, and training in – house people who will be involved with the process from the very start, and thus develop an intimate knowledge of the systems.

Ameren Missouri is using a condition-based approach for equipment replacement, based on an assessment of the performance and condition of a line or component. Ameren Missouri has implemented a two-year inspection cycle for network vaults and a four year cycle for network manholes. They have developed a draft criteria used to evaluate, manage, and prioritize replacement of network transformers and protectors within downtown St. Louis. These criteria are based on key considerations such as the transformer’s age, location, physical condition, loading, history with similar transformers styles, and oil quality. Note that at the time of the EPRI practices immersion that these criteria were in draft form. (See Maintenance: Network Transformer Replacement Criteria) )

With respect to conduit systems, the strategy team assessed the use of the existing clay tile conduits, with the attendant problems of high rate of water ingress and fragility. Other options were considered, and it was concluded that the clay tiles conduits would be replaced. The tiles will be abandoned in place and not be extracted.

Ameren Missouri will not be reusing old iron pipes due to the danger of shorting if the pipe becomes delaminated and the fact that the pipes are only 3 inches in diameter. This makes them impractical for modern insulated cables, many of which have a larger diameter and produce considerable heat when bundled together. This has also given the team an idea for researching the link between the failure of the old lead cables and the amount of delaminating of the iron pipe.

With respect to cable replacement, the strategy team is working on developing recommended diagnostic procedures for existing primary cables of different types with cables that fail the test procedure being replaced accordingly. The team has further recommended replacement of unjacketed lead cables and cloth-covered secondary cables.

The strategy team has developed an overall strategy designed to create route diversity among distribution system circuits, in order to minimize the impact of minor and major events. The team has also devised a draft plan that includes achieving true n-2 reliability for all network feeders and true n-1 for all radial feeders. The strategy also addresses general system diversity practices such as requiring that the circuits supplying a spot network be sourced from separate substation buses, route diversity practices such as limiting the number of network primary circuits from the same substation in the same duct bank to no more than two, and construction practices such as fireproofing cables in manholes.

The strategy teams are working on re writing the planning criteria to include route diversity requirements.

Another area being studied is the approach to sectionalizing urban underground feeders. Currently, the underground network system does not have any primary sectionalizing devices in the main feeders. The strategy teams are considering modifying the design to call for the addition of primary network feeder sectionalizing and tie points with a goal of limiting the number of switch operations to clear a network feeder or feeder section to no more than six operations. With the present design, network feeder systems with 15 – 18 transformers take a long time for the switching process, so incorporating primary sectionalizing devices would significantly reduce the number of switching operations needed to clear a feeder section.

Another area of focus for the strategy teams to address the legal and public relations issues that will surface associated with obtaining easements and permitting to perform the downtown revitalization work.

Technology

Ameren Missouri uses a number of systems to ensure that potential upgrades and new system designs are feasible and cost effective before considering them for funding.

Circuit and Device Inspection System (CDIS): Inspection findings are entered into the CDIS, and an algorithm assigns a “structural score” and an “electrical score” based on the inspection findings and weightings for various findings developed by Ameren Missouri. The scores are used to prioritize remediation at the detail level (for example, should I rebuild a particular manhole). CDIS is the permanent repository for inspection findings. It is used to produce reports that summarize inspection findings as well as a dashboard that monitors inspection progress.

Integrated Spending Prioritization (ISP): Ameren Missouri uses an Integrated Spending Prioritization (ISP) tool to compare investments by analyzing costs, risks and benefits. This active asset management system is used to compare projects at a high level, and aids Ameren Missouri management in selecting investments that will be of most benefit.

EPRI Distribution Engineering Workstation (DEW) and Siemens PTI PSS/E Software: These applications allow engineers to analyze existing and proposed circuits and configurations. Apart from load estimations, protective device coordination and power flow analysis, the system can help the engineers design a system with appropriate conductor and cable sizing, as well as the optimal capacitor placement.

4.9.3 - Duke Energy Florida

Design

Network Rehabilitation

(Network Revitalization – Florida Primary and Secondary Network Improvement Plan and ATS Switchgear SCADA Communications Refurbishment)

People

Duke Energy Florida has implemented a comprehensive plan focused on improving the secondary network infrastructure in Clearwater and St. Petersburg. The development and implementation of this plan is being led by the Power Quality, Reliability and Integrity (PQR&I) group. This group, led by a Director, is responsible for all asset management, planning and reliability of the electric systems in Duke Energy Florida. The group consists of two teams, one focused on the Central Region and the other, the Coastal Region, of which Clearwater and St. Petersburg are a part. The Duke Energy Florida PQR&I group also works closely with the PQR&I Governance group, which supports different local operating jurisdictions.

The genesis of the project was a mandate from the Duke Energy Florida Distributions Operations Vice President to examine the overall health of the network infrastructure and to recommend improvements to assure its continued safety and reliability. This mandate was driven by a recognition that the infrastructure is aging and a desire to forestall significant events, such as manhole fires, which can impact reliability, safety and customer service.

The focus of the examination is the network infrastructure in Clearwater (a secondary grid) and in St. Petersburg (spot network locations).

Organizationally, the Duke Energy Florida field resources that construct, maintain, and operate the network infrastructure within Clearwater and St. Petersburg fall within a specific Network Group which is part of the Construction and Maintenance Organization. The Network Group is led by a supervisor who reports to the Region General Manager. The group consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position), all part of the Network Specialist job family. These ten workers have responsibility for both the Clearwater and St. Petersburg underground systems, with some workers assigned to Clearwater and others to St. Petersburg, depending on the work load.

At the time of the practices immersion, the Network Group had assigned two Electrician Apprentices, and two Network Specialists (the journeyman position) to work with the St. Petersburg underground system, which includes the downtown area, the beachfront areas, and the southern peninsula. Much of the focus of these resources is the revitalization of the St. Petersburg network.

The Network Specialist is a jack-of-all trades, position, responsible for all facets of UG work, including cable pulling, splicing, and maintaining and operating equipment such as cables, joints, network switches, transformers, and network protectors. Network Specialists also work with the installation and maintenance of automation associated with the equipment they manage.

Duke Energy Florida is utilizing contractor resources to perform their cable replacements in Clearwater and St. Petersburg. The contractor crews are supervised by two Network Specialists who provide oversight and coordination to the contractor crew. A Short Term Decision Plan (STDP) in place with contractors has helped speed up the process of refurbishment. Note that Duke Energy Florida work teams are also held to work schedule goals and clear and stringent safety goals as part of a STDP. Safety, Customer Satisfaction, and Financial (O&M) components are a part of the STDPs in addition to the completion goals.

ATS Switchgear SCADA Communications Refurbishment

Duke Energy Florida recently added SCADA monitoring and control to automated transfer switches. These switches are part of a design that provides larger customers with a loop feed using a primary feeder, and a reserve feeder tied together at the customer’s site with an automatic transfer switch (ATS). In the event of an outage to the primary feeder, the customer’s load would be swapped over to the reserve feeder, on which capacity for the customer’s load has been reserved.

Duke added SCADA monitoring and control to these devices so that operation of the switch as well as monitoring of the switch status could be performed by the dispatcher. With this automation, when an event occurs that initiates operation of the ATS, the dispatcher would receive an alarm. The dispatcher can also initiate the swap of load from one feeder to the other or return the configuration to normal after the outage is restored.

The Network Specialist position was selected to install the automation, as the Network Specialist is the classification most familiar with the operation of ATS.

As part of the installation of the automation, the design included the addition of proximity sensors which detect the position of the switch blades as confirmation of the switch operating. The proximity sensors selected were an after-market component, and Duke Energy Florida has experienced frequent failures of this sensor, resulting in false alarms being sent to the Dispatchers in the DCC.

The Network Specialist position was selected to replace the faulty proximity sensors on the ATSs. Note that at the time of the practices immersion, Engineers at Duke Energy were working on developing a permanent solution.

Process

The process of assessing the health of the network infrastructure was implemented in three phases. The first, was an internal assessment performed by a team that included experts (Network Specialists) from the Network Group, the Network Group supervisor, and network engineering experts from the PQR&I group. This assessment included a description of system condition, including known issues and concerns, as well as a summary of recent investments made to the network system.

Phase two of this effort involved bringing in experts from other Duke Energy Operating companies to examine the condition of the network infrastructure and develop ideas for improvement.

The result of these two efforts was the identification of six key issues to be addressed, and a draft work plan for addressing these issues. The six issues identified are:

Succession planning for craft resources

Duke Energy Florida plans to finalize training modules for network craft workers.

Backlog of asset replacement and maintenance work

Duke Energy Florida plans to leverage contractor resources and off load non-network work.

Long-term strategic plan for the network

Duke Energy Florida plans to task planning engineer with developing long-term vision for the network

Design engineering expertise

Duke Energy Florida will review requirements, identify resource requirements, and assign resource or evaluate for FTE addition

Modeling ability

Duke Energy Florida plans to identify and appropriate software/module and assign resources or evaluate for FTE addition

Work methods process and procedure reviews.

Duke Energy Florida plans to perform a Cross-Jurisdictional (Duke energy wide) review and evaluation of enterprise standards

Duke Energy Florida has developed a work plan comprised of actions that support these issues, and has formed teams to focus on executing the plan in key areas. Below is a listing of the teams, and the major initiatives associated with each.

Team 1: Construction and Maintenance

Process & procedure reviews
Resource plan
Contractor oversight

Team 2: GIS

Map updates
GIS tool acquisition (to model secondary) and data transfer (to electronic)
Sustainability plan

Team 3: Planning

FTE addition – planning engineer
St. Petersburg / Clearwater short-term strategy
St. Petersburg / Clearwater long-term strategy

Team 4: Engineering & Construction Planning

Workforce & workload evaluation
Training & transition plan
Sustainability plan

Team 5: Work plan Execution

Offload non-network work from crews (e.g. ATS inspections, Design engineering, etc.)
Work plan functional model
Commissioning of outstanding devices (RA switches)

Team 6: Asset Plan

Slab replacements
Inspection process reviews
Asset replacement strategy
Grate replacements

Team 7: Standards

Replacement of switches with non-oil technology
Vertical feedthrough switches
Remote monitoring technologies
Manhole lid pressure relief device

At the time of the practices immersion, Duke Energy Florida had just launched these efforts. The third phase of their evaluation was to perform an external (third party) assessment of their plans – the performance of the EPRI practice immersion is part of that assessment process.

An example of the focus on network improvement is the revitalization efforts underway in St. Petersburg. The St. Petersburg underground system has certain components, such as manholes grates, cables, and elbows, in need of maintenance. Note that years ago, the decision was made to move away from low voltage network secondary systems in St. Petersburg. As a result, the former network infrastructure was broken into sections, essentially removing the grid, and leaving primarily spot networks. (Note - St. Petersburg does have a few unique locations where secondary network load remains and is supplied by transformers from a single radial feed. Engineers are working to redesign these locations). The existing infrastructure consists mainly of spot network locations, and medium voltage looped systems, with customers served by a primary and reserve feeder, with an automated transfer switch (ATS), which would swap load to the reserve feeder in the event of an outage to the primary feeder.

The following list briefly describes some of the refurbishment projects either completed or on-going in the St. Petersburg underground network.

Duke Energy recently rebuilt a 480V spot network service. Located in a walk in building vault, the spot network supply includes four new Eaton CM52 network protectors that utilize the ARMs (Arc Flash Reduction Maintenance System) that enables workers entering the vault to change the protection settings in the protector to reduce the fault clearing time and thus the arc energy in the event of a fault.

Figure 1: Wall mounted network protector control box, used to enable the ARMS system

Duke Energy replaced the cables that supply a large sporting complex. Note that during the larger sporting events held at the sporting complex, Duke Energy Florida will station network crew members at the transformer switches, so that they are on site to assist in restoring power in the event of an outage.
Duke Energy Florida has repaired and replaced primary switches that were identified as requiring an upgrade through inspection.
Duke Energy Florida upgraded older and deteriorating manholes and duct lines in a downtown center in anticipation of the construction of a new condominium and retail shopping center. Inspections of the existing manholes and duct lines showed the need for extensive manhole repair and for duct lines to be rerouted to accommodate the new construction.
Duke Energy Florida tied or networked the secondary of two radial transformers supplying significant loads, including a new condominium structure, a full block of restaurants, bars, a hotel, and concert venue, in order to provide a contingency in event of a transformer failure.
Duke Energy Florida is in the process of replacing many older network vault grates (see Figure 2).

Figure 2: Rebuilt grating for network vault

Downtown St. Petersburg has a high concentration of the medium voltage T-body connections constructed with center tap plugs that are highly susceptible to failure. The company has been replacing these components in conjunction with cable replacements, as most of the older design center plugs are associated with 1980s vintage cable systems.

ATS Switchgear SCADA Communications Refurbishment

When responding to these alarms on site, First Responders are provided with an ATS troubleshooting matrix that includes all items that should be checked. The company also has a training video for checking ATS switches.

The preferred resolution is to replace the sensors entirely with a new system.

4.9.4 - Duke Energy Ohio

Design

Network Rehabilitation

People

Duke Energy has a Reliability and Integrity group, focused on managing assets in to meet company performance goals, such as safety, reliability, and financial. Duke Energy has an Asset Manager within the Reliability and Integrity group, located in Charlotte, who directly supports the Dana Ave group in identifying opportunities to invest in the network assets.

The Asset Manager works closely with the Network Engineer, the Network Planning Engineer, and the Supervisor Construction and Maintenance within Dana Avenue to understand the condition of assets and identify opportunities to improve asset performance. The Asset Manager works closely with the UG Standards group, responsible for establishing specifications for network equipment. The Asset Manager also works closely with budgeting personnel to identify funds for investment in the asset base.

This group has implemented a ten year network rehabilitation plan that consists of changing out mainline cable sections, replacing PILC cables, and performing structural upgrades including rehabilitating vaults and manholes with structural deficiencies such as deteriorated roofs. Street vaults within Cincinnati have to be strong enough to support heavy equipment such as a fire trucks.

The design of the structural rehabilitation is performed either by structural engineers within the Substation group, or outsourced to engineering firms.

The rehabilitation field work is being performed by Dana Underground crews supplemented with contractor resources. Note that a few years before, Dana Avenue resources had been reassigned to other work centers to perform routine underground (non network) work. With the implementation of the ten year rehabilitation plan, Duke has returned these resources to the Dana Avenue group to support the rehabilitation efforts.

Process

Duke is in the second year of a ten year process of performing network facility rehabilitation. The driver of this rehabilitation is primarily to improve the reliability and safety of the network system.

The rehabilitation project was formulated based on an assessment of the network condition in Cincinnati. In the years prior to the implementation of the rehab project, some maintenance and rehabilitation needs had been subordinated to other investments. About three years ago, Duke Cincinnati experienced a violent failure of a network protector. From this, the Duke Reliability and Integrity group, together with the Dana Avenue leadership, the Network Engineer and Planning Engineer, met to develop a plan to rehabilitate aging and deteriorating facilities in the Duke Cincinnati network.

The group began by reviewing physical statistics, and historical maintenance and rehab methodologies. Historically, little physical statistic information was kept – records were kept by exception. They had a record of where the present problems were, but were not tracking what was fixed. Equipment replacements were driven primarily by load requirements, or equipment failure. . There was no primary cable replacement program in place; however, there was a network secondary cable replacement program underway. In addition, a review of past practices revealed that there was a limited pool of spare equipment in the event of a component failure.

The group (The Asset Manager, Dana Ave Supervisor, Network Engineer and Network Planning Engineer) began by establishing a pool of spare equipment – 10% of every type of network equipment installed. The group also gathered statistics on installed infrastructure, revealing that about 60% of the installed plant was beyond its useful life.

Using records / findings from inspections, the group implemented replacement of the equipment in the poorest condition, focusing on replacement of badly rusted or leaking transformers, and the oldest network protectors. (In the past two years, Duke has replaced approximately 24 network transformers). Historically, Duke had performed dielectric strength tests every four years. They are considering expanding this testing to better identify unseen problems.

From their analysis, Duke has implemented a ten year rehabilitation plan that includes replacement of mainline cable sections, replacement of PILC cables, assuring optimum transformer capacity in the network, rehab of network protectors with implementation of electronic relays, and performance of structural upgrades in deteriorated manholes and vaults.

Duke performs vault inspections 4 times a year, and manhole inspections every six years. Part of these field inspections includes identifying any structural or other potential civil deficiencies.

Duke will revisit the suspect manholes with either an in house civil expert or an external civil contractor to assess the civil condition and structural integrity of the manhole to identify high priority candidates for rebuild.

If it is determined that structural repairs must be made to the roof, Duke UG crews will build a temporary roof above their electrical facilities in the vault, but below the actual roof so that their facilities are protected from any debris that may fall during roof rehabilitation.

Figure 1: Temporary Roof

Figure 2: Temporary Roof (notice top of temp roof in red)

Note that while they are making the civil repairs, (and have the roads blocked off, etc) Duke will also perform an electrical rehab of the manhole facilities. For example, they will replace all of the lead cables in the manhole with poly cable.

Technology

Figure 3: Installation of new manhole around existing facilities (note two sections of manhole bottom)

Figure 4:

4.9.5 - Energex

Planning

Network Rehabilitation

(Network Underground Refurbishment)

People

Refurbishment of the underground network is the responsibility of the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Once every five years, Energex approaches their regulator with their investment plans, including investments in system refurbishment driven by their Conditioned Based Reliability Maintenance (CRBM program). Funding for Refurbishment and Replacement of equipment is approved and allocated by the Australian Electric Management Council (AEMC).

Process

Energex is coming up on its next round of regulatory funding and will seek approval for further underground network refurbishment. Based on its CBRM analyses, field tests, equipment failures, and safety and operation issues, it has determined it should replace obsolete relays with microprocessor based relays, replace gas filled transmission cables, replace oil circuit breakers with gas insulated breakers, rehabilitate the pit and duct system in the Central Business District, and replace oil switches with vacuum switches in the underground network.

Much of the planned or recommended refurbishment within the CBD depends on the approval of the Australian Management Electric Council (AEMC) when Energex’s five-year review comes due.

(See Asset Management in this report)

Technology

Energex uses Condition Based Risk Management System (CBRM) software from EA Technology to track the health and condition of assets throughout the underground network system. The system assigns a health index and risk score for all the assets in each class, such as circuit breakers, diagnostic tests of transformers, etc. Length of time in service and any refurbishment work is also input. The system can score assets based on aging mechanisms to predict the potential end-of-life of some components. Actual refurbishment and replacement work is driven by the calculated health scores.

4.9.6 - Georgia Power

Design

Network Rehabilitation

(Network Revitalization)

Background

The city of Atlanta, unlike many North American cities, has never seen a decline in population or density in the modern era. The network underground system in place now has grown from the original network installed at the turn of the 20th century, with improvements, upgrades, and maintenance continuous throughout the life of the network. Network engineers and designers have retained all original network maps wherever possible, and the originals are housed in a separate map room at Georgia Power. Updated, hardcopy maps are stored in the map room as well. Georgia Power has also scanned and converted to raster images all maps and stores them in its GIS system (ESRI).

The city of Savannah has proved challenging, as it is actually expanding its business district through the rehabilitation of historic buildings to small shops and condominiums. Georgia Power is upgrading the network there but must be mindful of the national historic district and limitations that imposes for new transformer placement, vault construction, and any other structural modifications.

It is notable that Georgia Power is not actively shrinking its networks. In fact, the company is on track to complete a new network in the Buckhead area of metro Atlanta and is proposing a plan for adding a network at the Port of Savannah. Note that the loading on the secondary network grid in Atlanta is declining, but that Georgia Power is using more spot networks than in the past to serve some customers.

People

The Network Underground Engineering group, in consultation with Area Planning engineers, and the Network UG Manager are responsible for making investment decisions based on their analyses of the implications of forecasted load on the system and conditions of assets in the field. Local distribution planning for the network underground infrastructure at Georgia Power is the responsibility of the engineering group within the Underground Division. The Underground Division is led by a Manager and consists of both engineering and construction resources responsible for the network infrastructure.

Decisions about investment in network equipment such as transformers and network protectors are the responsibility of Network Engineering group, and are based on equipment condition as determined through inspection and maintenance findings. This group reports organizationally to the Network UG Manager.

Network Operations and Reliability is comprised of both the field resources (field inspectors and field test engineers) that perform network equipment inspections and conduct network equipment maintenance, and the engineering resources that analyze the information from the inspection activity and make decisions whether to repair or replace network equipment based on the findings.

(See Attachment A for sample manhole inspection form.)

Decisions about investment in maintenance or repairs of structures such as manholes, transformers, or duct banks are the responsibility of engineers for civil, network, and structural design within the Network Underground group. This group is responsible for determining inspection approaches for structures, and for developing strategies for responding to inspection findings. In addition, this group develops standards for structure design and repair.

Projects of $2 million or less are brought before the Regional Distribution Council for approval. Any projects that require more funding are sent to the vice president of the Network Underground group and upper management for review and funding approvals.

Process

Georgia Power has a number of on-going wholesale network revitalization projects in the works, including the following:

Georgia Power is in the process of replacing older network protectors with either new units or refurbishing protectors in the field by replacing electromechanical relays with microprocessor relays. The network protector replacement initiative is being performed in tandem with the Georgia Power three-year network protector inspection cycle. When the inspection team finds a protector that is old (such as a CM-1) or needs to be upgraded with a microprocessor relay, they perform the upgrade during the field inspection whenever possible. Although this may slow the inspection crews down in their maintenance schedule, Georgia Power has stayed on track in its inspections and has found this practice the most cost-effective and expedient means for performing the upgrades and replacements.

The network protector inspectors are called Test Technicians who are non-degreed employees usually drawn from the ranks of Senior Cable Splicers.

Georgia Power is replacing all porcelain pot heads identified during its routine, planned vault inspections
Georgia power is also replacing older equipment that is part of the network SCADA (remote monitoring and control) with new, solid state equipment. Where necessary, the connection to the Network Operations center is being upgraded as well. Fiber is the preferred connection, but in some areas this is not a possibility, particularly in older vaults.
Georgia Power completed vault inspections and found a number of brick roof vaults that were deteriorating. The company decided to proactively replace all brick roof vaults with solid concrete rather than fix or repair old ceilings.
Georgia Power is in the process of replacing standard manhole covers with a SWIVELOC design (See Figure 1). These manhole covers are intended to resist ejection during a fire or explosion inside the manhole. They include a latching mechanism which allows the cover to lift several inches to allow venting of sudden pressure, but does not allow it to fly off unrestrained. (See Figure 2) The replacement effort is prioritized with manholes containing secondary conductors being retrofitted first. This is a multi-million dollar project. Estimated duration of the project is five years.

Figure 1: SWIVELOC Installation

Figure 2: SWIVELOC – underside of cover

The Savannah network is undergoing significant upgrades in addition to consideration of a new network at the Port of Savannah. Georgia Power is making network protector improvements, upgrading or replacing fuse boxes, replacing some disconnects between the network bus and protectors, and retrofitting network transformers located within vaults inside buildings, with FR3 coolant ^[1] . Note that all new transformers utilize FR3 fluid, as this new specification was adopted company - wide (GPC).
Older transformers are being replaced as warranted as part of Georgia Power’s routine inspections. When a field inspector finds a transformer that is a candidate for replacement, it is brought to the attention of the network design group. Georgia Power’s network transformer standard conforms with IEEE C57.12.40, (IEEE standard for Network, Three-Phase Transformers, 2500kVA and Smaller, High Voltage, 34 500 GrdY/19 920 and Below, Low Voltage, 600V and Below, Subway and Vault Types (Liquid Immersed)). In addition, Georgia power calls for: 1) transformers are welded onto metal rails to make them easier to pick up with a fork lift and to keep them off the vault floors (See Figure 3 and 2) every transformer is specified with phasing tubes on top to test for phase identification in the transformer (“Phasing Tubes” enable an operator to insert robes into a deenergized unit (See Figure 4). They can then put a signal on the cable and use signal detection to determine phasing.)

Figure 3: New transformer – note rails welded to transformer bottom

Figure 4: Transformer – phasing tubes

Georgia Power is selectively replacing lead cables with EPR. However, unlike many utilities, Georgia Power is maintaining lead wherever possible. The engineers find it reliable, cost-effective and easier to work with in confined manholes and vaults where there is limited space for the larger Y-splices required for EPR cables.

Technology

The company uses its GIS system to track inspections and flag any repairs that are needed. On-going, long-term projects such as SWIVELOC manhole replacements are tracked by spreadsheet and input into GIS.

^[1] Envirotemp™ FR3™ fluid is a fire resistant natural ester dielectric coolant specifically formulated for use in distribution and power transformers. Envirotemp™ and FR3™ are licensed trademarks of Cargill, Incorporated. http://www.cargill.com/products/industrial/dielectric-ester-fluids/envirotemp-fr3/index.jsp

4.9.7 - PG&E

Design

Network Rehabilitation

Transformer Replacement Program

People

In 2009, PG&E instituted a program to replace underground network transformers, with the prioritization based on the results of the transformer oil sampling program.

Replacement of transformers and their associated network protectors is undertaken by the PG&E’s General Construction Department, using both internal PG&E resources and external contractors.

Civil work, including vault construction is performed by PG&E’s General Constructions Gas Department. The vault construction is not typically precast concrete due to the physical constraints in the downtown areas of Oakland and San Francisco.

Process

The majority of PG&E’s current underground network transformers were replaced during the 1980s with non-PCB (polychlorinated biphenyl) types as part of the PCB replacement program. This means that virtually all the transformers on the current PG&E distribution network are 1980s vintage.

In 2009 PG&E instituted a program to replace underground network transformers. The prioritization of units to be replaced is based on the results of the transformer oil sampling program. Replaced units are replaced with new, rather than refurbished transformers.

Note: In 2009 PG&E replaced 20 units with refurbished units, but found that refurbished units had certain drawback, namely:

The cores, windings and paper insulation are from an existing unit and therefore, the life expectancy is less than it would be for a new unit.
There is little flexibility in timing of removal and installation since the only source remaining for the refurbished units are those that are already in service.

As part of the replacement of the network transformers, the program project will replace the associated network protectors (NP’s). (Note that the 1980s program to change transformers as part of the PCB replacement program did not involve NP’s. As a result, PG&E currently has some network protectors, which have been in service since the 1950’s and 1960’s.) By replacing the network protector at the same location where the transformer is being replaced, PG&E will capture significant labor and operating efficiency by replacing both units at once. Also, the fact that a transformer is being replaced is an indication that associated equipment may be nearing the end of its service life. The loading, age, and exposure to environmental conditions of the transformer reflect directly on the associated network protector.

In some instances, network protectors may have already been replaced at some point in the recent past. If the project manager identifies network protectors that have been replaced, an alternate protector will be selected.

In 2010 PG&E anticipates replacing 29 transformer units and their corresponding “throat mounted” network protectors. Next year, 2011, they expect to replace 67 units (30 regular & 37 high-rise. (See High-Rise Replacement Program).

Technology

The current transformers on the PG&E underground network are of a three (3) chamber design. PG&E’s transformer replacement program will transition to a single oil tank design (filled with natural ester - Envirotemp® FR3™) coupled with a stand alone G&W vacuum switch mounted on the wall of the vault.

The reason for the change in design is that in the legacy design the smaller tanks (primary and ground switch) contain a limited amount of oil (25 – 30 gallons). A failure in these tanks is more likely to lead to a vaporization of the oil, and the potential for a catastrophic explosion to occur. PG&E has therefore decided to implement a single main tank design in order to mitigate the potential of a catastrophic explosion occurring in any of its transformers.

PG&E is using throat mounted network protectors. (Eaton CM52, CM22 models, Richard Manufacturing 137NP, 313NP models.)

4.9.8 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 8.8 - System Rehabilitation Reconstruction

4.9.9 - Survey Results

Survey Results

Design

Network Rehabilitation

Survey Questions taken from 2018 survey results - Asset Management

Question 26 : Are you implementing targeted replacement programs for any of the following equipment?

Question 27 : If Yes, are any of your replacement programs Aged based, such as replacing all transformers >50 years old?

Question 28 : If Yes (to question 26), are any of your replacement programs Design based, such as replacing all high rise fluid filled transformers with dry type units, or replacing a certain type of cable?

Survey Questions taken from 2015 survey results - Design

Question 77 : Do you have any additional network “system hardening” initiatives underway?

Survey Questions taken from 2012 survey results - Planning and Maintenance

Question 3.13 : Do you have any network “system hardening” initiatives underway?

Question 6.32 : Are you currently implementing replacement programs for any of your network equipment?

Question 6.33 : If Yes, Please indicate which equipment is being replaced.

Survey Questions taken from 2009 survey results - Planning and Maintenance

Question 3.9 : Do you have any network “system hardening” initiatives underway?

Question 6.38 : Are you currently implementing replacement programs for any of your network equipment?

Question 6.39 : If Yes, Please indicate which equipment is being replaced.

4.10 - Network Reliability

4.10.1 - Con Edison - Consolidated Edison

Design

Network Reliability

(Network Reliability Index)

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Employee Development

Engineering and Planning - Responsibilities include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Network Reliability Index

Con Edison calculates a Network Reliability Index (NRI) to rank networks by reliability, to rank the feeders within each network by reliability, and to prioritize reliability improvements.

The utility started to develop the NRI program about 10 years ago. The NRI index is calculated using a probabilistic approach that is based on loading information gathered from their remote monitoring system, physical information such as transformer age and the presence of stop joints, and historic data such as average wet bulb and dry bulb temperature variables. The algorithm looks at 11 components and 3 temperature variables. Some other factors considered include failure rates for different temperatures and different load factors, load flow information from Con Edison’s PVL load flow system, circuit age, feeder ratings, and shift factor and pick-up factors of load from adjacent feeders.

Con Edison runs the NRI simulation for 20 years to predict the probability of a network to be in jeopardy of a failure, and what feeders may contribute to the jeopardy condition. The targeted reliability performance is for a network to experience no more than one failure in 1000 years (which is one network shutdown in 20 years systemwide). The NRI basis is that having any four related feeders out of service at one time in heat wave conditions and places a network in jeopardy.

The NRI ranking is used to prioritize investments in reliability improvement. Con Edison has a 10-year, $370 million program under way to improve the reliability of the distribution system (excluding substations.)

Some of the approaches the utility uses to improve reliability include:

Con Edison’s plan is to stop expanding the low-voltage network and begin feeding more customers from spot networks. For example, new customers with demands as low as 300 kW may be fed from spot networks in the future. In situations where Con Edison knows the system has secondary overloads, the utility will move customers to the primary. Their goal is to limit the exposure of the secondary network.
Con Edison has an initiative under way to reduce the size of networks by splitting the load of a given network into two distinct networks. The utility has targeted six networks for size reductions.
Con Edison has a program under way to change out paper and lead cables (primary) with Ethylene Propylene Rubber (EPR) cable, the current cable standard.
Con Edison is adding submersible s ulfur hexafluoride (SF ₆ ) switches to the underground (UG) network in areas where the utility has bifurcated feeders. This addition will enable them to sectionalize between the bifurcated circuit sections.

4.10.2 - HECO - The Hawaiian Electric Company

Design

Network Reliability

Reliability Improvement Initiative – Replacing manual switches

People

The HECO T&D Division has implemented a program to replace manual throw-over switches with automatic throw-over switches to improve customer reliability.

Process

HECO provides dual primary feeds to customers in order to provide N-1 reliability. In many locations, these dual feeds are designed with a manually operated throw over switch. HECO has analyzed their historic reliability performance and has concluded that the time that it takes to dispatch a Primary Trouble Man (PTM) to operate the manual throw over switch contributes significantly to their system CAIDI^[1] , particularly in certain locations, such as residential subdivisions, where many customers may be affected.

Consequently, HECO has implemented a plan to change out manual switches with automatic throw over switches in selected locations in order to improve system CAIDI.

^[1] CAIDI, the Customer Average Interruption Duration Index, is an industry accepted reliability measure of outage duration.

4.10.3 - AEP - Ohio

Design

Network Reliability

People

Investment decisions for network equipment such as transformers and network protectors for improved and sustained reliability for AEP Ohio are the responsibility of the Network Engineers, which is part of the Network Engineering group. This group, led by the Network Engineering Supervisor, is responsible for all aspects of network design including reliability for AEP Ohio, and provides consultative support to the other AEP operating companies. Investment decisions to support network reliability are made at the AEP Ohio management level with recommendations from the network engineering group.

Investment decisions to support network reliability are also discussed at theThe Network Standards Committee, is an AEP wide committee that holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and reliability issues. For example, after manhole fires occurred at several locations across the AEP system that were found to be due to deteriorated Styrene Butyl secondary cable, the Network Standards Committee developed a recommended companywide response that included the decision to implement a replacement program and the selection of a suitable replacement cable (see Network Revitalization ).

Process

Network Engineers, working with the parent company, AEP, keep detailed information on network and cable loads to make certain the system has enough capacity to serve its customers. The network systems in AEP Ohio, designed to either an N-1 or, as in Columbus, a full N-2 configuration, have been highly reliable with only one outage to network customers in the past thirty years. Reliability is, in effect, “baked in” to the AEP network designs that are planned for contingencies as specified in the corporate Network Planning Criteria guide.

Load forecasts and service forecasts are maintained by the Network Engineers in conjunction with the AEP Distribution Planning group. Working together, they forecast load and circuit requirements for up to ten years. If any new, significant loads are anticipated on the AEP Ohio network that may affect reliability of the system, the Network Engineering group works with the Distribution planners for increased capacity.

Duct line configurations for feeders are very standardized, as is cable racking within vaults and manholes. Duct lines are concrete encased. AEP design guidelines include other strategies to preserve reliability, including sourcing no more than two feeders supplying any one network off of a given bus section at the station or through any given station exit, and implementing designs that attempt physically separate electric facilities to assure contingency operations. For example, for N-2 areas, AEP designs systems to have no more than two network feeders on the same network installed within common duct banks, manholes, or transformer vaults. For N-1 systems, designs assure that the loss of any single duct bank and/or its manholes or vaults causes no outage to any network customer.

AEP uses arc proof tapes on all network primary cables inside of manholes and transformer vaults, as well as any non-network feeders that pass through a network manhole of vault.

The Network Underground group has developing standards for new networks, as well as upgrading its existing network, for a more uniform and reliable system.

Technology

AEP is in the process of establishing Operations center monitoring of its Canton network. This system will utilize the company’s dual-loop, redundant fiber-optic SCADA communications network. Note that AEP is in the process of updating its network remote monitoring system.

4.10.4 - Ameren Missouri

Design

Network Reliability

People

Ongoing network reliability is the responsibility of multiple individuals at Ameren Missouri, including both Energy Delivery Technical Services and Energy Delivery Distribution Services.

Historically, Ameren Missouri focused much of its reliability improvement activity on their radial system. The network system, because of its inherent reliability, hasn’t historically garnered the same attention. Recently, however, Ameren Missouri has ramped up its focus on network system reliability through the formation of the Underground Revitalization Department.

The Underground Revitalization Department focuses on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, development of a cable replacement strategy, development of a network transformer testing and replacement strategy, development of route diversity criteria, development of the criteria for manhole covers, and a criterion for conduit system replacement. All of these efforts are aimed at preserving the high levels of reliability supplied by their network infrastructure.

Local distribution planning is responsible for making investment decisions based on their analyses of the implications of forecasted load on the system. Local distribution planning of both the network and non-network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division. This Center is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP.

Investment decisions for network equipment such as transformers and network protectors are based on equipment condition determined through inspection and maintenance findings. They are the responsibility of Distribution Operations. The Distribution Operations Group, led by a manager, reports organizationally to the Vice President of Energy Delivery Distribution Services. Distribution Operations is comprised of both the field resources (Distribution Service Testers) who perform network equipment inspections and conduct network equipment maintenance, and the engineering resources who analyze the information from the inspection activity and make decisions of whether to repair or replace network equipment based on the findings.

Investment decisions concerning maintenance or repairs of structures such as manholes, faults, or duct banks are the responsibility of engineers responsible for civil and structural design within Energy Delivery Technical Services. This group is responsible for determining the inspection approach to structures, and for developing strategies for responding to findings. In addition, this group develops standards for structure design and repair. As an example, this group was responsible for changing Ameren Missouri’s vault standard to include requirements such as a thicker ceiling to meet a traffic rating requirement, and using larger grate openings.

Process

An example of a reliability driven strategy under development by the downtown St. Louis Underground Revitalization Department team is the development of transformer replacement criteria for evaluating, managing, and prioritizing replacement of both network and radial transformers within downtown St, Louis. This is based on key considerations such as the transformer type, historic performance, age, oil quality, condition, and physical location.

This strategy includes implementing routine oil testing, and inspections aimed at identifying and recording equipment condition information used to determine when replacements are required. The criteria also include a Network Transformer Replacement Scorecard used by inspectors to score the relative severity of non – field repairable issues. Information is entered into a data base which is used to analyze, rank and prioritize transformer replacements.

The Underground Revitalization Department is developing other strategies to address network system reliability including route diversity, sectionalizing, application of distribution automation and SCADA to the network, inspection and maintenance approaches, cable diagnostic approaches, cable replacement strategies, and civil issues such as manhole covers and conduit systems.

4.10.5 - CEI - The Illuminating Company

Design

Network Reliability

People

Within the Regional Engineering department, CEI has a group that is focused on reliability and power quality (Reliability Group). The group is comprised of 11 people who focus on reliability performance improvement and reporting for the Illuminating Company (overhead and underground system performance). The Reliability group works closely with Underground Group.

CEI’s Asset Management resources also focus on reliability improvement and employ Circuit Reliability Coordinators (CRCs) who perform circuit inspections based on reliability performance (See “Asset Management” - People ). Because underground feeders tend to perform more reliably than overhead feeders, the main focus of these coordinators is on the overhead portion of the distribution system.

The Underground group is the group with the main focus on the reliability performance of the underground ducted manhole distribution system (network and non – network). This group performs diagnostic testing, preventive and corrective maintenance activities, and system reinforcement (programs discussed more fully in the Maintenance and Operation section of this report).

Process

The Reliability group is responsible for all internal and external reliability reporting such as regulatory required reports for PUCO. In general, Asset Management (asset management resources within the Engineering Services group) analyzes the results of reliability inspections and provides information to the Reliability group for Reporting.

The main reliability metric used by CEI is SAIDI (System Average Interruption Duration Index). The Reliability group periodically produces a SAIDI ranking of distribution circuits. This ranking includes all circuits whether overhead or underground.

The Reliability group tracks and analyzes outages on the system on a daily basis. They produce an inoperable equipment list, which is a daily summary of the circuits / circuit sections that are out of service. The Reliability group will advise the Underground group of whether the repairs to the inoperable equipment should be handled as an emergency or not.

In general, the distribution system, overhead and underground, is inspected on a five year cycle. The Underground group performs the inspections of the underground ducted manhole system, with manholes inspected and maintained on a five year cycle.

Padmounted equipment is visually inspected externally on a five year cycle, and opened up for an internal inspection on a 15 year cycle. The Underground group is not responsible for the inspection of pad-mounted equipment. Pad-mounted equipment inspections are performed by the Electrical Services group, who work with overhead and URD facilities.

The Underground group is performing proactive cable diagnostic testing on both lead and hybrid (lead and EPR cable) feeders. They test about forty feeders per year. Ideally, they would like to test one fifth of the system per year (about 240 Feeders) but resource constraints have limited them to 40/yr.

The responsibility for reporting, analyzing and correcting the findings from the underground inspections lies with the Underground Group.

This differs from how the results from overhead inspections are being treated at CEI. Overhead circuits are being visually inspected on a 5 year cycle. Also, the Regional Circuit Reliability Coordinators are visually inspecting additional overhead circuits driven by reliability improvement. The data from both surveys is being collected, analyzed by Asset Management (asset management resources within the Engineering Services group) and forwarded to the Reliability group for reporting. Circuits are priority ranked, one through five, with the urgency of repair tied to the ranking. For example, a priority one circuit may represent a safety issue, is of the highest priority, and is fixed right away. A priority two issue is addressed in 30 – 90 days, and so on.

Underground feeders are not being inspected by the CRC’s as the circuits the CRC’s are inspecting are driven by reliability performance (based on SAIDI) and the UG circuits are generally more reliable. In addition, it would be impractical for CRC’s to conduct these inspections because of the particular skills associated with manhole entry and the diagnosis of underground equipment. However, the Underground department is performing a similar priority ranking when performing manhole inspections, with the priority assessment based on the judgment of the inspectors. The priority is utilized in scheduling the repair or construction ^[1] .

In years past CEI has budgeted funds to proactively replace lead cable with EPR cables. However, they currently do not have a proactive lead cable replacement program in place. They are investing in replacing older oil filled cable terminations (Spreaders), which have had a history of leaking and failing.

Technology

CEI is using basic Microsoft office products (Word, Excel) to produce reliability reports.

^[1] An opportunity for CEI would be to channel the results of the underground inspection to the asset management resources within the Engineering Services group so that their analysis and the subsequent reporting of the Reliability group include underground statistics.

4.10.6 - Duke Energy Florida

Design

Network Reliability

People

Reliability management is the responsibility of the Network Planning group at Duke Energy Florida, which is organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I), led by a Director of PQR&I for Duke Energy Florida.

To perform planning and reliability management work, the group divides the Duke Energy Florida territory into four separate zones. The cities of Clearwater and St. Petersburg, part of the South Coastal Region, are included in one of the four zones. Every zone is assigned a Lead Planning Engineer and Senior Planning Engineer, who are responsible for all distribution planning activities within the zone.

Engineers/Planners in these zones work on Reliability as well as Planning. Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time planning reliability and infrastructure upgrades.

All Planners have four-year degrees in Electrical Engineering, a requirement for the position.

Process

Because of the inherently reliable nature of the network design, and because their network system has been well maintained, Duke Energy Florida has not experienced major reliability problems. They also have not experienced power quality complaints from customers in their network.

Duke Energy Florida does have a hardening effort underway which includes replacement and upgrades of network infrastructure, such as replacing oil switches with solid dielectric vacuum switches, rebuilding deteriorated vault roofs and grates, and replacing cable and components that are aging or with which they have experienced performance issues.

Duke Energy Florida does have a remote monitoring system installed and is collecting asset data. Some of this information, such as frequent network protector operations, is used by the Network Group as a trigger for action. Other information, such as network transformer data, is being collected, but is not yet being used to trigger action. Duke Energy Florida’s goal is to expand the use of condition based analytics.

Technology

Duke Energy Florida has installed remote monitoring in its vaults. It uses a Qualitrol system to monitor information such as transformer oil level and temperature, and the status of the Oil Minder system. It uses the Eaton VaultGard system to aggregate information from the protector relay, such as voltage, current, protector position, etc. VaultGard also aggregates information from the Qualitrol system. Information is communicated from the VaultGard collection box via cellular communications by Sensus, a third party aggregator of information.

In the Duke Energy Florida design for spot network services within building vaults, the network system ground is separate from the building ground.

4.10.7 - Duke Energy Ohio

Design

Network Reliability

People

Duke Energy has an Asset Management organization that includes a group referred to as Reliability and Integrity (R & I) Planning. Within this group (R & I) there are resources focused on distribution integrity, looking at such things as inspection and maintenance approaches for assets of different type, and resources focused on reliability performance. This group is centered in Charlotte, with two resources, one Integrity resource and one Reliability resources focused on supporting Duke Energy Ohio, as well as other areas of the company.

The Asset Manager for Reliability collaborates closely with the network planning engineer (Part of the Distribution Planning organization), the network Project Engineer, Dana Avenue construction supervisors, and the Asset Manager for Distribution Integrity. In addition, the Asset Management group works closely with the standards department.

Process

The Dana Avenue underground group is focused on several initiatives to improve the reliability and integrity of the network system, including mainline change outs, PILC replacement, manhole refurbishment and structural upgrades. Much of this work is being done as part of a 10 year rehabilitation project underway at Duke Energy Ohio. (See Network Rehabilitation).

Duke Energy Ohio’s design criteria include considerations to assure continued system reliability. Examples include supplying only one feeder per network off of a given bus at the network substation, limiting the number of primary feeders in anyone vault or manhole to three or less in new installations, using arcproof tape to fire protect components, and actively identifying and mitigating high-risk areas. An example cited by Duke was a relocation of part of a substation to minimize the risk of flooding, performed in conjunction with a Department of Transportation project.

4.10.8 - Energex

Planning

Network Reliability

People

Reliability is the responsibility of the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

For the ten past the years, Energex has been investing in improving the reliability of the distribution system, including the infrastructure supplying the CBD. About ten years ago, Energex was experiencing about five outages per 100 km on its 11 kV distribution system. Through a targeted program to improve their reliability, they have improved their performance significantly.

Strategies Energex has employed to improve reliability in their CBD include the following:

Changed from compression to shear bolts for splice connections.
Resolved issues associated with certain epoxies used in cable joints.
Cable replacement.
Addressed workmanship quality issues associated with joint preparation - both Energex employees and contractors.
Established acceptable outage rates for each outage class, and defined actions to be taken when rates are exceeded.
Established a protocol for maintenance for UG assets, including the establishment of priorities for correction of identified deficiencies.
Established a heath index and risk score for all asset classes.

One challenge Energex faces in improving reliability is that it uses two classes of jointers (the job classification at Energex responsible for preparing cable joints and terminations) — one class for distribution and one class used for working with underground networks. Each work classification has its own set of joint standards. Furthermore, much of the work done outside the CBD is performed by contractors. In addressing issues such as workmanship, Energex must address these varied groups.

Another challenge faced by Energex management is that based on the recent strong reliability performance, the regulator is likely to relax reliability targets to levels experienced in 2009 and 2010. This relaxation in targets may affect Energex’s ability to obtain funding for continued attention to maintenance at current levels.

Technology

Energex uses Condition Based Risk Management System (CBRM) software from EA Technology to track the health and condition of assets throughout the underground system. The system assigns a health index and risk score for all the assets in each class, such as circuit breakers, transformers, etc. Length of time in service, test results, acceptable outage rates, and any refurbishment work is input into the system. The system can “score” some assets based on aging mechanisms housed within the system that can be used to predict potential end-of-life. Actual refurbishment and replacement work is driven by the calculated health scores.

Normalized reliability performance in 2012/13 as reported in the Energex Distribution Annual Planning Report 2013/14-2017/18 (DAPR) is as follows:


Normalized Reliability Performance		2012 / 13 Actual
SAIDI (mins)	CBD	1.41
	Urban	71.60
	Short Rural	156.40
SAIFI	CBD	0.01
	Urban	0.79
	Short Rural	1.53

4.10.9 - ESB Networks

Design

Network Reliability

People

Distribution planning at ESB Networks Networks, including the implementation of reliability standards, is performed by planning engineers within the Network Investment groups – responsible for planning network investments in the North and South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a GeFneration Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists” who have developed their expertise through field experience.

Planning standards and criteria for reliability are developed jointly between the Asset Investment group and the Strategy Group, which is part of the Finance and Regulation group within Asset Management.

Process

Planners design the system to N-1, with most supplies having a “forward feed” (preferred) and a “standby feed” (reserve). The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications of anticipated incremental forecasted loading. Planners (engineers and technologists) model the system and perform analyses to understand anticipated requirements, including contingency studies (N-1 planning) to assure that ESB Networks can pick up customers with standby feeders within the emergency ratings of their transformers and cables (long-term cyclical overloads of no more that from 125-150 percent of rating, and short-term (emergency) loading of no more than 150-180 percent of rating). From this analysis, planners determine what reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Another notable practice at ESB Networks is its cable reliability guidelines. If any cable experiences two faults, it is moved up the priority maintenance list and replaced. The cable is then forensically analyzed. ESB Networks has had problems with cable sheath corrosion due to the high concentration of salt in the air in Dublin, and it has found that cabling there needs to be strictly monitored.

Technology

For performing MV (10 and 20 kV) and for some 38-kV circuit studies, ESB Networks is using SynerGEE (GL Group). ESB Networks has tied this tool to its GIS database. For HV analyses (38 kV and 110 kV), ESB Networks uses PSS® Sincal from Siemens.

4.10.10 - Georgia Power

Design

Network Reliability

People

Investment decisions for network equipment such as transformers and network protectors are based on equipment condition determined through inspection and maintenance findings. Engineers in the Operations and Reliability Group of the Network Underground group are responsible for remotely monitoring the network system, and for performing inspection and maintenance of network assets. The Network Operations and Reliability group is comprised of both field resources (network field engineers, inspectors, and maintenance crews) that perform network equipment inspections and conduct network equipment maintenance, and the engineering resources that analyze the information from the inspection activity and make decisions whether to repair or replace network equipment based on findings from the field.

Investment decisions concerning maintenance or repairs of structures such as manholes, vaults, or duct banks are the responsibility of engineers responsible for civil and structural design within the Network Underground Engineering group. This group is responsible for determining the inspection approach to structures, and for developing strategies for responding to findings. In addition, this group develops standards for structural design and repair.

Process

Georgia Power engineers and area planners keep detailed information on network and cable loads to make certain the system has enough capacity to serve its customers. When the system flags a network or cable segment as near 90 percent capacity, the planner and/or design engineers analyze the system, and recommend changes for increasing the capacity of the system, such as adding new transformers, conductor, or adding new networks. Georgia Power makes plans up to four years in advance to insure adequate capacity and network reliability.

In Atlanta, Georgia Power tries to limit its network size to 40MVA, although they do have some 50MVA networks.

One notable aspect of its network underground substation design is that Georgia Power designs substations that use “network only” transformers that supply bus sections that source only network feeders. All feeders supplying any one network are fed off of the same substation bus. Also, voltage is regulated at the bus using load tap changer on the transformer secondary. This design approach assures consistent voltage among feeders supplying any one network, minimizing reliability issues associated with voltage imbalance such as pumping and cycling network protectors.

Area Planners design the stations so that there is always capacity at the station to back up network feeders, as network feeders at Georgia Power have historically been designed without tie points outside the station. (Note: at the time of the immersion, Georgia Power was beginning to put normally open ties between network feeders at selected locations). So, for example, at a three station bank, where one transformer is dedicated to supplying network load, and the other two-supply, non-network load, the units that supply the non-network load would be sized with reserve capacity to back up the network load in the case of the loss of the network transformer (N-1).

Duct line configuration for feeders emanating from substations are very standardized, as is cable racking within vaults and manholes. Primary feeders are in duct line at the bottom, with secondary feeders at the top. Duct bank is concrete encased. The Network Underground group has done a good job of developing standards for new networks, as well as upgrading its existing network, for a more uniform and reliable system.

Technology

Engineers in the Operations and Reliability Group at the Georgia Power Network Underground group are responsible for remotely monitoring the network system through its SCADA system that ties into the central Distribution Control Center, making recommendations about the type and implementation of network protectors, and are the first responders in the event of trouble on the network underground system. (See Operations section in this report.)

4.10.11 - National Grid

Design

Network Reliability

People

Network system reliability at National Grid is the shared responsibility of both the network planners within the Distribution Planning group and the Asset Strategy and Policy group.

The Reliability Analysis and Reporting group, within Asset Strategy and Policy, reviews circuit performance across the system, including network feeders, though most of their attention is focused on the radial system. For network feeders, this group works closely with planning engineers and UG engineers to develop recommendations for improvement. This group is also responsible for generating reliability reports. .

Note that the National Grid Albany network system has been highly reliable.

Process

National Grid has recently standardized its maintenance approach to network equipment, increasing the frequency of inspection from historical practice. One driver of increasing this maintenance frequency is to assure continued system reliability. Another is to increase the frequency of being able to gather data such as loading information to perform better analysis. Because National Grid has no remote monitoring on their network system (beyond the substation feeder breaker), the only opportunity they have to gather information about the equipment, whether condition information or loading information, is during field inspections. In general, network facilities in the Albany network are well-maintained.

At the time of the practices immersion, the Distribution Planning group was developing a specific recommended strategy for upgrading the secondary network system, which includes the addition of remote monitoring, increased maintenance, and network transformer oil testing such as dissolved gas analysis. In developing this strategy, each network was studied to determine whether to keep the network, expand it, shrink it, or eliminate it. The specific investment strategy for each network will be dictated by this overarching direction. For example, remote monitoring might appropriately be implemented in networks slated for expansion, whereas this might not be considered for networks planned for elimination.

A specific study of the network secondary distribution system serving Albany was performed as part of this process. The study included an analysis of thermal and voltage limits applied to the anticipated 2015 peak loading levels during normal, single and double contingency conditions. In addition this study analyzed the expected performance of the secondary network system for solid faults on secondary cables. Recommendations from this analysis include specific system reinforcements to meet anticipated peak loading levels and the application of cable limiters on each end of secondary mains and at secondary junctions.

The identification of secondary network system upgrades was prompted by an analysis performed by Distribution Planning to answer the question of whether outages to secondary network system, such as certain notable outages experienced by some other utilities, could potentially occur at National Grid. The analysis concluded that yes, the underlying issues that led to those other noteworthy outages, existed at National Grid and could potentially result in outages. The project to upgrade secondary networks has been added to the National Grid corporate risk register.

Technology

National Grid is loading network protector and network transformer information into Cascade, which will serve as the asset register.

National Grid uses a system called Computapole to record maintenance and inspection information. Network protector and transformer maintenance and repair data was previously maintained locally or in AIMSS. There is ongoing corporate wide discussion as to where the data will reside in the future. It may migrate to CASCADE with substation data, or may be maintained locally. NY East is and has been retaining data locally on Microsoft Access.

National Grid utilizes a prioritization decision support matrix that is used to determine project risk by weighing the anticipated probability and consequence of a particular event occurring. For example, an asset failure could be scored based on the probability or time to failure, and the consequences if indeed that asset would fail.

National Grid is piloting the implementation of remote monitoring in their network systems in their Buffalo, NY network.

4.10.12 - PG&E

Design

Network Reliability

People

Network system reliability at PG&E is a shared responsibility among the asset managers and planning engineers responsible for network infrastructure.

PG&E has effectively implemented an asset management process for network equipment. They have assigned a specific person as the “Manager of Networks”, part of the Distribution Engineering and Mapping organization. This asset manager is responsible for determining the investment, maintenance and replacement strategies for network assets including network transformers, network switches, and network protectors.

PG&E also has an asset manager called the Underground Cable Program Manager responsible for determining the investment, maintenance and replacement strategies for cable and cable systems. This asset manager is located within the Electric Distribution Standards and Strategy organization.

The network planning engineers, part of the Planning and Reliability Department, also have accountability for assuring network system reliability in both their design and planning activities.

The manager of networks, cable experts within the Standards group, and the network planning engineers collaborate closely with one another to establish investment strategies that assure continued network system reliability.

Finally, PG&E has a Reliability Manager that focuses on overall reliability of the division (network and non – network). This manager convenes bi- annual meetings to highlight and address reliability issues with proactive maintenance and refurbishment.

Process

PG&E has developed lifecycle plans that define assets management strategies for network equipment and cables ( See Attachment A ). These plans define strategies for replacement, maintenance, safety, etc. to meet PG&E’s asset reliability performance objectives. Some examples of specific strategies are summarized below.

One example of a reliability driven design strategy is PG&E’s decision to change the network unit design from one with a transformer mounted primary switch compartment to one with a remotely located solid dielectric switch as a primary sectionalizing point. This decision was made to eliminate a potential failure point to improve the reliability of the system.

Another example of reliability driven testing strategy is the implementation of cable diagnostic testing. PG&E has implemented the use of VLF testing, and has chosen the feeders to test based on historic feeder reliability performance based on analyses performed by planning engineers.

An example of a reliability driven maintenance strategy is the performance of annual transformer oil sampling and testing to identify and resolve impending transformer failures. (See Network Transformer Maintenance / Oil Testing.)

An example of a reliability driven replacement strategy is the implementation of a program to replace oil filled transformers located in high-rise buildings with dry type transformers to mitigate the potential effects of a catastrophic failure of an oil filled transformer in a high rise location.

4.10.13 - Survey Results

Survey Results

Design

Network Reliability

Survey Questions taken from 2015 survey results - Summary Physical/General and Design (Question 72)

Question 46: Have you developed any reliability metrics for assessing the performance of the network system?

Survey Questions taken from 2012 survey results - Planning

Question 3.14 : Have you developed any reliability metrics for assessing the performance of the network system?

4.11 - Network Transformer Design

4.11.1 - AEP - Ohio

Design

Network Transformer Design

People

Establishing specifications for the network unit, including transformers, network protectors and the primary switch design used in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineers in collaboration with the Network Engineering Supervisor. These personnel are geographically based in downtown Columbus at AEP Ohio’s Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is part of the Distribution services group at AEP, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Distribution Services group, including the Network Engineering Supervisor supports all AEP network design issues throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Network protector designs used throughout the AEP service areas are regularly studied and recommendations are made through this committee.

Technology

AEP’s network unit design calls for a wall-mounted solid dielectric vacuum switch that is separate from the transformer, a submersible network transformer that can accept ESNA style (elbows or T bodies) connections, and a transformer mounted network protector (see Figures 1, 2 and 3).

Figure 1: Primary transformer connection – T bodies

Figure 2: Network transformer. Note that the transformer does not have a primary switch compartment

Figure 3: Network protector mounted on network transformer

4.11.2 - Ameren Missouri

Design

Network Transformer Design

People

Network standards, including the standard design for the network unit, including the transformer, primary switch and network protector design, are the responsibility of the Standards Group.

This group develops both construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both an online and printed book format. Updated versions of the book format version are issued every 2-3 years.

Organizationally, the Standards Group is led by a Managing Supervisor, and is part of the Distribution Planning and Asset Performance Department, part of Energy Delivery Technical Services. The group is staffed with engineers.

For the network unit standard, Standards engineers work closely with the organization responsible for network equipment testing and maintenance – the Service Test Group. Ameren Missouri has an up to date material specification for the network unit; however, the construction standard for this installation is maintained separately, and is not part of the Construction Standards Book. Ameren Missouri plans to incorporate the standard for the network unit into its Construction Standards Book.

Process

Ameren Missouri’s network unit specification calls for a subway style transformer unit with an oil filled high-voltage disconnecting and grounding switch incorporated into the unit, and a throat mounted submersible network protector.

In general, Ameren Missouri uses a two chamber design for the network transformer – one chamber for the primary termination and one chamber for the switch compartment. However, their specification does allow for the high − voltage terminal and switch chambers to be combined into one chamber provided that the bushing height is equal to the two chamber design.

Ameren Missouri is not using cathodic protection in network unit installations. However, at the time of the practices immersion, Ameren Missouri was piloting the use of sacrificial anodes in selected network unit locations to assess their efficacy.

Technology

Ameren Missouri has recently modified its transformer standard to call for a tank design that can withstand high energies from internal faults before rupturing and, in the event of a tank rupture, direct ejected fluids downward into the vault. In addition, they require an anti corrosive coating in the bottom 12 inches of the tank.

4.11.3 - CEI - The Illuminating Company

Design

Network Transformer Design

People

The design of the network transformers is performed by the CEI Underground / LCI group, part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

Process

FirstEnergy has an Underground Distribution Network Desing Practice guideline. (Note that CEI’s network transformer design predates the development of the FirstEnergy Underground Distribution Network Design Practice.)

Guidelines from that practice include:

The Network Design practice calls for a maximum design loading of 100% of the transformer nameplate rating in a first contingency.
Network transformers should be physically isolated from one another, either separated by a firewall or located in separate vaults.
Network transformers must be adequately ventilated (20 square feet of clear opening per 100kVA of transformation). As transformers are replaced or upgraded, CEI will review the ventilation of existing vaults. Also, during maintenance in a customer owner vault, CEI will check the vault ventilation system to assure it is functioning. If not, they will send a letter to the vault owner.
Transformers should be connected to the system using 600 amp separable connectors (elbows) in order to improve repair times.

Technology

The Network is made up of approximately 57 vaults, and includes 61 network transformers (500, 750, and 1000 kVA transformers).

4.11.4 - CenterPoint Energy

Design

Network Transformer Design

People

Major underground design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group, the Padmounts group, deals with the design of three phase pad mounted transformer installations, including three phase looped systems used to serve commercial developments, and designs that use pad mounted transformers in conjunction with pad mounted switch gear to provide high reliability service to critical customers as described in this section. This group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources.

Another sub group focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. This group, the Vaults group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources.

The final subgroup is one focused on distribution feeder design. The Feeders group focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

For critical three phase loads, CenterPoint’s standard design utilizes a switch in conjunction with a pad mount transformer to improve reliability.

In this design, two primary feeds are brought into pad mounted switchgear. One feeder is the “normal” feed, and the other is the “emergency feed”. The switch gear has two fused taps that feed to pad mount transformers.

For this design, the loss of any one feeder enables CenterPoint to simply switch the load to the backup feeder by opening the normally closed switch and closing the normally open switch within the switchgear. In this design, the customers can be restored before CenterPoint troubleshoots and identifies and isolates the location if the problem that caused the interruption. Thus, this design type is more reliable than the three phase loop design, which is the CenterPoint standard for non critical loads. Note that all switching of padmount transformer switches is performed by the Major Underground group.

Figure 1: Padmounted switchgear

Figure 2: Three phase transformer served from switchgear

Technology

Historically, CenterPoint has used live front units with this design type. However, CenterPoint is currently moving to a dead front design.

4.11.5 - Con Edison - Consolidated Edison

Design

Network Transformer Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Transformer Design

Con Edison’s uses both liquid-filled submersible and dry-type above-grade transformers for network applications. Transformer tanks are made of copper-bearing carbon steel or, in some cases, stainless steel. Tanks are covered with a zinc primer and black epoxy resin. Cathodic protection is required in certain locations, where debris and/or water conditions exist. Transformer tanks are designed with a sacrificial tank so that the units can absorb the forces of a full short circuit without breaching.

Network transformers are three phase, and are connected delta-wye. Most units are sized at either 500, 1000, or 2500 kVA.

Transformers are equipped with an oil drainage valve, a liquid level indicator, thermometer with alarm contacts, a no load tap changer (in some cases), a purge valve assembly for gas filling and pressure testing, a pipe plug for oil filling and purging, and traditional markings / nameplate / identification information.

According to Con Edison, their transformer specifications are more stringent than general industry standards and the IEEE standards. For example, their transformers are designed with very low impedances. Con Edison does stress their transformers at times, but not continuously. They believe that, even though their design criterion is N-2, their system is robust enough to manage greater contingencies.

Con Edison has been adding instrumentation for its remote monitoring system to new and existing transformer installations.

Con Edison evaluates transformer loadability based in top oil/hot spot temperature and thermal time constant calculations as per ANSI standards. They require their transformers to be designed to maintaining prescribed top oil and hot spot maximum temperatures under certain levels of loading, and given assumptions of the number of contingencies (modes of operation), operating ambient temperatures, vault temperature rise, and load cycle (five types).

For example, Con Edison requires that a transformer under normal conditions (N-0) be able to be loaded to 145% of rated current indefinitely. For 208/120-V units, under normal conditions (N-0), Con Edison’s specification requires that the hot spot temperature not exceed 105°C and the top oil temp not exceed 125°C under full load.

Modes of Operation vs. Loading

Five different 24-hr period load cycles are considered
Normal: indefinitely
- 145% of rated current
1st Contingency: 24-hr duration, once/month
- 170% of rated current
2nd Contingency: 24-hr duration following 1st Contingency, once/year
- 180% of rated current

Modes of Operation vs. Max. Temp Limits

Normal
- 105°C max winding temperature
1st Contingency
- 125°C max winding temperature
2nd Contingency
- 150°C max winding temperature
Max Oil Temperature
- 125°C all modes

Con Edison’s specifications include tables that list the maximum allowable loading limits for transformers of different size and type, given the load cycle and mode of operation. This specification also provides loading limits for associated network protectors.

4.11.6 - Duke Energy Florida

Design

Network Transformer Design

People

Standards for network design, including the network transformer, are the responsibility of the Duke Energy Florida Standards group, which oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies. The Design Engineers are engaged in a Duke Energy corporate-wide process to consolidate design standards for network systems among the various Duke operating companies, due to be finalized in 2017.

Duke Energy Florida has developed network design standards, which are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D.)

Process

The Standards engineers who focuses on network infrastructure works very closely with experts within the Network Group, including the department manager and senior network specialists. Network standards for infrastructure in Clearwater and St. Petersburg are the result of the collaboration between the Standards group and Network Group.

Technology

Duke Energy Florida uses submersible network transformers to supply network customers. Transformer sizes range from 500 to 1500 kVA wye, with most units in Clearwater being 500kVA units, and most in St. Petersburg being 750kVA units. Transformer nameplate voltage rating is 12470 GRD.Y / 7200 - 208Y/120 (see Figure 1 and 2).

Figure 1: Network transformers – spot network location

Figure 2: Network transformer in submersible vault

In developing their network transformer specification, Duke Energy Florida mirrored the Con Edison specification, including specifying units that are designed to eject fluids to the floor in the event of a transformer tank rupture ^[1] , as shown if Figure 3.

Figure 3: GE Omega transformer rupture mechanism

Duke Energy Florida monitors network transformer and vault information in Clearwater using a system by Qualitrol. Using the Qualitrol transformer sensor module, they monitor transformer oil level and temperature, as well as the Oil Minder system associated with the vault sump pump, which can detect the presence of oil in the water and cease pump operation.

Duke Energy has recently teamed with Qualitrol to pilot an installation using a dissolved gas monitor at one transformer location. The monitor itself fits into the drain port of the transformer and is tied into the Qualitrol receiver. Their goal is to build an algorithm that considers transformer vintage, DGA results, etc., and uses that information to trigger replacement.

Duke Energy Florida is also monitoring information at the network protector using the Eaton VaultGard system (see Figure 4). VaultGard aggregates information from the Qualitrol module as well as from the network protector MCPV relay, and communicates it to Sensus, a third party, via cellular communications. Sensus provides information back to the Network Group.

Figure 4: VaultGard and Qualitrol control boxes on vault wall

^[1]gegridsolutions.com

4.11.7 - Duke Energy Ohio

Design

Network Transformer Design

People

Network standards are the responsibility of the collaboration of the network engineer, the planning engineer, and the Dana Avenue supervision. This group uses the old Cincinnati gas and electric construction manual as a guide. Ultimately, Duke Energy will develop a common network standard across the system.

Process

A standard network transformer installation calls for the transformer itself, elbows, cable, and grounding. For network installations, to cast each stock item set up separately so that each part is ordered individually.

Technology

Duke Energy Ohio utilizes submersible type transformers in their network. They used to buy a vault type and submersible type transformers but made the decision to buy strictly the subway type as the price difference between the two types was relatively small. Duke’s standard is to install network protectors on the transformers.

Figure 1: Network protector mounted to transformer

New network transformers with provisions for mounting a network protector are purchased in 500 kVA, 750 kVA, 1000 kVA sizes with a 216Y/125 volt secondary voltage and in 1000 kVA, 1500 kVA, 2000 kVA and 2500 kVA sizes with a 480Y/277 volt secondary voltage. Transformers are purchased as 13,200 volt delta units with a tap changer on the primary.

Because Duke has had problems with equipment deterioration due to salt contamination, their transformer design calls for a protective shield over the transformer primary termination to protect the terminations from salt and other contaminants. In selected faults they will place a fiberglass barrier over top of the network protector.

Figure 2: Primary dead front terminations

Duke’s network transformer specification calls for submersible grade units in all network applications, with specifications meeting or exceeding IEEE standards (C57.1240).

Duke also uses 600 amp separable connector elbows to terminate the primary on the transformer.

4.11.8 - Georgia Power

Design

Network Transformer Design

People

Network standards, including the standard design for the network transformer and primary switch, are the responsibility of the Standards Group and the Network Underground design engineers.

Organizationally, both the design of network systems, and the development of network standards are the responsibility of engineers within the Network Underground group. These may be engineers that are part of the Network Engineering Group, or principal engineers that report directly to the Network Underground Manager.

Organizationally, the Network Underground group is a separate entity, led by the Network Underground Manager, and consisting of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure, including the development of standards for network equipment.

Network design is performed by the Network Underground Engineering group, led by a manager, and comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees. Engineers are not represented by a collective bargaining agreement.

In addition to the engineers with in the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also deal with issues of network design, and are responsible for the development and maintenance of standards for network equipment. Standards are available in both an online and printed book format. Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. It is a living document, and the responsibility of the Standards Group comprised of the Principal Engineers in the Network Underground group. The standards are divided into two main sections: civil construction and network specifications and design.

Process

Georgia Power’s standard for network transformers conforms to IEEE C57.12.40 (IEEE Standard for Network, Three-Phase Transformers, 2500kVA and smaller), with two minor modifications to the manufacturer’s specifications:

transformers are welded onto metal rails to keep them off the vault floors and make them easier to pick up with a fork lift
every transformer has phasing tubes on top to test for current in the transformer. The phasing tubes are used to trace phases before operations. All new transformer installations are filled with FR3 organic ester fluid. Common transformer sizes for units supplying their network grid systems (208V) are 500 kVA and 1000kVA, with 500kVA units being the most common. For transformers feeding spot networks at 480V the most popular sizes are 1000 and 2000kVA units. Georgia Power does have 3000kV units supplying a small 4kV network.

Georgia power’s standard allows for both transformer units with separate compartments for the primary termination chamber and primary switch, and combined, one chamber designs, which are more recently being used for units with elbow type bushings. Georgia Power is using 200A-rated elbows and bushings for the primary terminations (See Figure 1).

Figure 1: New network transformer inventory

The transformer mounted primary switch includes open, closed, and grounded positions (See Figure 2). Georgia Power does not require a sight glass on the primary switch compartment.

Figure 2: Network transformer primary switch handle

Transformers are tested by Test Technicians who are part of the Network Operations and Reliability group (the Testing group). The group performs a transformer turns ratio test (TTR); a Megger test; and they take an oil sample for a dielectric test. These are industry standards tests that Georgia Power performs before putting the transformer into inventory.

Georgia power mounts the protector on the transformer and performs initial protector testing as well. This testing is performed by a two person team comprised of a Cable Splicer Senior and a Cable Splicer Journeyman. Georgia Power has implemented this approach to familiarize cable splicers with the network units they’ll be working on in the field.

Note: if a transformer has been in inventory for a long time, the Testing group will do a Megger test and an oil sample test again, to make sure it is safe to operate, and ready to commission.

4.11.9 - HECO - The Hawaiian Electric Company

Design

Network Transformer Design

(Padmount Transformers)

People

The Technical Services Division of the Engineering Department establishes transformer specifications for HECO.

Primary Trouble Men (PTM’s) perform switching on the units.

Technology

HECO’s standard three phase transformer design has fuses, taps, and an internal primary switch to enable a HECO Primary Trouble Man to switch between a primary and alternate feed.

4.11.10 - National Grid

Design

Network Transformer Design

People

Network standards, including the standard design for the network transformer , are the responsibility of the Distribution Standards department, part of Distribution Engineering Services. Distribution Engineering Services is part of the Engineering organization, which is part of the Asset Management organization at National Grid. Within the Standards group, National Grid has two engineers that focus on underground standards.

National Grid has up to date standards and material specifications for network equipment, including the network transformer primary switch, network transformer and network protector. Network material specifications are updated annually. Standards are updated on a five-year cycle.

Figure 1: Network Unit - Primary switch compartment

Note that because National Grid’s system is comprised of multiple network systems of different designs in both New York and New England, the standards book is organized with a common standards section that represents the whole company, and then individual sections that specify standards appropriate to the individual network systems that comprise their overall infrastructure.

Process

A new standard network unit at National Grid includes a submersible network transformer with a high-voltage disconnecting and grounding switch incorporated into the unit, and a throat mounted network protector. The network transformer is equipped with 600 dead front apparatus bushings for the primary cable termination onto the transformer.

Figure 2: Network Unit - protector

Figure 3: Network Unit

National Grid Albany does not presently install any high side interrupters. Any faults would be seen by the feeder breaker.

National Grid’s standard design for a network unit calls for it to be placed on hot dipped galvanized I-beams within the vault. National Grid uses anodes to provide corrosion protection.

Technology

Spot network vaults are equipped with a ground fault protection system designed to trip (open) all of the network protectors in the vault in the event of a ground fault. The customer is required to buy, install, and wire the National Grid approved ground fault protection system. Ground fault protection system equipment is installed in the customer’s electric room. However, a current transformer required to monitor neutral currents is installed in National Grid’s transformer vault.

4.11.11 - PG&E

Design

Network Transformer Design

People

Network standards, including the standard design for the network transformer and primary switch design, are the responsibility of the Manager – Distribution Networks. PG&E has assigned one individual as the Asset Manager for network equipment, including all components of the network unit. This asset manager is responsible for network equipment design standards, developing life cycle strategies for network equipment, and making capital and maintenance investment decisions for network equipment.

Technology

The current transformers on the PG&E underground network are of a three (3) chamber design. PG&E’s transformer replacement program will transition to a single oil tank design (filled with natural ester - Envirotemp® FR3™) coupled with a stand alone G&W vacuum switch mounted on the wall of the vault.

The reason for the change in design is that in the legacy design the smaller tanks (primary and ground switch) contain a limited amount of oil (25 – 30 gallons). A failure in these tanks is more likely to lead to a vaporization of the oil, and the potential for a catastrophic explosion to occur. PG&E has therefore decided to implement a single main tank design in order to mitigate the potential of a catastrophic explosion occurring in any of its transformers.

4.11.12 - SCL - Seattle City Light

Design

Network Transformer Design

(Network Transformers - Corrosion)

People

Organization

Network Design at SCL is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A . The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Process

Network Transformers — Primary Switch

SCL’s specification for network transformers calls for either a one- or two-chamber design for the transformer primary termination and switch. SCL has historically used a two-chamber design – one chamber for the terminations and one for the switch.

The two-chamber design originated with the use of Paper-Insulated Lead-Covered (PILC) cable and the need for a place to make lead wipes for the primary terminations.

SCL has stayed with the two-chamber design standard, but is currently trying out a one-chamber design, because most of their primary conductors are crosslinked polyethylene (XLP), with XLP terminations.

Their specification for a combination switch and terminal chamber requires that:

The high-voltage bushing (listed in Section 8.2.3 e of their material specification^[1] 0038.3) may not be used to support switch contacts in any way. Only flexible cable leads may be connected to the bushings.
The switch operating handle shall be 36 to 48 inches above the ground.
Only one set of drain valve, vent/level plug, and liquid level gauge is required (and shall be per Section 8.2.1 of material specification 0038.3)
The single chamber shall meet all other aspects of their material specifications for terminal and switch chambers (Sections 8.2.1, 8.2.2, and 8.2.3 of their specification 0038.3).
The viewing window shall be large enough to see the bottom of the bushings in oil.

^[1] SCL’s material specifications can be accessed at seattle.gov .

Network Transformers — Corrosion

SCL’s transformer specification conforms to ANSI standards (C57 12.40), and calls for a corrosion-resistant steel tank (5/12 inches thick with ½ inch cover and bottom). SCL does have some corrosion challenges with some transformers that are located near the waterfront. They have considered purchasing transformers with stainless steel tanks for these locations, but at this point are basically accepting a shorter transformer life at these locations (approximately 20-year life).

Cathodic protection is not being used for distribution transformers.

Note: SCL is utilizing cathodic protection for transmission oil-filled pipe-type cable.

4.11.13 - Practices Comparison

Practices Comparison

Design

Network transformer design

4.11.14 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.6.2 - Network Transformers

4.11.15 - Survey Results

Survey Results

Design

Network Transformer Design

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 6 : Do you require a firewall between two pieces of equipment in one vault?

Question 7 : Are you using a separately mounted primary switch (not part of the transformer unit)?

Survey Questions taken from 2015 survey results - Design

Question 51 : Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers) (check all that apply)

Question 55 : If you have primary termination and switch on your network transformers, does your specification call for?

Question 56 : Are you using a separately mounted primary switch (not part of the transformer unit)?

Survey Questions taken from 2012 survey results - Design

Question 4.9 : Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers)

Question 4.12 : For the primary termination and switch, does your network transformer specification call for a

Question 4.14 : Does your network transformer specification call for units with taps?

Survey Questions taken from 2009 survey results - Design

Question 4.9 : Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers)

Question 4.11 : Does your typical network design utilize: (see Graph below) (this is question 4.12 in the 2012 survey)

4.12 - Network Transformers—Primary Switch

4.12.1 - AEP - Ohio

Design

Network Transformers Primary Switch

People

Establishing specifications for the network unit, including transformers, network protectors and the primary switch design used in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineers in collaboration with the Network Engineering Supervisor. These personnel are geographically based in downtown Columbus at AEP Ohio’s Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is part of the Distribution services group at AEP, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Distribution Services group, including the Network Engineering Supervisor supports all AEP network design issues throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Network transformer/switch designs used throughout AEP are studied and recommended through this committee.

Process

AEP Ohio has networks in Columbus and Canton, Ohio. The Columbus urban area has four separate networks North, South, East, and West. All four networks are supplied from three substations and are served by six feeders each, with group of six sourced from the same substation. Canton has two separate networks servings its area. There is no overlap in among networks. Each network is built to N-2, with the Columbus networks being a true N-2 including the substation, and the Canton networks being N-2, with N-1at the station. This N-2 reliability is notable, whereas most urban underground network systems operate at an N-1 level. N-2 insures that if any two transformers go down, a third is available for picking up the network load and maintaining service. Some new service is deployed using spot networks and radial distribution within these areas, also planned and designed by the Columbus-based Network Engineering group.

AEP Ohio has network systems in both Columbus and Canton, Ohio. The Columbus urban area has four separate networks – North, South, Vine, and West – supplied from three substations. Each network is supplied from 138 kV/13.8 kV Δ -Y network transformers. All four networks, about 30 MVA each, are served by six dedicated network feeders at 13.8 kV, with each group of six originating from a single substation. There is no overlap in these networks. This is a preferred design in that the network feeders are sourced at the same voltage, which minimizes the possibility of problems with network protectors pumping or cycling. AEP reports few problems with protectors pumping, cycling, or opening under light network loading.

Each Columbus network is built to N-2 reliability. The substations that supply Columbus are designed using at least three transformers, with one serving as a ready reserve hot spare. In Columbus, the Vine network primarily serves spot networks in a high-rise area of downtown (Vine Station), with some mini-grids at 480 V. The other three networks (North, South, and West) serve a mix of grid (216 V) and spot loads.

Canton has one network supplied at 23 kV. The station that supplies Canton is designed to N-1, though networks themselves are also designed to N-2.

All new network service designs reference the AEP parent company Network Design Criteria guide, which outline both Single Contingency (N-1) and Double Contingency (N-2) Operations.

AEP had historically used a network unit design that incorporated the primary switch compartment into the transformer unit. However, its new standard calls for a separate wall-mounted solid dielectric vacuum switch to be used as the primary switch to disconnect the transformer from the primary circuit. The new transformer specification calls for transformers without an integrated primary switch as the wall-mounted vacuum interrupter serves this purpose.

AEP’s decision to move to separately mounted primary switch was driven by safety and operational flexibility. From a safety perspective, by moving to the wall-mounted vacuum switch, AEP has eliminated an oil-filled chamber on the transformer unit, eliminating the chance of a failure resulting in a fire and spreading to the remainder of the transformer unit. The wall-mounted switches can also be remotely operated from outside the vault of manhole.

From an operational flexibility perspective, the wall-mounted vacuum switch provides the ability to de-energize one network unit while leaving the rest of the circuit in service. Not having to take an entire circuit out of service improves reliability by not having to operate the remaining network in a first contingency, and eliminates a complicated and lengthy process to clear the entire feeder, that involves visiting all other transformer locations (grid and spots). In addition, clearing an entire feeder at AEP involves increased coordination with dispatcher resources as compared to operating a single switch which can be performed by local resources.

Technology

AEP is using the Elastimold MVI solid dielectric vacuum switch. This is a load break device and can be operated remotely from outside of the manhole or vault (see Figures 1 - 4).

Figure 1: Wall-mounted vacuum switch, Elastimold MVI

Figure 2: Wall-mounted vacuum switch

Figure 3: Switch control cabinet

Figure 4: Switch control cabinet – remote controller

In 480-V spot network vaults, AEP has historically supplied the vault with primary switches that are tied to the fire detection system, dropping the entire vault in the presence of a fire. Prior to the use of the solid dielectric vacuum interrupter, AEP had used SF₆ switches in this application.

AEP’s new standard is to tie the solid dielectric vacuum switches to both the fire detection systems and transformer sudden pressure alarms. If the system senses a transformer pressure alarm, it would drop the circuit supplying that transformer. If the system senses a fire (high temperature in the collector bus), it would drop the entire vault.

4.12.2 - Ameren Missouri

Design

Network Transformers Primary Switch

People

Network standards, including the standard design for the network transformer and primary switch design, are the responsibility of the Standards Group.

This group develops both construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both an online and printed book format. Updated versions of the book format version are issued every 2-3 years.

Organizationally, the Standards Group is led by a Managing Supervisor, and is part of the Distribution Planning and Asset Performance Department, part of Energy Delivery Technical Services. The group is staffed with engineers.

For the network unit standard; that is, the standards for the network transformer, primary disconnect and network protector, Standards engineers work closely with the organization responsible for network equipment testing and maintenance at Ameren Missouri – the Service Test Group. Ameren Missouri has up to date material specifications for the network unit equipment. However, the construction standard for this installation is maintained separately, and is not part of the Construction Standards Book. Ameren Missouri plans to incorporate the standards for the network unit equipment into its Construction Standards Book.

Figure 1 and 2: Photos of transformer primary Disconnect and ground switch handle

Figure 3: Photo of transformer primary Disconnect and ground switch handle

Process

Ameren Missouri’s network transformer specification calls for a subway style unit with an oil -filled high-voltage disconnecting and grounding switch incorporated into the unit. In general they utilize a two chamber design – one chamber for the primary termination and one chamber for the switch compartment – however, their specification does allow for the high − voltage terminal and switch chambers to be combined into one chamber provided that the bushing height is equal to the two chamber design.

The primary switch has five positions with the following operating sequence: Open, Transformer, Ground H3, Ground H3 & H2, and Ground H3, H2, & H1. The multiple ground positions are used for phasing.

For example, after a network feeder has been separated (for example because of splicing to repair cable), Traveling Operators will check phasing before restoring the feeder. They do this by going to a transformer location and moving the switch handle into the ground position. Back at the substation, they will hook up a home-developed annunciator device (called a rabbit cage.) This device uses a DC supply, and has indicator lights which illuminate when the cable legs are grounded.

When the transformer switch is in the ground position, all of the lights on the rabbit cage will be illuminated. The traveling operator will then move the switch handle - in the first position, the C light should go out, then the B light, finally the A light- indicating that the phasing at the transformer matches the phasing at the station. This test is always done twice before confirming phases.

The primary switch includes an electrical interlock to prevent operation when the transformer is energized.

The transformer switch compartment does not contain a site glass. Ameren Missouri does not require a visible break at the transformer disconnect switch.

Technology

Ameren Missouri currently has no primary sectionalizing devices on the network feeders. As part of their downtown revitalization Program, they are thinking about adding sectionalizing devices to limit the number of switching operations required to clear a network feeder (or feeder section) to six operations. Currently, they have some network feeders that have 15 - 18 network transformers. Thus, the switching process takes a long time. Inserting primary sectionalizing devices would minimize the number of switching operations required to clear a section of the feeder.

4.12.3 - CEI - The Illuminating Company

Design

Network Transformers Primary Switch

People

The design of the network transformers is performed by the CEI Underground / LCI group, part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

Process

The transformer primary switch is an externally operable disconnect switch with a ground position that short circuits and grounds the high-voltage windings and bushings connected to the feeder, and with phasing positions that are used to ground a given phase in order to perform phasing. For example, after locating and isolating a faulted section of cable, CEI crews may have to determine the phasing before reconnecting two cable sections. When phasing conductors to make repairs, they will go back to a network transformer and move the switch to the phase position to ground a particular phase. They will then use a small Megger tester to determine the corresponding faulted phase in the manhole.

Technology

CEI’s network transformer design includes a one-chamber design for the transformer primary termination and switch. The switch is an externally operable disconnect switch with a ground position and phasing positions.

4.12.4 - CenterPoint Energy

Design

Network Transformers Primary Switch

People

Network Unit design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group deals with the design of three phase pad mounted transformer installations, including looped commercial developments. This group, the Padmounts group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is not typically involved in network design.

Another sub group focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. The Vaults group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. Note this group designs the layout of the vault including the design of the network unit.

The final subgroup is one focused on distribution feeder design. The Feeders group focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

CenterPoint designs their network unit so that the primary disconnect (into the transformer) is physically separate from the transformer itself. CenterPoint does not purchase transformer units with a primary disconnect. Further, they have revisited locations where they had older units with primary disconnects and redesigned them to physically separate the disconnect from the unit.

Historically, CenterPoint utilized network transformers with a two compartment design as they terminated PILC cables in the primary compartment. They have modified most of these units to separate the primary disconnect, and convert the transformer primary entrance to dead front elbows.

Technology

Figure 1 shows a separate 600 amp load break disconnect used as a primary disconnect coming into the vault. Figure 2 shows live front terminations into the unit feeding from that disconnect.

Figure 1: 600 amp load break disconnect

Figure 2: live front terminations

On newer installations, CenterPoint is using dead front primary terminations (elbows), as shown in Figure 3

Figure 3: Dead front primary terminations

4.12.5 - Con Edison - Consolidated Edison

Design

Network Transformers Primary Switch

People

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Technology

Transformer Specification – Primary Switch

Con Edison’s network transformer specification differs from the transformer specification of many other utilities in that it does not call for an external primary disconnect ground switch.

Con Edison’s specification does call for an externally operable, two – position, high-voltage internal ground switch. In the Ground position, this switch will short circuit and ground the high-voltage windings and bushings connected to the feeder. The switch is mounted internally to the transformer because of space constraints in their vaults. The switch uses an electrical interlock to prevent the switch from being closed while the transformer is energized. This switch has been very reliable for Con Edison.

If Con Edison does have to disconnect a transformer from a primary feeder, the utility disconnects the feeders (lift the “elbows”) on the primary side.

4.12.6 - Duke Energy Florida

Design

Network Transformers - Primary Switch

People

Standards for network design, including the network transformer and primary switch, are the responsibility of the Duke Energy Florida Standards group, which oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies. The Design Engineers are engaged in a Duke Energy corporate-wide process to consolidate design standards for network systems among the various Duke operating companies, due to be finalized in 2017.

Duke Energy Florida has developed network design standards, which are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D .)

Process

The Standards engineers who focuses on network infrastructure works very closely with experts within the Network Group, including the department manager and senior network specialists. Network standards for infrastructure in Clearwater and St. Petersburg are the result of the collaboration between the Standards group and Network Group.

Technology

In supplying primary to a network vault, Duke Energy Florida will normally T-tap from the primary in a separate manhole and run the tap into the network vault.

Duke Energy Florida’s network design calls for the primary disconnect to be separate from the network transformer. Historically, they had utilized a three-way feed-through bushing arrangement for high side transformer isolation point (see Figure 1). Their current design utilizes a wall mounted three phase solid dielectric vacuum switch, as the disconnect point between the primary distribution system and the network transformer (see Figures 2and 3). Duke Energy Florida does not remotely monitor or control network transformer primary disconnect switches.

Figure 1: Network transformer disconnect point, older design three-way feed-through bushing arrangement

Figure 2: Newer design, wall-mounted, three phase solid dielectric vacuum switch feeding to a submersible vault network transformer which supplies the grid

Figure 3: Wall-mounted three phase solid dielectric vacuum switches supplying spot network transformers in a building vault

4.12.7 - Duke Energy Ohio

Design

Network Transformers Primary Switch

People

Network standards are the responsibility of the collaboration of the network engineer, the planning engineer, and the Dana Avenue supervision. This group uses the old Cincinnati gas and electric construction manual as a guide. Ultimately, Duke Energy will develop a common network standard across the system.

Technology

Historically, Duke used live front terminations on network transformers, with a two chamber design - one for the terminations and one for the primary switch. They recently changed their specification from live front terminations to dead front primary terminations (T bodies). The current specification calls for a one chamber design, with a non load break, three position (open, close, ground) primary disconnect switch mounted on the transformer primary.

The primary switch specification does not call for a site window. (Note that Duke will only operate the transformer primary switch in a no load condition, as the switch is a non load break switch. The primary feeder must be open and the secondary must be open in order to operate the switch).

This switch has an electrical interlock that prevents moving the switch when it is energized. The switch also has a mechanical stop in the closed position so that you have to hesitate going to the ground position so that the electrical interlock can function if necessary.

All new designs use EPR cables and T bodies as primary terminations.

Figure 1: Building Vault Transformer, live front terminations

Figure 2: Primary switch handle

Figure 3: UG Vault Transformer – Dead Front Terminations

Figure 4: Primary Switch Handle

4.12.8 - Energex

Design

Network Transformers - Primary Switch

See Network Design

4.12.9 - ESB Networks

Design

Network Transformers Primary Switch

People

The design of primary (MV) voltage infrastructure is performed by designers located within the Network Investment Management groups for larger designs, and within the ESB Networks Regions for the smaller designs. The Network Investment Management groups (North and South) are part of the Asset Investment group, within Asset Management. The Regions are organizationally part of the Operations Management Group, also part of the Asset Management organization.

Most designs are performed by an Engineering Officer – the designer position at ESB Networks. Designs are also performed by engineers and Technologists.

The development and maintenance of guidelines for performing primary network design are the responsibility of the Specification Management group, part of the Asset Investment group, also part of the Asset Management organization at ESB Networks.

The Specifications Management group has developed thorough guidelines for the design of primary switching. This guideline includes specific direction for optimizing designs.

Note that in addition to the Operations Management and Asset Investment groups, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Assets & Procurement, and Finance & Regulation. These groups work closely together to manage the asset infrastructure at ESB Networks.

ESB Networks may receive engineering consulting support from ESB Networks International (ESB NetworksI) for larger designs.

Technology

ESB Networks uses a standardized MV “packaged substation” consisting of an SF6 gas insulated ring main unit, the MV transformer (in Dublin, typically a 10-kVA primary to a 430-V secondary), and the secondary bus and protection that feed the secondary “mains” that supply the LV system in downtown Dublin.

The current design of the primary switch is an SF6 gas insulated ring main unit device (see Figure 1), with an “in” switch, an “out” switch, and a fused, switched tap leading to the transformer (kkt). The company describes these units as “maintenance free,” and obtains them from a supplier through a tendered arrangement. ESB Networks does have older oil-insulated devices installed on its system as well. These devices must be manually operated from within the indoor room. Note that the ring main units are designed with a venting system, such that any arcs will blow out the back of unit.

Figure 1: SF6 gas insulated ring main unit

ESB Networks’ standard primary switchgear (ring main unit) is a “load make,” but not a “load break” device. The switch is designed with an anti-reflex handle that prevents an operator from inadvertently and reflexively opening the switch if the operator happens to close into a fault, as the device cannot break load. If the operator does close into a fault, ESB Networks relies on the tripping of the breaker that sources the 10-kV feeder.

4.12.10 - Georgia Power

Design

Network Transformers Primary Switch

People

Network standards, including the standard design for the network transformer and primary switch, are the responsibility of the Standards Group and the Network Underground design engineers.

Organizationally, both the design of network systems, and the development of network standards are the responsibility of engineers within the Network Underground group. These may be engineers that are part of the Network Engineering Group, or principal engineers that report directly to the Network Underground Manager.

Organizationally, the Network Underground group is a separate entity, led by the Network Underground Manager, and consisting of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure, including the development of standards for network equipment.

Network design is performed by the Network Underground Engineering group, led by a manager, and comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees. Engineers are not represented by a collective bargaining agreement.

In addition to the engineers with in the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also deal with issues of network design, and are responsible for the development and maintenance of standards for network equipment. Standards are available in both an online and printed book format. Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. It is a living document, and the responsibility of the Standards Group comprised of the Principal Engineers in the Network Underground group. The standards are divided into two main sections: civil construction and network specifications and design.

Process

Georgia Power’s standard for network transformers conforms to IEEE C57.12.40 (IEEE Standard for Network, Three-Phase Transformers, 2500kVA and smaller), with two minor modifications to the manufacturer’s specifications: 1) transformers are welded onto metal rails to keep them off the vault floors and make them easier to pick up with a fork lift; and 2) every transformer has phasing tubes on top to test for current in the transformer. The phasing tubes are used to trace phases before operations. All new transformer installations are filled with FR3 organic ester fluid. Common transformer sizes for units supplying their network grid systems (208V) are 500 kVA and 1000kVA, with 500kVA units being the most common. For transformers feeding spot networks at 480V the most popular sizes are 1000 and 2000kVA units. Georgia Power does have 3000kV units supplying a small 4kV network.

Georgia power’s standard allows for both transformer units with separate compartments for the primary termination chamber and primary switch, and combined, one chamber designs, which are more recently being used for units with elbow type bushings. Georgia Power is using 200A-rated elbows and bushings for the primary terminations (See Figure 1).

Figure 1: New network transformer inventory

The transformer mounted primary switch includes open, closed, and grounded positions (See Figure 2). Georgia Power does not require a sight glass on the primary switch compartment.

Figure 2: Network transformer primary switch handle

Transformers are tested by Test Technicians who are part of the Network Operations and Reliability group (the Testing group). The group performs a transformer turns ratio test (TTR); a Megger test; and they take an oil sample for a dielectric test. These are industry standards tests that Georgia Power performs before putting the transformer into inventory.

Georgia power mounts the protector on the transformer and performs initial protector testing as well. This testing is performed by a two person team comprised of a Cable Splicer Senior and a Cable Splicer Journeyman. Georgia Power has implemented this approach to familiarize cable splicers with the network units they’ll be working on in the field.

Note: if a transformer has been in inventory for a long time, the Testing group will do a Megger test and an oil sample test again, to make sure it is safe to operate, and ready to commission.

4.12.11 - HECO - The Hawaiian Electric Company

Design

Network Transformers Primary Switch

People

Network transformers are sized by the Planning Division. The design of a network transformer installation is performed by the T&D Division of the Engineering Department. The transformer chosen would be based on HECO specifications.

The Technical Services Division of the Engineering Department establishes transformer specifications for HECO.

Technology

HECO’s network transformer design includes a two-chamber design for the transformer primary termination and switch .

4.12.12 - National Grid

Design

Network Transformers Primary Switch

People

Network standards, including the standard design for the network transformer and primary switch design, are the responsibility of the Distribution Standards department, part of Distribution Engineering Services. Distribution Engineering Services is part of the Engineering organization, which is part of the Asset Management organization at National Grid. Within the Standards group, National Grid has two engineers who focus on underground standards.

National Grid has up to date standards and material specifications for network equipment, including the network transformer primary switch. Network material specifications are updated annually. Standards are updated on a five-year cycle.

Note that because National Grid’s system is comprised of multiple network systems of different designs in both New York and New England, the standards book is organized with a common standards section that represents the whole company, and then individual sections that specify standards appropriate to the individual network systems that comprise their overall infrastructure.

Process

National Grid Albany’s network transformer specification calls for a subway style unit with a high-voltage disconnecting and grounding switch incorporated into the unit. For dedicated network feeders such as in the Albany network, the high-voltage switch is a “dead break” switch. Operation of the dead-break switch requires that the transformer be de-energized. The switch has electrical interlocks which prevent movement of the switch from any position when the transformer is energized.

Figure 1: Primary disconnect and ground switch

Note that in applications where network transformers are connected to a non-dedicated feeder (not applicable to the Albany network), National Grid will call for a “mag break” high-voltage switch. Operation of the mag-break switch to the “open” position requires that only magnetizing current be present on the transformer. The switch has an electrical interlock that prevents switching from “closed” to “open” when the network protector is closed. This allows the switch to operate from “closed” to “open” when the primary feeder is energized provided the network protector is open. Operation of the mag-break switch from “closed” to “ground” position requires the transformer to be de-energized. A second interlock prevents switching from “closed” to “ground” when the transformer is energized.

Primary terminals for new purchases are 600 ampere apparatus bushings. (dead - front design).

Figure 2: 600A dead front primary termination

Figure 3: Lead primary terminations

Technology

National Grid Albany uses a two chamber design for its network primary termination; one for the terminations themselves, and one for the internal disconnecting and ground switch. National Grid has many in service units with lead-wiped PILC primary terminations. Their current standard calls a dead front termination using for 600 A apparatus bushings.

4.12.13 - PG&E

Design

Network Transformers Primary Switch

People

Network standards, including the standard design for the network transformer and primary switch design, are the responsibility of the Manager – Distribution Networks . PG&E has assigned one individual as the Asset Manager for network equipment, including all components of the network unit. This Asset Manager is responsible for network equipment design standards, developing life cycle strategies for network equipment, and making capital and maintenance investment decisions for network equipment.

The Asset Manager is a four year degreed engineer, with a law degree. He has one four year degreed engineer working for him, but works very closely in a “matrixed” environment with other PG&E organizations key to the network, including Network Planning, Maintenance and Construction (responsible for executing the strategies developed by the Asset Management), and the Reliability organization responsible developing UG Cable strategies. The Asset Manager collaborates closely with these other field organizations, including monthly visits with field crews.

The Asset Manager is a true asset owner, held accountable for the performance of the network. As the VP, M&C Electrical Networks, the leader of the field resources focused on the network, described it, “Bob (the Asset manager) sets the strategy, M&C executes it”.

The Asset Manager has developed and maintains up to date standards that describe the Network Transformer and Primary Switch design.

Process

PG&E has changed their network unit design to separate the primary switch from the transformer tank itself. This new design physically separates the primary disconnect switch from the transformer itself creating a smaller footprint within the fault, making it easier to work on from a crew perspective, and minimizing the chances of a catastrophic failure in the main transformer tank migrating to a secondary failure in the primary switch.

PG&E plans to change all of their network units to this new design, anticipating that it will take 30 years to complete.

Technology

Historically, PG&E had used a two chamber design for its network primary termination; one for the terminations themselves, and one for the internal ground switch. PG&E has made the decision to move away from this design, instead using a solid dielectric switch mounted on the wall of the vault as the primary sectionalizing point, and using single tank transformers without a ground switch. The reason for this change is that PG&E has found that catastrophic failures of the transformer can be worsened by secondary explosions of the small oil chambers used for the primary disconnects and ground switch. There can be enough power in an arcing event that the small amount of oil in each of these smaller chambers is atomized causing a potential secondary explosion from the

PG&E plans to add SCADA monitoring and control to these primary switches.

Figure 1: Photo of Solid Dielectric Switch

Figure 2: Photo of Solid Dielectric Switch

Figure 3: Photo of Transformer

Figure 4: Photos of transformer - Protector

4.12.14 - SCL - Seattle City Light

Design

Network Transformers Primary Switch

People

Organization

Network Design at SCL is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A . The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Technology

Network Transformers — Primary Switch

SCL’s specification for network transformers calls for either a one- or two-chamber design for the transformer primary termination and switch. SCL has historically used a two-chamber design – one chamber for the terminations and one for the switch.

The two-chamber design originated with the use of Paper-Insulated Lead-Covered (PILC) cable and the need for a place to make lead wipes for the primary terminations.

SCL has stayed with the two-chamber design standard, but is currently trying out a one-chamber design, because most of their primary conductors are crosslinked polyethylene (XLP), with XLP terminations.

Their specification for a combination switch and terminal chamber requires that:

The high-voltage bushing (listed in Section 8.2.3 e of their material specification^[1] 0038.3) may not be used to support switch contacts in any way. Only flexible cable leads may be connected to the bushings.
The switch operating handle shall be 36 to 48 inches above the ground.
Only one set of drain valve, vent/level plug, and liquid level gauge is required (and shall be per Section 8.2.1 of material specification 0038.3)
The single chamber shall meet all other aspects of their material specifications for terminal and switch chambers (Sections 8.2.1, 8.2.2, and 8.2.3 of their specification 0038.3).
The viewing window shall be large enough to see the bottom of the bushings in oil.

^[1] SCL’s material specifications can be accessed at seattle.gov

4.12.15 - Practices Comparison

Practices Comparison

Design

Network Transformer Primary Switch Design

4.12.16 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.6.1 - Network Transformer Primary Switch

4.12.17 - Survey Results

Survey Results

Design

Network Transformers — Primary Switch

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 7 : Are you using a separately mounted primary switch (not part of the transformer unit)?

Question 8: When do you operate a network transformer’s primary switch?

Survey Questions taken from 2015 survey results - Design

Question 55 : If you have primary termination and switch on your network transformers, does your specification call for?

Question 56 : Are you using a separately mounted primary switch (not part of the transformer unit)?

Survey Questions taken from 2012 survey results - Design

Question 4.12 : For the primary termination and switch, does your network transformer specification call for a

Survey Questions taken from 2009 survey results - Design

Question 4.11 : Does your typical network design utilize: (see Graph below) (this is question 4.12 in the 2012 survey)

4.13 - Network Unit Design

4.13.1 - AEP - Ohio

Design

Network Unit Design

People

Establishing specifications for the network unit, including transformers, network protectors and the primary switch design used in the AEP Ohio networks supplying metropolitan customers in Columbus and Canton is the responsibility of the Network Engineers in collaboration with the Network Engineering Supervisor. These personnel are geographically based in downtown Columbus at AEP Ohio’s Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is part of the Distribution services group at AEP, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Distribution Services group, including the Network Engineering Supervisor supports all AEP network design issues throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Network protector designs used throughout the AEP service areas are regularly studied and recommendations are made through this committee.

Process

AEP had historically used a network unit design that incorporated the primary switch compartment into the transformer unit. However, its new standard calls for a separate wall-mounted solid dielectric vacuum switch to be used as the primary switch to disconnect the transformer from the primary circuit. The new transformer specification calls for transformers without an integrated primary switch as the wall-mounted vacuum interrupter serves this purpose.

AEP’s decision to move to separately mounted primary switch was driven by safety and operational flexibility. From a safety perspective, by moving to the wall-mounted vacuum switch, AEP has eliminated an oil-filled chamber on the transformer unit, eliminating the chance of a failure resulting in a fire and spreading to the remainder of the transformer unit. The wall-mounted switches can also be remotely operated from outside the vault of manhole.

From an operational flexibility perspective, the wall-mounted vacuum switch provides the ability to de-energize one network unit while leaving the rest of the circuit in service. Not having to take an entire circuit out of service improves reliability by not having to operate the remaining network in a first contingency, and eliminates a complicated and lengthy process to clear the entire feeder, that involves visiting all other transformer locations (grid and spots). In addition, clearing an entire feeder at AEP involves increased coordination with dispatcher resources as compared to operating a single switch which can be performed by local resources.

Technology

AEP’s network unit design calls for a wall-mounted solid dielectric vacuum switch that is separate from the transformer, a submersible network transformer that can accept ESNA style (elbows or T bodies) connections, and a transformer mounted network protector (see Figures 1 and 2). All new AEP Ohio designs utilize Eaton CM52 network protectors and fiber-optic connections from the protector to the Operations Center for control and monitoring (see Figures 3 and 4).

Figure 1: Wall-mounted primary switch

Figure 2: Primary transformer connection – T bodies

Figure 3: Network transformer. Note that the transformer does not have a primary switch compartment

Figure 4: Network protector mounted on network transformer

4.13.2 - Ameren Missouri

Design

Network Unit Design

People

Network standards, including the standard design for the network unit, including the transformer, primary switch and network protector design, are the responsibility of the Standards Group.

This group develops both construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both an online and printed book format. Updated versions of the book format version are issued every 2-3 years.

Organizationally, the Standards Group is led by a Managing Supervisor, and is part of the Distribution Planning and Asset Performance Department, part of Energy Delivery Technical Services. The group is staffed with engineers.

For the network unit standard, Standards engineers work closely with the organization responsible for network equipment testing and maintenance – the Service Test Group. Ameren Missouri has an up to date material specification for the network unit; however, the construction standard for this installation is maintained separately, and is not part of the Construction Standards Book. Ameren Missouri plans to incorporate the standard for the network unit into its Construction Standards Book.

Process

Ameren Missouri’s network unit specification calls for a subway style transformer unit with an oil filled high-voltage disconnecting and grounding switch incorporated into the unit, and a throat mounted submersible network protector.

In general, Ameren Missouri uses a two chamber design – one chamber for the primary termination and one chamber for the switch compartment. However, their specification does allow for the high − voltage terminal and switch chambers to be combined into one chamber provided that the bushing height is equal to the two chamber design.

Figure 1: Network Unit – Primary terminations

Ameren Missouri is not using cathodic protection in network unit installations. However, at the time of the practices immersion, Ameren Missouri was piloting the use of sacrificial anodes in selected network unit locations to assess their efficacy.

Network protectors are purchased with microprocessor relays for use with Ameren Missouri’s remote monitoring system.

Ameren Missouri does not currently install any high side interrupters. Any faults would be seen by the feeder breaker.

Technology

Ameren Missouri has recently modified its transformer standard to call for a tank design that can withstand high energies from internal faults before rupturing and, in the event of a tank rupture, direct ejected fluids downward into the vault. In addition, they require an anti corrosive coating in the bottom 12 inches of the tank.

Figure 2: Network Unit – network protector

4.13.3 - CenterPoint Energy

Design

Network Unit Design

People

Network Unit design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group deals with the design of three phase pad mounted transformer installations, including looped commercial developments. This group, the Padmounts group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is not typically involved in network design.

Another sub group focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. The Vaults group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. Note this group designs the layout of the vault including the design of the network unit.

The final subgroup is one focused on distribution feeder design. The Feeders group focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

CenterPoint designs their network unit so that the primary disconnect (into the transformer) is physically separate from the transformer itself. CenterPoint does not purchase transformer units with a primary disconnect. Further, they have revisited locations where they had older units with primary disconnects and redesigned them to physically separate the disconnect from the unit.

Historically, CenterPoint utilized network transformers with a two compartment design as they terminated PILC cables in the primary compartment. They have modified most of these units to separate the primary disconnect, and convert the transformer primary entrance to dead front elbows.

See Network Design - Process

Technology

Figure 1 shows a separate 600 amp load break disconnect used as a primary disconnect coming into the vault. The next picture shows live front terminations into the unit feeding from that disconnect.

Figure 1: 600 amp load break disconnect

Figure 2: live front terminations

On newer installations, CenterPoint is using dead front primary terminations (elbows), as shown in below.

Figure 3: dead front primary terminations

CenterPoint has also elected to separate the network protectors from the units, where they can. The picture below shows the network protector placed on a stand but located physically separate from the unit. For new installations, CenterPoint would design the network protectors to be physically separate from the transformer. The driver for this change was to keep a fire in the network protector from spreading to the transformer.

Figure 4: Network Protector separate from the transformer

Where CenterPoint is unable to separate the network protector from the transformer because of space constraints, they have replaced the transformer oil with R-Temp^[1] , an alternate cooling fluid that has a higher flashpoint than mineral oil.

Because the R-Temp fluid is very viscous and thus doesn’t circulate and cool the transformer as well as oil, CenterPoint de-rates these transformers by 12%.

Figure 5: R-Temp sticker on transformer

The largest network protectors used at CenterPoint are 2500A units.

^[1] Note that R-Temp fluid is no longer available, and CenterPoint specification now calls for FR3.

4.13.4 - Duke Energy Florida

Design

Network Unit Design

People

Standards for network design, including the makeup of the network unit including the primary switch, network transformer, and network protector, are the responsibility of the Duke Energy Florida Standards group, which oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies. The Design Engineers are engaged in a Duke Energy corporate-wide process to consolidate design standards for network systems among the various Duke operating companies, due to be finalized in 2017.

Duke Energy Florida has developed network design standards, which are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D ) In addition, the Standards engineer has developed a Distribution Engineering Manual section on Secondary Networks, which provides good background information on network component design considerations including cable limiter placement and coordination, protector operation, and manhole and vault considerations. See Attachment C.

Process

The Standards engineers who focuses on network infrastructure works very closely with experts within the Network Group, including the department manager and senior network specialists. Network standards for infrastructure in Clearwater and St. Petersburg are the result of the collaboration between the Standards group and Network Group.

Technology

Primary Switch

In supplying primary to a network vault, Duke Energy Florida will normally T-tap from the primary in a separate manhole and run the tap into the network vault.

Duke Energy Florida’s network design calls for the primary disconnect to be separate from the network transformer. Historically, they had utilized a three-way feed-through bushing arrangement for high side transformer isolation point (see Figure 1). Their current design utilizes a wall mounted three phase solid dielectric vacuum switch, as the disconnect point between the primary distribution system and the network transformer (see Figures 2 and 3). Duke Energy Florida does not remotely monitor or control network transformer primary disconnect switches.

Figure 1: Network transformer disconnect point, older design three-way feed-through bushing arrangement

Figure 2: Newer design, wall-mounted, three phase solid dielectric vacuum switch feeding to a submersible vault network transformer which supplies the grid

Figure 3: Wall-mounted three phase solid dielectric vacuum switches supplying spot network transformers in a building vault

Network Transformer

Duke Energy Florida uses submersible network transformers to supply network customers. Transformer sizes range from 500 to 1500 kVA wye, with most units in Clearwater being 500 kVA units, and most in St. Petersburg being 750 kVA units. Transformer nameplate voltage rating is 12470 GRD.Y / 7200 - 208Y/120 (see Figure 4 and 5).

In developing their network transformer specification, Duke Energy Florida mirrored the Con Edison specification, including specifying units that are designed to eject fluids to the floor in the event of a transformer tank rupture [1], as shown in Figure 7.

Duke Energy Florida monitors network transformer and vault information in Clearwater using a system by Qualitrol. Using the Qualitrol transformer sensor module, they monitor transformer oil level and temperature, as well as the Oil Minder system associated with the vault sump pump, which can detect the presence of oil in the water and cease pump operation.

Duke Energy has recently teamed with Qualitrol to pilot an installation using a dissolved gas monitor at one transformer location. The monitor itself fits into the drain port of the transformer and is tied into the Qualitrol receiver. Their goal is to build an algorithm that considers transformer vintage, DGA results, etc., and uses that information to trigger replacement.

Duke Energy Florida is also monitoring information at the network protector using the Eaton VaultGard system (see Figure 6). VaultGard aggregates information from the Qualitrol module as well as from the network protector MCPV relay, and communicates it to Sensus, a third party, via cellular communications. Sensus provides information back to the Network Group.

Figure 4: Network transformers – spot network location

Figure 5: Network transformer in submersible vault

Figure 6: VaultGard and Qualitrol control boxes on vault wall

Figure 7: VaultGard and Qualitrol control boxes on vault wall

Figure 8: VaultGard and Qualitrol control boxes on vault wall

Network Protector Clearwater

At 125/216V, Duke Energy Florida has standardized on the CM22, with internal NP fuses (see Figures 8 and 9). Duke Energy Florida uses a remote monitoring system in its network vaults in Clearwater. The company uses the Eaton VaultGard communication platform for recording and aggregating data from the network protector MPCV relay and from other vault sensors (Qualitrol). This information is communicated through a Sensus cellular monitoring system to a central server every half hour. Within the Network Group, information from Sensus, such as secondary loading, is monitored daily. Note that the Sensus system is read only, with the functionality to remotely control equipment being disabled for security purposes.

The network mains are supplied with four sets of cables using stud moles on the protector. Their vault design calls for the use of a separate uni-strut rack with insulated cable clamps that is mounted into the vault wall to support weight of the secondary cables.

Limiters are installed at each secondary junction on the secondary mains on the outgoing secondary cable.

St. Petersburg

At 277/480V spot network locations, Duke Energy Florida has standardized on the CM52, a fully submersible protector with a dead front design (see Figures 10 and 11). Duke Energy Florida’s network protector specification also calls for features such as:

External disconnects, which are used to separate the protector from the secondary collector bus. These disconnects are a safety feature used in a 480V design to mitigate arc flash risks. On this network protector, the NP fuses are internal and link style, as Duke Energy Florida is able to create the visible break between the NP and the secondary bus using the disconnects. Note that the disconnects can only be opened with keys which can only be accessed when the NP handle is in the open position because of an interlock system.
Wall-mounted ARMS (Arc Flash Reduction Maintenance System) modules, which enable a worker entering the vault to change the protection settings in the protector to reduce the fault clearing time and thus the arc energy in the event of a fault.
A submersible Stacklight, which is an annunciator system that indicates network protector status through a series of different colored lights.
Note that Duke Energy Florida has not installed the Sensus remote monitoring system in spot network protector vaults, in St. Petersburg.

Figure 9: CM22, spare unit, in case

Figure 10: CM22, spare unit

Figure 11: Spot network vault with CM52. Note uni-strut cable support racks

}

Figure 12: CM52 – note the external disconnects, stack light, and stud models atop the protector

[1] OMEGANetworkTransformers.pdf

4.13.5 - Duke Energy Ohio

Design

Network Unit Design

People

Network standards are the responsibility of the collaboration of the network engineer, the planning engineer, and the Dana Avenue supervision. This group uses the old Cincinnati Gas and Electric construction manual as a guide. Ultimately Duke Energy will develop a common network standard across the system.

Process

A standard network unit at Duke Energy Ohio includes a submersible network transformer with a one chamber primary switch, dead front terminations on the primary and a network protector mounted on the transformer secondary.

Duke is presently not installing any high side interrupters. Any faults would be seen by the feeder breaker.

Technology

See Figure 1

Figure 1: Network Unit (Photograph from the Dana Avenue Training Facility)

4.13.6 - Georgia Power

Design

Network Unit Design

See Network Design

See Network Transformers Primary Switch

See Network Protector Design

4.13.7 - National Grid

Design

Network Unit Design

People

Network standards, including the standard design for the network unit, are the responsibility of the Distribution Standards department, part of Distribution Engineering Services. Distribution Engineering Services is part of the Engineering organization, which is part of the Asset Management organization at National Grid. Within the Standards group, National Grid has two engineers that focus on underground standards.

National Grid has up to date standards and material specifications for network equipment, including the network transformer primary switch, network transformer and network protector. Network material specifications are updated annually. Standards are updated on a five-year cycle.

Note that because National Grid’s system is comprised of multiple network systems of different designs in both New York and New England, the standards book is organized with a common standards section that represents the whole company, and then individual sections that specify standards appropriate to the individual network systems that comprise their overall infrastructure.

Process

A new standard network unit at National Grid includes a submersible network transformer with a high-voltage disconnecting and grounding switch incorporated into the unit, and a throat mounted network protector. The network transformer is equipped with 600 dead front apparatus bushings for the primary cable termination onto the transformer.

National Grid Albany does not presently install any high side interrupters. Any faults would be seen by the feeder breaker.

National Grid’s standard design for a network unit calls for it to be placed on hot dipped galvanized I-beams within the vault. National Grid uses anodes to provide corrosion protection.

Figure 1: Network Unit - Primary switch compartment

Figure 2: Network unit - protector

Figure 3: Network unit

Technology

Spot network vaults are equipped with a ground fault protection system designed to trip (open) all of the network protectors in the vault in the event of a ground fault. The customer is required to buy, install, and wire the National Grid approved ground fault protection system. Ground fault protection system equipment is installed in the customer’s electric room. However, a current transformer required to monitor neutral currents is installed in National Grid’s transformer vault.

4.13.8 - PG&E

Design

Network Unit Design

People

Network standards, including the standard design for the network unit, are the responsibility of the network asset manager (Manager of Networks). PG&E has assigned one individual as the Asset Manager for network equipment, including all components of the network unit. This asset manager is responsible for network equipment design standards, developing life cycle strategies for network equipment, and making capital and maintenance investment decisions for network equipment.

The asset manager is a four year degreed engineer, with a law degree. He has one four year degreed engineer working for him, but works very closely in a “matrixed” environment with other PG&E organizations key to the network, including Network Planning, Maintenance and Construction (responsible for executing the strategies developed by the Asset Management), and the Reliability organization responsible developing UG Cable strategies. The asset manager collaborates closely with these other field organizations, including monthly visits with field crews.

The asset manager is a true asset owner, held accountable for the performance of the network. As the VP, M&C Electrical Networks, the leader of the field resources focused on the network, described it, “Bob (the asset manager) sets the strategy, M&C executes it”.

The manager of networks has developed and maintains up to date standards that describe the network transformer and primary switch design.

Process

A new standard network unit at PG&E includes a wall mounted solid dielectric vacuum switch that serves as a primary disconnect, a submersible network transformer, dead front terminations on the transformer primary coming from the disconnect switch, and a network protector mounted on the transformer secondary.

Figure 1: Solid Dielectric Switch

Figure 2: Solid Dielectric Switch

Figure 3: Transformer

Figure 4: Transformer Protector

PG&E recently changed their network unit design to physically separate the primary switch from the transformer tank itself. This new design, used for both new installations and transformer replacements, results in smaller equipment footprint within the vault. This makes it easier to work in from a crew perspective, and minimizes the chances of a catastrophic failure in the main transformer tank migrating to a secondary failure in the primary switch.

PG&E plans to change all of their network units to this new design, anticipating that it will take 30 years to complete.

PG&E does not currently install any high side interrupters. Any faults would be seen by the feeder breaker.

Technology

Historically, PG&E had used a two-chamber design for its network primary termination; one for the terminations themselves, and one for the internal ground switch. PG&E has made the decision to move away from this design, instead using a vacuum switch mounted on the wall of the vault as the primary sectionalizing point, and using single tank transformers without a ground switch. The reason for this change is that PG&E has found that catastrophic failures of the transformer can be worsened by secondary explosions of the small oil chambers used for the primary disconnects and ground switch. There can be enough power in an arcing event that the small amount of oil in each of these smaller chambers is atomized causing a potential secondary explosion from the vaporized oil.

In the new design using the wall-mounted vacuum disconnect switch, the concern of a catastrophic failure of the smaller oil chambers in the old design are eliminated.

PG&E is using G&W vacuum switches in their new design. These switches are small enough that day can be dropped into a hole as one unit.

The new transformer consists of a single transformer tank – the primary termination compartment and switch compartment are eliminated. All new PG&E transformers are insulated with high flashpoint natural ester oil. PG&E is also selectively using explosion resistant tanks in high risk areas, and dry-type transformers in high rise buildings.

4.13.9 - Portland General Electric

Design

Network Unit Design

People

At PGE, distribution/network engineering develops and maintains the standards for the network unit equipment, including the primary disconnect and grounding switch, network transformer, and network protector. In addition, Distribution Engineers will establish network protector settings.

Standards are forwarded to the Standards Department for inclusion in company standards documents. Distribution Engineers assume responsibility for network standards as they have the expertise specific to network equipment.

The Distribution Engineers are not based in the Portland Service Center (PSC) or CORE group but have direct responsibility for the network and work closely with the CORE. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees these engineers. The underground Distribution Engineers are qualified electrical engineers.

Process

PGE’s network unit design calls for an integrated three-position disconnect and grounding switch, a submersible network transformer connected in delta-wye that can accept Energy Services Network Association (ESNA) style (typically straight ESNA receptacles) connections, and a transformer-mounted network protector (see Figures 1 through 4).

Figure 1: Network unit, primary switch side

Figure 2: Network unit, protector side

Figure 3: Three-phase network transformer bank

Figure 4: Separately-mounted network protector and primary switch

For the primary switch, PGE prefers a single switch chamber design rather than having a separate termination and switch chamber. The switch chamber includes a site glass to provide a visible opening, and the switch blades are painted white for more visibility.°

Transformer sizes are typically 500 kVA or 750 kVA in the area networks. Transformer sizes on spot networks can be 500, 750, 1000, or 1500 kVA, depending on the spot network load requirements.

All new designs utilize the Eaton CM52 network protectors. PGE has CMD units installed as well. (All installed protectors are one of these two styles).

Figure 5: CM52

Figure 6: CMD

The primary cable system is a combination of lead cables and EPR insulated cables. PGE replaces lead cables with EPR cables as opportunities arise. The secondary system uses both lead and EPR cables. PGE does not have a secondary cable replacement program underway.

PGE has a few locations with non-standard designs. For example, in a vault where spacing may not allow for a three-phase network unit, PGE may build the network unit by banking three single-phase transformers and using a separately mounted primary switch and network protector.

In most of its spot network vaults, PGE has installed a ground fault relay scheme that measures the neutral and ground current through a current transformer (CT). If the current exceeds a threshold, it trips all of the network protectors supplying the spot and locks them into the open position. Once this system activates, the protectors can only close with manual intervention. PGE installed this scheme because the primary protection scheme will not see through to a fault on the downstream side of the protector prior to the collector bus. PGE has experienced incidents in which the customer bus in front of (upstream of) the switchgear faulted, and the ground fault protection scheme worked as intended.

For the protective system to work correctly, PGE requires that the customer-side ground and neutral not be grounded on the customer side, but instead be isolated, and that it be tied in with the ground fault scheme on the vault secondary side.

In addition, most vaults also have a trip scheme tied in with thermal sensors located above the collector bus and transformers. This scheme also trips all of the protectors supplying the spot.

Network Improvements: In the last 10 years, PGE has invested in network units, including:

Adding a remote monitoring system
Replacing (in the last five years) slightly more than one third of the network protectors with a new all “dead-front” design to improve safety by minimizing exposure to arc flash when working with protectors. Its new standard network protector is the Eaton CM52.

Overall, PGE’s network rarely has problems with protectors pumping and cycling, as source network feeders from the same substation bus carefully regulate the voltage. However, in some older, lightly loaded buildings, it has protectors that hang open.

Monitoring Network Protectors: PGE remotely monitors network protector information, including the voltage and all three-phase currents at the network protector, on the transformer, and on the bus side of the protector. Other variables monitored include the power factor, temperature, and whether the position contact breaker within the network protector is open or closed. Readings are available in seconds.

PGE leverages access to this information to support the maintenance and operation of the system. For example, part of the clearance process for a primary feeder involves checking the monitored values to confirm that network protectors have opened. If the monitored information shows that one of the protectors is still closed, a crew will go the vault to troubleshoot.

Network Protector Quality Assurance: Crews bring new network protectors to the warehouse for testing according to some initial settings before acceptance into inventory. This is an initial quality assurance check to ensure no issues when the unit is installed. In addition, the Special Tester checks the equipment just before it enters service.

Technology

All PGE Network Protectors are either CMD or CM52 units from Eaton. Eaton’s CM52 Network Protectors carry a UL certification and BIL rating. They can cope with ratings between 800 and 4500 amps, and between 216 and 600 volts at 60 Hz. Eaton systems have high interrupting and fault close ratings, and the components are modular and standard across the different ratings. By using the same units, PGE reduces the need for a large part inventory and additional training for technicians and crews.

PGE uses CM52 network protectors in 125/216 and 277/480 volt Y connected secondary network systems. At PGE, the 125/216 volt systems are the area networks, while the 277/480 volt systems are the spot network locations. The systems include an air circuit breaker with an operation mechanism, network relays, and control equipment. The units are available as submersible variants and can be used standalone or mounted on the transformer throat. Submersible units are made of welded steel, which is bonderized and painted. The network protectors include an internal window that allows crews to see the internal hardware. The door can be hinged on either side [1].

CM52 units include externally-mounted, silver-sand fuses to interrupt fault currents if the networker fails to trip. Additional internal cooper-link or lead alloy fuses can be installed inside the enclosure.

On the CM52 network protectors used by PGE, fuses are mounted externally and do not include a “visual open.”

PGE is considering the use of the CM52 Arc Reduction Module System (ARMS) in future spot network locations. (Historically PGE has not used the system in part because much of the company’s in-service plant was the older CMD unit, which cannot fit with ARMS).

PGE does not use remote racking as standard because this would require complex retrofitting and modification.

Network Protector Remote Monitoring: PGE uses Eaton MPCV relays within its network protectors. The network fits with the Mint II system and has a PowerNet server platform interface. The optic fiber to the Mint II monitors is set in an H&L Fiber Loop configuration. The H&L Instruments system converts the fiber communications to the protocol used on the NPs, and vice versa.

At present, PGE only uses the system for monitoring, not for control. For example, when clearing a feeder, crews open the feeder breaker and double check through the remote monitoring that the protectors are open and that there is back-feed at the station.

PGE is assessing the Eaton VaultGard monitoring system to harden the system, using the looped fiber optic communications already installed throughout the downtown area. The reason for looking at VaultGard is that it is a web-based protocol with integrated software that allows a higher degree of control than PGE’s existing system.

Transformers: The typical transformer sizes on the grid network are 500 kVA or 750 KVA. For spot networks, transformers can be 500, 750, 1000, or 1500 kVA.

SF6 Switches: PGE has some older SF6 switches throughout the system that are being replaced with S&C Vista SF6 switches. Most are located in PGE’s radial urban underground infrastructure, but some may be used as primary switches for the network unit. PGE is verifying the integrity of the permanent pressure gauge on the switch, which is filled with SF6 and needs 8 psi (55 kPa) of pressure. Crews rely on the permanent pressure gauge if there is a tag on the switch and if it has been checked. The gauges are checked every year. The old switches do not always read the same as the calibrated gauge so they are being replaced.

Figure 7: SF6 Primary Switch

Instructions for the Eaton Type CM52 Network Protectors 800 to 4500 Amperes. Eaton, Moon Township, PA: 2010. http://www.eaton.com/ecm/groups/public/@pub/@electrical/documents/content/ib52-01-te.pdf (accessed November 28, 2017).

4.13.10 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.6 - Network Unit Design

4.14 - New Service Design

4.14.1 - Ameren Missouri

Design

New Service Design

People

Design of the urban underground infrastructure supplying St. Louis, including new service design, is the responsibility of the engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The Underground Division, led by a manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including network and non network vaults and manholes, size equipment, perform load flow analyses, and prepare line drawings that describe the designs. All engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

The Energy Services Consultants (Estimators) take the one line designs developed by the engineers and complete the design package, including all the physical elements of the design. Estimators have a combination of years of experience and formal education, including two-year and four-year degrees, and are part of the union, IBEW.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis. Engineers who are assigned to this team will also participate in the design of spot network installations and indoor rooms.

Ameren Missouri has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both online and printed book format.

Process

Typically, small to medium loads 500kVA and less requiring 120/208V service are connected to the network grid. Customers with larger loads, or who request 480V service are normally served from either a padmounted transformer or an indoor substation. Padmounted services are usually not practical within St. Louis because of the downtown congestion.

The most common design for larger loads in downtown St. Louis is the indoor substation (also called “indoor room”). Most new services to larger downtown loads in St. Louis are served with a dual, primary metered feeder scheme: either two preferred feeders, or one preferred feeder and one reserve feeder. There are existing spot network services within St. Louis, but new services are not served via a spot network.

Larger customers often receive primary metered service, with Ameren Missouri providing two primary supplies to the customer. These primary supplies feed into switches, either fuses or breakers as chosen by the customer, and can be manually or automatically (auto transfer) operated. After the breakers, lines feed into the primary metering gear, and then on to the customer switchgear or transformation. Note that in this arrangement, all equipment except cable and meters are owned by the customer, including the primary switches that precede the primary metering point.

For a secondary metered customer, Ameren Missouri provides the switches and transformation that precede the metering point. In this design, Ameren Missouri may provide either a preferred and reserve feeder, or a two preferred feeder design.

In ascertaining expected customer load, Ameren Missouri will look at similar buildings to estimate demand using square footage and expected load density by customer type. They will also perform a load flow analysis to understand the impact on the system of connecting the new load. They will run both the normal and n -1 cases.

4.14.2 - CEI - The Illuminating Company

Design

New Service Design

People

The design of the network ducted manhole system is performed by the CEI Underground / LCI group (Design Group), part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

The group’s responsibilities include network system and non – network system designs and the development of standards for the ducted manhole system including vault and manhole design standards and customer design standards. The group prepares construction drawings for the conduit system, vaults and manholes.

Process

When CEI Underground/LCI group receives an application for a new service in an area served by the network, the engineer may involve the Planning department engineers to see if the new load addition can carry the load on the network from a particular transformer or mole. Typically a new load of less than 400kW will be connected to the network. Larger loads are served from either the 4kV or 11kV radial systems.

If the project involves just a tap, the design will be performed by the engineers within the Design Group who focus on serving customers (the LCI).

If the project involves a cable line extension, both a cable engineer, and an LCI engineer are usually involved in the design. The cable engineer would design the conduit system up to the point of the customer interface, and the LCI engineer would develop the service interface, including the transformation and switchgear.

The Underground Engineering / LCI group will perform the civil design as well.

Note that the customers served by the network do not pay a “network” rate for their electric service – their rates are the same as similar customers served by non-network infrastructure.

Technology

Engineers will prepare the required construction drawings that show the duct configurations, show the manhole design, reference standards pages, etc. Wherever possible, they will use the GIS system as a foundation for a drawing. They may show a portion of an existing vault drawing if the project involves a revision. In general, the prints they produce are very clear and well received by the Underground Group.

FirstEnergy’s CREWS system is used to develop a bill of materials and costs estimate.

4.14.3 - CenterPoint Energy

Design

New Service Design

(Network New Service)

People

New Services in the network are designed by the Vaults group of the Engineering Department within the Major Underground Group.

The Vaults group, led by a Lead Engineering Specialist, designs infrastructure the electrical infrastructure within vaults including network services. The group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources.

If, in order to serve the customer, primary facilities must be extended, then the Feeders subgroup of the engineering department would be involved in the project to perform the design of the feeder extension.

Process

Customers served by the network do not pay a “network” rate for their electric service – their rates are the same as similar customers served by non-network infrastructure.

4.14.4 - Con Edison - Consolidated Edison

Design

New Service Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Engineering and Planning - Responsibilities include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

The Energy Service Organization at Con Edison has various subsections that are involved in the process of responding to customer requests for service: the Service Assessment team, Engineering, Layout, and Project Management.

Service Assessment Team

The Service Assessment Team interfaces with the customer or contractor and prepares the load letter, which details the customer work request and scope of the work. They ensure that the load letter includes critical data such as type of use, commercial or residential, information on the number of units, etc. They create a project within a computer system (Commercial Operations Reporting System — CORS) used to track each project. The request then flows to Engineering.

Engineering

Within Engineering, a copy of the load letter and, sometimes, a plot plan is assigned to a senior design technician, who develops an estimated demand. These technicians apply different demand factors depending on the type of space to be served. They look at the location of the new building, look at the project plan, and determine how to provide the service. They may have to run a load flow study to determine how the grid will be affected by adding this new service. Engineering also develops information to be provided to the customer such as short-circuit current, in-rush service, etc.

The engineer looks at the project plan, and then determines whether or not a load flow must be done. Adding new customers to the 208-V secondary grid usually requires a load flow analysis. If the engineer decides that the load addition cannot be met by simply connecting the load to the grid, he or she develops a design that adds transformation to the network. Historically, load additions of 500 MW or greater require the addition of new transformers, though the utility analyzes each case to determine the best way to serve the load.

One of the challenges that Con Edison faces is dealing with “creepage.” This is a term used to describe the load creeping upwards over time, even though Con Edison may be unaware of it. For example, this phenomenon includes people adding window air conditioning, plasma TVs, and other devices that cause overall loading to increase over time with an existing customer base.

Con Edison currently doesn’t tie its meters to individual service points in their modeling system. The utility has difficulty understanding the load profiles of metered load in aggregate (an apartment building, for example). Con Edison is looking forward to the benefits of a future Advanced Metering Infrastructure (AMI) system, which will provide the ability to model aggregated loads and consider coincident demand.

Layout

After the engineering is performed, the project goes to the Layout group. The Layout group is responsible for the electrical layout and the “build,” which is the civil layout.

The Engineering tech who prepares the layout looks on their plate maps (electronic maps) to understand what facilities are already in place. The tech also looks at the sketch of the building point of entry. Sometimes the tech field-checks jobs to determine what lanes to use for conduits, etc. Layouts are performed on a micro-station using a tool called Smart Layout.

The Layout group develops the bill of material, establishes the accounting charges, and develops an hour’s estimate. At Con Edison, projects costing over $100,000 require a unique (project-specific) approval.

Con Edison uses a software system called DOCS (Division Operations Reporting System) to aid them in performing new service designs. DOCS is a work management system that the field and engineering use to define the elements of the job, resources, and the costs. This system is based on assembly units. They call for a device, and the material and labor associated with that device rolls up beneath it.

Con Edison develops a design that meets the customer’s needs. If customers desire additional capacity beyond their needs, the customers are required to pay the difference in cost. For example: A customer requests service for 4 MW of load. Let’s say that after Con Edison analyzes their loading, factors in diversity, etc., Con Edison determines that, in fact, the customer only requires 2 MW of capacity to meet their load demands. Con Edison would develop a design that meets the 2 MW need. Should the customer want service for 4 MW, the customer would be required to pay Con Edison for the incremental cost to service 4 MW. This is done either through a front-end payment, (which is reimbursed if the customer actually meets 4 MW), or through a minimum demand charge.

Project Management

Energy Services has two project manager positions — the CSR Project Manager, who manages smaller projects less than 1000 kW, and the CPM Project Manager, who manages larger projects, 1000 kW and greater.

The CSR and CPM Project Managers receive the layout and issue work orders to construction management (for contracted work) and electric operations to execute the project. They ensure that the customer gets service on time. They coordinate dates, check the customer’s work to make sure it makes sense, ensure that the termination points are adequate, obtain city approvals, etc.

4.14.5 - Duke Energy Florida

Design

New Service Design

People

Design of new services in the urban underground centers in Clearwater and St. Petersburg is performed by the Distribution Design Engineering group, which works out of offices in both cities. The groups are responsible for designing new and refurbished network designs, as well as underground radial and looped distribution designs. The Distribution Design Engineering group is led by a Manager, Distribution Design Engineering, and is organizationally part of a Distribution Design Engineering Group responsible for Duke Energy Florida’s Coastal region, led by a Director.

The Design Engineering group is comprised of two sub - groups: an Engineering group, comprised of degreed engineers, and a Technologists group, comprised of non-degreed Network Technologists. Work within the Design Engineering group, both in Clearwater and St. Petersburg, is assigned geographically, such that a designer (either an Engineer or a Technologist) is responsible for both network and non-network designs within an assigned geographical area. Some designers focus on commercial customers, while others focus on residential customers. For example, the St. Petersburg design group has two engineers that focus on commercial designs – both engineers have four-year engineering degrees.

The criteria for choosing non-degreed Technologists may include years of experience, and for new job postings, at least a two-year degree in electrical technology. The existing group has individuals with varied experience, including distribution operations, control, and transmission.

The Design group is experiencing a large turnover in its Engineering staff, as a number of employees with many years of experience are retiring. A challenge for the group as positions turnover will be acquiring new resources with design experience.

Network design standards are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D .)

Process

Both downtown St. Petersburg and Clearwater are experiencing moderate growth. Most new work is designed with a non-network design. More specifically, most new larger buildings are designed with a primary and reserve looped feeder scheme, with an automated transfer switch (ATS), and fed through Duke Energy Florida’s ducted manhole system.

Design engineers typically perform preliminary research on circuit loads before design, but also work closely with Planners to make final design decisions with respect to anticipated circuit capacity. The Planners decide the scope of work from a macro level, such as determining, for example, where a feeder should be split to supply new load. A design process example cited by Duke Energy Florida personnel was the recent addition of two high-rise buildings in St. Petersburg. The existing network feeders there were projected to be overloaded with the addition of the new building load. The Design Engineers consulted with the Planning team (see Planning in this document), who performed modeling studies to determine whether the Designers could extend an existing feeder or needed to install a new feeder to the location to meet anticipated capacity requirements.

The Design Engineers perform the detailed design including selection of materials, and the project layout, including the cable route. The Design Engineer will inspect current GIS maps and perform site visits to manholes to inspect condition and duct line configuration to determine whether there is ample room to pull new cable.

One of the first steps in the design process is a thorough field investigation to find out what is currently in the manholes and duct lines, and to make certain it is mapped correctly in the current GIS. Field inspections are performed by Network Specialists under the supervision of a Network Design Engineer.

Any updates required to the GIS maps, as determined by inspection, are red-lined and submitted to the GIS technicians for input into the electronic system. The Network Designers have found that these field inspections and on-site red-line updates of the GIS are essential since the GIS mapping of the urban underground system and, in particular, the network, is out of date. The inspections serve two purposes: first they are necessary to understand field conditions and complete new service designs, and secondly, they serve to update the GIS, which is foundational to the company’s Outage Management System (OMS).

Note that Duke Energy Florida’s GIS system does not provide a true representation of the network system, detailing all primary and secondary feeders. Accurate, detailed maps of this infrastructure are maintained within the Network Group, and are separate from the company GIS (see Mapping). Hand-drawn manhole drawings, which are kept up to date by the Network Group and are currently the most accurate record of the manhole configuration, are in the process of being entered into the GIS. From within GIS, PDF versions of the manhole drawings can be accessed.

After inspection and GIS updates, the Design engineers complete design work using an online design system (a WMIS system, by Logica) that provides the ability so select compatible units (CU) for network infrastructure that includes estimated costs of labor and associated materials. This system produced a cost estimate and bill of materials. Design drawings are prepared online using the GIS system as a base, using a “red line” file. Final input acceptance of the as built “red-line” drawing is incorporated into the permanent GIS record by the GIS team.

Vault Design

Network vault designs, including vault dimensions and characteristics, and placement of required switchgear, network protectors and transformers, etc., are created one at a time, according to the location and design requirements at the site. Since there has been very low demand for new vaults, this custom design approach to vault design works effectively. All underground vault transformers are specified as submersible units, yet maintained as “dry,” with sump pumps installed in all vaults. Vault design standards are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D ).

Final Designs: Peer Review

Final designs are submitted for a peer review, normally performed by senior design engineers, and – for network projects - network specialists. Circuits, project layout, CUs selected, etc. are checked against Duke Energy Florida standards by the peer reviewers and if any changes are required, they are sent back to the Designers. Peer reviewers are especially concerned with the “ constructability ” of any designs in a given area. The peer-review process includes online and informal meetings between the peer reviewers and the designers – this provides checks and balances throughout the design process. It is notable that the implementation of the peer review process was a direct result of feedback from the field.

When the design passes peer-review, and is below a certain dollar amount ($50,000), it can proceed directly to construction. If it is a higher cost project (above $50,000), it must go to management for review and sign-off. Anything above $100,000 must be reviewed by a Director. In most network designs, a customer charge (CIAC- contribution in aid of construction) is levied before work begins. Duke Energy Florida calculates the appropriate CIAC on a case by case basis, by determining the difference in cost between the estimated cost of its normal and customary radial design and the estimated cost of the proposed underground work. A Work Order is created once the Design passes peer review and customer charges are received.

Material and Component Ordering

For the purposes of performing the design, Duke Energy Florida has established compatible units (CUs) for certain network components that include material and labor estimates. Some of the high cost items with long lead times, however, are not included as CUs in the design system (Real-Time Adaptive Resource Management or RTArm, by Logica), such as network transformers. These items must be ordered “outside” the existing system. At the time of the immersion, approximately 80% of the network CUs were available, with 20% of network components having to be special ordered.

Once the Design has been final approved, it goes to a Construction/Maintenance Specialist to review the Work Request and make certain that the proper material and component CUs have been requested. The Construction/Maintenance Specialist must double check and order the CUs indicated in the final design/work order. The Construction/Maintenance specialist may add CU’s to better reflect the labor and material requirements of the project.

One challenge for Duke Energy in utilizing CUs for network projects is the variability in requirements for network labor, making it difficult to assign a particular labor estimate to a work type. In order to better estimate a network project, labor CUs may need to be entered into the system to cover activities such as the need to pump water out of flooded manholes.

Manholes, Network Feeders

In manholes, primary feeders are usually mounted on cable racks in the lower part of the manhole, while secondary cabling is mounted above, higher in the manhole. Many existing manholes contain three primary feeders in one manhole. The designers realize the placing of multiple feeders in one manhole increases the exposure and consequences of an event occurring in that manhole. Thus, for newer designs, designers strive to minimize the number of feeders in any one manhole hole. In underground radial designs, cables are routed to avoid a single-point-of failure by using looped cables from pull boxes.

All network feeders in downtown Clearwater (supplying a true 125/216V network) have their own network cable manholes/duct lines (not shared with non-network circuits).

Technology

Duke Energy Florida uses GIS system for mapping of the entire electric grid — radial as well as network. Note that Duke Energy Florida ’ s GIS system does not provide a true representation of the network secondary. Users of the GIS can access PDF drawings of manhole prints that detail manhole and vault infrastructure.

Duke Energy Florida is in the process of updating its GIS system records to fully represent network infrastructure. Duke Energy Florida is also migrating to a new GIS system, GE Smallworld.

Duke Energy Florida uses a Work Management Information System (WMIS), by Logica (now part of CGI). RTArm, by Logica, is used for material and component tracking and ordering, as well as assigning job hours for projects.

4.14.6 - Duke Energy Ohio

Design

New Service Design

(Engineering and Urban Development)

People

Network design is performed by two Designers who are part of the Distribution Design department. This department performs all distribution design work for Duke’s Ohio and Kentucky utilities.

The two designers, called Customer Project Coordinators (CPCs), who focus on the Cincinnati network, work closely with the Network Project Engineer, also part of the Distribution Design organization. These CPCs design customer driven changes and additions to the network system including the design of secondary buss work, transformer sizing, and network protector sizing. They work closely with the network Project Engineer to design system reinforcement projects.

In addition to working closely with the network Project Engineer, these CPCs work closely with the Planning Engineer focused on the network. For example, they will check with the Planning Engineer to assure the network can accommodate a load increase.

The CPC’s also work closely with construction crews. These crews need to be present when the CPC’s gain access to faults. Consequently, there is communication between the CPC’s and field crews on a daily basis. The CPC’s have a good working relationship with the field.

The two CPC’s also act as “key contacts” for customers other than major customers. Major customers have a separate key contact representative at Duke although many of the questions that arise from these major customers are ultimately answered by the two CPC’s.

The CPC’s are two-year degreed engineers.

Process

Duke Energy Ohio has a defined geographic area served by the secondary network system. Virtually all the load within that geographic boundary is served by the secondary network.

Duke Energy Ohio does not have a network service rate. Customers served by secondary network pay the same rates as customers served off of the non-network system. An exception is that Duke Energy Ohio has a three phase residential rate available within their network.

Much of the engineering work in the network is system reinforcement work driven identified by Duke. When new customer additions do arise within the boundaries of Duke Energy Ohio’s defined network, Duke Energy Ohio will decide whether or not to put the new load on the network system. While most load within the network boundary is served by the secondary network, Duke has made decisions not to put certain new load on the network, even when the load edition occurs within the network geography. An example is the “Banks" area of Cincinnati. This area is being redeveloped, with the majority of the load to be residential. Consequently, Duke Energy Ohio elected to serve this redeveloped area with a URD radial fed system, rather than add the load to the network secondary system.

A Duke engineer noted that having a firm geographic boundary for their network, makes it easier to respond to or reject special requests. For example, a building owner within the network boundary may not want to provide a vault, and request a radial type service. Duke can resist or reject this special arrangement, as they would not allow a radial service fed off of a network feeder.

Customer costs for connecting to the network system depend on the size of the load edition. Duke Energy Ohio performs a revenue test, comparing anticipated revenue with the costs. If the revenue of the new load edition is not enough to recover the costs, the customer will have to make a contribution. Duke will either collect this contribution upfront, or prepare an agreement with the customer requiring payment due after construction is completed.

Duke Energy Ohio designers (CPCs) will obtain load information from the customers. Using an Excel program, they will adjust the customer provided loads, considering diversity, to develop an estimated demand. From this, Duke will determine how many transformers/network protectors will be required to serve the new load. The CPC’s will provide the customer with a document that describes Duke’s requirements in terms of vault design. (See Design - Vault - Manhole Design ) The CPC’s will prepare the required engineering drawings, and bills of material.

Duke Energy Ohio’s CPC’s work closely with the customer to design building vaults. Much of the ultimate design tends to be dictated by the customer. Duke is considering developing a more standard vault design that they can provide to customers, although the knowledge it will be difficult to enforce customer compliance with the standard. (For example, a customer may not be willing to, or be able to provide the physical space required by the Duke standard)

Technology

The network distribution designers (CPCs) prepare an AutoCAD drawing. To develop the bill of material, they use a system called JET. Within this system they can pull the required material from an overall list of materials. By doing so, the JET system generates a cost estimate.

At the time of the EPRI immersion, Duke Energy Ohio was in the process of installing a system called Expert Designer (Bentley) , that will be used in the future for network design. Within Expert Designer, CPCs will use MicroStation to design and build the cost estimate for the job. The system will be tied to Duke’s EMACs system, which is used to order materials, and set up the billing for the customer. Duke Energy Ohio does have the ability to import customer drawing into their design system. Note that Duke Energy Ohio does not yet have connectivity between their GIS data for the network and their design systems.

4.14.7 - Energex

Design

New Service Design

People

The Systems Engineering group, led by a group manager, and part of the Asset Management organization is responsible for establishing design standards for the distribution network. Energex also has a Design organization within its Service Delivery organization, also led by a group manager, and responsible for performing designs of specific projects, including new service projects.

The Design group is comprised of four-year degreed engineers, with some assigned a focus on the distribution system. These designers are geographically situated at 15 different “hub” locations throughout its territory. They are distributed geographically to be close to the field, but the assignment of work is not strictly geographic, with work often assigned based on work peaks and troughs.

Design classification includes electricity supply design advisors who are the people who perform the job layouts. These advisors are not degreed engineers, but they are able to apply the standards and lay out the projects using the Energex design tools, such as AutoCAD.

Process

For a new project in the CBD, the Planning group would likely have the first contact. The project would be initiated by a customer request, such as a new high-rise in the CBD. The planning engineer would be responsible for understanding the anticipated demand (load) of the new customer, comparing that to the available capacity, and whether any reconfiguration or upgrade of the system is required.

As part of the analysis, the planning engineer would also look into the customer’s requirements, including any payments required by the customer. Customers must supply a room (vault) for the medium-voltage substation that meets Energex’s requirements, including fire ratings, ventilation, and alarms. Note that while the costs of dedicated transformers and secondary can be passed on to the customer, the costs of the mesh 11kV system, including any required upgrades, are borne by the entire customer base as defined by regulatory agreements.

The output of the planner’s work is a project scope document that includes a one-line diagram that outlines how the customer is to be served (i.e., number of transformers, switches, and where to tap into the existing 11kV mesh), and a letter of offer and contract with the customer.

The project flows to a design project coordinator, who leads the project, and whose role is to assure that nothing slips through the cracks. This person assigns and coordinates the various resources that are brought to bear on completing the project.

A project designer is responsible for the design of the project. The designer develops a specific project design, as well as costs estimates for the project. Design considerations include whether to utilize relay controlled circuit breakers as part of the meshed design, or whether the customer load is small enough to supply with a “T” off the main circuit to a ring main unit. Note that the CBD meshed 11 kV design using relay controlled CBs can quickly escalate costs. The designer lays out the 11 kV cabling design, as well as the low-voltage distribution board (secondary bus from which the LV system emanates). SCADA engineers may be involved in the project if there be a need to pull fiber into the new location. Engineers are assigned to address issues such as the design of the protective relays, pilot cables, control systems, grounding (earthing), etc.

Technology

AutoCAD, load flow analysis software, and project management software are used in the initial planning and implementation of new service.

4.14.8 - ESB Networks

Design

New Service Design

( LV Designs)

People

Organizationally, the design of both MV and LV infrastructure is performed by designers located within the Network Investment Management groups for larger designs, and within the ESB Networks Regions for the smaller designs. The Network Investment Management groups (North and South) are part of the Asset Investment group, within Asset Management. The Regions are organizationally part of the Operations Management Group, also part of the Asset Management organization.

For most designs, the design is performed by an Engineering Officer – the designer position at ESB Networks.

The development and maintenance of guidelines for performing MV and LV network design are the responsibility of the Specification Management group, part of the Asset Investment group, also part of the Asset Management organization at ESB Networks.

The Specifications Management group has developed thorough guidelines for the design of LV and MV networks. This guideline includes specific direction for optimizing designs.

Note that in addition to the Operations Management and Asset Investment groups, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Assets & Procurement, and Finance & Regulation. These groups work closely together to manage the asset infrastructure at ESB Networks.

Process

ESB Networks serves 90,000 rural customers with LV service by mini-pillar overhead (above ground) joint boxes on a pedestal. (Note, note that in Dublin, submersible junction boxes are utilized). Service to the mini-pillars is delivered through a low voltage network supplied from MV 200/400/630-kVA substations that include a ring main unit, LV panel, and transformer. These “all-in-one” units are only 11 cubic meters in volume, and transformers can be replaced without replacing the LV panel or ring main unit. ESB Networks practice is that these MV units are supplied by a main feeder at MV, 10kV 20kV.

LV cables are taken to the customer border, where builders are required to connect the customer. ESB Networks provides an Electrical Supply book for builder guidance. Note that most customers are served by the LV infrastructure (see Figure 1 through 3), and builders or contractors are required to connect customers to service within ESB Networks-specified guidelines. ESB Networks service is taken from the customer boarder and clipped or “cleated” to the house by the builder. ESB Networks provides a MV (primary) service to larger customers, usually with loads in excess of 500 kVA.

Figure 1: Connection of standard LV house service with ESB Networks specifications

Figure 2: Mini pillar on site

Figure 3: Mini pillar, internal view

4.14.9 - HECO - The Hawaiian Electric Company

Design

New Service Design

People

New services are designed by the Customer Installations Department (CID). The CID is comprised of three divisions – Administration, Meter, and Planning and Design.

The Administration division, comprised of ten resources performs administrative tasks on behalf of the department. The Meter division, comprised of fifteen resources, installs meters and performs meter testing.

The Planning and Design division is comprised of 25 planning and design resources who design all new service projects from single family homes to large skyscrapers. These resources include Junior Customer Planners, the entry level position in the division, Customer Planners, and Design Planners, all represented by a collective bargaining agreement (Union positions). The Division also employs a full time drafter position, and Electrical Facility Technicians (EFT’s) who assist customers with obtaining permits, identifying existing as – built plans, and perform other research and administration associated with jobs involving excavations. The division also employs CID Engineers (non bargaining) who perform designs for larger (>500kW) service requests.

Process

The new service process starts with a potential customer completing a service request. If the project is small, the customer himself may submit the service request. For larger projects, it is typically an electric service contractor who submits the request. The request is made up of the customer’s application, plans, elevations, and a projected load sheet. The request includes information such as the date service is required, the service voltage, and, through the load sheet, an estimated load / demand. Note: Much of the application information / and load sheet information is available to customers at the HECO website, HECO.com.

New service requests are received by a central administration group (not part of CID) where the application is entered into HECO’s CIS system and assigned a tracking number. Projects are assigned to different individuals within CID depending on their size and location. For example, projects with anticipated loads of greater than 500kW are typically assigned to a CID engineer. Subdivision requests are forwarded to the department supervisor^[1] .

All service requests with loads of greater than 100kW are reviewed by a CID engineer in order to make the load projections more realistic. HECO has found that anticipated load projections are often overstated by applicants.

The CID group will perform field investigations and prepare the layout to service the new load. They may submit requests to the Distribution Planning Division to assure that there is available capacity on a given circuit to serve a new load.

The CID group would also design new service connections in the network, where the service involves tapping of existing network facilities. If a new vault location is required for a network service (quite rare), the T&D Engineering Division would perform the design. Note: HECO uses cable limiters on service taps from the street grid. Cable limiters are only used on the customer end of the service if the service terminates in a bus room; otherwise, the service would feed into the customer breaker.

HECO’s line extension policy requires the customer to bear any costs of the extension that exceed an anticipated 60 months of revenue. Underground line extension costs include a calculation of the cost differential between underground and overhead – this differential is included in the cost estimate that is compared to the anticipated revenue to determine the customer contribution. The customer also bears the cost of providing the concrete encased conduit / duct back for the primary, and conduit on for the services, all the way to the meter entrance.

Technology

The CID Planning and Design division will prepare the required construction drawings. Drawings are either prepared by hand or laid out in Microstation. HECO’s GIS system may be used to find a point of connection, but is not being used as a base for construction drawings.

The Bill of Materials, and cost estimates are developed by using HECO’s Standard Material Unit (SMU) system, a legacy system.

^[1] For subdivision requests, the developer will often hire an electrical consultant who lays out the infrastructure and duct bank configuration and provides a design to HECO. There are several established contractors who know the HECO system and HECO policies well.

4.14.10 - National Grid

Design

New Service Design

People

There are two designers who perform network designs for the National Grid Albany network.

One designer (a Design Investigator) focuses on designing smaller new services connections to the network, 800 amps and below. This individual has a two year degree, though the degree is not mandatory for the position. This designer has field experience as both a cable splicer and maintenance mechanic. This designer also performs some non- network UG and overhead service designs.

The other designer (a Designer C) performs all larger and more complicated network designs, including network reinforcements, large new services projects greater than 800 A, and vault designs. This individual has a two-year degree, a requirement for the position. This designer also performs non – network UG designs.

Organizationally, both designers are part of the Distribution Design organization, led by a manager, and part of the Engineering organization at National Grid. This organization is structured centrally, with resources assigned to and in some cases physically located at the regional locations. The designers who support the Albany network are both physically located at the NYE building in Albany.

Both designers are represented by a collective bargaining agreement. The Design Investigator and Designer classifications are two different classifications with different progressions.

Both designers work very closely with the field engineer, part of Distribution Planning, assigned to the underground department to support the Albany network.

National Grid will determine the appropriate service type for a customer based on their load, criticality and location. There have been times where they have asked a customer to accept network service (a sports arena, for example). National Grid Albany does not use a separate rate for network customers.

Process

The National Grid Albany network secondary system is confined to a certain geographic boundary within Albany. Typically, small to medium loads requiring 120/208V service will be connected to the network grid. Customers with loads > 800 kVA will typically receive a 277/480 V spot network service. National Grid designs spot networks to n-1 for peak load.

Most National Grid spot network vaults are located underground, rather than in building vaults. Some spot networks are at grade level or on building roofs. The buildings will supply the vault, providing space, lighting and ventilation.

In the National Grid vault design, the collector bus is supplied by the customer and located in a separate vault, with the customer’s equipment. National Grid runs secondary cables from the spot network units, through conduits and makes the secondary connections on the customer collector bus. National Grid uses cable limiters on secondary cables feeding from the network protector to the customer.

All other non - network loads are served by radial distribution systems. These distribution systems are primarily radial underground distribution with a preferred feeder / alternate feeder design, fed through a manhole / conduit system.

Much of the existing primary and secondary system is built with PILC cables. National Grid’s current standard calls for EPR insulated primary cables. The secondary cable standard calls for EPR insulated cables with a Hypalon (low smoke) jacket.

4.14.11 - PG&E

Design

New Service Design

People

A new customer who wishes to connect to the PG&E network system applies for service to the Service Planning Department. A Service Planning representative is assigned to interface between the customer and the planning engineers within the Planning and Reliability Department, who are responsible for design. The service planning representative acts as a key account manager. The planning engineers also work closely with project estimators who develop cost estimates and determine whether the design laid out by the planning engineer is workable in the field.

Process

The Service Planning Department gathers loading information. They are familiar with the electrical system and can determine whether the customer will be best served by the network or radial system. Planning engineers also perform a load flow analysis to understand the impact on the system of the additional load under both the normal and n-1 cases.

Technology

Typically small to medium loads, 500VA and less requiring 120/208V service will be connected to the network grid. Loads from 500VA to 1MW will get a 120/208V spot. Loads greater than 1MW typically receive a 277/480 V spot network service.

4.14.12 - SCL - Seattle City Light

Design

New Service Design

People

Organization

Network Design at SCL, including the design of new services, is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A . The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Documentation

SCL utilizes a Network Construction Guideline that includes sections that inform design and

construction. The guideline contains sections for:

Safety
General items, such as voltage and current tables for cables
Drawing standards
Cable installation and testing
Services
Cables, bus bars and secondary taps
Primary splices and terminations
Transformer installation and vault preparation
Duct and pole risers
Vaults and handholes
Streetlights
Meters

SCL’s guideline can be accessed at seattle.gov

Process

SCL serves customers from its existing 208 and 480 V secondary networks. Spot network services to new large load buildings are normally supplied at 480 V. Note that about 80% of new load is served as a spot network, rather than tapping the existing network secondary.

SCL performs a feeder load analysis as part of their Feeder Assignment process in response to an anticipated new load. The term “Feeder Assignment” means determining which feeder or feeders will serve a new network load. A Network Services engineer requests the feeder assignment based on a new or supplemental load need.

The System Engineer within the Network Design department performs an analysis to determine the best scenario for serving the new load. This analysis includes ensuring that the network design criteria are met, and that any feeder imbalance is restricted to less than 20%. See Attachment B , for a flow diagram of the Feeder Assignment Process.

4.15 - Non-Network Design

4.15.1 - Ameren Missouri

Design

Non-Network Design

People

Design of non network infrastructure for supplying downtown St. Louis customers, such as “indoor room” designs, is the responsibility of the engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The Underground Division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group, led by a supervising engineer, is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including non-network designs, performing equipment sizing, load flow analyses, and preparing line drawings that describe the designs. All of the engineering positions are four year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

The Energy Services Consultants (Estimators) take the one line designs developed by the engineers and complete the design package, including all the physical elements of the design. Estimators have a combination of years of experience and formal education, including two-year and four-year degrees, and are part of the union, IBEW.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis. Engineers who are assigned to this team will also participate in the design of spot network installations, and indoor rooms.

Process

Customers with larger loads, or who request 480V service are normally served from either a padmounted transformer or an indoor substation. Padmounted services are usually not practical within St. Louis because of downtown congestion. The most common design for larger loads in downtown St. Louis is the indoor substation (also called “indoor room”).

Most new services to larger downtown loads in St. Louis are served with a dual primary feeder scheme: either two preferred feeders, or one preferred feeder and one reserve feeder. There are existing spot network services within St. Louis, but new services are rarely served via a spot network. (Ameren Missouri does not provide new spot network services, but may rarely serve a customer via and existing spot.)

Larger customers often receive primary service, with Ameren Missouri providing two primary supplies to the customer. These primary supplies feed into switches, either fuses or breakers as chosen by the customer, and can be manually or automatically (auto transfer) operated. After the breakers, lines feed into the primary metering gear, and then on to the customer switchgear or transformation. Note that in this arrangement, all equipment except cable and meters are owned by the customer, including the primary switches that precede the primary metering point.

Figure 1: Preferred / Reserve feeder Scheme Primary Switchgear

Figure 2: Preferred / Preferred Scheme Primary Switchgear

Figure 3: Preferred / Preferred Scheme Primary Switchgear

Figure 4: Preferred / Preferred Scheme Transformation

For a secondary metered service from an indoor sub, Ameren Missouri would provide the switches and transformation that precede the metering point. In this design, Ameren Missouri may provide either a preferred and reserve feeder, or a two preferred feeder design.

The preferred/ reserve feeder design is a single transformer design. In the preferred/reserve feeder design, the loss of the preferred feeder causes the customer’s load to be transferred (either manually or automatically) to the reserve feeder.

Figure 5: Preferred / Reserve feeder Scheme Transformer

In the preferred / preferred feeder design, the customer would continue to be supplied by the remaining feeder after the loss of one feeder.

Ameren Missouri plans to N -1 in St. Louis. Every feeder has both normal customer commitments and reserve commitments. Reserve feeders are planned in such a way that they will anticipate a certain amount of reserve commitment. When engineers perform contingency analysis, they model the system and run studies to ascertain if they can pick up load within the emergency rating of the reserve feeders. When they model the system with one feeder out, the models enable them to simulate customer load being connected to reserve features.

The customer is responsible for providing the indoor substation vault to Ameren Missouri specifications including:

Space in the room for required equipment
Doors (3 hr fire rated)
Space for ventilation
Lighting
Pulling eyes
Oil retention tank
Ground Grid

Ameren Missouri encourages, though doesn’t require, customers to tie their building ground in with Ameren Missouri’s ground system. Most customers do.

The vault ventilation system is separate from the building ventilation system. Ameren Missouri does not require or permit supplemental forced ventilation. Rather they work with the builder to assure that the louvers are big enough to have adequate ventilation without forced air.

4.15.2 - CEI - The Illuminating Company

Design

Non-Network Design

People

The design of the non – network ducted manhole system is performed by the CEI Underground / LCI group, part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

The group is comprised of Engineers (5) and Design Technicians (3). The department currently includes two younger employees brought into the department in anticipation of retirements, so that departmental knowledge is preserved.

The majority of the design of both the network and non-network systems is done in house. Underground network / non- network design is seldom outsourced at CEI.

The group’s responsibilities include network system and non – network system designs and the development of standards for the ducted manhole system including vault and manhole design standards and customer design standards. The group prepares construction drawings for the conduit system, vaults and manholes.

Process

The Cleveland downtown area is fed from three substations - Lakeshore, Hamilton, and Horizon. CEI has a large ducted manhole system that provides radial non – network service to the majority of customers in the Cleveland area. More specifically, they provide the following design types:

33 kV sub transmission feeding larger customers and distribution substations
11 kV sub transmission, serving the majority of large urban customers, with multiple feeds, through a ducted manhole system
13.2 kV – distribution voltage serving customers radially (prevalent in overhead and URD distribution, but they have some limited 13.2 distribution in the ducted manhole system, including feeder exits at the stations)
4340 V (4kV) delta – distribution voltage serving customers radially in a ducted manhole system. This is the most prevalent design type in the Cleveland area.

The Underground system consists of about 2000 miles of cable and 10,000 manholes.

Much of the CEI underground system is build with lead (PILC) cables. CEI has about 1550-1600 miles of PILC installed. The new cable standards include both EPR and XLP cable types. Typically, CEI uses EPR Cables when transitioning from lead to non – lead cable. Substation Feeder exits are typically designed with 750 AA XLP cables.

Similar to their approach to network design, if the non-network project involves just a tap, the design will be performed by the engineers within the Design Group who focus on serving customers (the LCI group). If the project involves a cable line extension, both a cable engineer, and an LCI engineer are usually involved in the design.

CEI’s line extension policy requires the customer to pay 40% of the costs for the line extension upfront^[1] .

See Network design - Process

Technology

Engineers will prepare the required construction drawings that show the duct configurations, show the manhole design, reference standards pages, etc. Wherever possible, they will use the GIS system as a foundation for a drawing. They may show a portion of an existing vault drawing if the project involves a revision to an existing vault. In general, the design drawings they produce are very clear and well received by the Underground Group (field).

FirstEnergy is using a home grown system called Crews to develop a bill of materials and cost estimate for system designs. This system uses assembly units (called “compatible units” or “macro units” at FirstEnergy) which aggregate materials and cost estimates for certain construction unit types (single phase tangent structure pole top, as an overhead example). For underground system designs, FirstEnergy is in the process of adding underground compatible units to their system so that they can fully utilize Crews for underground designs.

^[1]This line extension policy is subject to change based on a proposal before the PUCO

4.15.3 - CenterPoint Energy

Design

Non-Network Design

People

Major underground design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. This includes non – network designs such as running a main feeder and a back up feeder. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group, the Padmounts group, deals with the design of three phase pad mounted transformer installations, including looped commercial developments. This group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources.

Another sub group, the Vaults group, focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. This group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources.

The final subgroup, the Feeders group, is focused on distribution feeder design. This group focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

CenterPoint uses various designs to serve urban load depending on the location, service voltage, load requirements, customer needs. Design types include network services, such as a 120/208V network grid system, and low and high side spots.

Similarly, CenterPoint also uses various non network designs to meet customer requirements. A common design is running multiple 12.4 kV primary feeds into a building vault, one normal and one back up, with either a manual or automatic throw over between the primary feeders, and supplying a 120/208 V or 277/480 V service to the customer through a CenterPoint owned transformer. CenterPoint maintains ownership of the transformer (s) in the customer’s vault in most cases. Electrically, the two feeders first come to a disconnect point. This can be a “feed through” connection, 600A blade type disconnects, or motor operated switches and vacuum interrupters.

In some cases CenterPoint uses an automatic throw over switch that will “throw” the load over onto the other feeder if one feeder is interrupted.

CenterPoint works closely with customers to try to meet their needs and often will customize their designs accordingly. Customers are responsible for the costs of any additional infrastructure they desire beyond a standard level of service provided by CenterPoint.

Technology

Figure 1 and 2: Disconnects, Various design types

Figure 3 and 4: Disconnects, Various design types

4.15.4 - Duke Energy Florida

Design

Non-Network Design

People

Non-network design in the urban underground centers in Clearwater and St. Petersburg is performed by the Distribution Design Engineering group, which works out of offices in both cities. The groups are responsible for designing new and refurbished network designs, as well as underground radial and looped (non-network) distribution designs. The Distribution Design Engineering group is led by a Manager, Distribution Design Engineering, and is organizationally part of a Distribution Design Engineering Group responsible for Duke Energy Florida’s Coastal region, led by a Director.

The Design Engineering group is comprised of two sub - groups: an Engineering group, comprised of degreed engineers, and a Technologists group, comprised of non-degreed Network Technologists. Work within the Design Engineering group, both in Clearwater and St. Petersburg, is assigned geographically, such that a designer (either an Engineer or a Technologist) is responsible for both network and non-network designs within an assigned geographical area. Some designers focus on commercial customers, while others focus on residential customers. For example, the St. Petersburg design group has two engineers that focus on commercial designs – both engineers have four-year engineering degrees.

The criteria for choosing non-degreed Technologists may include years of experience, and for new job postings, at least a two-year degree in electrical technology. The existing group has individuals with varied experience, including distribution operations, control, and transmission.

The Design group is experiencing a large turnover in its Engineering staff, as a number of employees with many years of experience are retiring. A challenge for the group as positions turnover will be acquiring new resources with design experience.

Process

Both downtown St. Petersburg and Clearwater are experiencing moderate growth. Most new work is designed with a non-network design. More specifically, most new larger buildings are designed with a primary and reserve looped feeder scheme, with an automated transfer switch (ATS), and fed through Duke Energy Florida’s ducted manhole system.

Design engineers typically perform preliminary research on circuit loads before design, but also work closely with Planners to make final design decisions with respect to anticipated circuit capacity. The Planners decide the scope of work from a macro level, such as determining, for example, where a feeder should be split to supply new load. The Design Engineers perform the detailed design including selection of materials, and the project layout, including the cable route. The Design Engineer will inspect current GIS maps and perform site visits to manholes to inspect condition and duct line configuration to determine whether there is ample room to pull new cable.

One of the first steps in the design process is a thorough field investigation to find out what is currently in the manholes and duct lines, and to make certain it is mapped correctly in the current GIS. Field inspections are performed by Network Specialists under the supervision of a Network Design Engineer.

Any updates required to the GIS maps, as determined by inspection, are red-lined and submitted to the GIS technicians for input into the electronic system. The Network Designers have found that these field inspections and on-site red-line updates of the GIS are essential since the GIS mapping of the urban underground system and, in particular, the network, is out of date. The inspections serve two purposes: first they are necessary to understand field conditions and complete new service designs, and secondly, they serve to update the GIS, which is foundational to the company’s Outage Management System (OMS).

After inspection and GIS updates, the Design engineers complete design work using an online design system (a WMIS system, by Logica) that provides the ability so select compatible units (CU) for infrastructure that includes estimated costs of labor and associated materials. This system produces a cost estimate and bill of materials. Design drawings are prepared online using the GIS system as a base, using a “red line” file. Final input acceptance of the as built “red-line” drawing is incorporated into the permanent GIS record by the GIS team.

Final designs are submitted for a peer review, normally performed by senior design engineers, and – for network projects - network specialists. Circuits, project layout, CUs selected, etc. are checked against Duke Energy Florida standards by the peer reviewers and if any changes are required, they are sent back to the Designers. Peer reviewers are especially concerned with the “ constructability ” of any designs in a given area. The peer-review process includes online and informal meetings between the peer reviewers and the designers – this provides checks and balances throughout the design process.

When the design passes peer-review, and is below a certain dollar amount ($50,000), it can proceed directly to construction. If it is a higher cost project (above $50,000), it must go to management for review and sign-off. Anything above $100,000 must be reviewed by a Director. A Work Order is created once the Design passes peer review and customer charges are received.

Once the Design has been final approved, it goes to a Construction/Maintenance Specialist to review the Work Request and make certain that the proper material and component CUs have been requested. The Construction/Maintenance Specialist must double check and order the CUs indicated in the final design/work order. The Construction/Maintenance specialist may add CU’s to better reflect the labor and material requirements of the project.

In manholes, primary feeders are usually mounted on cable racks in the lower part of the manhole, while secondary cabling is mounted above, higher in the manhole. Many existing manholes contain three primary feeders in one manhole. The designers realize the placing of multiple feeders in one manhole increases the exposure and consequences of an event occurring in that manhole. Thus, for newer designs, designers strive to minimize the number of feeders in any one manhole hole. In underground radial designs, cables are routed to avoid a single-point-of failure by using looped cables from pull boxes.

Technology

Duke Energy Florida uses GIS system for mapping of the entire electric grid — radial as well as network. Note that Duke Energy Florida ’ s GIS system does not provide a true representation of the network secondary. Users of the GIS can access PDF drawings of manhole prints that detail manhole and vault infrastructure.

Duke Energy Florida is in the process of updating its GIS system records to fully represent network infrastructure. Duke Energy Florida is also migrating to a new GIS system, GE Smallworld.

Duke Energy Florida uses a Work Management Information System (WMIS), by Logica (now part of CGI). RTArm, by Logica, is used for material and component tracking and ordering, as well as assigning job hours for projects.

4.15.5 - Duke Energy Ohio

Design

Non-Network Design

People

Both distribution network design and non-network design is performed by a Network Project Engineer and two Designers who are part of the Distribution Design organization. This organization is focused on all distribution design work for Duke’s Ohio and Kentucky utilities.

Theses resources work closely with one another and with the Planning Engineer focused on the network to design modifications to the network.

Technology

Duke Energy Ohio serves all loads – major and non major - within the geographic section of Cincinnati they have deemed their network service territory with true network designs. Smaller loads are served through the secondary grid, while larger loads are served with true spot networks.

Within this geography, Duke Energy Ohio is not using non network designs, such as running dual primary feeders with an automatic throw over switch to supply major loads.

4.15.6 - Energex

Design

Non-Network Design

Note: Energex does not utilize a low voltage meshed secondary “network” in its CBD. This section discusses their design approach in serving the Brisbane Central Business District.

People

Energex has a Systems Engineering group, led by a group manager, and part of the Asset Management organization. This group is responsible for establishing the design standards for the distribution network. Energex also has a Design organization within its Service Delivery organization, also led by a group manager, and responsible for performing designs of specific projects, including new construction and system reinforcement projects. The Design group is comprised of four-year degree qualified engineers and engineering associates.

Process

To serve the downtown Brisbane central business district (or CBD), Energex is using an 11kV primary system, and supplies loads using single feeder supplies, or - in the Central Business District - using two and three feeder meshed 11kV systems.

There are four major substations that supply the load in downtown Brisbane. These substations are sourced at 110 kV by a combination of overhead and UG feeders. Within the stations are multiple 110 kV: 11kV dual winding transformers supplying the 11kV bus that sources the 11kV distribution system.

Energex runs multiple primary feeders at 11 kV out of these stations as part of a meshed system. Most of the feeders supplying the CBD are part of a three feeder mesh, where each of the feeders is fed out of the same substation, and are normally tied together at a “mesh point” located at a medium-voltage substation location. The feeders supply medium-voltage substations containing transformers (typically, either 1000 or 1500 KVA units), that supply the low-voltage system that supplies the down town load. Energex designs the mesh with sectionalizing points (circuit breakers or CBs), normally SF6 or oil (older design) switches located at various points along the feeder, protected with bus differential relaying, and a pilot wire scheme, so that devices operate simultaneously. These sectionalizing points may be designed on either side of a medium-voltage station, or separating multiple units within a medium-voltage substation, such that even with the loss of any one feeder section, customers can be supplied from the remaining mesh after performing some switching. Note that Energex does not use any automatic switching schemes, or remote control of these switches. Energex does install basic alarming in their medium-voltage stations, such as alarms for an open breaker, and general alarms (battery charge, sump pump). Alarms communicate by wire to an RTU at the substation supplying the primary feeder, and then through a WAN back to their SCADA.

For example, some high rise facilities may be supplied by Energex via multiple transformers separated by a switch on the primary. In the case of a fault on one feeder section, the bus differential relays isolate the section, resulting in a loss of supply to one of the transformers supplying the customer, and thus a partial loss of service to the customer. However, the customer may have the ability to perform switching on his side to energize the de-energized secondary bus by closing a secondary bus tie, after decoupling the secondary bus from the Energex transformer (using an interlock system that would prevent him from closing the bus tie until after it has separated itself from the Energex transformer). In this scenario, the customer load is restored, being supplied by the remaining in-service transformer.

The primary feeders also have bus over current protection at the source and at the mesh point. As UG feeders supplying the CBD, the primary feeders do not employ automatic reclosing and, upon sensing a fault, trip and lock out immediately. At the supply substation (110 kV: 11 kV), Energex has automatic changeover of the buses, so that the bus remains energized even with the loss of any one substation transformer. CBD has transformers operating in parallel so there is no auto changeover required on CBD substation busses.

Characteristics of a Three-Feeder Mesh Network

(from the Energex Standard Network Building Blocks document, Feeders BMS 03929, Updated: 13/12/2012, see Figure 1).

The layout of a developed three-feeder mesh network is shown in Figure 1 The network has the following characteristics:

Any two of the three feeders of the mesh ideally must be capable of supplying the total load of the mesh.
Distribution substations are installed generally in each major building.
Local low-voltage (LV) supply may be run onto the street from a distribution substation in a building in order to supply other customers on the street.
A fault in any of the 11 kV cables within the mesh results in the faulted cable being isolated by the circuit breakers (CB) at each end of it. Supply is maintained to the majority of the load supplied by the mesh.
Where the 11 kV bus in a distribution substation has a single CB for two transformers (e.g., Distribution Substation ‘A’), a fault in either 11 kV cable connected to the substation results in loss of supply to one transformer and partial loss of supply to the building. The building generally would have a transfer scheme on the LV side, a standby generator, or both.
If an 11 kV cable that has a teed connection to a load fails, the teed load loses 11 kV supply until the cable is repaired. Teed connections should not be installed in three-feeder mesh systems.
Individual distribution transformers are protected generally by fused units, sometimes by CBs.
A large CBD area may have many three-feeder mesh networks supplying it.
A three-feeder mesh may have a further backup connection to another three-feeder mesh, and other variations depending on the situation.
A CB may feed more than one mesh as shown, and protection must be arranged to suit (see Figure 1).

Figure 1: Energex 11 kV CBD Feeder Diagram

Technology

Medium-voltage substations in the CBD are usually located within building vaults. The medium-voltage stations consist of primary (11 kV) switches protected by bus differential relaying, transformers, and secondary switchgear that supplies both the building load (see Figure 7) and feeds into the low-voltage network serving the CBD (see Figures 2 to 6 and Figure 8).

Figure 2: Energex employee giving safety briefing before entering a C/I substation, locating in a building vault

Figure 3: Dry type transformer supplied by the three feeder mesh

Figure 4: Primary terminations (PILC) on dry type transformer

Figure 5: Multiple dry type transformers

Figure 6: Circuit breakers with bus differential relaying

Figure 7: Low-voltage switchboard, with feeds to the customer

Figure 8: Typical building vault substation with ring main unit (foreground) and transformer (background)

At some locations, Energex may “Tee” off the primary feeder with a substation consisting of an SF6 gas insulated ring main unit (the primary switch gear current design) with an “in” switch, an “out” switch, and a fused, switched tap leading to the transformer. The use of a packaged substation with a ring main unit is a common design outside of the CBD.

In URD applications, Energex uses a similarly designed “packaged” substation, a pad-mounted unit consisting of the ring main unit ( “in” switch, an “out” switch, and a fused, switched tap leading to the transformer), the transformer, and the low-voltage switchboard supplying the low-voltage network feeding the development (see Figures 8, 9 and 11). Note that URD developments are fed by an extensive low-voltage network feeding through mini pillars (see Figure 10). Services are tapped from these mini-pillars to serve customers (see Figure 12).

Figure 9: Typical pad-mounted 'packaged' substation supplying UG development. High-voltage switches (ring main unit) in the front, transformer in the middle, and low-voltage switchboard in the back

Figure 10: Typical pad-mounted 'packaged' substation supplying UG development (another view). Note mini pillar to the right of the substation

Figure 11: Low-voltage switchboard supplying the LV network feeding the development

Figure 12: Typical home, note mini-pillar in the foreground supplying the customer

Energex has SCADA at the substation, and some remotely monitored and controlled normally open tie points between 11kV feeders out on the system, but in general, they have little SCADA beyond the substation.

Energex is currently installing a PQ meter on the low-voltage side of all distribution transformers greater than or equal to 200 kVA, three phase.

At the time of the immersion, Energex was in the process of implementing the Power On DMS product, which provides electronic displays of the distribution networks, both medium voltage and low voltage.

4.15.7 - ESB Networks

Design

Non-Network Design

People

Organizationally, the design of both MV and LV infrastructure is performed by designers located within the Network Investment Management groups for larger designs, and within the ESB Networks Regions for the smaller designs. The Network Investment Management groups (North and South) are part of the Asset Investment group, within Asset Management. The Regions are organizationally part of the Operations Management Group, also part of the Asset Management organization.

For most designs, the design is performed by an Engineering Officer (EO) – the designer position at ESB Networks.

The development and maintenance of guidelines for performing MV and LV network design are the responsibility of the Specification Management group, part of the Asset Investment group, also part of the Asset Management organization at ESB Networks.

The Specifications Management group has developed thorough guidelines for the design of LV and MV networks^[1]. This guideline includes specific direction for optimizing designs.

Note that in addition to the Operations Management and Asset Investment groups, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Assets & Procurement, and Finance & Regulation. These groups work closely together to manage the asset infrastructure at ESB Networks.

^[1] Note that the term “networks” here is a general term that refers to distribution infrastructure. It is not meant to describe an interconnected or meshed LV system.

Process

A typical ESB Networks distribution design for both an urban setting and a suburban setting involves the installation of either an “indoor sub” (common in an urban setting) or “unit sub” (common in a suburban setting or a “greenfield” residential development), which consists of primary ring main unit or switchgear, a larger three-phase transformer (common size is 630 kVA), and an extensive LV secondary system, designed with multiple junctions and normally open tie points between adjacent LV feeders. Note that most customers are served by the LV infrastructure. ESB Networks provides a MV (primary) service to larger customers, usually with loads in excess of 500 kVA.

The design approach in an urban setting is similar to the design approach used by most U.S. utilities, where dense loads are served by MV “substations,” supplying an extensive secondary network. A key difference is that many U.S. utilities use a meshed LV secondary network. Consequently, the MV “substations” are designed as “network units,” and thus include not only the primary switchgear and larger three-phase transformers, but network protectors that serve to prevent back feed onto the primary from the meshed secondary in the event of a primary feeder outage.

In urban settings, the MV substation is designed as an “indoor room,” occupying an aboveground building vault designed and built to ESB Networks specifications (see Figure 1). (See MV Substation Design for more information.) Note that ESB Networks uses almost no submersible vaults in Dublin.

Figure 1: Exterior doors to an indoor room vault

In urban settings, ESB Networks uses a standardized MV “packaged substation” consisting of an SF6 gas insulated ring main unit, the MV transformer (in Dublin, typically a 10-kVA primary to a 430-V secondary), and the secondary bus and protection that feed the secondary “mains” that supply the LV system in downtown Dublin. The design is such that the transformer (typically a 630-kVA unit) can be replaced without replacing the ring main unit or LV panel.

The ring main unit consists of an incoming switch, and outgoing switch, and a fuse, switched tap to the transformer (kkT). One of these switches is typically normally open, and provides a sectionalizing point on the 10-kV MV system. Note that ESB Networks design guidelines discourage the use of gear with an additional tap (kkT units), as the company has found that this can lead to very complex designs that include loops within loops.

At ESB Networks, the LV feeders are designed electrically radial, with normally open ties between adjacent feeders, and multiple junction points for sectionalizing. These junction points are often accessed using “mini-pillars,” which are small aboveground pedestal boxes, and in belowground hand holes in the more urban settings. When installing a new indoor room MV station, ESB Networks attempts to split existing adjacent LV feeders to provide additional load support and opportunities for sectionalizing in outages.

For supplying housing developments in a more rural setting, ESB Networks uses an approach that is conceptually similar to the approach used in an urban setting. The company places a unit sub consisting of a ring main unit (switchgear) and larger three-phase transformer near the load center (see Figure 2 and 3), and supplies the customers from an extensive LV system (see Figures 4 through ). This approach differs from the U.S. approach to servicing housing developments of using a more extensive MV system, and small single-phase transformers.

Figure 2: SF6 insulated ring main unit, kkT

Figure 3: Sealed, oil-filled transformer

Figure 4: Secondary panel

Figure 5: Exterior door to a unit sub, used in residential developments

Figure 6: Unit sub secondary cabinet – Note the fused secondary feeders emanating from the bottom

Figure 7: Unit Sub Primary cabinet – Note the tap to the transformer

ESB Networks’ design guidelines acknowledge differences in developing optimal designs for urban areas versus housing developments in “greenfield” areas. As an example, the guidelines acknowledge that in urban areas, the size and type of loading on the system may change significantly with time. Also, in urban areas, the costs of adding LV cables in the future to support load growth can be very high because of excavation costs and the inability to pass costs on to a particular new customer. Consequently, the optimal designs for an urban infrastructure, as defined in the ESB Networks design guidelines, acknowledge these characteristics. For example, the guidelines indicate that a good urban design should acknowledge the difficulties associated with excavation, and thus take advantage of worthwhile opportunities to install additional circuits – especially if there is a strong likelihood that these additional circuits will be utilized (anticipated load additions, for example).

ESB Networks Network engineers have developed a list of design approaches to be avoided – referred to as the “dirty nine.” These refer to particular design approaches that are suboptimal and can lead to increased costs.

Technology

ESB Networks is using a home-grown Excel application for calculating load drop. At the time of the immersion, ESB Networks was experimenting as part of an electric vehicle pilot with the looping of LV feeders in certain locations. ESB Networks has installed fusing in the center of these loops, designed to blow if there is reverse power circulating currents.

4.15.8 - Georgia Power

Design

Non-Network Design

People

Non-network system designs are generally not handled by the Network Underground group. They are the responsibility of the Georgia Power Distribution groups in the Regions. However, , if any non-network design requires concrete-encased duct line construction, the Network Underground group will work closely with the regions on these projects. The Network Underground group is responsible for all duct line design throughout the Georgia Power system.

Non-network designs that utilize the ducted system, such as designs to large downtown loads that utilize a primary and reserve feeder scheme, are the responsibility of the Regions. However, projects that involve duct line designs will involve the Network Engineering group as well. This group, led by the Network Underground Engineering Manager, is comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees. Engineers are not represented by a collective bargaining agreement.

In addition to the engineers with in the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also deal with issues of network design.

Process

New services to larger loads in Georgia urban areas are served either with a spot network service, or with a dual, primary radial feeder scheme: either two preferred feeders, or one preferred feeder and one reserve feeder. These radial feeder schemes often include the ability to switch with a “PMH” type transfer – not a fast transfer scheme. Both spot network services and dual primary radial schemes are common at GA Power. Georgia Power engineers noted that some customers perceive the transfer service with two sources as more reliable than the network service.

There is no difference in electrical rates seen by the customer between a spot network service and dual primary feeder scheme. Costs differences are associated with the upfront costs for the infrastructure that is provided by the customer to accommodate the installation, with network vault costs being higher because of the need for more area, a higher fault rating for customer switch gear, etc. If a customer requires dedicated reserved capacity on a reserve feeder as part of a dual feeder supply, they must may for that reserved capacity. Customer connection costs for customers connecting to the secondary grid include costs associated with maintain and operating the network grid.

Typically, contracts come in from Marketing after a request for service to Georgia Power. This is the case for most large customers. It is customary for the Marketing representative handling the account to provide preliminary engineering with the load requirements for customer site. The group has a standard procedure to choose from models of different load types. The group can calculate load factors on all types of equipment, and project customer demand. The models do not require demand curves, only winter and summer peak load calculations, and the type of business the customer is engaged in. These factors are calculated before turning the project over to the design engineers.

4.15.9 - HECO - The Hawaiian Electric Company

Design

Non-Network Design

People

Underground non-network design is performed by the HECO T&D Division. This group is part of the Engineering Department.

The group is comprised of 2 lead engineers, 13 design engineers and a supervisor. All are four year degreed engineers with about half the group having their PE license.

The majority of the design of both the network and non-network systems is done in house. Underground network / non- network design is seldom outsourced at HECO.

The group’s responsibilities include network system and non – network system designs, and the preparation of construction drawings for the conduit system, vaults and manholes.

The department is a relatively young one, with many newer employees. The department manager noted that the group is an excellent training ground and a good stepping stone for other opportunities within HECO.

The T&D Division works closely with other groups, depending on the nature of the work. For customer work, they would interface closely with the Customer Installations Department (CID). For example, the CID would lead the design of a new customer vault, while the T&D Division would lead the design of a HECO vault or of a customer vault relocation. Similarly, the T&D Division works closely with the Civil / Structural Division, also part of the Engineering Department. The T&D Division would specify the size and type of vault needed, for example, while the Civil / Structural Division would perform the detailed civil design.

Process

HECO has a large ducted manhole system that provides radial non – network service to the majority of customers in Honolulu. More specifically, they provide the following design types:

46kV sub transmission - Pressurized gas filled cable feeding some large customers and distribution substations
25 kV distribution, serving large urban customers, with multiple feeds, through a ducted manhole system. The 25kV system was built as part of a master plan to convert all of the 12kV distribution on O’ahu to 25KV in response to anticipated load growth. HECO converted sections, and installed dual rated equipment in anticipation of conversion. However, as economic conditions have changed, HECO has abandoned this strategy and is now installing new distribution at 12kV.
12 kV distribution^[1] , serving customers radials, with multiple feeds, through a ducted manhole system. Note that HECO runs all of its primary in concrete encased conduits.

Much of the older HECO underground system is build with lead (PILC) cables. The new cable standard is to use XLP insulated conductors.

The T&D Engineering group performs designs for both customer driven projects, such as relocations and line extensions, and for internally developed projects such as system reinforcement projects. The group designs reliability improvement projects and performs load balancing. The group also performs civil designs for duct lines, vaults and manholes, as well as assists with the development of standards for underground enclosures.

The group does not design the layouts for a development. This work is normally performed by either the Customer Installation Department (CID) or by a contactor engaged by the developer. If a circuit must be extended to serve a development, the T&D Engineering group will design that extension, but not the URD layout.

The group does not design services (service drops) to customers. Design of services to customers is performed by the Customer Installations Department (CID).

The HECO distribution system is designed to a true N-1.

The majority of customers in Honolulu are served by non network designs. HECO uses 2 main feeders into each large customer, a “Fuse” feeder and a “Switch” feeder. The “Fuse” feeder is the main feeder that normally supplies the customer. The Switch feeder is designed as a backup feeder for a given customer, even though that feeder does serve other customers as the main feeder. Circuits are typically loaded to no more than 50%, so that they can carry the full load of an alternate feeder.

All three phase transformers are fed from two primary feeders - a main feeder and an alternate. Single phase underground facilities are designed as loop systems with fault indicators located in every transformer.

All underground primary cable (newer)^[2] is installed in concrete encased conduit, including URD designs. All secondary and service cables are installed in conduit as well, though not concrete encased in residential areas.

Technology

The design group is using various software applications for various tasks.

Their main design software is a homegrown application that is used to generate bills of material and cost estimates. They will use MicroStation to prepare construction drawings.

HECO is using “USAmp+” (USi) to perform cable ratings, and Pull-Planner (American Polywater) to assist with cable pulling calculations.

^[1] HECO has both 11.5kV and 12.47kV Distribution systems.

^[2] HECO does have older direct buried infrastructure installed.

4.15.10 - National Grid

Design

Non-Network Design

People

National Grid Albany uses radial distribution (non-network) designs to serve much of Albany. The underground department in Albany is responsible for the construction and maintenance of the radial system in Albany as well as the network systems.

Process

The Albany network secondary system is confined to a certain geographic boundary within Albany. All other loads are served by radial distribution systems. These distribution systems are primarily radial underground distribution fed through a manhole / conduit system. Much of the primary cable system is built with PILC cables.

In Albany, non-network customers are served radially with a preferred feeder / alternate feeder design.

Technology

National Grid utilizes fault current indicators (FCIs) liberally in their radial system.

4.15.11 - PG&E

Design

Non-Network Design

People

PG&E uses radial distribution (non-network) designs to serve much of San Francisco and Oakland. The Planning and Reliability Department group does distribution planning for both the network and not network distribution systems.

Process

PG&E network secondary systems are confined to certain geographic boundaries within San Francisco and Oakland. All other loads are served by radial distribution systems. These distribution systems are primarily radial underground distribution fed through a manhole / conduit system.

Within San Francisco, new loads to be built within the network geography will be served on the network. Loads outside this geography will be served by the radial distribution system. In Oakland, PG&E is actively minimizing load additions to the network. Consequently, new loads to be added within the network boundary in Oakland may be served by the radial distribution system, rather than by the network.

Non-network customers in both Oakland and San Francisco are served radially. PG&E does not provide a separate feeder to serve radial customers, even large ones, for free. If the customer wants a second “backup” feeder, they must pay for it. PG&E has a separate tariff that specifies the costs of the backup service, including the costs of installation, costs of ownership, and costs of reserve capacity. Note that PG&E may on occasion install a second feeder free of charge to selected new loads that benefit the public good.

4.15.12 - Survey Results

Survey Results

Design

Non-Network Design

Survey Questions taken from 2012 survey results - Design

Question 4.4 : What type of design are you using for new civil structures such as manholes and vaults?

Survey Questions taken from 2009 survey results - Design

Question 4.5 : What type of design are you using for new civil structures such as manholes and vaults? (this question is 4.4 in the 2012 survey)

4.16 - Non-Network Service

4.16.1 - Ameren Missouri

Design

Non-Network Service

People

Design of the urban underground infrastructure supplying St. Louis, including non-network service design, is the responsibility of the engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The Underground Division, led by a manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, size equipment, perform load flow analyses, and prepare line drawings that describe the designs. All engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

The Energy Services Consultants (Estimators) take the one line designs developed by the engineers and complete the design package, including all the physical elements of the design. Estimators have a combination of years of experience and formal education, including two-year and four-year degrees, and are part of the union, IBEW.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis. Engineers who are assigned to this team will also participate in the design of spot network installations and indoor rooms.

Ameren Missouri has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both online and printed book format.

Process

Customers with larger loads, or who request 480V service are normally served from a non - network design, either a padmounted transformer or an indoor substation. Padmounted services are usually not practical within St. Louis because of the downtown congestion; thus, the most common design for larger loads in downtown St. Louis is the indoor substation (also called “indoor room”).

Most new services to larger downtown loads in St. Louis are served with a dual, primary metered feeder scheme: either two preferred feeders, or one preferred feeder and one reserve feeder.

Larger customers often receive primary metered service, with Ameren Missouri providing two primary supplies to the customer. These primary supplies feed into switches, either fuses or breakers as chosen by the customer, and can be manually or automatically (auto transfer) operated. After the breakers, lines feed into the primary metering gear, and then on to the customer switchgear or transformation. Note that in this arrangement, all equipment except cable and meters are owned by the customer, including the primary switches that precede the primary metering point.

For a secondary metered customer, Ameren Missouri provides the switches and transformation that precede the metering point. In this design, Ameren Missouri may provide either a preferred and reserve feeder, or a two preferred feeder design.

In ascertaining expected customer load, Ameren Missouri will look at similar buildings to estimate demand using square footage and expected load density by customer type. They will also perform a load flow analysis to understand the impact on the system of connecting the new load. They will run both the normal and n-1 cases.

Technology

Most larger load locations within St. Louis are fed using non-network designs. See Non - Network Design - Technology for photographs of typical equipment used for larger non network services.

4.16.2 - CEI - The Illuminating Company

Design

Non-Network Service

(11kV Non – network Service to Large Customers)

People

The design of the non – network ducted manhole system is performed by the CEI Underground / LCI group (Design Group), part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

Process

CEI serves most large urban loads from their 11kV system (regarded as a sub-transmission system). This system is a delta system with a ground provided by a grounding transformer at the substation.

Most of the services to large urban loads are fed from multiple feeds into the buildings. A typical design involves two or more primary feeders entering a building vault at a large customer site. One feeder is considered the main feed, and the other(s), backup. CEI will try to source the multiple feeders in to a given building from multiple substations. Often, they include an auto – throw over scheme in the vault at the customer ’ s site (the customer is responsible for this cost). In other cases, the throw over switch is manual. The customer will normally provide a primary switch gear room and transformer room, or a vault. CEI maintains ownership of the transformer (s) in the customer’s vault in most cases. (See below for photographs of a typical installation)

The backup feeder they provide is a spare feeder (referred to as an “area spare”) that they run from the substation. Rather than reserving capacity on a customer by customer basis on feeders that serve customer load when normally configured, the 11kV system is designed with a spare feeder; that is, a feeder that under normal conditions is not loaded. Spare feeders are not fed off of dedicated spare transformers at the substation; rather, they are simply additional feeders fed off the bus at the sub, and feeding to multiple customers in the downtown for the purpose of backing up the main service feeders.

Each spare feeder backs up the load served by multiple feeders. The system is designed such that one spare feeder can back up 6 normal feeders. The six feeders backed up by a given spare are fed from multiple sources so that it is highly unlikely multiple feeders backed up by a given spare would be out of service at any one time.

For planned interruptions, such as needing to take a feeder out for maintenance or repair, CEI will go into each affected vault and perform a parallel transfer, which will tie in to the spare circuit, paralleled across the common bus in the “throwover” device. Then they will open the breaker for the normal circuit. This will often be transparent to the customer.

CEI will notify customers or the interruption to the normal feed where they have to, but not in all situations. If the circuit will be out for a few days, meaning that the customer is no longer receiving n-1, the Outage Coordinator - the person who makes customer contacts in anticipation of a planned outage - will notify critical customers that the alternate feeder is out of service.

To de-energize the spare feeder, CEI will send Underground electricians into all of the vaults, deactivate the auto transfer schemes and make a visible disconnect. When the spare feeder is de-energized, CEI will use that opportunity to address corrective maintenance issues along the feeder.

Technology

Below are photographs of a typical design involving two primary feeders entering a building vault – one is the supply feeder, and the other is the back up (Spare) feeder. In this example, the vault is provided by the customer and is built to CEI specifications. Electrically, the two feeders first come to a disconnect point. This can be a “feed through” connection as shown in photo below (Note: photo only shows the one incoming feeder shown – three phases, fed from the bottom).

In some designs, CEI requires the installation of “Minirupter”, a group operated interrupting device. From here the feeders go into an automatic throw over switch (in this example, a G&W switch). This device will “throw” the load over onto the other feeder if one feeder is interrupted. In the photo below the right is the normal feed, the left is the spare, and the center is the output from the device that will feed over to the transformer.

In this particular example, the transformer is housed in a separate transformer room, separated from the switch (above) by a wall. The feeder cables feed from the throwover switch through the wall into the transformer room.

Prior to going into the transformer – the circuits go through a set of power fuses. The picture below shows the cabinet in which the fuses are housed. The feeders enter through the top and continue to the transformer from the bottom (not shown)

The picture below shows the feeders going into the transformer (from the left).

See Spot Network Design - Process

4.16.3 - CenterPoint Energy

Design

Non-Network Service

(High Side Spot Networks)

People

High Side Spot Network design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group deals with the design of three phase pad mounted transformer installations, including looped commercial developments. The Padmounts group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is not typically involved in high side spot network design.

Another sub group, the Vaults group, focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. This group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. Note this group designs high side spot networks, where appropriate.

The final subgroup, the Feeders group, is focused on distribution feeder design. This group focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

For large, critical customers, such as medical centers, CenterPoint may provide a high side spot network service. This type of service, provided by CenterPoint to about twenty customers, utilizes transformer high side breakers and interrupters, low side disconnects between the transformer and the secondary bus, a normally closed tie breaker on the transformer secondary bus, and electronic relays to control the protection scheme.

An example service may involve four transformers, each sourced by a high side disconnect and interrupter. Transformers could be 3750 kVA or 5000 kVA units. There is a normally closed bus tie on the transformer secondary, with each side of the tie supplied by two transformers. (See photographs below). In the event of the loss of one of the incoming feeders, the secondary bus would continue to be energized by the remaining transformers. The firm capacity of the vault for planning purposes is set at 120% of the combined rating of three of the four transformers (N-1). In the event of the loss of one of the transformers, the secondary bus tie is opened so that the customer load can continued to be supplied from the remaining secondary bus section. (Note that the remaining transformer capacity in this scenario may not be able to supply the customer’s entire load, as the remaining bus section is supplied by only two of four transformers. This situation would only be temporary, however, until CenterPoint could isolate the failed unit, then close the bus tie, bringing the third unit back on line.)

For some large customers, CenterPoint will provide a three breaker auto transfer scheme rather than a high side spot network. This scheme splits the load between two feeders with a normally open tie breaker between the units. For 35kV service, they will normally split the load at 6000 kVA and greater. At 12kV, they will split the load at 4000 kVA and greater. They will sometimes use motorized switches to transfer the load between feeders. Though slower than breakers, they are less expensive. In newer installations, they are using SF6 switches.

Technology

Below are photographs of some CenterPoint High Side spot network facilities.

Figure 1: High side disconnect (top left), high side interrupter (bottom right)

Figure 2: 480 V tie breaker

Figure 3: Transformers being fed by 12kV primary cables

Photo above shows two transformers being fed by 12kV primary cables being fed from the disconnect and interrupter mounted on the wall on the right side. Secondary energizes the 480 V bus (top left). Note the 480V fused disconnect cabinet (grey cabinet) in the very left of the photograph, between the transformer and the secondary bus.

4.16.4 - Duke Energy Florida

Design

Non-Network Service

See Design - Non-Network Design

4.16.5 - HECO - The Hawaiian Electric Company

Design

Non-Network Service

(Large Customers)

People

Underground non-network design to large customers is performed by the Customer Installation Department (CID). If a line extension (usually in a public right of way) is needed to bring the line up to the point where the service design will begin, the T&D Division of the Engineering Department will design the line extension.

Process

HECO serves most large urban loads from either their 12kV system or 25KV distribution systems.

Most of the services to large urban loads are fed from multiple feeds into the buildings. A typical design involves two or more primary feeders entering a building vault at a large customer site. One feeder is considered the main feed, and the other(s), an alternate. HECO will try to source the multiple feeders in to a given building from multiple substations. Normally, the feeders will tie into an auto – throw over scheme in the vault at the customer’s site, often PMH gear. In other cases, the throw over switch is manual^[1] . The customer will normally provide a primary switch gear room and transformer room, or a vault. HECO maintains ownership of the transformer (s) in the customer’s vault in most cases.

The backup feeder they provide normally serves other load, but has enough capacity to act as a backup for the normal feed into a given customer’s site.

For planned interruptions, such as needing to take a feeder out for maintenance or repair, HECO will go into each affected vault and perform a parallel transfer, which will tie in to the spare circuit, paralleled across the common bus in the “throw-over” device. Then they will open the breaker for the normal circuit. This will often be transparent to the customer.

HECO will notify customers of the planned interruption to the normal feed where they have to, but not in all situations. If the circuit will be out for a few days, meaning that the customer is no longer receiving n-1, Account Managers within the Energy Solutions Department of the Marketing Service Division will notify critical customers that the alternate feeder is out of service.

Technology

Below are photographs of a typical design involving two primary feeders entering a building vault – one is the supply feeder, and the other is the back up (Spare) feeder. In this example, the vault is provided by the customer and is built to HECO specifications. Electrically, the two feeders first come to PMH switching device (left figure), with an automatic throwover. From the switchgear, the circuits feed two transformers from fused taps.

Figure 1: Padmounted Switchgear with auto throwover. PTM removing Fuses

Figure 2: Three Phase Pad fed from fused tap in the switchgear

^[1] Customer pays the incremental cost of the automatic throw-over switch. For certain customer types, such as hospitals, HECO will install automatic throw-over devices as standard.

4.16.6 - PG&E

Design

Non-Network Service

Process

Non-network customers in both Oakland and San Francisco are served radially. PG&E does not provide a separate feeder to serve radial customers, even larger ones, for free. If the customer want a second “backup” feeder, they must pay for it. PG&E has a separate tariff that specifies the costs of backup service, including the costs of installation, ownership, and reserve capacity. Note that PG&E may on occasion install a second feeder free of charge to selected new loads that benefit the public good.

4.17 - Organization

4.17.1 - AEP - Ohio

Design

Organization

People

Design of the networks serving Columbus and Canton Ohio, the two areas of focus for this urban underground network immersion study, is performed in Columbus by the AEP Network Engineering group, which is organizationally part of the AEP parent company. Within the Network Engineering group, the company employs two Principal Engineers and one Associate Engineer who are responsible for network design for AEP Ohio. These planners are geographically based in downtown Columbus at its AEP Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is organizationally part of the Distribution Services organization, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Network Engineering Supervisor and the distribution services organization reporting to the AEP Vice President of Customer Services, Marketing and Distribution Services support all AEP network designs throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

Two Principal Network Engineers primarily oversee the designs for Columbus networks; one Associate Network Engineer primarily oversees Canton, but often helps with Columbus-based projects. The Network Engineers are responsible for all aspects of the network design, from inception to implementation, including the preparation of work orders, material acquisition, site inspections, and project completion.

AEP Ohio also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues.

AEP Network Engineers design the network system in Columbus to a full N-2 resiliency, including the substations and spot network locations. This N-2 reliability is notable, as most urban underground network systems operate at an N-1 level. N-2 insures that if any system components fail, the remaining facilities can carry the load and maintain service. For example, all spot network locations are designed with at least three transformers, with any one transformer able to carry the peak spot network load. The AEP Network engineers will also perform radial (non-network) designs for customers who locate within the city centers, and who do not opt for or require network service.

AEP network engineers perform all designs associated with the network, including new service projects and system reinforcement projects. The Engineers perform all aspects of design including network unit design, equipment sizing, performing load flow analyses, and preparing project drawings that describe the designs for construction.

Two Technicians assist the engineers with the preparation of drawings in MicroStation and AutoCAD. This is a full-time position and is assigned to the Network Engineering department.

All civil design for network projects, including manholes, vaults and duct lines, is outsourced to a civil engineering firm. The primary Civil Engineer at that firm is a retired AEP Ohio employee who has many years of experience working with AEP Ohio underground networks.

The AEP Network Engineer responsible for customer designs works closely with the AEP Customer Service Representatives and the customer to insure designs for customer service meet all AEP as well as customer specifications.

Technology

AEP uses MicroStation as a graphics platform, and for preparing most engineering drawings. Some drawings are prepared using AutoCAD.

4.17.2 - Ameren Missouri

Design

Organization

People

Design of the urban underground infrastructure supplying St. Louis, both network and radial, is the responsibility of the engineering group within the Underground Division. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP. This Center, led by manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including vault designs, network unit designs, equipment sizing, perform load flow analyses, and prepare one-line drawings that describe the designs. All of the engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

The Energy Services Consultants (Estimators) take the one line designs developed by the engineers and complete the design package, including all the physical elements of the design. Estimators have a combination of years of experience and formal education, including two year and four-year degrees, and are part of the union, IBEW.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. This group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis.

Ameren Missouri has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. Standards are available in both an online and printed book format.

4.17.3 - CEI - The Illuminating Company

Design

Organization

(Culture)

People

The design of the network is performed by the CEI Underground / LCI group (Design Group), part of the CEI Regional Engineering Services group, located in NRHQ (Northern Region Headquarters). “LCI” stands for Large Commercial and Industrial, as the group has new service design responsibility for large commercial and industrial customers.

EPRI observed an excellent working relationship between the Underground / LCI group (Design Group) and the Underground Network Cable Services Section (Underground Group). Each group voiced high degrees of respect for one another. The strong relationship is fostered by frequent face to face interaction between the engineers and the field force. In performing a design, an engineer will work with the field force to assure that the design is physically workable. For example, a designer may visit the field to determine whether there is enough room in a manhole for the proposed design. When preparing the job, the designer will put the name of the field crew that will be performing the work on the job print.

Process

While there is no formal program in place to foster the strong relationship, the managers of the two departments implement certain activities to continue to build the relationship. For example, a new designer joining the Design group will be assigned to work with the Underground Manager for a period of time to gain exposure to underground construction, maintenance, and operations (engineer may participate in performing fault location, for example). Similarly, a field employee (perhaps on light duty) will be assigned to work for a certain amount of time with the Design group.

Culture

Ducted Network Underground Users Group

People

FirstEnergy is made up of multiple operating companies, including CEI, whose distribution systems have been built historically from different standards. Each of those companies has some portion of their distribution infrastructure fed underground in ducted manhole conduit systems, either radially or with meshed secondary networks.

In order to focus on the unique challenges of underground ducted manhole systems, and to identify opportunities to synergize on the best ideas each operating company has to offer, FirstEnergy Standards organized a Ducted Network Underground Users group (Ducted Systems Users Group), led by a Senior Engineer within Corporate Design Standards, and with participation from each operating company.

Process

The Ducted Systems Users group meets three times per year. The focus of the group is to pair operating people and corporate people across the company to drive consistency across the system and look for best practices.

In 2008, the Ducted Systems Users group performed a review of the network and fully ducted systems across the company to identify needs and make recommendations. From this review, they produced a list of recommendations for addressing issues identified during their review. FirstEnergy is in the process of developing action plans to implement these recommendations.

Recommendations include:

Develop long range plans for network systems (Expand, maintain, or contract),
Assuring that underground systems are accurately represented in FirstEnergy’s project prioritization methodology,
Assessing current and longer term manpower needs,
Development of current system wide standards, practices manuals, and specifications for network, ducted system materials
Modeling network / ducted system infrastructure consistently and using up to date technology
Review planning and protection approach to network systems, including modeling.

4.17.4 - CenterPoint Energy

Design

Organization

People

Underground distribution design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group deals with the design of three phase pad mounted transformer installations, including looped commercial developments. This group, called the Padmounts group, is comprised of Engineers, Engineering Specialists, nd is supplemented with contractor resources.

Another sub group focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. This group, called the Vaults group, is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is responsible for both the civil and electrical vault design.

The final subgroup is one focused on distribution feeder design. This group, called the Feeders group, is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

The four groups work closely with one another and with the construction organization.

Process

CenterPoint uses various designs to serve urban load depending on the location, service voltage, load requirements, and customer needs. Design types include Network service (network grid system is at 120/208V), Spot network service (208V and 480V secondary), High Side spot network design, multiple primary feeds with either manual or automatic throw over, and other designs as requested by the customer. All network services are supplied from the 12.47kV system.

CenterPoint works closely with customers to try to meet their needs. Customers are responsible for all civil costs, and costs of any additional electrical equipment they desire beyond a standard level provided by CenterPoint.

4.17.5 - Con Edison - Consolidated Edison

Design

Organization

(Culture)

People

Con Edison’s Network Organization includes:

Construction
Responsibilities include Construction Management, Construction Services, Public Improvement, Substation and Transmission Construction, Administrative Services, and Environmental, Health and Safety (EHS) and Training.

Central Engineering
Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

System and Transmission Operations
Responsibilities include Financial Planning, Environmental and Safety Monitoring and Compliance, Transmission Planning, System Operation, and Transmission Operation.

Engineering and Planning
Responsibilities include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.

Substation Operations
Responsibilities include Substation Planning, Environmental, Health & Safety, Protective Systems Testing, and Substation Operations.

Electric Operations
Responsible for Con Edison’s Operations Centers including Manhattan, Brooklyn and Queens, and Staten Island, as well as the Transformer and Meter shops. Con Edison’s Operations Centers are responsible for Electric Construction, Electric Operations, Environmental, Health and Safety, and Financial Planning / Operations Services.

Purchasing
Responsibilities include Minority Women Business Enterprise, Materials, Systems Support, Services, Technology and Strategic Initiatives, Construction, Major Projects, and Contractor Performance.

Enterprise Shared Services
Responsibilities include Corporate Emergency Planning and Security, Equal Employment Opportunity Affairs, Research and Development, Facilities, Shared Services Administration, Human Resources, and Finance and Administration.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

4.17.6 - Duke Energy Florida

Design

Organization

People

Network design is performed by the Distribution Design Engineering group for Duke Energy Florida, which works out of offices in both downtown St. Petersburg and downtown Clearwater. The groups are responsible for designing new and refurbished network designs, as well as underground radial and looped distribution designs. The Distribution Design Engineering groups in Clearwater and St. Petersburg are led by a Manager, Distribution Design Engineering, and are organizationally part of a Distribution Design Engineering Group responsible for Duke Energy Florida’s Coastal region, led by a Director.

The Design Engineering group is comprised of two sub - groups: an Engineering group, comprised of degreed engineers, and a Technologists group, comprised of non-four year degreed Network Technologists. Work within the Design Engineering group, both in Clearwater and St. Petersburg, is assigned geographically, such that a designer (either an Engineer or a Technologist) is responsible for both network and non-network designs within an assigned geographical area. Some designers focus on commercial customers, while others focus on residential customers. For example, the design group has two Engineers that focus on commercial designs – both Engineers have four-year engineering degrees.

The criteria for choosing non-degreed Technologists may include years of experience, and for new job postings, at least a two-year degree in electrical technology. The existing group has individuals with varied experience, including distribution operations, control, and transmission.

The Design group is experiencing a large turnover in its Engineering staff, as a number of employees with many years of experience are retiring. A challenge for the group as positions turnover will be acquiring new resources with design experience.

4.17.7 - Duke Energy Ohio

Design

Organization

People

Network design, as well as non-network design, is performed by the Distribution Design department at Duke Energy Ohio. This department performs designs for Duke’s Ohio and Kentucky service territories. The group is led by manager and is broken into smaller design groups that focus on designs for particular Duke Service centers. Each of these smaller design groups is led by a supervisor.

The Distribution Design department employs a Project Engineer, reporting directly to the department Manager, who has prime responsibility for engineering support of the network. This engineer is a four year degreed engineer. The Project Engineer works closely with the Network Planning Engineer (Distribution Planning department) and the network Construction & Maintenance supervisors.

In addition, the Distribution Design department employs two Designers who are responsible for network designs, including load editions, forced work, and system reinforcement. These designers report to a Supervisor within Distribution Design. These Designers prepare the engineering drawings and other materials associated with job packages that go to Construction. These Designers are two year degreed engineers. Note that these designers have responsibility for non-network designs as well.

4.17.8 - Energex

Design

Organization

People

Energex has a Systems Engineering group, led by a group manager, and part of the Asset Management organization. This group is responsible for establishing the design standards for the distribution network. Energex also has a Design organization within its Service Delivery organization, also led by a group manager, and responsible for performing designs of specific projects, including new construction and system reinforcement projects. The Design and System Engineering groups are comprised of four-year degree qualified engineers and engineering associates.

4.17.9 - ESB Networks

Design

Organization

People

Design of the network underground at ESB Networks is performed by engineers within the Asset Investment organization. The Asset Investment organization is comprised of the Network Investment groups, both north and south, a Generation Investment group and a Specifications group, each led by a manager.

The Asset Investment group is part of Asset Management.

Design standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

4.17.10 - Georgia Power

Design

Organization

People

Design of the urban underground infrastructures supplying metropolitan areas in Georgia is the responsibility of the Network Engineering group within Network Underground.

The Network Underground Network group is a centralized organization responsible for management of network infrastructure throughout Georgia Power. The group is led by the Network Underground Manager, and is comprised of groups responsible for all aspects of managing the network, including network engineering, construction, operations and reliability.

Design of the network is the responsibility of the Network Engineering group. This group, led by the Network Underground Engineering Manager, is comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees.

In addition to the engineers with in the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also deal with issues of network design.

Georgia Power area planners and design engineers evaluate design the system to N-1, such that the system is designed to supply the load even with the loss of one key component. For example, if Georgia Power has three transformers at a substation, and one of the transformers serves the Network, then one of the responsibilities of a network designer is to insure that if a network bank fails for whatever reason, then the other two transformers can instantaneously pick up the full load of the failed network bank. This assures a high level of customer reliability.

Engineers design the system, including vault designs, network unit designs, equipment sizing, perform load flow analyses, and prepare one line drawings that describe the designs. All of the engineering positions are four-year degreed positions. Engineers are not represented by a collective bargaining agreement.

The GIS Technicians assist the engineers with drawings and completing the design package, including all the physical elements of the design.

Construction crews are responsible for ductlines and manholes and some vault construction; however, most Atlanta customers are given functional and dimensional requirements for vaults and are required to construct transformer vaults to meet the Georgia Power requirements.

The Georgia Power Marketing organization serves as the conduit between the customer and the design engineers for aiding in the design and cost estimates for projects. Often, customers will work directly with the engineers during the design and implementation phases. Most design engineers physically visit the site prior to and during project construction.

Georgia Power has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. Standards are available in both an online and printed book format. Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. It is a living document, and the responsibility of the Standards Group comprised of Principal Engineers in the Network Underground group. The standards are divided into two main sections: civil construction and network specifications and design.

4.17.11 - HECO - The Hawaiian Electric Company

Design

Organization

(Culture)

People

Design activities are performed by multiple groups at HECO. The T&D Engineering Division designs most of the customer driven and internally driven projects. They work closely with the Customer Installations Division, who focuses on the design of the service itself to the customer, and in laying out URD designs. The Technical Services Division focuses on standards, practices, and specifications and provides specialized engineering support, such as developing strategies for cable diagnostic testing, or facility replacement.

Designer / Line Worker Exchange

The Designer / Line Worker exchange program is aimed at C&M line workers who are close to achieving the Crew Leader level, and at Planners within the CID Planning and Design Division of the Customer Installation Department (CID).

Process

EPRI observed strong working relationships between the T&D Engineering Division, the Customer Installations Division and the Technical Services Division. In addition, EPRI noted an excellent working relationship between Technical Services Division engineers and the C&M Underground field force. High degrees of mutual respect were evident in the interactions observed by EPRI investigators.

HECO has implemented certain activities to foster the strong working relationship between the two groups. For example, it is not uncommon for a Technical Services Engineer to meet with the field force prior to the start of the work day to discuss a particular project and participate in the morning tailboard meeting. Also, the Engineer may be present during diagnostic testing to aid the field crew in administering the diagnostic test and in interpreting the results.

HECO has implemented a Designer / Line worker exchange program (see below) to raise each group’s appreciation of the work of the other, and to build strong relationships between the two groups. The program is aimed at Line workers who are close to achieving the crew leader level. The line workers are assigned to shadow the various divisions of the Customer Installations Department for a four week period, to better understand the design elements of a customer project. Similarly, though not part of the formal program, CID Planners are assigned to work in the line department, where they are given a combination of office and field experiences, and are able to see selected jobs all the way to completion.

HECO is considering expanding this exchange program to involve the T&D Division of the Engineering Department.

Designer / Line Worker Exchange

HECO has implemented a novel four week training program aimed at C&M line workers who are close to achieving the crew leader level. The line workers are assigned to shadow the various divisions of the CID group for a four week period, to better understand the design elements of a project. This four week rotation includes time with the Administration Division, the Meter Division, and the Planning & Design Division of the CID. This program is a formal one, required for progression to Crew Leader.

Similarly, CID Customer Planners within the Planning & Design Division are assigned to work in the C&M (line) department, where they are given a combination of office and field experiences, and are able to see selected jobs all the way to completion. Note that this program is informal, and not necessarily required for a Planner to advance to Designer.

HECO has found that this training raises each group’s appreciation of the work of the other, and has helped to build strong relationships between the two groups.

4.17.12 - National Grid

Design

Organization

People

At National Grid, distribution design is part of the Engineering organization. Engineering is part Distribution Asset Management organization, which also is includes Asset Strategy, Distribution Planning, Investment Management, and Transformation.

The Engineering organization is made up of: Substation Engineering Services; Distribution Design; Protection, Telecommunications and Meter Engineering; and Distribution Engineering Services.

There are two designers who perform network designs for the National Grid Albany network. They are part of the Distribution Design organization.

One designer (a Design Investigator) focuses on designing smaller new services connections to the network, 800 amps and below. This individual has a two year degree, though the degree is not mandatory for the position. This designer has field experience as both a cable splicer and maintenance mechanic. This designer also performs some non- network UG and overhead service designs.

The other designer (a Designer C) performs all larger and more complicated network designs, including network reinforcements, large new services projects greater than 800 A, and vault designs. This individual has a two-year degree, a requirement for the position. This designer also performs non – network UG designs.

Organizationally, both designers are part of the Distribution Design organization, led by a manager, and part of the Engineering organization at National Grid. This organization is structured centrally, with resources assigned to and in some cases physically located at the regional locations. The designers who support the Albany network are both physically located at the NYE building in Albany.

Both designers are represented by a collective bargaining agreement. The Design Investigator and Designer classifications are two different classifications with different progressions.

Both designers work very closely with the field engineer, part of Distribution Planning, assigned to the underground department to support the Albany network.

4.17.13 - PG&E

Design

Organization

People

Network design at PG&E is performed by the planning engineers within the Planning and Reliability Department. This department is led by a Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems, and is also responsible for network design. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution design.

Both network planning engineers are four year degreed engineers. The planning engineers are represented by a collective bargaining agreement (Engineers and Scientists of California).

For large customers who wish to connect to the PG&E network system, a Service Planning representative is assigned to interface between the customer and the planning engineers within the Planning and Reliability Department who are responsible for the design. The service planning representative acts as a key account manager.

The planning engineers also work closely with project estimators (Estimators or Senior Estimators) who develop cost estimates and perform field checks to see if the design laid out by the planning engineer is workable in the field. The estimators also prepare the job packet for construction. PG&E has estimators located in local offices to work with smaller projects, and estimators located in their Resource Management Centers, who work with larger projects. The estimators that work on network design projects are located in the San Francisco division.

Cable design is the responsibility of experts within the Standards Department.

Planning engineers and Estimators are represented by collective bargaining, Engineers and Scientists of California (ESC).

4.17.14 - Portland General Electric

Design

Organization

People

Distribution/Network Engineers: Three Distribution Engineers cover and design the underground network, as well as work with customers to design customer-owned facilities, such as vaults, which may house network equipment. The underground Distribution Engineers are qualified electrical engineers and are not based in the Portland Service Center (PSC) or CORE group. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. When needed, PGE hires civil engineers to perform certain planning tasks.

Network Engineering develops and maintains the standards for the network, which are forwarded to the Standards Department. For example, Network Engineers developed the cable rating standards for the network cable systems. Distribution Engineers assume responsibility for network standards as they have the expertise specific to network equipment.

Distribution Engineers also provide the loading information that the Planning Department uses to create CYME and PSSE models.

Standards Department: The Manager of Distribution Engineering and T&D Standards oversees the Standards Department, and focuses on overhead and underground residential distribution (URD) systems rather than the network system. After recently experiencing reorganization, the group now employs one technical writer and four standards engineers.

Service & Design at PSC: Service & Design’s role is to work with new customers or existing customers with new projects, making it responsible for customer requests for new connections and customer-generated system upgrades, such as a building remodel. The supervisor for Service & Design’s wider responsibility includes the downtown network. The supervisor reports to the Service & Design Manager, who is a peer of the Distribution Engineering and T&D Standards manager. Both of these positions report to the General Manager of Engineering & Design and directly to the vice president.

The Supervisor of Service & Design at PSC and its group undertakes capital work if it is initiated by the customer. The “Mapper/Designer” reports to the Supervisor of Service & Design at PSC and provides the computer-aided design (CAD), geographic information system (GIS), and design service.A Field Inspectormeets with customers/customer contractors. Two inspectors work for the Service & Design organization, with one specializing in the network.

Service & Design Project Managers (SDPM): Network planning associated with customer-driven projects requires regular coordination with the customer throughout the project life. PGE has a position called a Service & Design Project Manager (SDPM), who works almost exclusively with externally-driven projects, such as customer service requests. At present, two Service & Design Project Managers cover the network and oversee customer-related projects from the first contact with the customer to the completion of the project. They coordinate with customers to assure that customer-designed facilities comply with PGE specifications.

The SDPMs can be degreed engineers, electricians, service coordinators, and/or designers. Ideally, a SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. In addition, SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC), as well as the ability to use or learn the relevant information technology (IT) systems. PGE prefers a selection of SDPMs with a diverse range of experience and backgrounds.

SDPMs work on both CORE and non-CORE projects. This ensures that expertise is distributed and maintained across departmental and regional boundaries.

Key Customer Manager (KCM): PGE has nine KCMs reporting to Manager of the Business Group. Generally, they are geographically distributed, with three on the west side, one downtown, one in Salem, three on the east side, and one acting as a rover. KCMs liaise with large customers and communicate their needs.

Process

The PSC System Layout

The PSC service territory includes a mixture of overhead and underground facilities. West of the 405 freeway, PGE’s feeders are predominantly overhead and served by overhead crews located at the PSC. The PSC territory also contains five network systems, three of which are supplied from one substation and two from another substation. Each of the networks is designed to N-1, such that customers will remain in service even with the loss of any one piece of equipment.

The specific network systems are each assigned to individual underground Distribution Engineers.

The network uses a delta-wye configuration, and network and radial systems never mix together on individual feeders (i.e., all network feeders are dedicated to supplying network load).While network feeders supplying a network may emanate from different bus sections, PGE regulates the voltage and has had few problems with protectors pumping or cycling.

Many of the buildings in the downtown Portland area are becoming more energy efficient, reducing loading. In some locations, light loading conditions have caused network protectors to open.

Overall, due to the multiple redundancies in the network design, the downtown system is very reliable.

Substation Configurations: One of the two substations, which supplies three networks, is sourced by three 115-kV primary feeders, which supply four power transformers. The substation serves both network and radial feeders. Each of the three networks is supplied by four dedicated network feeders, at 12.4 kV, with each emanating from a different bus section. Voltage regulation is performed at the bus level. One of the networks consists of only spot network loads. PGE prefers to serve spot networks with four feeders, where possible, although some spot network locations are supplied by two or three feeders. The other two networks that this substation sources contain both grid network and spot network loads.

The other substation that supplies two networks is located on the other side of theWillamette River, and its feeders cross the waterway to supply downtown Portland. This is the older of the two substations. Each of the networks is supplied by four dedicated network feeders, at 11 kV, with each emanating from different bus sections. However, this substation also supplies radial load through radial feeders that emanate from the same bus sections as do the network feeders. Each feeder has its own regulator (in contrast to the other station, where regulation is at the bus level) to prevent pumping and cycling of network protectors because of voltage differences at the station. This gives PGE finer control, but limits capacity.

In the future, all loads that the second substation supplies will transfer to a new substation, which is under construction at the time of this immersion process. 12.4-kV feeders from this new station will supply networks [1].

Marquam Substation: PGE is building the new Marquam Substation, which will address a number of issues with the older substation:

The new substation will eliminate the river crossing that the older substation used
The new substation will have added capacity in anticipation of future load growth
The substation solves the existing co-mingling of the radial and network feeders on the same bus
The new facility will be able to cope with the load that the newer substation supplies when that substation is rebuilt in the future
The new substation will include a group feeder pickup capability for quickly restoring the network after an outage.

The Marquam Substation will have the capability to serve five separate network systems with a peak load of 120 MVA. Two of the network systems will be transferred from the existing older station. A third will be transferred from the newer station within 10 years. The fourth and fifth network systems are earmarked for future load growth.

Marquam getaway duct banks will consist of four 48-in. (122 cm) diameter steel casings for crossing underneath a major roadway, with the conduit emanating from the casings tied into new vaults. Each of the casings will contain fourteen 6-in. (15 cm) diameter conduits.

The substation will have a maximum total network load of 75 MVA for each of the five network systems, and none of the separate four 12.4-kV feeders in each network will exceed 15 MVA load. Load balancing will balance primary feeders within a +/- 10% tolerance [2].

The new design will supply networks with a standard four-feeder system, and will provide future back-up capability for existing substations.

Technology

PSSE

PGE’s Planning Engineers use the PSSE application, which supports electric transmission system analysis and planning, and is used for modeling and simulations [3]. PSSE can model networks with up to 200,000 buses, and users can perform steady-state contingency analyses and test corrective actions and remedial schemes. Users can analyze balanced and unbalanced faults, as well as perform deterministic and probabilistic contingency analyses. PGE can use the system to model substation topology, and users can anticipate potential network issues and model alternatives. PSSE includes a comprehensive library.

PSSE supports a number of analyses, including:

Power flow
System dynamics
Short circuits
Contingency analyses
Optimal power flows
Voltage stability

The system is compatible with other systems, and add-ons support bidirectional flows and the modeling of distributed generation installations [4].

PSSE is presently only able to model three-phase loads, not single-phase loads. PSSE is also unable to show loops graphically and creates errors when modeling the secondary network, which has prevented accurate models. PGE is transitioning to CYME software, which is presently used for the radial system, and intends to add the secondary network. To do this, PGE will use ArcGIS/ArcFM to model and display loops.

Geographic Information System (GIS) – ESRI ArcGIS

To support planning, engineers use ArcFM, which is built upon ESRI’s ArcGIS system. Users can access ArcGIS mapping software via a browser, desktop application, or mobile device, and organizations can share maps and data. ESRI’s system allows users to capture, analyze, and display geographical information, enabling display of maps, reports, and charts.

GIS is used to map assets and circuits, and can be linked to the customer information system and other enterprise applications. The maps provided with ArcGIS include facility maps, circuit maps, main line switching diagrams, and a service territory map [5,6].Operators can use ArcGIS to schedule work and dispatch crews, and they can also locate crews and view work status and progress [7].

With ArcGIS, operators and crews can locate assets and infrastructure, as well as determine how they are connected. The view of the electrical system includes connectivity, service points, and underground assets. Crews can follow how current flows through the interconnected network and determine upstream and downstream protective devices. The GIS allows users to overlay external data, including images, county maps, and CAD files onto the map view.

The GIS includes ArcMap and ArcFM viewer, which allows designers to use compatible work units and send these to the Maximo system. In 2017/2018, PGE will investigate processes for transferring ArcGIS information into CYME.

Other Software Applications

PGE uses an Enterprise Resource Planning (ERP) system called PowerPlan, which has an Oracle attachment named “Pace.” This system provides financial data about projects. Other technologies used for planning include SharePoint, Field View, the PGE Engineering Portal, PI ProcessBook, and the T&D Database.

Maximo for Utilities 7.5

IBM’s Maximo for Utilities 7.5 system supports asset and work management processes for transmission and distribution utilities, covering most asset classes and work types. The system allows users to create work estimates and manage field crews. Maximo can integrate with a number of systems, including fixed-asset accounting, mobile workforce management solutions, and graphical design systems. The Maximo Spatial system is compatible with map-based interfaces, such as ESRI ArcGIS, and follows J2EE standards [8].

Maximo for Utilities supports operations across a number of areas:

A compatible unit library helps planners and designers estimate compatible units when creating a project.

Maximo 7.5 can upgrade with several optional modules, including the Asset Management Scheduler, which allows tasks to display in a Gantt view that shows the task dependencies and durations specified in the work order. The Spatial Asset Management module includes a map-based interface to track assets and locate work order and/or service request locations [9].

The PowerPlan Adapter is a corporate-level suite intended to facilitate accounting during operations. The system automates asset lifecycle management and supports compliance monitoring. The PowerPlan Adapter aggregates work orders and ensures that all aspects of a task are included. Users can add costs for labor, materials, and contractors when they arise [10].

Asset Resource Management (ARM) Field Manager: ARM Field Manager is a mobile platform that allows crews to access and report data for all work, including customer service information, emergency situation reports, procedure-based maintenance work, and compatible-unit based construction work.

Outage Management System (OMS)/Oracle NMS

PGE migrated to an Oracle NMS outage management system, which is based upon Websphere technology [11]. Oracle NMS is a scalable distribution management system that manages data, predicts load, profiles outages, and supports automation and grid optimization. The system combines the Oracle Utilities Distribution Management and Oracle Utilities Outage Management systems into one single platform. The system supports outage response and the integration of distributed resources [12].

Oracle NMS blends SCADA function and GIS models to combine as-built and as-operated views of the system. The application includes a number of advanced distribution management functions, including network status updates in real time, monitoring and control of field devices, switch planning and management, and load profiling. Oracle NMS can integrate with other supervisory control and data acquisition (SCADA) and GIS systems, and monitors network health-using data from a number of systems [13]. The NMS includes a simulation mode for training and supports switch planning and control.

Oracle NMS maintains a network model that handles the whole grid, includes every device, and integrates with existing systems using standards-based protocols such as Inter-Control Center Communications Protocol (ICCP), Common Information Model (CIM), and MultiSpeak-based web services. The system can also integrate with a range of GIS and advanced metering infrastructure (AMI) systems.

PGE’s NMS/OMS integrates outage information, location, switching, and work management functionality into a single system, in which operators can view and manage system status and operational data in real time. The system uses a data model to predict the location of outages and can present data on a dashboard via customized reports.

Marquam Substation Project Quick Facts. Portland General Electric., Portland, OR: 2017. Click this (accessed November 28, 2017).
Portland General Electric, Marquam Substation Network Distribution Ductbank Casings, internal document.
Siemens. “Power Transmission System Planning Software.” Siemens.com. http://w3.siemens.com/smartgrid/global/en/products-systems-solutions/software-solutions/planning-data-management-software/planning-simulation/Pages/PSS-E.aspx (accessed November 28, 2017).
PSS®E High-Performance Transmission Planning Application for the Power Industry. Siemens AG, Energy Sector, Erlangen, Germany: 2009. https://www.energy.siemens.com/hq/pool/hq/services/power-transmission-distribution/power-technologies-international/software-solutions/pss-e/psse_brochure_200902.pdf (accessed November 28, 2017).
ArcGIS Solutions. “Electric Facility Maps.” Solutions.ArcGIS.com.http://solutions.arcgis.com/utilities/electric/help/electric-facility-maps/ (accessed November 28, 2017).
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).
GIS for Electric Distribution. ESRI, Redlands, CA: 2010. http://www.esri.com/library/brochures/pdfs/gis-for-electric-distribution.pdf (accessed November 28, 2017).
T. Saunders, J. Souto Maior, and V. Garmatz. “IBM Maximo for Utilities.” IBM, 2012. ftp://ftp.software.ibm.com/software/tivoli_support/misc/STE/2012_09_11_STE_Maximo_for_Utilities_Upgrade_Series_v4.pdf (accessed November 28, 2017).
IBM. “IBM Maximo for Utilities, Version 7.5.” IBM.com.https://www.ibm.com/support/knowledgecenter/en/SSLLAM_7.5.0/com.ibm.utl.doc/c_prod_overview.html (accessed November 28, 2017).
Maximo Adapter. PowerPlan, Atlanta, GA: 2017.https://powerplan.com/resources/minimize-risk-and-optimize-maximos-implementation-with-powerplan (accessed November 28, 2017).
Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.
Siemens. “Power Transmission System Planning Software.” Siemens.com. http://w3.siemens.com/smartgrid/global/en/products-systems-solutions/software-solutions/planning-data-management-software/planning-simulation/Pages/PSS-E.aspx (accessed November 28, 2017).
Modernize Grid Performance And Reliability With Oracle Utilities Network Management System. Oracle, Redwood Shores, CA: 2014. http://www.oracle.com/us/industries/utilities/046542.pdf (accessed November 28, 2017).

4.17.15 - SCL - Seattle City Light

Design

Organization

(Culture)

People

Network Design at SCL is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A. The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Documentation

SCL utilizes a Network Construction Guideline that includes sections that inform design and construction. The Guideline contains sections for:

Safety
General items, such as voltage and current tables for cables
Drawing standards
Cable installation and testing
Services
Cables, bus bars and secondary taps
Primary splices and terminations
Transformer installation and vault preparation
Duct and pole risers
Vaults and handholes
Streetlights
Meters

4.17.16 - Survey Results

Survey Results

Design

Organization

Survey Questions taken from 2015 survey results - Summary Overview

Question 10 : Which of the following functions does your network engineering/planning group(s) perform? (check all that apply)

Survey Questions taken from 2012 survey results - Design

Question 4.1 : Do you have a dedicated / distinct network design group? Or are your network designers part of a design group that also performs non network design?

Question 4.2 : If yes, does your network design group do both electrical and civil designs?

Survey Questions taken from 2009 survey results - Design

Question 4.1 : Do you have a dedicated / distinct network design group? Or are your network designers part of a design group that also performs non network design?

Question 4.2 : If yes, does your network design group do both electrical and civil designs?

Question 4.3 : How many people perform Network Design at your company?

4.18 - Power Quality

4.18.1 - AEP - Ohio

Design

Power Quality

People

Power quality issues are addressed by the Customer Service Representatives working with the Network Engineers and the Network Engineering Supervisor in the downtown Columbus offices. Engineers can assist customers with power quality monitoring and also make recommendations for solving power quality issues.

Process

AEP Ohio has not experienced many issues with poor power quality in its network system. Most power quality issues are confined to customers’ on-premises switchgear, such as backflow from elevators.

4.18.2 - Ameren Missouri

Design

Power Quality

People

Power Quality issues are addressed by the Engineering Group within Distribution Operations, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Process

Ameren Missouri historically has had very few power quality issues arise in their network.

4.18.3 - CEI - The Illuminating Company

Design

Power Quality

People

Within the Regional Engineering department, CEI has a group that is focused on reliability and power quality (Reliability Group). The group is comprised of 11 people who focus on reliability performance improvement and reporting for the Illuminating Company (overhead and underground system performance). The Reliability group works closely with Underground Group and with Asset Management.

Process

In general, CEI’s approach to power quality is reactive; that is, they will perform power quality monitoring at a customer’s location upon receiving a complaint, or after a service issue has been raised. One exception is at major customer sites, such as an automobile plant, where they will employ proactive PQ monitoring.

Technology

CEI uses industry accepted power quality monitoring equipment such as recording monitors from Dranitz – BMI. They will utilize the software that was provided with the recording device to perform analysis.

4.18.4 - CenterPoint Energy

Design

Power Quality

People

The analysis of power quality issues with Major Underground infrastructure is performed by the Major Underground Engineering department. Most of the analysis is performed by the Consulting Engineer within the department, although other resources will be used as required, depending on the nature of the issue.

Process

Customer power quality issues typically come through the Key Accounts group. For example, a major customer may report that their chillers are tripping off or their computers are going down. The Key Account representative will mobilize the appropriate CenterPoint resources to respond to the complaint.

Technology

CenterPoint uses industry accepted power quality monitoring equipment such as recording monitors from Dranitz – BMI. They will utilize the software that was provided with the recording device to perform analysis.

4.18.5 - Con Edison - Consolidated Edison

Design

Power Quality

People

The Power Quality (PQ) group monitors PQ performance systems in networks and stations for the whole company. The department consists of three engineers, two technicians, and one specialist.

The group’s main focus is on customer analysis and problem resolution. In many cases, customer controls are too sensitive and respond to sags on the system. For example, Con Edison might experience a feeder lockout, and a customer control system could see a sag on the system, causing their facilities to trip (for example, elevator controls). In many cases, the solution is for the customer to change the settings on their controls to be less sensitive.

Process

The PQ group installs power quality monitors on the secondary of the network. More specifically, they select a multi-bank location in the middle of the network. They put the monitoring apparatus on the secondary bus, in a customer space. They do this for every network.

The group also places one PQ monitoring node in the area station that supplies that network. This monitoring point monitors the primary system behavior. The utility currently has installed a PQ node on the sub for each network in 48 out of 57 stations, with completion scheduled for the summer of this year.

Con Edison is in the process of placing a PQ monitoring node at every transformer in the station.

Technology

The older PQ monitoring installations use telephone lines to communicate information; the newer installations use Ethernet. Con Edison has worked with Dranetz to design new plug and play PQ meters for new installations.

The PQ group uses PQ view (from EPRI) to analyze the numbers and display the monitored information on PQ web. They also use PQ View to display information from their RTF application. RTF is Con Edison’s technology for predicting the location of faults in the underground (see the following RTF Application discussion).

Con Edison desires a flexible system that can integrate PQ data with other data, such as SCADA data. They are accomplishing this on a small scale using their heads up display (HUD) system.

4.18.6 - Duke Energy Florida

Design

Power Quality

People

Reliability management is the responsibility of the Network Planning group at Duke Energy Florida, which is organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I), led by a Director of PQR&I for Duke Energy Florida.

To perform planning and reliability management work, the group divides the Duke Energy Florida territory into four separate zones. The cities of Clearwater and St. Petersburg, part of the South Coastal Region, are included in one of the four zones. Every zone is assigned a Lead Planning Engineer and Senior Planning Engineer, who are responsible for all distribution planning activities within the zone.

Engineers/Planners in these zones work on Reliability as well as Planning. Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time planning reliability and infrastructure upgrades.

All Planners have four-year degrees in Electrical Engineering, a requirement for the position.

Process

Because of the inherently reliable nature of the network design, and because their network system has been well maintained, Duke Energy Florida has not experienced major reliability problems. They also have not experienced power quality complaints from customers in their network.

Duke Energy Florida does have a hardening effort underway which includes replacement and upgrades of network infrastructure, such as replacing oil switches with solid dielectric vacuum switches, rebuilding deteriorated vault roofs and grates, and replacing cable and components that are aging or with which they have experienced performance issues.

Duke Energy Florida does have a remote monitoring system installed and is collecting asset data. Some of this information, such as frequent network protector operations, is used by the Network Group as a trigger for action. Other information, such as network transformer data, is being collected, but is not yet being used to trigger action. Duke Energy Florida’s goal is to expand the use of condition based analytics.

Technology

Duke Energy Florida has installed remote monitoring in its vaults. It uses a Qualitrol system to monitor information such as transformer oil level and temperature, and the status of the Oil Minder system. It uses the Eaton VaultGard system to aggregate information from the protector relay, such as voltage, current, protector position, etc. VaultGard also aggregates information from the Qualitrol system. Information is communicated from the VaultGard collection box via cellular communications by Sensus, a third party aggregator of information.

In the Duke Energy Florida design for spot network services within building vaults, the network system ground is separate from the building ground.

4.18.7 - Duke Energy Ohio

Design

Power Quality

People

Duke Energy Ohio has a Power Quality group. This group is located in downtown Cincinnati, and are part of the Distribution Design organization within Field Operations.

Power quality issues associated with the Cincinnati network are usually addressed by the network Project Engineer. The Power Quality group assists the Network Project Engineer in resolving PQ issues.

Technology

Duke Energy Ohio has installed power quality monitors in their network substations at the transformer secondary. These monitors measure the current, voltage, power, and reactive power of each network feeder. These monitors also provide total power . / reactive power for each secondary network grid. The monitored information is tied in with the SCADA system.

Duke is not using routine sub cycle monitoring of network feeders. They will install digital fault recorders on network feeders when addressing a power quality issue.

4.18.8 - Energex

Design

Power Quality

People

Certain engineers or the Standards group within the Asset Management team supervise power quality issues throughout the network.

Process

Energex installs power quality monitors on the low voltage side of all distribution transformers greater than or equal to 300kVA, on substation transformers.

Energex is looking at moving to a 230-V standard (similar to Europe), where they are currently at 240 V +/- six percent. They believe there is enough tolerance for most residential customers to accept 230 V, except at industrial/manufacturing sites, which are at 250 V.

Technology

Voltage monitors are used throughout system for under/over-voltage monitoring.

4.18.9 - ESB Networks

Design

Power Quality

People

ESB Networks has a notable planning and documentation process that is based on continually updated criteria and standards. Input for planning and execution of projects can originate in any level of the company, from field crews through upper management.

ESB Networks standards cover all major aspects of the planning of its network underground system, including continuity, power quality, operational switching arrangements, substation designs, and environmental issues.

4.18.10 - Georgia Power

Design

Power Quality

People

Power quality issues are addressed by engineers in the Network Operations and Reliability Group, part of the Georgia Power Network Underground group. This group is responsible for remotely monitoring the network system. The Operations and Reliability Group is led by a Manager and is comprised of four-year degreed test engineers, and test technicians who deal system reliability issues, including power quality.

To advise customers on power quality issues arising on the customer’s side of the meter, Georgia Power has an Enhanced Power Quality group in the marketing department. This is a group of engineers who can assist customers with power quality monitoring and also make recommendations for solving power quality issues.

Process

Georgia Power has not experienced many issues with poor power quality in its network system.

4.18.11 - PG&E

Design

Power Quality

People

Power quality issues that arise in the network are normally addressed by the network planning engineer. PQ complaints in the network are rare, and usually stem from problems on the transmission system.

PG&E does have a separate Power Quality group that responds to PQ complaints. Within the Power Quality group, they have an engineer with over 15 years of experience in responding to PQ issues. The Power Quality group would typically assist the network planning engineer in resolving a PQ complaint.

4.18.12 - Portland General Electric

Design

Power Quality

People

Special Tester: The Special Tester position plays a major role in maintaining power quality and reliability throughout the system. Special Testers respond to power quality issues and voltage complaints.

The Special Tester assigned to the CORE has experience as a journeyman lineman, and has received additional training and technical skills, including a focus on network protectors and performing infrared (IR) thermography.

IR Technician: PGE also has an IR technician (IR tech) position. IR techs inspect primary systems and network protectors as part of the Quality and Reliability Program (QRP), a reliability-focused program offered to high-value customers. PGE has three IR techs who mainly focus on the transmission system, though they also work on high-priority secondary systems. None are dedicated solely to the CORE.

Distribution/Network Engineers: Three Distribution Engineers cover the underground network and have responsibility for network reliability. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. The underground Distribution Engineers are qualified electrical engineers.

Key Customer Manager (KCM): PGE has nine KCMs reporting to Manager of the Business Group. Generally, they are geographically distributed, with three on the west side, one downtown (and responsible for network customers), one in Salem, three on the east side, and one acting as a rover. KCMs liaise with large customers and communicate their needs. They may be involved when reliability or power quality issues emerge.

Process

Overall, due to the multiple redundancies in the design, the network is very reliable and has few outages. Accordingly, many of the reliability initiatives on the network and CORE focus on power quality and reliability for key customers. The network has few power quality issues and most arise when customers install 240-volt-rated equipment in a 216-volt environment. As a result, PGE is not presently investing in any significant hardening of the network infrastructure.

QRP Customers: In 2004, PGE offered the QRP to high-value customers requiring very high reliability. This program entails a high-level focus on quality and reliability, and targets 24 high-profile distribution and transmission customers.

QRP customers receive reliability reviews from PGE, including:

An annual walk through inspection of underground facilities, including IR and visual inspections of equipment including splices, connectors, transformers, and pad-mounted switches
Suggested targeted reliability improvement projects, including liaising with some major customers concerning distribution automation pilots
Power quality metering with I-Grid or PML
Tracking SEMI F47 power quality events, including momentary interruptions
Root cause analysis for any events affecting service
Meetings with account representatives, engineers, and field staff
Crew checklist with requirements for hipot (high potential) testing all underground cables for all non-residential cables larger than 2/0 AL. This circuit verification is performed on network cables which have been out of service, before reenergizing the feeder. The crew foreman and Special Tester sign the checklist and it adds to the job records.
Partial Discharge (PD) testing of newly installed cable terminations and splices
Use of cable injection to extend the life of direct-buried cables
Increased budgeting to replace cables with repeated faults or corroded concentric neutrals
Installing all new primary cables in conduit
Using all jacketed cables
Transitioning from direct current (DC) hipot methods to alternating current (AC) very low frequency (VLF) cable testing of older cables
Continue to maintain an on-line cable testing database of hipot readings and cable failures
Root cause investigations and analysis on all significant outage events due to human error, equipment, or material failures

As part of QRP, IR inspections are performed on network infrastructure on a four-year cycle. This inspection includes all the primary infrastructure, beginning at the substation and including the network unit. The Special Tester or an IR tech perform inspections. Where resources permit, they may also IR test secondary systems.

PGE performs other activities as appropriate to bolster the reliability of the infrastructure to key customers. One example is the use of standby generators at one major customer to improve reliability and increase capacity. At another major customer, PGE is piloting the use of bolted connections for splices instead of compressions connections that have been traditionally used. For the purpose of this pilot, and to meet customer expectations, PGE is photographing each of the splices and the Standards Group is tracking the performance of the bolted connections.

Other Reliability Programs

PGE has a number of reliability programs for all its underground systems, including:

Monitoring Reliability (Non-Network): PGE’s Outage Management System (OMS) tracks and logs outages, and is integrated with the Customer Information System (CIS), GRID (an electronic map-based connectivity system), outage histories, and interactive voice response (IVR). All of this information is collated and a monthly evaluation ensures that the data is accurate. This verified data is used to calculate System Average Interruption Duration Index (SAIDI), System Average Interruption Frequency Index (SAIFI), and other data presented in PGE’s Annual Reliability Report.

Momentary outages are logged and recorded at substations equipped with supervisory control and data acquisition (SCADA) and MV90, a system that collects data at meters. Of PGE’s 146 distribution substations, 59% are fitted with SCADA and 35% with MV90. The remaining 5% of substations with neither system have readings taken monthly [1].

Power Quality:

Voltage Problems: PGE places recorders on circuits entering buildings if engineers need to understand what could cause voltage problems. The Special Tester downloads the recordings onto computers to analyze the issue. The Special Tester assigned to the CORE experiences slightly different issues then testers working on the radial system.

On the CORE, testers perform fewer recordings and work closely with the Network Engineers. One of Special Testers’ main jobs is to test the network protectors. They test the network protectors on the 480 spot networks once a year and the grid networks (125/216) every two years. The network protector testing is presently on schedule.

Fault Locating: To locate faults, crews use a DC hipot thumper, which all special testing crews have in the truck. Testers travel from manhole to manhole until they locate the fault.

Technology

PGE uses Oracle Network Management System (NMS) as an OMS system. Oracle NMS can integrate with CIS, GRID (an electronic map-based connectivity system), outage histories, and IVR to produce reliability metrics. Momentary outages are logged and recorded at substations equipped with SCADA and MV90, a system that collects data at meters [1].

Seven-Year Electric Service Reliability Statistics Summary 2007-2013. Oregon Public Utility Commission, Salem, OR: 2014. http://www.puc.state.or.us/safety/14reliab.pdf (accessed November 28, 2017).

4.18.13 - SCL - Seattle City Light

Design

Power Quality

Unspecified

4.19 - Spot Network Design

4.19.1 - AEP - Ohio

Design

Spot Network Design

People

Spot network design of the networks serving Columbus and Canton Ohio, the two areas of focus for this urban underground network immersion study, is performed in Columbus by the AEP Network Engineering group, which is organizationally part of the AEP parent company. Within the Network Engineering group, the company employs two Principal Engineers and one Associate Engineer who are responsible for network design for AEP Ohio. These planners are geographically based in downtown Columbus at its AEP Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, and is organizationally part of the Distribution Services organization, reporting ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the Director of Engineering Services who in turn reports to the AEP Vice President of Customer Services, Marketing and Distribution Services. In addition to responsibility for designs of the AEP Ohio networks, the Network Engineering group also provides consultative support services to the other AEP operating companies.

Two Principal Network Engineers primarily oversee the designs for Columbus networks; one Associate Network Engineer primarily oversees Canton, but often helps with Columbus-based projects. The Network Engineers are responsible for all aspects of the network design, from inception to implementation, including the preparation of work orders, material acquisition, site inspections, and project completion.

The Network Engineers perform all aspects of spot network design, including network unit design, equipment sizing, performing load flow analyses, vault designs, and preparing job drawings that describe the designs. A Technician assists the engineers with the preparation of drawings using MicroStation and AutoCAD. This is a full-time position and is assigned to the Network Engineering department.

Process

New service requests in the downtown areas served by AEP Ohio networks are referred to the Network Engineering group by Customer Service Representatives. Rather than dividing the territory by geographic location, AEP Customer Service Representatives are assigned service types, such as public works, new office construction, manufacturing, etc. In contrast, the Network Engineers divide the system up geographically, with each Network Engineer having responsibility for two networks (four total networks in Columbus and two in Canton). The Service Representatives know which Network Engineer to contact for customers services according to the location.

AEP has seen growth in spot network load in its downtown networks. Engineers note that while load on the network grids is declining, new buildings are moving into the cities and many are taking service through a spot network, while others are being served with radial designs using pad-mounted equipment.

Spot networks at AEP Ohio provide service at 480 V. In keeping with its double contingency design for its Columbus networks, each spot network has at least three transformers. Transformers are sized such that if any two transformers of a three unit spot are down, the remaining unit can carry the peak load and retain service to the customer.

Newer spot network vault designs include wall-mounted solid dielectric vacuum switches for each primary feeder supplying the spot, EPR insulated primary cables terminating on the network transformers with an ESNA style connection (elbows or T bodies), and transformer mounted network protectors (see Figures 1 and 2).

Figure 1: Wall-mounted vacuum switch

Figure 2: Primary termination on transformer

Protectors are designed with secondary disconnects to be able to separate the protectors from the collector bus (see Figures 3 and 4).

Figure 3: Network protector

Figure 4: Non-load break disconnects to separate protector from secondary bus work

AEP has historically used multiple collector bus designs, including bus duct, open copper bus bar, and cable bus designs. Its preference and current standard is to use a cable bus design that utilizes crabs (see Figure 5). AEP also installs disconnects between the secondary bus and the customer service (see Figure 6).

Figure 5: Spot network vault secondary cable bus – note use of vertically mounted crabs

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Figure 6: Non-load break disconnects separating customer service from secondary cable bus

Spot network vaults are designed with systems that will de-energize vault components in the event of certain alarms. For example, a fire alarm system will drop the entire vault by opening primary switches if collector bus temperature sensor thresholds are exceeded. A transformer supped pressure alarm will result in the opening of the switch that supplies that transformer, dropping the unit from service.

AEP spot networks call for the customer to ties their ground to the building steel.

Technology

Network Engineers are guided by Network Design Criteria published by the parent company. CYME SNA and CYMCAP are used for circuit and load calculations and for producing network maps. Line drawings are developed in MicroStation and AutoCAD before turning them over to a Civil Engineer contractor to complete the civil designs. At the job conclusion, the “as-builts” are incorporated into CYME SNA and updated in the Smallworld GIS.

Design specifications include the following information:

Civil construction specifications, including customer vault dimensions
Full electrical components, and their specifications, including N-2 design criteria for transformers and feeders
Duct line specifications and grounding
Network protectors and Operation Center communications

4.19.2 - Ameren Missouri

Design

Spot Network Design

People

Design of the urban underground infrastructure supplying St. Louis, including spot network design, is the responsibility of the engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. The Underground Division, led by a manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including network and non network vaults and manholes, size equipment, perform load flow analyses, and prepare line drawings that describe the designs. All engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

The Energy Services Consultants (Estimators) take the one line designs developed by the engineers and complete the design package, including all the physical elements of the design. Estimators have a combination of years of experience and formal education, including two-year and four-year degrees, and are part of the union, IBEW.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis. Engineers who are assigned to this team will also participate in the design of spot network installations and indoor rooms.

Ameren Missouri has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. These standards and specifications are used by engineers and estimators in developing network designs. Standards are available in both online and printed book format.

Process

Most new services to larger downtown loads in St. Louis are served with a dual, primary metered feeder scheme: either two preferred feeders, or one preferred feeder and one reserve feeder. There are existing spot network services within St. Louis, but new services are not served via a spot network. In some instances, Ameren Missouri may connect a service to an existing spot.

Ameren Missouri designs spot networks to n-1 for peak load, planned or unplanned.

Most spot networks at Ameren Missouri supply 277/480.

Most spot network locations in St. Louis are located within underground vaults, not within building vaults.

Typically, small to medium loads 500kVA and less requiring 120/208V service are normally connected to the network grid. Customers with larger loads, or who request 480V service are normally served from either a padmounted transformer or an indoor substation. Padmounted services are usually not practical within St. Louis because of the downtown congestion. The most common design for larger loads in downtown St. Louis is the indoor substation (also called “indoor room”).

Larger customers often receive primary metered service, with Ameren Missouri providing two primary supplies to the customer. These primary supplies feed into switches, either fuses or breakers as chosen by the customer, and can be manually or automatically (auto transfer) operated. After the breakers, lines feed into the primary metering gear, and then on to the customer switchgear or transformation. Note that in this arrangement, all equipment except cable and meters are owned by the customer, including the primary switches that precede the primary metering point.

For a secondary metered customer, Ameren Missouri provides the switches and transformation that precede the metering point. In this design, Ameren Missouri may provide either a preferred and reserve feeder, or a two preferred feeder design.

In ascertaining expected customer load, Ameren Missouri will look at similar buildings to estimate demand using square footage and expected load density by customer type. They will also perform a load flow analysis to understand the impact on the system of connecting the new load. They will run both the normal and n -1 cases.

Technology

Most larger load locations within St. Louis are fed using non-network designs. However, Ameren Missouri does serve spot network locations throughout the city. These are true spot networks, with multiple primary feeders, transformers and network protectors supplying large load centers (high rises). Primary feeders are dedicated to supplying the spot network or street grid loads; that is, they do not serve radial customers.

Note that Ameren Missouri’s secondary network grid is a 216/125 V network - they do not have any 480 V secondary grids.

4.19.3 - CEI - The Illuminating Company

Design

Spot Network Design

People

The design of the network is performed by the CEI Underground / LCI group (Design Group), part of the CEI Regional Engineering group, located in NRHQ (Northern Region Headquarters).

Process

The Cleveland network serves only two spot networks, each with a 120/208V secondary. Most major customers in Cleveland are served primarily by CEI’s 11kV sub transmission system – see 11kV Non – network Service to Large Customers - Non-Network Service - Process

4.19.4 - CenterPoint Energy

Design

Spot Network Design

People

Spot Network design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group, the Padmounts group, deals with the design of three phase pad mounted transformer installations, including looped commercial developments. This group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is not typically involved in spot network design.

Another sub group, the Vaults group, focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. This group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. Note this group designs building vault spot networks.

The final subgroup, the Feeders group, is focused on distribution feeder design. This group focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

CenterPoint provides a spot network service to customers at 12kV with a 120/208 V secondary. Transformer sizes are usually either 600 kVA or 750 kVA units. Each vault is designed with a firm capacity of 120% of one of the banks, the remaining bank in a first contingency. So, for example, a vault with two 600kVA units would have a firm capacity of 720 kVA.

CenterPoint also provides a 480V spot network service in a customer provided building vault (dry vault). In this design, the primary disconnects are normally mounted on the wall, remote from the transformers. These vaults are typically supplied by either 1000 kVA or 1500 kVA units. Each vault has a firm capacity of N-1 with 120% overload. So, for example, a vault with two 1000 kVA units would have a firm capacity of 1200 kVA.

All vaults have a visible disconnect, either a blade that is open in air or gas that they can see, or an Elbow that is parked. Before they check for dead and ground, they must have a visible disconnect on every point feeding that cable.

Technology

Below are photographs of facilities in a typical building vault. Note that the transformer and network protector are physically separate, a standard design at CenterPoint.

Figure 1: Transformer and network protector

Figure 2: Spot network vault secondary buswork

4.19.5 - Con Edison - Consolidated Edison

Design

Spot Network Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Con Edison serves many spot networks (they call them 460’s). Typically, these consist of multiple transformers (with a 460-V secondary) located in vaults just outside a building, connected via secondary cables to network protectors located within the building. Con Edison has about 1800 transformers with a 460-V secondary. The utility has one limited 460-V street grid in Manhattan.

Note that in their spot network design, each network transformer is located in a separate vault, and within the building, each network protector is located in a separate room. In many cases, the transformers are located under the street outside the building, while the network protectors are located indoors.

In some cases, Con Edison serves a 460-V customer through a “Reach,” which is a term used to describe a situation where Con Edison serves a 460-V customer by tapping the 460-V secondary in one building and running cable to another. This arrangement “reaches” from one building to another. The utility installs a disconnect switch called a “Pringle Switch” (Eaton) to be able to disconnect.

4.19.6 - Duke Energy Florida

Design

Spot Network Design

People

Network design, including the design of spot networks at Duke Energy Florida, is performed by the Distribution Design Engineering group for Duke Energy Florida, which works out of offices in both downtown St. Petersburg and downtown Clearwater. The groups are responsible for designing new and refurbished network designs, as well as underground radial and looped distribution designs. The Distribution Design Engineering groups in Clearwater and St. Petersburg are led by a Manager, Distribution Design Engineering, and are organizationally part of a Distribution Design Engineering Group responsible for Duke Energy Florida’s Coastal region, led by a Director.

The Design Engineering group is comprised of two sub - groups: an Engineering group, comprised of degreed engineers, and a Technologists group, comprised of non-degreed Network Technologists. Work within the Design Engineering group, both in Clearwater and St. Petersburg, is assigned geographically, such that a designer (either an Engineer or a Technologist) is responsible for both network and non-network designs within an assigned geographical area. Some designers focus on commercial customers, while others focus on residential customers.

The Designers work closely with the distribution Planning group in designing spot networks. Planners perform load modeling and analysis and provide input to the designers. For new spot network locations, designers will develop and submit a preliminary design to a peer review group for comment and suggestions. This peer review involves construction personnel who will review the design for “constructability.” Work does not begin until a spot network design has been signed off by the review group.

The design of the network is also influenced by the Duke Energy Florida Standards group, which Group oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida.

Process

Duke Energy Florida has eight 277/480V spot networks locations in St. Petersburg. All are two feeder spot networks, some with two transformers and others with a four transformer configuration (In the four transformer spot, feeders use split, separated busses to the transformers, with the first feeder supplying the first and second transformer, and the second feeder supplying the third and fourth transformer). Two feeders supplying any one spot network are sourced from the same substation.

Note that years ago, downtown St. Petersburg did have a network grid, but the company moved away from that, with the spot networks being the only remaining secondary network installations in St. Petersburg. Most of the infrastructure in St. Petersburg is comprised of a primary and reserve feeder loop scheme, with automated transfer switches (ATS). The ATSs are tied in with SCADA and can be monitored and controlled from the DCC.

Spot networks are located in building vaults. At some locations, the installation is comprised of transformer secondary mounted network protectors. At others, network protectors are located separate from network transformers (see Figures 1 and 2).

Figure 1: Spot network location with pad mounted transformer

Figure 2: Indoor spot network location with separately mounted network protectors

Spot network vault civil maintenance, including maintenance of optional air conditioning, is the responsibility of the property owner. Many spot network locations include chemical fire suppression systems, installed at the owner’s expense. These systems are tested yearly by the property owners under Duke Energy Florida supervision.

Technology

Duke Energy Florida’s spot network design utilizes separately installed wall-mounted primary disconnect switches. Their current standard calls for a solid dielectric load break three-phase vacuum switch.

Figure 3: Solid dielectric primary disconnect switches supplying a spot network

At 277/480V, Duke Energy Florida has standardized on the CM52, a fully submersible protector with a dead front design. Duke Energy Florida’s network protector specification also calls for features such as:

External disconnects, which are used to separate the protector from the secondary collector bus. These disconnects are a safety feature used in a 480V design to mitigate arc flash risks. On this network protector, the NP fuses are internal and link style, as Duke Energy Florida is able to create the visible break between the NP and the secondary bus using the disconnects. Note that the disconnects can only be opened with keys which can only be accessed when the NP handle is in the open position because of an interlock system (see Figure 4).
Wall-mounted ARMS (Arc Flash Reduction Maintenance System) modules, which enable a worker entering the vault to change the protection settings in the protector to reduce the fault clearing time and thus the arc energy in the event of a fault (see Figure 5).
A submersible Stacklight, which is an annunciator system that indicates network protector status through a series of different colored lights(see Figure 4).

Figure 4: Top of network protector. Note the external disconnects and Stacklight

Figure 5: Control box for enabling ARMS system

Duke Energy Florida does not typically utilize a secondary collector bus in its spot network vault locations. Rather, secondary is run in cable trays to a demarcation point with the customer’s facilities. Limiters are typically not used between service runs and the customer.

Duke Energy Florida also uses a remote monitoring system. The company uses the Eaton VaultGard communication platform for recording and aggregating data from the network protector and vault. This information is communicated through a Sensus cellular monitoring system to a central server every half hour. Within the Network Group, information from Sensus, such as secondary loading, is monitored daily. Note that the Sensus system is read only, with the functionality to remotely control equipment being disabled for security purposes.

Figure 6 and 7: Spot network location

4.19.7 - Duke Energy Ohio

Design

Spot Network Design

People

Network design, including the design of spot networks, is performed by a Network Project Engineer and two Designers who are part of the Distribution Design organization. This organization is focused on all distribution design work for Duke’s Ohio and Kentucky utilities, including network design.

These resources work closely with one another and with the Planning Engineer focused on the network.

Process

Any significant new load within the geographic bounds of the Cincinnati network is served via a 480V spot network.

Technology

Duke Energy Ohio has 480V spot network locations throughout Cincinnati. These are true spot networks, with multiple primary feeders, transformers and network protectors supplying large load centers (high rises). Primary feeders are dedicated to supplying either the spot network or street grid loads; that is, they do not serve radial customers. There are a few isolated locations where a 480V service is fed from a spot vault to service an adjacent load.

Note that their secondary network grid is a 208 V network - they do not have any 480 V secondary grids.

Below are some photographs from a spot network vault.

Figure 1: Spot Network Transformer

Figure 2: Spot Network Protector

Figure 3 and 4: Secondary Cables from Protectors to Collector Bus

4.19.8 - Georgia Power

Design

Spot Network Design

People

Design of the urban underground spot networks supplying metropolitan area customers in Georgia is the responsibility of the network engineering group within the Network Underground group. The Network Underground group, led by the Network Underground Manager, consists of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure at Georgia Power. It is a centralized organization, responsible for all Georgia Power network infrastructures.

The Network Engineering group, led by the Network Underground Engineering Manager, is comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees. Engineers are not represented by a collective bargaining agreement.

In addition to the engineers with in the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also deal with issues of network design.

Engineers design the system, including spot network designs, vault designs, network unit designs, equipment sizing, perform load flow analyses, and prepare one-line drawings that describe the designs.. The design is then turned over to draftsmen who do final CAD drawings that detail all the specifications, both civil construction and electrical component, and input them into the GIS system. There are 12 design engineers and 5 draftsmen (called Technicians).

Georgia Power has a Standards Group that has developed construction standards and material specifications for designs and equipment used in the network underground. Standards are available in both an online and printed book format. Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. It is a living document, and the responsibility of the Standards Group comprised of the Principal Engineers in the Network Underground group. The standards are divided into two main sections: civil construction and network specifications and design.

Customer requests for receiving spot network service usually come in through the Georgia Power Marketing group. Some Marketing group members are degreed engineers, others are not. All have extensive experience in performing standard load calculations. The Marketing group is not represented by collective bargaining.

Process

New services to larger loads in Georgia urban areas are served either with a spot network service, or with a dual, primary radial feeder scheme: either two preferred feeders, or one preferred feeder and one reserve feeder. These radial feeder schemes often include the ability switch with a “PMH” type transfer – not a fast transfer scheme. This type of service is fairly extensive at GA Power, as customers perceive the transfer service with two sources as more reliable.

There is no difference in electrical rates seen by the customer between a spot network service and dual primary feeder scheme. Costs differences are associated with the upfront costs for the infrastructure that is provided by the customer to accommodate the installation, with network vault costs being higher because of the need for more area, a higher fault rating for customer switch gear, etc. If a customer requires dedicated reserved capacity on a reserve feeder as part of a dual feeder supply, they must may for that reserved capacity.

Typically, contracts come in from Marketing after a request for service to Georgia Power. This is the case for most large customers. It is customary for the Marketing representative handling the account to provide engineering with the load requirements for customer site. The group has a standard procedure to choose from models of different load types. The group can calculate load factors on all types of equipment, and project customer demand. The models do not require demand curves, only winter and summer peak load calculations, and the type of business the customer is engaged in. These factors are calculated before turning the project over to the design engineers.

Most spot networks on the Georgia Power networks are 480V. (They do have some 4160V spot networks). A typical spot network vault will be supplied by two or three network units located within the vault. These units are sourced by 20kV network circuits. Georgia Power will allow multiple units in the same vault (room), as transformers are insulated with FR3 rather than oil. The most commonly used transformer sizes for spot network locations are 1000 and 2000kVA units.

Georgia Power uses a fully insulated (EPR) bus conductor for its collector bus. This may be more costly than designs seen in other networks, but Georgia Power is satisfied that it adds another layer of protection and reliability to the system and to its customers. In 480V spots, Georgia Power will position a current limiting fuse on the protector spade leading to the collector bus.

Technology

Georgia Power uses its GIS system to keep extensive and detailed maps of all spot networks. Spot network maps and designs are now drawn up in a CAD system by design engineers and draftsmen. CAD maps and designs are fed into GIS. In addition, design engineers refer to the Standards Group online or hard copy book for standard designs and acceptable variations.

Georgia power has remote monitoring and control of all network protectors in spot network locations. At large customer locations, they may have bus monitoring installed as well. Information from the spot networks is tied to the Network Operations center either through radio, or through a fiber system.

4.19.9 - HECO - The Hawaiian Electric Company

Design

Spot Network Design

People

Underground network design is performed by the HECO T&D Division. This group is part of the Engineering Department. The group works closely with the Planning Division in network designs.

The group is comprised of 2 lead engineers, 13 design engineers and a supervisor. All are four year degreed engineers with about half the group having their PE license.

Process

HECO serves 27 spot networks in Honolulu, all with 480y/277 V secondaries. Note that most major customers in Honolulu are served by HECO’s radial non – network designed systems.

4.19.10 - National Grid

Design

Spot Network Design

People

Network design at National Grid, including the design of spot networks, is performed by the network designer. This designer, a Designer C, performs all larger and more complicated network designs, including spot network designs, both electrical and vault.. This individual has a two-year degree, a requirement for the position. This designer also performs non – network UG designs. This designer works very closely with the field engineer, part of Distribution Planning, assigned to the underground department to support the Albany network.

Organizationally, the Designer C is part of the Distribution Design organization, led by a manager, and part of the Engineering organization at National Grid. This organization is structured centrally, with resources assigned to and in some cases physically located at the regional locations. The designers who support the Albany network are both physically located at the NYE building, in Albany.

The designer is represented by a collective bargaining agreement.

Process

National Grid Albany designs spot networks to n-1 for peak load.

National Grid has a 277/480 V spot network system supplied by five 34.5KV feeders and serving fourteen spot network locations. Two additional large customers are dual fed primary voltage customers off of these 34.5kV feeders. There are also ten customers fed from 11 spot networks off of the 13.2kV general network feeders. Three of these are 125/216v, the rest 277/480v. Additionally, there is one customer fed off of two of these 13.2kV feeders through a padmount (PMH-9) switchgear. Note that the primary feeders supply only the spot network loads – National Grid Albany does not have a 277/480V secondary grid network. Spot network locations are designed to n-1.

National Grid’s design calls diversified duct line routes for primary feeders to minimize the number of feeders in a given duct line. National Grid uses arc proof taping of cables. All duct lines are concrete encased, including primary cable ducts, and secondary cable duct. .

Much of the existing primary and secondary system is built with PILC cables. National Grid’s current standard calls for EPR insulated primary cables. The secondary cable standard calls for EPR insulated cables with a Hypalon (low smoke) jacket.

A typical spot network will consist of two to four network transformers sized to meet loading requirements (National Grid uses transformers from 500kVA to 2500kVA in Albany - 300kVa are used in smaller networks; most spot networks are served with either 2000 or 2500 kVA units). National Grid uses submersible transformers with throat mounted submersible type network protectors. Transformers are equipped with a primary disconnect and grounding switch.

Typically, small to medium loads requiring 120/208V service will be connected to the network grid. Customers with loads > 800 kVA will typically receive a 277/480 V spot network service.

Most National Grid spot network vaults in Albany are located underground, rather than in building vaults. Some spot networks are at grade level or on building roofs. The buildings will supply the vault, providing space, lighting and ventilation.

In the National Grid vault design, the collector bus is supplied by the customer and located in a separate vault, with the customer’s equipment. National Grid runs secondary cables from the spot network units, through conduits and makes the secondary connections on the customer collector bus. National Grid uses cable limiters on secondary cables feeding from the network protector to the customer.

Technology

National Grid has 14 different spot network locations in Albany served from five primary 34.5kv feeders. These are true spot networks, with multiple primary feeders, transformers and network protectors supplying large load centers. Three of the five primary feeders supplying the spot networks are dedicated to supplying the spot network; that is, they do not serve radial customers. The other two feeders also serve other loads, one supplying a large primary metered customer, and the other serving as a substation tie. There are also ten customers fed by 11 spot networks, and one dual fed through a padmount PMH-9 switchgear on the 13.2kV general network feeders.

Note that their secondary network grid in Albany is a 208 V network - they do not have a 480 V secondary grid network in Albany.

Spot network vaults are equipped with a ground fault protection system designed to trip (open) all of the network protectors in the vault in the event of a ground fault. The customer is required to buy, install, and wire the National Grid approved ground fault protection system. Ground fault protection system equipment is installed in the customer’s electric room. However, a current transformer required to monitor neutral currents is installed in National Grid’s transformer vault.

Below are some photographs from a spot network vault.

Figure 1: National GridSpot Network unit Note - cable limiters protecting secondary cables feeding from top of protector

Figure 2: Secondary cables feeding into customer equipment room

Figure 3: CT that is part of ground fault protection system

4.19.11 - PG&E

Design

Spot Network Design

People

Network design at PG&E is performed by the planning engineers within the Planning and Reliability Department. This department is led by a Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems, and is also responsible for network design. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution design.

Both network planning engineers are four year degreed engineers. The planning engineers are represented by a collective bargaining agreement (Engineers and Scientists of California).

The planning engineers work closely with project estimators (Estimators or Senior Estimators) who develop cost estimates and perform field checks to see if the design laid out by the planning engineer is workable in the field. The estimators also prepare the job packet for construction. PG&E has project estimators located in local offices to work with smaller projects, and estimators located in their Resource Management Centers, who work with larger projects. The estimators that work on network design projects are located in the San Francisco division.

Planning engineers and Estimators are represented by collective bargaining, Engineers and Scientists of California (ESC).

Process

PG&E designs spot networks to n-1 for peak load.

Typically, small to medium loads 500kVA and less requiring 120/208V service will be connected to the network grid. Customers with loads from 500kVA to 1MW desiring 120/208V service can be supplied by a 120/208Vspot network. Loads greater than 1 MW will typically receive a 277/480 V spot network service. PG&E does not have a 277/480V network grid.

In ascertaining expected customer load, PG&E will look at similar buildings to understand demand. They will also perform a low flow analysis to understand the impact on the system of connecting the new load. They will run both the normal case and n -1 case. The decision of whether to serve a customer from the grid or a spot may depend on the impact of the load and associated infrastructure additions to the overall grid capacity. If, for example, adding a new customer and associated transformers helps the grid in an n-1 situation, PG&E may decide to serve the load from the grid rather than from a spot.

In the network, PG&E services spot networks using UG vault type transformers. Most times, the buildings will put their spot network vault underground, accessible from both the building and the sidewalk. Customers provide the space, lighting and ventilation.

PG&E will design the layout for the spot network vault and provide specifications for the customer. A typical spot network is served by three transformers. Note that PG&E’s design calls for no more than two transformers in any vault without fire isolation.

In most cases, PG&E does not require the customer to supply a secondary collector bus. Rather, they use secondary cables in cable trays and tie the secondary directly to the customer’s service using landing lugs on the customer bus stubs (bus bar). See Attachment B for a copy of PG&E’s Service Entrance From Underground Vault Using Bus Bars standard.

Note, sometimes in a 208V spot, the number of cables requires a collector bus.

PG&E covers their secondary cables with rubber mastic and ties their secondary cables into the secondary bus. PG&E does not use cable limiters in spot networks.

Technology

PG&E has both 208 V and 480V spot network locations throughout San Francisco and Oakland. These are true spot networks, with multiple primary feeders, transformers and network protectors supplying large load centers (high rises). Primary feeders are dedicated to supplying either the spot network or street grid loads; that is, they do not serve radial customers.

Note that their secondary network grid is a 208 V network - they do not have any 480 V secondary grids.

Below are some photographs from a spot network vault.

Figure 1: Spot Network Unit

Figure 2: Secondary Cables from protectors to secondary cable

Figure 3: Secondary Cables to customer service bus stubs

4.19.12 - SCL - Seattle City Light

Design

Spot Network Design

People

Organization

Network Design at SCL is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A . The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Process

SCL installs multiple network transformers with network protectors in the same vault to supply a spot network load. Depending on the size of the load, SCL may install two separate vault locations in the building. See Attachment C for an SCL schematic and photograph of a typical spot network vault installation.

SCL’s grounding practice in building vaults is to tie the system ground in with the building steel / grounding system.

SCL runs a separate low-voltage secondary neutral (in addition to the tape shield) through each vault tied in with the substation ground. This neutral is necessary for two reasons: to maintain ground connectivity to maintain the same potential from one vault to another, and to carry the neutral currents experienced with system imbalances.

Technology

Fire Protection

SCL uses both fire protection heat sensors and temperature sensors in vault design.

The fire protection heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225 ˚ F. SCL has installed fire protection heat sensors in 95% of its building vaults. These sensors are not utilized in “street” vaults.

The temperature sensors, part of the DigitalGrid (Hazeltine) system, send an alarm to the dispatcher at 40 ˚ C – well before the network protector trip threshold is reached. SCL currently has completed installation of these sensors in about 20% of their vaults. They plan to install these sensors in all of their network vaults (both in building vaults and in “street” vaults).

Cable Cooling System

SCL has designed and installed a novel chilled-water heat-removal system to increase the ampacity of cables at a certain location that was identified as a thermal bottleneck due to the number of adjacent network primary feeders, depth of burial, and other factors.

They have been successful in increasing the ampacity of these cables by 40% through the installation of this water-cooling system. See Attachment D for a detailed description of the project.

4.19.13 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.12 - 480V Spot Network Protection

4.19.14 - Survey Results

Survey Results

Design

Spot Network Design

Survey Questions taken from 2015 survey results - Summary Overview and Design

Question 25 : What is the typical number of feeders required to supply your spot networks?

Question 55 : If you have primary termination and switch on your network transformers, does your specification call for?

Survey Questions taken from 2012 survey results - Design and Summary Physical/General (Question 2.7)

Question 2.7 : How many feeders (minimum) supply your spot networks?

Question 4.11 : In a building vault, do you tie your neutral in with the building steel / ground system?

Question 4.12 : For the primary termination and switch, what does your typical network design utilize?

Survey Questions taken from 2009 survey results - Design

Question 4.10 : In a building vault, do you tie your neutral in with the building steel / ground system? (this question is 4.11 in the 2012 survey)

Question 4.11 : Does your typical network design utilize: (see Graph below) (This question is 4.12 in the 2012 survey)

4.20 - Standards

4.20.1 - AEP - Ohio

Design

Standards

People

Network standards for AEP Ohio are the responsibility of the Network Standards Committee. This committee has representatives from all AEP operating companies with urban electrical grid networks. The committee is responsible for formulating, studying, and recommending improvements or refurbishments to its operating company networks.

Note that while AEP’s approach to developing the standards is through this committee, selected engineers may “own” certain areas of standards focus. For example, one engineer is the point person for the network transformer standard, another engineer is focused on electrical stands, and another engineer is focused on civil standards. These point people work closely with regional representatives from across the system through the network standards committee.

Process

The network standards committee works closely with the parent company’s Distribution Services organization, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and reliability issues.

The following are examples of revised, modified, or new standards that were the direct outcome of teleconferences and studies made by the committee:

Replacement program for secondary cable
Adoption of the CM52 network protector
Upgrade to a new fiber-optic SCADA communications network
Use of “super vaults” wherever possible in new vault construction

Technology

Standards are available in both an online and printed format.

4.20.2 - Ameren Missouri

Design

Standards

People

Ameren Missouri has a Standards Group, led by a Managing Supervisor, and reporting to the Manager – Distribution Planning and Asset Performance. The Standards Group is responsible for developing and maintaining distribution standards for the company, including network equipment. This group also prepares material specifications for distribution equipment and engineering practice guidelines.

Within this organization are experts who focus on developing and maintaining specific underground standards. For example, they have a cable engineer, who is an expert with cable and cable systems, and responsible for the development of cable standards for the company (See Cable Design). Another example is a staff member who is a tools expert.

Standards Group engineers/subject matter experts are available to respond to questions and issues raised by the field force. The department has established key performance indices for service that include responding to materials issues within twenty calendar days.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis. Engineers assigned to this team will also participate in the design of spot network installations, and indoor rooms.

Process

Standards Group engineers work closely with the Service Test Group within Distribution Operations on developing equipment standards such as those for transformers and network protectors. Standards also work closely with Safety and Construction in the development of new construction standards.

Standards Group engineers visit each operating center at least annually to discuss issues with standards, communicate changes and gather feedback from the field force.

Standards Group engineers arrange and support training in new materials and equipment. For example, standards engineers participate in annual refresher training of the network unit delivered to the field force by the Distributions Operations Group. The Standards Group also arranges vendor demonstrations for the field force of new or changed equipment.

The Standards Group has implemented a formalized Unsatisfactory Performance Report (UPR) process used by the field force to report problems with distribution materials. The process includes:

Claimant completes UPR form and submits to Supervisor of Standards - with sample of defective equipment if possible;
Supervisor enters case into UPR database and assigns to Standards engineer;
Engineer reviews report and sample, then determines response based on knowledge of item or report from manufacturer after submittal to manufacturer for analysis;
Engineer responds to claimant and forwards to secretary;
Secretary distributes to distribution list and posts on Standards website

(See Attachment B for a sample of the UPR form.) for a sample of the UPR form.)

Technology

Distribution standards and material specifications are available to employees in an on line format through an internal Ameren Missouri website, or in a printed book format. Updated standards books are issued about every two to three years. These updated include engineering practice guidelines.

The Standards Group issues a quarterly newsletter entitled “The Standards Report” that includes changes in standards that have occurred in the previous quarter as well as articles on relevant issues. (See Attachment C for a sample of the newsletter.) for a sample of the newsletter.)

4.20.3 - CEI - The Illuminating Company

Design

Standards

(Design Standards / Practices / Specifications)

People

FirstEnergy has a Corporate Operations Services organization which contains the corporate Design Standards organization.

The Design Standards organization is comprised of 9 people, either Engineers or Distribution Specialists with field experience. The group is “equipment line” focused, with a primary individual and a backup individual focused on a given equipment line (cable, for example).

The group is focused on the material, and works closely with the supply chain, including the selection of suppliers.

In conjunction with construction practices for ducted systems, FirstEnergy has formed a system wide group, Ducted System New Product Review Committee, charged with reviewing materials and standards associated with network systems. The group is lead by a Senior Engineer within the corporate Design Standards group, and has representation from all Operating Companies, including CEI.

The group meets quarterly and focuses on sharing new materials and specifications. A main focus of the group is communication. For example, FirstEnergy recently issued a new network protector specification and utilized this forum to communicate the issuance of the spec across the system.

Process

The group develops Material Specifications, Construction Standards, and Engineering Practices Manuals.

Material specifications exist for most of the equipment used in ducted manhole systems (cable, terminations, elbows, T bodies,etc)

There are minimal system wide construction standards for networks and underground ducted systems. For example, there is no standard design for an underground vault. Most of the construction standards for ducted systems exist within the individual operating companies, and are left over from the time when standards departments existed within each operating company. The Ducted Systems Users Group, focused on identifying and addressing the needs of the ducted systems across the company, has recognized the need to develop system wide standards for networks / ducted systems, and has recommended doing so. (See Ducted Network Underground Users Group)

Engineering Practices are documents that provide an in depth explanation of selected technical duties. For example, an engineering practice may provide guidance on transformer sizing. FirstEnergy has developed two Engineering practices that focus on networks; and Underground Distribution Network Design Practice, and a Cable Limiter Application Policy for Secondary Network Areas. (See Attachment A and Attachment E)

Technology

Standards / Specifications / Practices are available to employees as a hard copy documents or on FirstEnergy’s intranet (local drive).

4.20.4 - CenterPoint Energy

Design

Standards

(Design Standards / Practices / Specifications)

People

At CenterPoint, the Distribution Standards and Materials group (Standards group) is part of Distribution Engineering & Services Electric Distribution Engineering Group, a separate group from Major Underground. This group is responsible for distribution standards and materials company wide.

Major Underground has a Staff Engineering Specialist who liaises with the Standards group. This individual, part of the Major Underground organization, coordinates with Standards to address inventory issues and specification issues, and to coordinate equipment failure root cause analyses. This individual also works with vendors to troubleshoot equipment problems. In addition, this individual will perform incoming material inspections for switches and breakers, and perform site evaluations of new vendors.

Note that for most high volume material, the Standards group has material coordinators assigned who interface with CenterPoint operating centers on material issues. However, in Major Underground, because of lower volume of materials, and generally higher unit costs, CenterPoint utilizes the Staff Engineering Specialist to liaise with Standards as described above.

The Service Center – Underground Operations, where the Major Underground group is located, houses the “parent” warehouse for underground material for CenterPoint.

Process

The Standards group develops construction standards for Major Underground with input from the Major Underground design groups (Vaults, Feeders and Padmounts Groups). Civil Construction standards are included in the standards.

The Standards group does not currently produce engineering guidelines for major underground design, but they are considering developing such a guide.

The Standards group issues a monthly newsletter highlighting material and standards issues. Hard copies of the newsletter are provided to the field force.

4.20.5 - Con Edison - Consolidated Edison

Design

Standards

People

Con Edison has excellent documentation of work processes, guidelines, and standards. In every case where EPRI would expect to see formal documentation of a specification or procedure, Con Edison was able to produce an up-to-date document. Moreover, the standards themselves were properly aimed at their intended audience, with field guidelines including bulleted lists, tables, drawings, and so on, to facilitate the use of the guideline by field employees.

In some cases, Con Edison standards exceed ndustry standards. For example, their transformer standard specfications are more stringent that general industry standards and the IEEE standards.

Con Edison has expert resources that stand behind the information in their written documentation, and revisit it to ensure its continued currency and relevance. For example, Con Edison has expert cable resources that produce their network cable specifications. These individuals stay current on cable trends and ensure that the specifications reflect the latest industry thinking.

Process

Underground Network Equipment Standards Committee

Con Edison has an underground network standards committee that meets periodically (usually about six times a year) to address issues with underground standards and equipment. The committee includes representatives from the Distribution Equipment Engineering department, the transformer repair shop, and field construction representatives, both union and management. At these meetings, the group reviews equipment failure causes and characteristics. The members of the team perform vendor visits and attend seminars to give presentations. Con Edison focuses the meeting content on current needs and issues, such as responding to a safety incident. Con Edison has found this committee to be highly valuable for identifying and resolving issues with equipment and standards.

4.20.6 - Duke Energy Florida

Design

Standards

People

The Duke Energy Florida Standards Group oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. This engineer is an Electrical Engineer, a requirement for the engineer who specializes in Network Standards. The engineer also has a PE license, a requirement to obtain certain levels within the engineer family. The Standards group reports to a Director, also required to be an Electrical Engineer.

Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies.

Duke Energy Florida has separate Overhead and Underground Standards documentation, with all content available on line. Network accessories are a separate chapter in the Underground book.

As a result of the merger between Duke Energy and Progress electric, the Duke Energy Florida Standards group is in the process of updating its Standards documentation, seeking to consolidate standards from the former companies and develop standard approaches where possible. This process is schedule to be completed mid-2017. The Network Standards book containing the Network Equipment subsection details both Duke Energy and Progress Electric (now Duke Energy Florida) equipment. The task of merging them is difficult as different equipment is currently deployed in the field. Wherever possible, the Standards group will recommend similar/equivalent equipment, depending on the deployment.

Process

Standards consist of both Overhead Standards and Underground (including networks) Standards books. Both are kept online. The Underground Standards book is broken out into sub-sections, such as Secondary Network Equipment, Switchgear, Cable, etc. (See Attachment F for a sample page from the standards book).

The group also maintains a Network Design Guidelines book, last updated eight years ago, which specifies recommended design criteria for networks, and a Network Training guidebook for recommended Network Engineer Training sessions. The training guidebook serves as an introduction to a training module covering network basics and includes documentation on Secondary Network Design.

For certain items, such as network protectors, the Standards book also details material specifications, used for purchasing equipment. For example, the Duke Energy Florida has standardized on CM22 (Eaton) network protectors, except at 480V spot network locations, where a CM52 is specified. Many of these specifications are determined in consult with the broader corporate wide Standards group. Duke Energy Florida standards engineers are planning to coordinate closely with engineers from Duke Energy Ohio to update Material specifications for network equipment, as the Ohio group has extensive network underground equipment.

As part of their process for modifying standards, all requests for changes in standards must go through the corporate Standards Committee, where approval can be granted or substitutes proposed.

A complication for the Duke Energy Florida Standards group is integrating its purchasing and procurement systems with the main accounting and ordering systems of the corporation. Florida underground Standards had to develop its own Compatible Units (CUs) for every component and work activity, and integrate it into the Duke corporate system. Previously, the Network group had work request numbers and ordered all CUs directly under that one number, rather than reporting/recording work and material in detail by CU. Commonly used network materials and components are now part of the main corporate system, with the exception of larger purchase items with long lead times, such as network transformers, which are special ordered.

Florida is in the process of moving its legacy Work Management and materials ordering system to Maximo. Once integrated with Maximo, contractors will also have the ability interface with the system.

Overhead Standards

Overhead systems are a part of the company Standards, which include all standardized components and materials for overhead construction. Most Overhead Systems are presented in the ordering system in a “kit” format (combinations of compatible units which comprise common designs) to simplify ordering and design work.

Manhole and Vault Standards

The Standards group reviews, approves, and publishes civil design standards for underground structures, such as manholes, duct lines, and vaults. Duke Energy Florida has existing, older specifications for pre-cast manholes, but is in the process of merging them with Duke corporate standards. Most new vault or duct line designs are custom built, however. As an example, the Standards Group, in cooperation with Network Designers, specified a custom vault for a spot network service to Duke’s new Distribution Control Center (DCC) including network transformers, network protectors, collector bus, and secondary services. The Standards group maintains documentation of “as builts” and any custom civil designs on the network. Vault and manhole design standards are contained in the “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D)

Cable Standards

Cable and Cable Accessory Standards are determined by the Network Standards group, in cooperation with the local (Duke Florida) and Duke Corporate Network Standards groups. Incoming cable and accessories are spot inspected to identify failures.

Failed cable samples are sent to a Duke Energy Florida Engineer for forensic analysis and/or sent to external laboratories for analysis.

One cable problem that Duke Energy Florida is addressing through standardization is related to currently installed T-body splices in the field. The older style center tap connection point between two T-bodies has an external, metal ring than can corrodes over time when submersed in water and creates a high stress point on the tap. Florida has standardized on a replacement center tap with an EPDM rubber coating. Florida is also evaluating whether T-bodies are necessary in new construction, particularly in locations where a three-way split is not required (simply connecting two cables). In these locations, they are substituting T-bodies, the historical design, with standard splices. One complication of replacing existing, corroded center plugs, usually found during inspections, is that many are underwater. If the water is removed (while energized), the plug may fault because it is using the water to de-stress. Experience has shown that if the water is removed, the center plugs typically fail shortly thereafter. Areas identified with the older style center plugs, with the exposed metal rings, are scheduled for replacement. Duke Energy Florida will de-energize the circuit segment to be worked and replace the center plugs as soon as possible. Standard operating procedure in the field is to spike the de-energized cable to make certain it is not live before any replacement work is performed.

Cable Splicing Standards

Duke Energy Florida currently utilizes push on and crimped splices as a standard, but is considering standardization on cold shrink splices using shear bolt connections as a future standard. Overall, older push on and crimp solutions have experienced some failures due to workmanship issues, and Duke Energy Florida believes that the new standard will minimize workmanship problems. The final decision had not been made at the time of this report, however.

Equipment Failure Reporting

Duke Energy Florida currently uses a Facility Management Data Repository to report and document failed equipment. The report, developed by Progress Electric, includes all relevant information, such as who discovered/reported the defect, where it happened, etc. These reports are issued as bulletins over the company’s internal network first to Standards, and then companywide via a Web portal. The emphasis at Duke Energy Florida is to catch defects before they lead to failures. The Network Group led the state in 2015 with these “good catches” that identified defects and corrected them before they caused network problems.

A Network Engineer is assigned to the Standards group who performs forensic analysis of failed components. Overall, however, Duke Energy Florida has seen very few failures over the years.

Technology

The underground network Standards guide is available online.

In terms of material, components, and work management, Florida is in the process of migrating from its legacy systems to Maximo, a Duke corporate standard. RTArm, by Logica Software, is now used by Duke Florida as a scheduling program, designed to support distribution operations. This will be integrated with Maximo, the system that is currently the Duke corporate standard.

Duke Florida also uses a company-wide Web portal for near miss and defective equipment bulletins. Engineers and Network Technicians can reference these bulletins, past and present, online.

4.20.7 - Duke Energy Ohio

Design

Standards

People

Duke energy has the standards department located in Charlotte. Within this organization, they have one individual, and engineer, who focuses in particular on developing and maintaining underground standards. This engineer works very closely with the field force. Any questions or issues with respect to underground equipment including conduit, faults, manholes, post, go through this individual.

The Standards department prepares the Construction Standards and a Construction Work Practices Book entitled the Underground Construction Handbook. These are two separate documents. The Construction Standards book typically describes standards at a higher level than the Construction Work Practices Book (Handbook), which drills down to the detail.

For example, for a standard for a lead splice, the Construction Standards book would contain a picture of the splice, stock numbers, pricing, etc. The UG Construction Handbook would contain detailed cutback requirements for preparing the splice.

See Attachment D for a representative splice drawing from the Underground Construction Handbook (A 15KV trifurcating stop joint drawing).

Note that Duke Energy is in the process of creating one Construction Standards book for the company, combining prior standards books used by Duke’s Carolina companies and Midwest companies. The current construction standards manual does not contain standards for network specific equipment such as network protectors or transformers. Duke has formed companywide team, with representation from around the company, to develop network standards.

Duke is not looking to create a common Construction Book for the company at this time, as these construction books contain location specific details of certain installations, such as details of the buss work at a particular vault in Cincinnati. These details are available on paper and online templates that can be used by designers. Note that because the Duke Energy system is combined of multiple operating companies, there is little standardization among the in-service construction across Duke Energy.

Process

Duke standards include detailed descriptions of the construction, drawings of the construction, as well as things such as stock numbers, pricing, and the amount of cluster labor associated with the installation of the standard, as well as any associated standards.

The standard department keeps these up-to-date on a regular basis. For example labor and material costs are revisited annually and updated based on a five-year rolling average of actual costs.

Construction drawings are usually developed in CAD or MicroStation.

Technology

Duke Energy displays its standards on an online standards viewer developed by Duke. This database includes standards for non-network specific components such as splices, but does not include network components such as network protectors and network transformers. Note that Duke Energy is in the process of creating standards for network equipment. They have defined the team, with participation from around the company, to develop standards for network components.

This software was developed by the standards department in collaboration with planning and the reliability and integrity group.

Standards information is available to field personnel through manual construction standard books located in the trucks.

4.20.8 - Energex

Design

Standards

People

The Standards group is comprised of engineers, mostly four-year degree qualified engineers, though some are engineering associate positions. The Standards group is a part of System Engineering, within the Asset Management group.

Energex has comprehensive engineering standards, construction standards, and maintenance standards. Standards are made available to employees on the internet. Energex performs a complete review of all standards on a one to three year cycle. As changes occur mid cycle, Energex distributes bulletins that provide the updated information to the employee base.

The Standards group also produces standard building block documents for different asset types, which serve as overall guides for installation of assets of each type. For example, Energex has a standard building block guide for network feeders, which serves as a guide for all planning, design and construction processes for all new feeder installations in substations, overhead and underground areas.

The Standards group also produces the material specifications for T&D materials. This group works closely with their counterparts from Ergon, a sister utility serving the remainder of Queensland, to develop specifications, and work closely with the vendors to evaluate products and with procurement to obtain products. Standards engineers perform the technical evaluation of all vendor offerings.

Process

The standards group has assigned a lead subject matter expert (SME) for each asset type. For example, one standards engineer may be the SME for new substation products. SMEs provide engineering support for issues that arise that are not covered in the existing standards guidelines.

Energex has also formed Operating Advisory Councils, with representatives from Standards, Design, and field resources who utilize the standards and materials specified by Standards. The OAC meets monthly, and includes jointers, who can provide real world feedback to the group on materials, tools, and standards. The OAC is also used to introduce new equipment. The OAC may establish dead trials of a new product at the Energex training facility performed by field workers to gather their feedback in the selection process.

Technology

Standards are all kept in documents in an electronic business management system. Standards manuals are updated and formally reviewed on a one to three-year basis. There are no hard copies of the standards; all are on the company intranet. Between formal reviews, when a new revision is made to the standards, it is posted in the appropriate manual and a bulletin is broadcast to company personnel. The bulletin details the change in standard and refers to the page number in the manual where the change has been made.

4.20.9 - ESB Networks

Design

Standards

People

Design standards for ESB Networks underground networks are developed by the Asset Investment group working closely with the Assets and Procurement group. Organizationally, both Asset Investment and Assets & Procurement are part of Asset Management. Within the Asset Investment group, there is a Specifications Group led by a manager. Within the Assets and Procurement group, there is an Underground Networks group which focuses on underground equipment such a cable, and a Strategic procurement group.

Process

Designs are comprehensively reviewed every five years. The recommendations and any changes are recorded and published on the ESB Networks intranet. In addition, engineers attend monthly meetings capturing information from field crews, planners, and asset managers for use in reformulating or proposing changes to design standards. For example, ESB Networks has moved to standardizing on SF6 switchgear due to its compact size and better resiliency in its underground network system. As a result, all new switchgear is SF6, and the company has a project underway to replace existing switchgear with SF6 over the next few years.

Technology

Design standards are reviewed and changes are recorded in the company online intranet for use by planners, design engineers, and contractors.

4.20.10 - Georgia Power

Design

Standards

People

Network standards are the responsibility of the Standards Group within the Network Underground group. The standards group is comprised of two principal engineers who work in the Network Underground group. One of these engineers reports to the Network UG Engineering group, and the other, directly to the Network UG Manager.

The Network Engineering group, led by the Network Underground Engineering Manager, is comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network, including standards and material specifications for network equipment.

In addition to the engineers within the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also support the development of network standards, policies, and procedures

Georgia Power maintains up to date material specifications and standards for network design and construction. The standards contain information pertaining to duct lines, manholes, vaults, cables, joints and terminations, services and network equipment.

The standards group also produces guidelines and functional requirements for vault design that are provided to customers responsible for the design of building vaults.

Process

Standards Group engineers work closely with the Testing Group within the Network Operations and Reliability group to develop equipment standards such as those for transformers and network protectors. The Standards Group also works closely with Safety, Maintenance, and Civil Construction in the development of new construction standards.

The standards group utilizes an informal process for vetting new standards with the work force. They will invite selected field foreman to the office and provide an overview of the new material. The Foreman will then introduce the new material to the field force. In the case of introducing a new device to the field, the standards engineers will prepare a demonstration, often with the participation of the vendor, and invite the field force to comment and provide feedback. This information is factored in before the new material is introduced to the field.

The process for reporting failed equipment is also informal. For example, if a splice fails, the decision of whether or not to perform a post failure forensics analysis lies with the field foreman. If the splice is very old, the foreman may decide that it simply came to the end of its life and not report it. If a newer splice, the foreman may package and send the failed splice into the standards group. Some forensics analysis of failed joints and terminations is performed by Georgia Power engineers, and other analysis is performed by NEETRAC.

Technology

Standards are available in both an online and printed book format. Standards were first documented and codified in the 1970s, and they include what was already documented on the network from the 1940s and any new standards developed since then. The standards are divided into three main sections: civil construction, and electrical specifications and design, and an engineering handbook.

4.20.11 - HECO - The Hawaiian Electric Company

Design

Standards

(Design Standards / Practices / Specifications)

People

HECO Construction Standards, Engineering Standards and Material Specifications are developed and maintained by the Technical Services Division within the Engineering Department.

The Technical Services Division is comprised of 9 people, either Engineers or Distribution Specialists with field experience. The group is “equipment line” focused, with a primary individual and a backup individual focused on a given equipment line (cable, for example).

The group is focused on the material, and works closely with the supply chain, including the selection of suppliers.

Process

The group develops and maintains Construction Standards, Engineering Standards and Material Specifications and for underground ducted systems.

Their Construction Standards book includes both standards for the construction of typical underground installations, such as a three phase pad mounted transformer installation, and Engineering Standards, such as a Conduit Application guide.

Technology

HECO Material Specifications are available to employees on the HECO intranet on a webpage established and maintained by the Technical Services Division.

The HECO Construction Standards are available to employees as a hard copy. HECO is currently in the process of adding these standards to the Technical Services Division web page.

4.20.12 - National Grid

Design

Standards

(Design Standards / Practices / Specifications)

People

Distribution standards, including standards for network equipment, are developed and maintained by the Distribution Standards group, part of Distribution Engineering Services. The group is also responsible for developing material specifications.

Distribution standards include a section on network equipment and enclosures, as well as separate sections for cables and joints. Standards are updated on a five - year cycle. The materials specifications section is updated annually.

The distribution standards for National Grid were developed by consolidating the pre - existing standards of the operating companies that now comprise National Grid. These standards include a section of standards that are representative of and applicable across all of National Grid, as well as standards that are uniquely applicable to one operating company or another.

Standards Engineers have a close working relationship with Work Methods resources (See Work Methods), also part of Distribution Services. This group serves as the eyes and ears of the field force, working closely with the field, performing job audits and writing underground operating procedures. Changes to standards are often communicated to the field through Work Methods and / or the use of Utility Bulletins (See Safety – Utility Bulletins.)

Standards Engineers also collaborate closely with the Underground Engineers.

Standards resources stay connected with industry happenings through continuing education and participation in industry groups such as IEEE.

Process

Distribution Standards are maintained on a five-year cycle.

The Standards group will annually communicate changes to the standards to the field through presentations. These presentations are used to communicate changes made to the standards book and to solicit feedback. New standards are reviewed, as well as the results of field audits (typically performed by Work Methods)

Field Audits, performed on random projects by Work Methods, are performed each year to identify and resolve issues with the standards and how they are being built. Work methods resources select jobs ad random, review the job design, and the “as built” construction to identify opportunities for improvement.

Ideas for new standards and materials are vetted and tested by the Standards group. As an example, the Standards group commissioned laboratory tests of various duct sealants before selecting a product as an National Grid standard.

National Grid’s process for reporting minor equipment defects is through the use of a Defective Equipment Report form. The person identifying the equipment defect would complete the form, and send it to Standards. National Grid has an Electric Operating procedure, EOP UG009, which tracks splice and other equipment failures. In addition, a splice form is required to be filled out by the splicing crew for splices made in conventional duct and manhole systems (not URD). These forms are given to a clerk for database entry.

For more significant defects or failures that may have resulted in significant outages or safety issues, National Grid will implement a formal incident analysis (IA) process. An IA team is formed with a team leader assigned by the company Safety Department. Standards would be involved in performing forensic analyses (either internally or externally) on failed equipment associated with the incident.

Technology

Distribution standards are available to field personnel both electronically and in manual form. National Grid maintains a standards website, which includes the ability to for the field force to submit questions. These questions are reviewed and answered on a weekly basis.

Figure 1: Underground Construction Standards Book

National Grid communicates changes through the Utility Bulletin, a brief write up used to quickly communicate information to the field force, engineers and supervision. Utility Bulletins may include information about new products, including how to apply them and when to use them, as well as issues of work methods or safety.

4.20.13 - PG&E

Design

Standards

(Design Standards / Practices / Specifications)

People

PG&E has a standards department, entitled Electric Distribution Standards and Strategy located in San Francisco. The department, part of the Distribution Engineering and Mapping group, is responsible for developing and maintaining distribution standards for the company, including network equipment.

Within this organization, they have experts who focus on developing and maintaining specific underground standards. For example, they have a cable standards engineer, who is an expert with cable and cable systems, and responsible for the development of cable standards for the company.

For network equipment, the Standards Department works closely with the Manager of Networks, also part of Distribution Engineering and Mapping. The manager of networks has lead responsibility for network equipment and has produced a program reference binder for the San Francisco and Oakland networks. This binder contains key information about the network systems, including network strategies, roles and responsibilities, project information, capital and expense budgets, detailed work procedures, information about maintenance programs, training, and pertinent engineering standards, including standards for vaults, manholes, transformers, and network protectors.

PG&E also has a position called Senior Distribution Specialist, part of the Electric Distribution Standards Strategy group. There is one senior distribution specialist assigned to the underground system. This specialist is a subject matter expert, and acts as an interface between the Standards Department and field resources. (See Senior Distribution Specialist for more information). Specialists act as the “eyes and ears” of the Standards Department, and meet with standards engineers every two months to address issues.

Process

Electric Distribution Standards and Strategy group convenes a Standards Committee comprised of standards representatives, field representatives, field supervisors, and the manager of networks.

Technology

Distribution standards, and the information contained in the San Francisco and Oakland Networks Program Reference Binder are available to field personnel both electronically and in manual form.

4.20.14 - Portland General Electric

Design

Standards

People

For PGE, the network Distribution Engineers develop and maintain the standards for the network, which are then forward to the Standards Department for inclusion in company standards. For example, network engineering developed the cable and submersible transformer standards for the network. The reason for this arrangement is that the Distribution Engineers have the knowledge of the equipment unique to network systems.

The network’s engineers use some informal standards for vault construction and are working with the Standards Department to formalize the process. Network engineering is ultimately responsible for the design and specifications of vaults and vault equipment, and has overall responsibility for the appropriate standards.

Service & Design Project Managers (SDPMs) may also be involved in developing network standards. For example, one network SDPM is working on a standard for customer-owned vaults that house PGE equipment. This is often the case in spot network locations, where the customer provides the vault to PGE specifications, and PGE owns the equipment inside the vault up to the interface with the customer at the collector bus.

The Manager of Distribution Engineering and T&D Standards oversees the Standards Department. The group employs one technical writer and four standards engineers.

Process

Network Documentation: At present, PGE is working on developing formalized standards and specifications network equipment. The written specifications presently covering the network include network transformers and cables. PGE does not have a specific material specification for a network protector but has standardized on the Eaton CM52.

These standards are primarily material specifications that inform the purchase of equipment and are not intended to be construction guidelines for field crews. However, PGE has begun developing building/construction standards and best practices for the network by assembling and consolidating loosely stored standards drawings kept by distribution engineering.

PGE is presently gathering and consolidating documentation about the CORE network system, making it easier to locate standards and specifications pertaining to the underground network system. In addition, the utility is gathering the “butterfly” drawings depicting each vault and manhole. The butterfly maps show vault grounding. Distribution engineering is working with the Design Department to update these plans. In the future, the butterfly diagram will include the specifications for cable racking and spacing.

Vaults

PGE’s Network Engineers are responsible for vault construction standards. As with much of the network equipment, some of the standards associated with vault construction are informal, and PGE is working with the Standards Department to formalize them. At present, the designer, inspector, and customer discuss the specific requirements on a case by case basis. On the radial system, more Class A vaults are being constructed, so PGE is focusing on developing better standards for these before formalizing standards for new network vaults.

Other Standards

Ladder Extension: PGE is investigating installing underground ladder extensions on manhole/vault ladders to make it easier to get in and out of a vault/manhole. This could take the form of a temporary extension that can slip onto the existing ladder to extend it when crews work in a vault/manhole.

Power Tool Standardization: Across the company, PGE changed all its battery-operated tools to one brand instead of managing inventory, multiple brands, and multiple batteries. They now use a single brand (Makita) and single type of battery. (Sherman + Reilly batteries also fit the Makita tools.) The company also moved away from reliance on hand tools to mechanized/battery-operated tools in order to lessen the risk of carpal tunnel syndrome and improve ergonomics.

This may also improve work quality because it is easy to adjust the settings on the tools, allowing workers to make a more accurate crimp or a cleaner cut, for example. PGE can set tools to certain standards and document this, such as setting a certain crimping standard for the number of pounds to apply on a joint.

Bolted Connections: At a major customer, PGE is piloting use of bolted connections for splices instead of the compression connections that have been traditionally used. For the purpose of this pilot, and to meet customer expectations, PGE is photographing each of the splices. The Standards Group is also tracking the performance of the bolted connections.

Splicing: PGE no longer uses lead splices in the network, and replaces or transitions lead to EPR as opportunities arise. PGE uses both cold shrink and heat shrink technologies.

Quality Assurance (QA) Requirements

PGE has a good QA program with manufacturers, which is very detailed and includes vendor audits. The QA Tester is certified in ISO 9001 and, when undertaking an ISO audit, will bring Distribution Engineers to provide technical knowledge. The QA Tester audits the vendors’ manufacturing floor. For example, when they chose the Eaton Network Protector, Type CM52, the QA Tester looked at their manufacturing process and visited the vendor.

PGE thoroughly tests and audits equipment and component suppliers. This includes checking that the supplier follows QA procedures, such as ISO 9001:2008 [1]. If a component fails, PGE tests similar components in the batch to ensure that the fault is not a production issue affecting all units.

PGE will work with manufacturers and vendors to improve QA processes and equipment specifications on an ongoing basis. PGE also ensures that engineering diagrams are identifiable to a specific engineer to ensure traceability and accountability, as well as checks that all measuring and test equipment is calibrated and audited.

PGE can audit the production facilities to ensure compliance with PGE and other relevant standards. Inspectors will check processes and documentation. They may also request training documentation for employees at the facility to ensure that they have received the correct training [2].

New Equipment Audits/QA: At the Portland Service Center (PSC), PGE performs an intake audit/inspection of network equipment as it is received. All network equipment is delivered to the PSC, and the material/inventory clerk undertakes visual inspection for shipping damage.

Before network protectors are placed in the field, they are set up in the “shop,” configured with the initial settings, and cycled through various tests. The procedure includes the usual network protector maintenance procedures and tests, including the application of the test kit.

Transformer Turns Ratio (TTR) Testing: New transformers are TTR tested, either on arrival or before deployment to the field. The TTR test is an AC low-voltage test which determines the ratio of the high-voltage winding to all other windings at no-load. The ratio test is performed on all taps for every winding. Note that the Special Tester performs TTR testing.

New Cable Testing: PGE does not test new cables because they have had no issues and believe their cables are high quality.

PGE does perform a circuit verification test by administering a DC hipot test before energizing the cable after installation. Crews also perform VLF testing on the substation getaway cables. PGE is not performing tan delta testing. PGE is not testing secondary cables.

Example = Cable Standards

PGE has experienced few cable-related issues on the network, and part of that is related to its comprehensive cable standards. For example, on its underground system, PGE uses 15-kV EPR Jacketed Concentric Neutral Cable, which is covered by Specification L20506. Some of the cable characteristics in that specification are presented here.

The specification includes the 0.39-, 0.59-, and 0.79-in2 (500-, 750-, and 1000-kcmil) copper-jacketed cable sizes used on PGE’s network. The cable is suitable for use in ducts, direct burial, wet and dry conditions, and in sunlight and open air. The cable follows a number of industry standards and specifications. The center conductor is copper wire processed under ASTM B3, ASTM B496, and ICEA S-94- 649-2013, Part 2. The moisture barrier, outside diameter of the central conductor, and the conductor shield conforms to ICEA S-94-649-2013.

The insulation is class III ethylene-propylene rubber, meets the applicable standards, and can meet a maximum operating temperature of 221°F (105°C). The insulation shield is a black, semiconducting thermoset polymer polyolefin or ethylene propylene rubber extruded directly over the insulation. The concentric neutral conductor is flat-strap copper and can handle a neutral fault current capacity of 18,000 A for 12 cycles at a maximum of 221°F (105°C) normal operating temperature. The jacket is non-conducting black, polypropylene, or thermoplastic rubber, and the cable should be marked appropriately. Cable ends are capped to avoid water ingress.

Cable reels are made from steel and have a maximum size of 96 in. (29 cm) in diameter and 53 in. (16 cm) regarding maximum width. The inside cable end is fastened to the flange and delivered without wrapping. The outside cable ends are fitted with factory-installed pulling eyes, which act as a common eye for all three phases of the triplexed cable set. It has a maximum working strength equal to the sum of the maximum allowable strengths for each of the center conductors of the triplexed cable set. The pulling eye provides a waterproof seal for the cable end [3].

Portland General Electric (PGE) Assessment Report of GE Shreveport, internal document
ibid.
Portland General Electric. From L20506 15-kV EPR Jacketed Concentric Neutral Cable, internal document.

4.20.15 - SCL - Seattle City Light

Design

Standards

People

Organization

Network Design at SCL is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A . The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

SCL utilizes a Network Construction Guideline that includes sections that inform design and

construction. The guideline contains sections for:

Safety
General items, such as voltage and current tables for cables
Drawing standards
Cable installation and testing
Services
Cables, bus bars and secondary taps
Primary splices and terminations
Transformer installation and vault preparation
Duct and pole risers
Vaults and handholes
Streetlights
Meters

Process

Standards Meeting

SCL convenes a monthly standards meeting at which issues with the design standards are discussed and resolved. The meeting is attended by network design engineers and crew leaders.

4.20.16 - Survey Results

Survey Results

Standards

(Construction)

Ducted System New Product Review Committee

Survey Questions taken from 2012 survey results - Design

Question 5.9 : Do you have a process for inspecting or testing incoming network materials?

Question 5.10 : If yes, what material is inspected or tested?

Survey Questions taken from 2009 survey results - Design

Question 5.10 : Do you have a process for inspecting or testing incoming network materials?

4.21 - System Hardening

4.21.1 - CenterPoint Energy

Design

System Hardening

People

CenterPoint invests in initiatives to strengthen or harden its infrastructure. This includes things such as network equipment rehabilitation in Houston, hardening activities in Galveston, and reinforcing infrastructure to address potential contingencies, such as the catastrophic loss of a substation.

Process

CenterPoint had experienced failures of older network protectors. In older network units, the protector was attached to the transformer, so that some protector failures would result in a transformer oil fire. Similarly, primary transformer switches would sometimes fail catastrophically. CenterPoint decided to redesign a few network unit locations to physically separate the protector and primary switch from the transformer where space permitted. Most of the older protectors were replaced with new units, with communication enabled relaying. Where they didn’t have room, they would replace the transformer oil with a higher flash point alternate.

CenterPoint has also implemented efforts to improve their ability to back up major substations in the event of the catastrophic loss of the station. In one case, CenterPoint built additional overhead tie points to improve their ability to back up a particular station serving a major load center. In another case, they added infrastructure and ties to be better able to back up a major substation serving a key customer and major load center.

In 2008, CenterPoint experienced a hurricane (Ike) that severely impacted its facilities, particularly in the Galveston Area. As a consequence, CenterPoint identified certain areas to invest in hardening its facilities, so that they are better able to withstand the affects of a significant wind and flooding event. Hardening activities include things such as raising the elevation of key substation equipment, and using stainless steel equipment in coastal areas, including padmounted equipment.

Figure 1: Elevated Substation Control House

Figure 2: Elevated Substation Facilities

Major Underground has been involved in system hardening activities, including a particular project to redesign the alley ways in Galveston.

Parts of Galveston are served by overhead distribution in alleyways. This distribution is quite old and congested, with clearance issues in some locations. In some locations, the clearances were so tight, that if a customer wanted to perform a building renovation, CenterPoint would cut in primary and secondary isolators in order to de-energize the distribution in the customer work area. In an effort to resolve these issues, and to better harden the system against the effect of storms, CenterPoint developed a novel design.

Moving the infrastructure underground with a conventional underground design was rejected because of space issues (no room for padmounted switches or transformers), and because of the significant flooding that can occur in a major storm, as was experienced in hurricane Ike. Consequently, CenterPoint developed a solution where they install underground dead front style equipment on wood poles in the alley ways; that is, equipment that eliminates any exposed energized conductors.

The project, presently underway, includes retro fitting overhead transformers with dead front bushings and elbows, and the development and installation of a padmount style SF6 switch installed on an overhead pole and rack, with two line feeds (one main and one emergency) and four load feeds. In total, CenterPoint plans to install about thirty of these switches.

This novel design eliminates the alleyway congestion, and addresses CenterPoint’s concerns with clearances, safety and infrastructure hardness.

Technology

See the pictures below.

Figure 3: Galveston Alleyway

Figure 4: Transformer Bank – note elbows on primary

Figure 5: Overhead Switch

Figure 6: Overhead Switch (Close up)

4.21.2 - Con Edison - Consolidated Edison

Design

System Hardening

People

Planning for the Future (Third Generation group (3G))

Con Edison has formed a group tasked with addressing the challenges they face in meeting their projected demand and service needs given their current system design. Con Edison refers to their current design, which is a conventional networked secondary design, as second generation, or “2-G.” The group is referred to as the “3 G” group, in that they are focused on new, third-generation system designs to meet their challenges.

Many of the challenges that Con Edison faces are similar to those faced by other network utilities. In some cases the challenges may be exacerbated at Con Edison because of their large size and physical constraints. Some of the challenges they face are the high costs of redundant systems necessary to provide N-2 levels of reliability in parts of their territory, increasing fault current, limited physical space to expand the system, low equipment utilization factors, and new load types and distributed generation.

The 3-G group is looking specifically at ways to apply technology to reduce costs by avoiding or deferring capital expansions, increase operating flexibility, and increase equipment utilization while maintaining customer reliability and service.

For example:

They have performed international benchmarking studies and participated in employee exchange programs with foreign utilities to identify practices used in utilities internationally to address some of the same challenges that they face.
They are working with the vendor community to identify new technologies, such as fast switches that can be used to transfer load between feeders beyond the substation secondary bus.
They are redesigning their approach to substation design, seeking to avoid building them, or building new stations in a way that makes more use of installed assets, eases congestion, and makes their construction cheaper while being capable of operating with the same reliability.
They are revisiting their approach to connecting new customers, seeking changes to customer connection requirements that reduce the number of customers connected from the networked secondary grid.

4.21.3 - Duke Energy Florida

Design

System Hardening

See Design - Network Rehabilitation

4.21.4 - Energex

Design

System Hardening

Due to its unique geography, the Brisbane CBD is subject to flooding. As a result, Energex has done much to improve, harden and upgrade its infrastructure to handle worst-case scenarios, with a focus on reliance, mitigation options, remote control of devices, etc. The company has many best practice flood and contingency plans. See Flood Plan .

4.21.5 - Georgia Power

Design

System Hardening

See Network Rehabilitation

See Cable Installation and Replacement

4.21.6 - PG&E

Design

System Hardening

Transformers - High-Rise Replacement Program

People

PG&E has instituted a proactive program to replace oil filled transformers located in high rise buildings. The program is aimed at mitigating the potential effects of a catastrophic failure of an oil-filled transformer in a high rise location.

Replacement of transformers will be undertaken by the PG&E’s General Construction Department, using both internal PG&E resources and external contractors.

Process

In 2011 PG&E will be replacing 37 high-rise oil transformers with dry type transformers if vault size, ventilation, and other conditions allow. Otherwise, the transformers will be replaced with an explosion resistant main tank design utilizing natural ester oil.

The program calls for the replacement of any transformers within the footprint of the building, including the ground floor. The assumption is that many of the buildings may still be adversely impacted in the event of a catastrophic transformer explosion located in a vault below the building due to the lack of fire suppressant systems, and the inter-connectivity of the vault ventilation system with the building ventilation.

The program will replace a total of 92 high-rise units within three years. The majority of the replaced units will be scrapped because PG&E is moving to the single tank design in non high rise locations (see Transformer Design)

In addition, as part of the program, network protectors will be replaced depending on the age and condition of the unit. Since many of these protectors are relatively new, it is not anticipated that many of them will be replaced.

In 2010, as part of an interim step before beginning the major replacement project, PG&E pre-selected eight high-rise units, and changed out the main tank mineral oil with natural ester. Natural ester provides a higher flash point than mineral oil, and provides some additional time to install the dry type units. The units selected were ones where there were elevated levels of dissolved gases that appeared during the testing of the units.

Technology

In conjunction with ABB, PG&E recently developed and completed the selection of the new dry-type transformer to be installed in high-rise buildings in the San Francisco and Oakland.

Figure 1: Network transformers are available with dry-type core and coil assemblies, and use special polyester resin or cast epoxy as the principal insulation means for primary and secondary windings. The choice depends upon the economics of the project

The typical Dry-Type Network Transformer in a typical high rise, PG&E owns the transformers, while the rest of the vault infrastructure is owned by the customer. The cables running up the buildings are steel jacketed with intermittent splices – these are customer owned. The customer typically runs a spare set of cables in the buildings.

Note that PG&E continues to work with ABB to develop a second generation dry type transformer with a smaller footprint.

4.21.7 - Survey Results

Survey Results

Design

System Hardening

Survey Questions taken from 2015 survey results - Design

Question 77 : Do you have any additional network “system hardening” initiatives underway?

Survey Questions taken from 2012 survey results - Planning

Question 3.13 : Do you have any network “system hardening” initiatives underway?

Survey Questions taken from 2009 survey results - Planning

Question 3.9 : Do you have any network “system hardening” initiatives underway?

4.22 - Three Phase Loops

4.22.1 - CenterPoint Energy

Design

Three Phase Loops

People

Major underground design at CenterPoint is performed by the Engineering Department contained within the Major Underground Group. The Engineering department is led by a Manager and is comprised of four main sub groups.

One sub group is a technical group that includes the engineers who design the protection schema and remote monitoring systems in the underground.

Another sub group deals with the design of three phase pad mounted transformer installations, including three phase looped systems used to serve commercial developments. The Padmounts group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources.

Another sub group focuses on vault designs, interfacing very closely with the Key Accounts Consultants (also part of Major Underground) who interface with large customers. The Vaults group is comprised of Engineers, Engineering Specialists, and is supplemented with contractor resources. This group is typically not involved in three phase loops designs.

The final subgroup is one focused on distribution feeder design. The Feeders group focuses on both network and non network feeders. This group is comprised of Engineering Specialists, Engineering Technicians, and is supplemented with contractor resources.

Process

CenterPoint serves commercial developments with a three phase loop design. Three phase loops utilize three phase pad mounted transformers with three primary switches incorporated into the transformers. One switch is on the incoming feed, one switch is on the outgoing feed, and the third switch isolates the primary from the transformer.

In the normal configuration, cables feed in and out of these units in a loop fashion. If there is a fault in a cable section, CenterPoint can restore service by isolating the faulted section and switching within the transformer cabinets to restore customers. Note that in the loop design, customers are not restored until after the problem is found, or at least isolated to a cable section.

Note that CenterPoint does not use fault current indicators in its three phase loop design, as they have found the fault indicators to be unreliable.

Sometimes, CenterPoint will design a manhole in front each of the transformers rather than loop directly in and out of units. In this design, cables in the manhole would be tapped to and from each transformer. Often manholes are used because the primary must be installed before the contractor or customer is ready with the pads on which to place the three phase units. In this case, CenterPoint will pull cables to the manholes. Then, at a later date when the pads are ready, they will place the transformers units and pull the cable to and from the manholes.

The loop design is a reliable one in that load can be supplied from alternate directions. CenterPoint does offer an alternate design that provides even better reliability utilizing pad mount transformers in conjunction with a switch (See Padmount Transformer with Switch ). However, the installation cost of the three phase loop design costs is about half of the pad with switch option.

Technology

CenterPoint purchases three phase transformers with three switches, one being the incoming feed, one the outgoing feed, and the third switch isolates the transformer from the primary bus in the transformer. Three phase units are also purchased with taps.

Figure 1: Three Phase Transformer - Primary Compartment Note three switches: A -in, B - out, and TX, which separates the transformer from the 12kV bus

Figure 2: Three Phase Transformer - Secondary Compartment

4.23 - Vault - Manhole Design

4.23.1 - AEP - Ohio

Design

Vault Design

People

Network standards, including standards for vault and manhole designs, are the responsibility of the Network Engineering group in cooperation with the Network Standards Committee and the parent company, AEP.

The Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network design and implementation issues. Vault and manhole designs used at AEP Ohio and throughout the AEP system are developed through this committee.

Process

During the design phase, AEP Network Engineers lay-out the design of network vaults and manholes using one-line drawings that indicate the position and dimensions of all internal components, such as duct lines, cable position and racking, transformers and network protectors, secondary bus, and grounding. These drawings are then converted to electronic architectural drawings by a Technician using MicroStation and AutoCAD. AEP works closely with its Civil Engineering contractor to prepare associated civil designs.

The electronic drawings are sent to the Civil Engineering contracting firm who is also responsible for the civil construction. The contractor is expected to construct the vault to AEP specifications, in consult with AEP Engineers. If changes need to be made in vault or manhole designs prior to or during construction, the contractor informs AEP Ohio Engineers who make changes to their electronic drawings. Note that AEP has worked closely with its civil contractor for many years and has a strong working relationship.

Wherever possible, AEP Ohio uses pre-cast manholes and vault designs. These designs include ground rod sleeves, as each new manhole and vault is designed to be grounded with two driven ground rods at opposite corners the vault, with a ground ring (usually 4/0 cu) around the vault/manhole. The grounding is not tied to the vault / manhole rebar. Note that this design differs from an historic design which had the ground bus mounted to the vault ceiling. AEP moved away from this design as deteriorating vault ceilings in older vaults could compromise the grounding system integrity. In spot network vaults on customer premises, the vault grounding is usually tied to the customer’s steel building frames (see Figures 1 and 2).

Figure 1: Manhole grounding (older design) with ceiling-mounted grounding, note ground pad

Figure 2: Manhole grounding (newer design) with floor-mounted ring bus

In cases of customer premise-based transformers vaults, such as a spot network vault or customer service vault, AEP supplies a Civil Engineering contractor with vault construction reference drawings that detail duct lines, transformer and network protector type and placement, and SCADA. Customer spot networks have at least three underground commercial transformers (UCTs), as all AEP Ohio network service is designed to operate in a double contingency (N-2). The Civil Engineer contractor builds the vaults under the supervision of the Network Engineering group. Historically, the AEP demarcation point between AEP and the customer has included connections at a customer’s bus duct, connections at a crab in the manhole, or connections at a disconnect switch. The current design calls for a set of 4500A disconnect switches, where customers pick up their load onto their switchgear on site. It is common practice for Network Engineers to inspect the customer site before commissioning. Customer vaults are a mix between on premise vaults in basements and sidewalk vaults on the street (see Figure 3).

Figure 3: Sidewalk vault

The Super Vault

Of particular note is the inception of what AEP Ohio calls “super vaults.” After concerns were raised over space limitation in vaults, wherever possible, AEP is installing a larger vault design that can more easily accommodate its use of at least three transformers in the same vault, its use of an insulated secondary bus design that uses racked secondary crabs, its use of wall-mounted primary vacuum interrupters supplying each network unit, and use of submersible transformer mounted CM52 network protectors with disconnects between the protector and collector bus, and between the collector bus and customer switchgear. Where space permits, this larger vault design will be installed (see Figures 4 and 5).

Figure 4: Spot network “super” vault. Note the wall-mounted primary disconnect switch on left wall

Figure 5: Spot network “super” vault

Network Engineers design vaults with an insulated secondary busses that uses racked crab connections to bus the secondary cables coming from the protectors and to feed customer services (see Figure 6).

Figure 6: Secondary collector bus using Homac crabs

Technology

Network Engineers design vaults and manhole according to the printed and online AEP Network Planning Criteria guide in cooperation with its Civil Engineering contractor. Vault and manhole drawings are compiled in MicroStation and AutoCAD and updates are made to Smallworld GIS for company-wide reference and access.

AEP Ohio uses the Eaton VaultGard system for monitoring and controlling network protectors over its dual-loop, fully redundant fiber-optic SCADA communications network.

AEP uses a ladder extension safety post on its permanently mounted vault ladders to facilitate vault entry. This device provides a handhold for safer movement to and from the ladder (see Figures 7 and 8).

Figure 6: Ladder safety post extension

Figure 7: Ladder safety post extension

4.23.2 - Ameren Missouri

Design

Vault-Manhole Design

(Vault Design)

People

In heavily populated areas such as downtown St. Louis, Ameren Missouri relies upon both network designs and non network designs such as indoor substations (also called “indoor rooms” at Ameren Missouri), to supply power to buildings.

The Ameren Missouri standards manual currently focuses on the electrical design protocols of network vaults. Ameren Missouri is in the process of adding civil design standards including vault structure, and manhole structure designs to the manual. Because building vaults (particularly, indoor room vaults) is often the responsibility of the customer, Ameren Missouri has developed comprehensive vault design specifications to enable external contractors to build safe and effective vaults that adhere to Ameren Missouri standards.

Design of the urban underground infrastructure supplying St. Louis, including network vaults and non network “indoor rooms”, is the responsibility of the Engineering group within the Underground Division, organizationally part of Energy Delivery Distribution Services, reporting to a VP. This Center, led by a manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues.

Engineers design the system, including spot network vault designs (less common) and indoor room designs (most common). All of the engineering positions are four-year degreed positions. Some engineers within this group have their PE licenses, although this is not a job requirement. Engineers are not represented by a collective bargaining agreement.

The Energy Services Consultants (Estimators) take the one line designs developed by the engineers and complete the design package, including all the physical and civil elements of the design. Estimators have a combination of years of experience and formal education, including two-year and four-year degrees, and are part of the union, IBEW.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. As part of this group’s role, they are addressing issues such as the development and update of planning criteria for the network, and the design of enhancements to the downtown area, such as developing potential designs to build a new substation to supply network load in St. Louis. Engineers who are assigned to this team will also participate in the design of spot network installations, vaults and indoor rooms.

Currently, the Ameren Missouri standards manual is focused only on the electrical design protocols of vault design, but the new manual currently under development will include civil design standards, including vault structure, manhole design, and handholds.

Process

Ameren Missouri has 265 vaults that house transformers and network protectors (and many more that are empty.) Most of these network vaults are part of the network grid system. A typical grid network vault is owned by Ameren Missouri and is located beneath the sidewalks.

Submersible vault “lift out” hatches for installing and removing the network unit are typically solid, not vented. Vaults are designed with two entrances, one on either side of the vault. Both entrances use ventilated covers. Ameren Missouri mounts a vault tag just under the access grate on the primary side of the network unit. In this way, an operator who is performing switching knows in which vault entrance to enter to perform switching.

Figure 1: Ameren Missouri workers opening ventilated vault entrance cover

Figure 2: Vault tag visible through the grate, indicating that this particular vault entrance accesses the primary side of the network unit

Vault entrances are designed with a pull – out access and protection apparatus referred to as either the “safety basket” or the “cage”. The “cage” is a device that is raised above the vault entrance, and is used to ease vault entry and exit by providing a hand rail for moving on or off the vault ladder, and for work area protection, by preventing either pedestrians or workers from accidentally falling into the hole. (See photographs below).

Vault ladders are permanently mounted to the vault wall.

Figure 3 and 4: The 'Cage'

Technology

Ameren Missouri has installed a remote monitoring system in every vault on their network, providing automatic feedback of the conditions within vaults. This monitors voltage by phase, loading by phase, protector status, transformer tank pressure, oil level, oil temperature alarm status, and the water level in the vault.

This system uses ETI electronic metering in the protector relay, and the monitoring points are aggregated at a box mounted on the vault wall that communicates via wireless, with one box per network unit. The Power Line Carrier System transmits from the vaults to receivers at the area substations, with the information available on the intranet via Net RMS. The readings are tied in with SCADA.

Information is accessed via a computer, with the information provided by a third party, and the system obtains readings from the protector every 12 or 15 minutes. The system also allows operators to request the current status by polling protectors and provides graphics for easy comparison with historical readings. The system is new and is not yet fully accurate, but adjustments and improvements are ongoing.

The vaults do not use fire alarm systems. Some vaults have sump pumps that drain into the street or into the storm sewers, with socks preventing oil contamination.

4.23.3 - CEI - The Illuminating Company

Design

Vault-Manhole Design

People

Civil Design is the responsibility of the CEI Underground / LCI group within Engineering Services. This group maintains and establishes vault / manhole design standards for the region.

In addition, Corporate Standards has issued a Distribution Engineering Practice for Network Design that includes guidelines for a new vault and manhole design. (See Attachment A.) Note that CEI’s in place design predates the engineering practices guideline developed by First Energy.

CEI typically retains the services of five different contractors retained for to perform civil work.

Process

Civil Design is the responsibility of the CEI Engineering Services group.

A “Vault” at CEI, is an enclosure that contains a transformer, and is ventilated and kept dry. Vaults can be located in the street or in buildings. Customer Vaults inside buildings may contain customer switchgear.

CEI network vaults are designed with sump pumps. CEI is not utilizing oil sensing monitors to deactivate the sump in the presence of oil in the water in their existing vault installations. FirstEnergy’s Design practice does call for an oil sensor shut off control in new sump pump installations.

CEI’s present vault design calls for two separate personnel entrances. If the vault is to contain two transformers, they are to be separated by a firewall – or located in separate vaults.

In a vault within a customer’s building, the transformer ground is tied in with a ground around the vault, and is tied in with the building ground.

A “manhole” is an enclosure typically located in the street used for accessing cables. Manholes that contain equipment such as switches are designed with two separate personnel access openings.

CEI will build large “interceptor” manholes to intercept a number of substation exits cables before bringing them into a new station, or before they feed into the grid. CEI may also use an “area way”, which is a tunnel that is used to contain substation exit cables en route to a main manhole.

Technology

CEI utilizes precast designs for new manhole / vault installations. The only exception would be situational, such as the need to install a manhole around an existing duct bank, which would force a “pour in place”. CEI’s system does have some older brick manholes with dirt floors.

CEI is not using skid free vault and manhole covers. They are monitoring the OSHA proposed recommendations on a Friction Coefficient, but have not yet changed their standard. CEI avoids avoid putting vault and manhole covers in pedestrian areas such as cross walks.

4.23.4 - CenterPoint Energy

Design

Vault-Manhole Design

People

Vault Design is the responsibility of the Vault Design group within the Engineering Department. The Engineering department is part of Major Underground. The Vaults group is led by a Lead Engineering Specialist, and is comprised of five resources, including an engineer and Staff Engineering Specialists.

Process

These resources interface with major customers to design building vaults. The customer will provide CenterPoint information about their loads and preliminary drawings. The Vault Design group will develop the anticipated demand and design the vault layout to meet their load needs. CenterPoint doesn’t have a standard footprint for a building vault. Instead, they work individually with customers to establish vault dimensions and characteristics. If the customer asks for a standard, CenterPoint will provide them some information, but they have found that the customer’s architect will typically have changes.

CenterPoint will provide all of the specifications to the customer. For example, CenterPoint requires that the customer provide concrete encased duct bank to bring primary feeds into the vault. They require a 2 x 6 duct bank arrangement, using 6 inch conduits, with 4 inches of concrete cover and two inches of concrete between conduits. Upon initial installation, three of the holes will be occupied; two circuit conduits and a neutral conduit.

The actual infrastructure is built by the customer according to CenterPoint specifications. When built, CenterPoint will inspect the facilities to ensure they meet specifications.

CenterPoint prepares a Terms and Conditions document that contains information about what equipment they will put in the vault, customer expectations, CNP standards, and easement information. CenterPoint requests a “right to occupy” the vault space. This is a legal document that the customer must sign so that they can occupy the building.

Most new installations at both 12 and 35 kV are designed with a main feed and an emergency feed with an automatic transfer scheme. However, CenterPoint does have multiple spot network installations in place.

Technology

Vaults are designed with concrete walls and are equipped with pulling eyes. All transformer vaults have a minimum of two entrances, with fire doors with a three hour fire rating. The doors are equipped with panic hardware.

Building vaults are designed with a dedicated independent unit to ventilate the vault. CenterPoint does not permit the customer to use their air conditioning system to ventilate the transformer vault. They will allow the customer to install either air conditioning or forced air cooling, but they encourage air conditioning. The system must be a separate closed system so that air from the vault is not mixed with other building areas in case of a fire. Also, they require the customer to install smoke and fire dampers.

CenterPoint also uses thermostats in their air conditioned customer vaults. In certain vaults, when the temperature reaches 95 degrees the system will send a signal to the customer and an alarm back to CenterPoint’s remote monitoring system. When the temperature reaches 130 degrees, the thermostat heat probe system will trip a primary breaker to isolate the vault.

In certain vaults, the design includes a water sensor that will send an alarm to CenterPoint’s remote monitoring system and the customer if the water level rises to one level in the vault, and trip the primary breaker when the water level reaches a second predetermined height.

Figure 1: Water Level Sensor

In some vaults, the water sensor will alarm the remote monitoring system, but not trip a breaker. CenterPoint will set this alarm level so that it alarms before a sump pump in the hole would begin pumping water or oil into the street. Note that CenterPoint is not using an Oil Minder system on sump pump installations,

Figure 2: Heat Probe

Figure 3: Temperature Control Box

Figure 4: Remote Monitoring Control Box

In a network vault, the heat temperature probes will trip all network protectors.

4.23.5 - Con Edison - Consolidated Edison

Design

Vault-Manhole Design

People

Organization

Central Engineering - Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.

Employee Development

Con Edison invests in developing its design employees through three distinct programs focused on employee development. One program is focused on the development of newer engineering employees, another at incumbent employees, and the third at bargaining unit employees who are entering the management ranks. The programs are described more fully on page 3-53 of this report. Note that these programs are not limited to design employees, but are available to all employees who qualify.

Process

Vault/Manhole Design

Con Edison has a specification that lists all standard and nonstandard types of transformer manholes and vaults and describes their application in forming various arrangements of single or multi-bank installations for 208V network systems.

Con Edison uses two standard-sized equipment installations within vaults: a 500-kVA transformer with protector (also referred to as a “network unit”), and 1000-kVA network unit. For 500-kVA network units, there are two standard reinforced concrete vaults: one that houses the network unit itself (the overall inside dimensions are: 11 ft, 0 in. L x 4 ft, 2 in. W x 7 ft, 0 in. H), and another that houses the crab connections of multiple transformer ties and services or street ties, or both (the overall inside dimensions are: 8 ft, 6 in. L x 5 ft, 5 in. W x 7 ft, 6 in.). These vaults are either pre-cast or field poured, depending on conditions.

For 1000 kVA network units, there are six standard and one nonstandard reinforced concrete vaults. Three of these are for the purpose of housing the transformers-protector units (each vault with different dimensions, and one vault design with a service takeoff). The remaining four are bus vaults, designed to accommodate the interconnections of 1000 kVA network unit secondaries, street ties and service take-offs (each with different dimensions and including a single bus, single bus with diving bell, double bus, and double bus with diving bell vault design). The standard vault structures are available as pre-cast or field poured, depending on conditions.

Con Edison has specifications for pre-cast vaults for use in sidewalk areas. These structures are designed to satisfy typical or “ideal” conditions. Cable entries and other openings are fixed for the most common applications of pre-cast structures, which makes for an inherent lack of flexibility in installation. Therefore, certain field conditions preclude the installation of pre-cast structures, and field-poured installations must be used.

Con Edison field-inspects a percentage (target – 50%) of the field-poured manholes and vaults installed each year. The focus of the inspection is to ensure the proper and adequate placement of rebar in the concrete.

Con Edison has a specification for the design and construction of 265/460 transformer vault and network compartments by a contractor.

This specification describes the division of responsibility between the contractor and Con Edison, and provides the dimensional requirements as well as the design and construction requirements for these structures.

Con Edison’s manhole specification calls for pre-cast floors, walls, wedges, and roof slab, with a cast iron manhole frame and cover.

4.23.6 - Duke Energy Florida

Design

Vault - Manhole Design

People

Network design, including the design of manholes and vaults, is performed by the Distribution Design Engineering group for Duke Energy Florida, which works out of offices in both downtown St. Petersburg and downtown Clearwater. The groups are responsible for designing new and refurbished network designs, as well as underground radial and looped distribution designs. The Distribution Design Engineering groups in Clearwater and St. Petersburg are led by a Manager, Distribution Design Engineering, and are organizationally part of a Distribution Design Engineering Group responsible for Duke Energy Florida’s Coastal region, led by a Director.

The design of network is also guided and supported by the Duke Energy Florida Standards group, which Group oversees all standards for distribution equipment and materials. One Engineer within the group oversees all network equipment standards for Duke Energy Florida. Duke Energy has a Corporate Standards committee which focuses on developing common standards throughout the Duke Energy family of companies. Across the Duke Energy family of companies, there is a core Network Group of four or five members within the broader Standards groups that assist each other and collaborate on choosing all material and specification standards for the underground network throughout the company, including Florida. This core underground team draws on members from across the Duke Energy operating companies.

Vault and manhole designs adhere to the Duke Energy Florida Standards Guide, as developed by the Duke Energy Network Engineers in cooperation with the corporate Duke Energy Standards group. See “Duke Energy Florida Section 29; Networks, Vaults, and Transclosures.” (See Attachment D .) This document contains manhole standards for various manhole configurations, information about manhole lids and cable racking materials, and guidelines for constructing both building vaults and submersible (sidewalk and street) vaults, including equipment placing, ventilation requirements, and sump pump installations.

Process

Manhole civil designs vary depending on the manhole configuration. For example, a three-way manhole has a different shape than does a two way manhole. Most in service manholes were built many years and were poured in place. All network feeders in downtown Clearwater (supplying a true 125/216V network) have their own network cable manholes/duct lines (not shared with Non- network circuits).

The duct bank configuration can vary depending on infrastructure, but a typical configuration is a 3 x 3 duct bank. Duke Energy Florida is consistent in the assignment of duct positions. For example, primary cables (12470 / 7200V) are always pulled through the bottom duct positions. The neutral (Duke Florida does pull a separate neutral) is always pulled through a duct in the same position (duct number five). Secondary cables are run in the upper ducts.

A standard manhole configuration for Duke Energy Florida includes insulated metal cable racks that support cables, with primary feeders located on the lower racks and secondary feeders on the upper racks see Figures 1 and 2). Duke Energy Florida specifies the position of facilities on the cable racks, with positions closest to the wall being the cable ties across the vault, middle positions being the street mains, and outside (away from the wall) being for services. Each manhole has a ground ring around the roofline tied to a driven ground. Every Duke Energy Florida manhole and vault has a driven ground.

Figure 1: Cables feeding into manhole from duct bank

Figure 2: Cable racks supporting secondary

Many existing manholes contain three primary feeders in one manhole. The designers realize that placing multiple feeders in one manhole increases the exposure and consequences of an event occurring in that manhole. Thus, for newer designs, designers strive to minimize the number of feeders in any one manhole hole. In underground radial designs, cables are routed to avoid a single-point-of-failure by using looped cables from pull boxes.

Duke Energy uses “mole” connectors for secondary cables and applies cable limiters.

Network vault designs, including vault dimensions and characteristics, and placement of required switchgear, network protectors, and transformers, etc., are created one at a time, according to the locality and design requirements at the site. Since there has been very low demand for vaults, this custom design approach has been satisfactory. Note that designs are informed by the Duke Energy Florida standards.

All underground vault transformers are specified as submersible units, yet maintained as “dry,” with sump pumps installed in all vaults.

Technology

Manholes

The Duke Energy Florida Network Group has developed a simulated manhole, made of plywood, for training purposes. This manhole, mounted on wheels so that it can be moved, contains cable racks and can be used for training of manhole configuration (see Figures 3 and 4).

Figure 3: Training manhole - exterior

Figure 4: Interior of training manhole showing racking

Duke Energy Florida Network Group maintains detailed manhole prints that show all of the facilities that are placed on each wall, duct bank positions, cable rack positions, as well as detailed manhole dimensions. On the drawing, each wall is laid flat on the drawing itself (if you were to take a scissors and cut the walls and fold them up you would replicate the manhole shape). See sample manhole drawing, Attachment E . PDF versions of the manhole prints and Excel versions of the supporting data sheets can be accessed from the GIS system.

Duke Energy Florida is investigating the application of self-ventilating manhole systems, though hadn’t installed any at the time of the practices immersion. They noted that their manhole tops are not designed with “lips,” making the installation of a Stabilock style system much more problematic. To add the lip to the existing opening would result in an opening which is too small (29 ½ inches). Consequently, to install self-venting manhole systems that require the lip for retention requires a change out of the manhole roofs, which is a costly effort.

Vaults

All underground vaults have sump pumps with an Oil Minders system installed, designed to alarm and stop pumping in the presence of oil in the water see Figures 5 and 6). The Oil Minder system is monitored by the Qualitrol system, installed in each vault.

Figure 5: Network Vault, sump pump

Figure 6: Sump pump Oil Minder system

All vaults have permanently installed, grounded ladders. Each vault has ventilated grates with two access points for a man to enter the vault – one on the primary switch side and one on the protector side (see Figures 7 and 8). At the time of the practices immersion, Duke Energy Florida was in the process of replacing vault grating systems (see Figure 9).

Figure 7: Network vault, two entrances, one on either end of vault

Figure 8: Network vault, permanently mounted ladder

Figure 9: New vault top / grate

A typical network vault, located underground, contains a wall-mounted solid dielectric switch (such as the Elastimold MVS) as a sectionalizing point between the primary and the network transformer (see Figures 10 and 11). The handle of this device can be operated from outside the hole.

Figure 10: Network vault, wall-mounted primary disconnect switch

Figure 11: Network transformer, elbow connections supplied from disconnect switch

The transformer is supplied using ESNA style (separable) connections. The network protector (CM22) is typically mounted on the transformer secondary. Protectors are equipped with micro process or relays (Eaton MPCV) that monitor protector and other vault conditions.

Duke Energy Florida has installed remote monitoring in its vaults. It uses a Qualitrol system to monitor information such as transformer oil level and temperature, and the status of the Oil Minder system. It uses the Eaton VaultGard system to aggregate information from the protector relay, such as voltage, current, protector position, etc. VaultGard also aggregates information from the Qualitrol system (see Figure 12). Information is communicated from the VaultGard collection box via cellular communications by Sensus, a third party aggregator of information.

Figure 12: Wall mounted VaultGard and Qualitrol data boxes. Information communicated via cellular through Sensus

In St. Petersburg, network designs are limited to spot network vaults which are located in buildings (see Figure 4-44). Building vaults are built and maintained by the customer and must conform to Duke Energy Florida’s design and maintenance requirements.

Building designs vary, but in general include a separate (from the transformer) primary disconnect switch, transformers, and protectors. Duke Energy Florida does not utilize a collector bus; rather, secondary cables are typically run on cable racks and trays. Duke Energy Florida will terminate its secondary cables at a junction terminal provided by the customer (see Figure 13).

Figure 13: St. Petersburg, spot network vault, primary disconnects

Figure 14: Spot network vault, customer interface

Duke Energy Florida has standardized on the CM52 for its spot network 277/480V spots. These protectors are equipped with various safety features, including:

External disconnects, which are used to separate the protector from the secondary collector bus. Note that the disconnects can only be opened with keys which can only be accessed when the NP handle is in the open position because of an interlock system (see Figure 15).
Wall-mounted ARMS (Arc Flash Reduction Maintenance System) modules, which enable a worker entering the vault to change the protection settings in the protector to reduce the fault clearing time and thus the arc energy in the event of a fault.
A submersible Stacklight, which is an annunciator system that indicates network protector status through a series of different colored lights.

Figure 15: Spot network vault and NP handle disconnect

4.23.7 - Duke Energy Ohio

Design

Vault-Manhole Design

(Vault Design)

People

Network design, including vault design, is performed by a Network Project Engineer and two Designers who are part of the Distribution Design organization. This organization is focused on all distribution design work for Duke’s Ohio and Kentucky utilities, including network design.

Theses resources work closely with one another and with the Planning Engineer focused on the network to design modifications to the network.

Process

Duke Energy Ohio’s designers (CPC’s) work closely with the customer to design building vaults. Much of the ultimate design tends to be dictated by the customer. Duke is considering developing a more standard vault design that they can provide to customers, although the knowledge it will be difficult to enforce customer compliance with the standard. (For example, a customer may not be willing to, or be able to provide the physical space required by the Duke standard)

See Design - New Service Design for more information

Technology

Collector Bus

Duke Energy Ohio designs and fabricates the collector bus is used in vaults. These buses are made of copper flat stock for both the collector central bus itself and for the “services” into the customer’s switchgear.

The secondary collector bus, energized from the network protectors, is designed with a fuse panel for each large load fed off the bus. Network protector type fuses (sand type) are used. Duke has six basic fuses that they maintain for the fuse panels.

The collector bus design tends to be custom, as customer requirements dictate the final design. Duke Energy Ohio does have some basic standards, but they deviate from them frequently as the older standards are based on underground vaults and much of the work in the past 10 years has been in overhead vaults. In general, Duke has increased spacing requirements because of larger equipment size.

Figure 1: Secondary cables from network protectors energizing collector bus

Figure 3: Copper flat stock from central collector bus to fusing

Figure 4: Fuses between collector bus and customer load

Figure 5: Copper flat stock services from fuses to customer load (taped)

Figure 6: Secondary collector bus in a submersible vault (Note the wall mounted protectors in this older vault. )

Fire Protection

Duke Energy Ohio designs its vaults with a fire protection system. This system is designed to open up the network protectors in the vault in the event of a fire. Historically Duke had used a Fenwall fire protection system. This system is inspected yearly as part of the fault inspection.

Duke is in the process of installing a new fire protection system as part of their rehabilitation efforts in the network.

Duke Energy Ohio uses arc proof tape within its network.

Figure 7: Fire wire installed on collector bus

Figure 8: Fire protection system control box

Salt Contamination

Duke has had problems with equipment deterioration due to salt contamination. In their transformer design, they install a protective shield over the transformer primary termination to protect the terminations from salt and other contaminants. In selected vaults, they will place a fiberglass barrier over top of the network protector.

Their transformer specification includes paint specifications that take this potential for salt contamination into account.

Figure 9 and 10: Protective Barriers

Figure 11 and 12: Protective Barriers

Duke is not using cathodic protection in the network. They noted that their network vaults are very dry.

Sump Pumps

Duke, Cincinnati vaults are designed with drains that are tied into the storm sewer system. Most of their vaults are dry; consequently, they do not use sump pumps. Note - Duke Indiana, in their Terre Haute network, does use sump pumps in their vault design.

4.23.8 - Energex

Design

Vault Design

See Network Design

4.23.9 - ESB Networks

Design

Vault Design

(MV Substation Building)

People

The ESB Networks Asset Investment group is responsible for establishing specifications for its MV substation vaults. Within this group, there is a Specification Manager who is responsible for establishing the specifications for MV substation building construction..

Process

In most cases, the indoor substation building vault is built by the customer to meet the specifications established by ESB Networks. After completion of building the vault, the customer is required to complete a “Certificate of Completion for MV Substation,” indicating that the design meets ESB Networks’ specifications. An ESB Networks representative performs a formal final inspection and acceptance of the completed substation building room before installing the electricity connection.

Technology

ESB Networks’ standard vault design for a MV substation is an indoor room design. Virtually all of the 2040 MV substation vaults located in Dublin are of this aboveground, indoor room design. ESB Networks has almost no submersible distribution equipment on their system.

Located within the vault is a standardized MV “packaged substation” consisting of an SF6 gas insulated ring main unit, the MV transformer (in Dublin, typically a 10-kVA primary to a 430-V secondary), and the secondary bus and protection that feed the secondary “mains” that supply the LV system in downtown Dublin.

The current design of the primary switch is an SF6 gas insulated ring main unit device, with and “in” switch, an “out” switch, and a fused, switched tap leading to the transformer (kkt). The company describes these units as “maintenance free,” and obtains them from a supplier through a lease arrangement. ESB Networks does have older oil insulated devices installed on its system as well.

ESB Networks’ design is to loop its 10-kV MV feeders in and out of these switches, designing normally open tie points between feeders. This provides them the ability to sectionalize to isolate outage sections and to feed each MV transformer from either direction.

ESB Networks’ standard primary switchgear (ring main unit) is a “load make,” but not a “load break” device. The switch is designed with an anti-reflex handle that prevents an operator from inadvertently and reflexively opening the switch if the operator happens to close into a fault, as the device cannot break load. If the operator does close into a fault, ESB Networks relies on the tripping of the breaker that sources the 10-kV feeder.

The primary cable that runs from the primary switchgear to the transformer is laid in a cable tray (duct), which is easily accessible by removable duct covers either made of wooden blocks, or a glass reinforced polyester material.

Standard transformer sizes are 200, 400 and 630 kVA, with the 630-kVA unit being the most prevalent. Most customers in Dublin are served from the secondary system but Dublin does have about 170 customers that take primary service at 10 kV. ESB Networks’ standard transformer is a dual-voltage unit, as most of its service territory outside of Dublin is served at 20 kV, while the feeders supply downtown Dublin Park at 10 kV. ESB Networks describes these transformers as sealed units that do not require routine oil testing.

Secondary mains emanate from a secondary cabinet mounted adjacent to the transformer. The secondary mains are fused. The ESB Networks specification calls for the substation room structure, including the floor, walls and ceiling, to have a four-hour fire-rating.

The reinforced steel that is incorporated into the substation floor is also grounded. (If reinforcing steel is not incorporated in the substation floor, the customer must install a copper mesh below the floor.) The substation ground system is isolated from the customer side grounding system.

The standard substation doors are hot-dip galvanized steel doors that include vertical louvers that allow for maximum ventilation while permitting no access to foreign bodies. Note that the doors do not have a certified fire-rating because they open onto a low fire risk, outside location. The standard door design includes access hatches for the access of temporary generator cables into the station if required, and for the customer to install a smoke detector (see Figure 1).

Each room contains an oil containment vessel, in case of a transformer oil leak.

ESB Networks has not installed any remote monitoring in these MV stations (see Figure 2).

Figure 1: Steel doors

Figure 2: Transformer and secondary gear

4.23.10 - Georgia Power

Design

Vault Design

People

Network standards, including standards for vault designs, are the responsibility of the Principal Engineers at Network Underground that report directly to the Network Underground Manager.

Organizationally, the Network Underground group is a separate entity, led by the Network Underground Manager, and consisting of engineering, construction, maintenance and operations resources responsible for the network underground infrastructure, including the development of standards for network equipment.

Network design is performed by the Network Underground Engineering group, led by a manager, and comprised of Engineers (Electrical and Civil) and Technicians concerned with the planning, design, and any service issues associated with the network. The Engineers are four-year degreed positions, while Technicians have a combination of years of experience and formal education, including two-year and four-year degrees. Engineers are not represented by a collective bargaining agreement.

In addition to the engineers within the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager. These Principal Engineers also deal with issues of network design, and are responsible for the development and maintenance of standards for network equipment, including vault standards. Standards are available in both an online and printed book format. The standards are divided into two main sections: civil construction and network specifications and design.

Process

Georgia Power’s standard vault design for a submersible vault is a poured in place design. Submersible vaults are accessible through manholes and through grating, depending on location. Vaults typically have a rectangular opening on top that is large enough to move a transformer through, with two hatch covers with a center support than can be removed (See Figure 1).

Figure 1: Vault Entry through manhole access. Note the removable hatches beyond the manhole for installing / removing the transformer

Vault access is through manhole covers, using permanently mounted ladders. In some cases, the access ladder will bring you to the top of the transformer, with another permanently mounted ladder to bring you to the ground. Some vaults have ladder extensions (“Ladder Up”) to facilitate vault entry. For manhole (not vault) entry, fiberglass sectional ladders (side rails are fiberglass, rungs are aluminum) are dropped into the manhole (See Figure 2).

Figure 2: View from inside the transformer vault. Note permanently mounted ladder to the top of the transformer (right side), and the permanently mounted ladder on the wall for access to the vault floor (left side)

Submersible vaults / manholes have bay forms built into the corners to take the bend out of the cable in the manhole. Therefore, the cables can maintain their bending radius and still be close to the wall. Typical duct sections come in various formations, 6 inches duct in a 2xX configuration.

Georgia Power uses both pre-cast and poured in place manholes, with pre-cast being the standard for most. The precast manhole includes a one inch sleeve for future driving of a ground rod in the manhole.

For a customer vault in a new building, the customer is provided with a copy of Georgia Power vault requirements, and prepares a vault design per those requirements. The final vault design must be approved by Georgia Power. For a customer-premise vault, Georgia Power brings the duct line to the edge of the property, where it meets the street; the customer builds the duct line from the street into the building, and they build the vault. It is not uncommon for an engineer from Georgia Power to make site visits prior to and during customer vault construction to make certain the vault meets the company’s standards and will accommodate the transformers and equipment needed. Typical vaults including customer-based vaults for spot networks often contain multiple transformers. Georgia Power standards call for ample room in the vaults for future expansion and to provide adequate ventilation.

The vault standards for customer buildings do not call for fans, as Georgia Power does not want customers to rely on them in case of any failure. Instead, vaults are designed with ample space for open ventilation. Georgia Power does all cable racking, not the customer (See Figure 3.).

Figure 3: Spot Network Vault

(See Attachment C for a typical drawing indication the duct line terminus to a customer property.)

A notable practice in cable racking in manholes is the use of the Georgia Power Peachtree racking system (See Figure 4). This system calls for consistent racking approach that consists of primary cables racked on the bottom, with secondary cable pairs racked above. Cables are clearly marked and numbered, and this approach facilitates future expansion out of the manhole. Georgia Power has found this is a tremendous benefit in standardizing design, streamlining maintenance, and providing greater worker safety.

Figure 4: Excerpt from GA Power cable racking diagram showing Peachtree racking

Network Underground design engineers have standardized on a secondary collector bus with 2000 MCM copper, at 600V that is fully insulated with EPR and a full jacket (See Figure 5 and Figure 6). In some cases engineers may use double buses, such as two A, two B, two C depending on the load and customer needs. Vault construction must accommodate this. Services are connected to the bus through a down drop which is connected to the bus with disconnectable tee lugs.

Figure 5: Insulated collector bus

Figure 6: Collector bus material cross section

Technology

Georgia Power has been using SCADA control and monitoring for approximately 15 years in its vaults and substations. Although they do not monitor vault temperature, they can control and monitor network protector status in near real-time. Network vault designs include a specification for where and how to place SCADA line(s), with fiber optic cable into the Operations Center network as the preferred method. Vaults do not include fire alarm systems.

Network civil and electrical engineers often use the online Georgia Power network standards book to design vaults and provide customers with reference designs, including detailed model blueprints that specify the location of duct lines, bay forms, racks, etc.

The Network Underground group has begun a small pilot project employing the Eaton Vault Guard system for monitoring and controlling network protectors, but at the date of this immersion report has not recommended them as a standard for the network.

4.23.11 - HECO - The Hawaiian Electric Company

Design

Vault-Manhole Design

People

Civil and Structural Design is performed by the Civil / Structural Division within the Engineering department. The Civil / Structural Division is comprised of a principal engineer, 2 lead engineers, 6 engineers, 2 drafting technicians, 2 project clerks, and 5 surveyors.

The Civil / Structural Division assists the Technical Services Division with the development of standards for underground enclosures.

Process

HECO’s definitions of a “Vault” and of a “Manhole” conform to the NESC definitions.

From the NESC, a Vault is a structurally solid enclosure, including all sides, top, and bottom, above or below ground where entry is limited to personnel qualified to install, maintain, operate, or inspect the equipment or cable enclosed. The enclosure may have openings for ventilation, personnel access, cable entrance, and other openings required

for operation of equipment in the vault. In general, a “Vault” at HECO is an enclosure that contains a transformer, and is ventilated and kept dry. Vaults can be located in the street or in buildings. Customer Vaults inside buildings may contain customer switchgear.

From the NESC, a Manhole is a subsurface enclosure that personnel may enter used for the purpose of installing, operating, and maintaining submersible equipment and cable.

Some HECO network vaults are designed with water level alarms that are tied to the HECO SCADA, In general, however, HECO has very little SCADA in their network facilities.

Technology

Most HECO vaults are pre-cast. They do use poured in place enclosures at selected locations.

4.23.12 - National Grid

Design

Vault-Manhole Design

People

Network design at National Grid, including vault design, is performed by the network designer. This designer, a Designer C, performs all larger and more complicated network designs, including vault designs for both grid and spot network vaults. This individual has a two-year degree, a requirement for the position. This designer also performs non – network UG designs. This designer works very closely with the field engineer, part of Distribution Planning, assigned to the underground department to support the Albany network. This individual also works closely with account executives who interface with major customers in planning and designing spot network vaults.

Organizationally, the Designer C is part of the Distribution Design organization, led by a manager, and part of the Engineering organization at National Grid. This organization is structured centrally, with resources assigned to and in some cases physically located at the regional locations. The two designers who support the Albany network are both physically located at the NYE building, in Albany.

The designer is represented by a collective bargaining agreement.

National Grid has up to date standards and material specifications for network equipment, including the network vault. Network standards are the responsibility of the Distribution Standards department, part of Distribution Engineering Services. Distribution Engineering Services is part of the Engineering organization, which is part of the Asset Management organization at National Grid. Within the Standards group, National Grid has two engineers that focus on underground standards.

Process

National Grid has 251 vaults that house transformers and network protectors.

A typical network vault is located beneath the sidewalk. For a spot network, the vault is provided by and owned by the building owner and typically located beneath the sidewalk in front of the building. Customer owned vaults may be placed in private right of way or within the City of Albany’s right of way – in these cases the customer is responsible for obtaining rights of way. For National Grid owned vaults, National Grid typically obtains an easement to place their vaults within the City’s right of way.

National Grid’s vaults and manholes are pre-cast, with two standard sizes (present standard): 8 x 20 x 11 for transformers up to 1000 kVA and 10 x 22 x 12 for larger units.

Spot network vaults are designed with removable concrete panels and with ventilated openings (gratings) on either end for cooling. Vaults have two entrances, one on either side of the vault. Openings are lockable with piston assisted lifting. Entrances may be designed with vented covers, or solid covers.

For spot network vaults, National Grid provides the customer with specifications for the vault including the size, layout, placement of pulling eyes, ventilation requirements, sump pump requirement, lighting, grounding, auxiliary power, etc. The typical spot vault installation includes secondary cable trays leading to conduits that feed from the vault to an adjacent vault or equipment room owned by the customer. National Grid secondaries will terminate on customer equipment.

National Grid ties all of its vault equipment to ground, including the switch handle on the transformer primary ground switch. National Grid standards call for the vault ground to be kept separate from the building ground. For customer services, National Grid runs full sized insulated neutrals into the customer building connecting to the neutral bus. It is the customer’s responsibility to ground the neutral bus on their end.

National Grid utilizes sump pumps in many of its network transformer vaults. Most are in automatic operation. All sump pumps have an oil sensing unit which will shut off the pump in the event of oil in the vault. In addition, filter baskets are installed around the sump pumps to trap oil and debris before getting to the sump pumps.

National Grid’s standard design for a network unit calls for it to be placed on hot dipped galvanized I-beams within the vault. National Grid uses anodes to provide corrosion protection.

Spot network vaults are equipped with a ground fault protection system designed to trip (open) all of the network protectors in the vault in the event of a ground fault. The customer is required to buy, install, and wire the National Grid approved ground fault protection system. Ground fault protection system equipment is installed in the customer’s electric room. A current transformer required to monitor neutral currents is installed in National Grid’s transformer vault.

National Grid seals all duct entrances with fire sealant. National Grid uses fire proof tape on cables.

Technology

Figure 1: Anode, transformer base

Figure 2: Primary switch handle, grounded

Figure 2: CT for ground fault protection system

Figure 3: Wiring from NP to the customer’s equipment room for the ground fault protection system

Figure 4 and 5: Spot network secondary cables – feeding from protector to customers equipment room

4.23.13 - PG&E

Design

Vault-Manhole Design

People

Network standards, including the standard design configuration of a network vault, are the responsibility of the Manager – Distribution Networks. PG&E has assigned one individual as the asset manager for network equipment, including all components of the network unit. This asset manager is responsible for network

The Civil Engineering group, within the Substation Engineering Department, performs civil designs such as vaults.

Most civil construction work at PG&E is performed by civil construction resources from the PG&E Gas Division or by external contractors. PG&E network resources will perform minor civil repairs.

equipment design standards, developing life cycle strategies for network equipment, and making capital and maintenance investment decisions for network equipment.

The development of the standards for the vault enclosure itself (civil design aspects) is the responsibility of the Civil Engineering group, part of the Substation Engineering Department at PG&E. Vault designs are also developed by this group using internal PG&E resources. Note that civil construction work is performed by resources from PG&E’s gas department.

PG&E has developed and maintains up-to-date standards that describe the network vault design (for both poured in place and pre-cast designs). Note that in the downtown network area, most vaults are poured in place. Precast vaults are most common on the rest of the PG&E system.

Process

PG&E uses both pre-cast and “poured-in-place” manholes. In their congested downtown area, most are poured in place. The rest of the system uses primarily pre-cast units. PG&E has detailed standards that describe their underground electric vault requirements.

PG&E has 771 vaults that house transformers and network protectors.

A typical vault for a spot network is provided by the building owner ^[1] . This type of fault is often an underground vault located beneath the sidewalk in front of the building, and placed so as to be on private property. The “lift out” hatches are solid, not vented. In Oakland, PG&E uses removable sections in vaults housing smaller sized transformers.

Figure 1: Vault roof, solid “lift out” hatch

Vaults are designed with two manhole entrances, one on either side of the fault. One entrance uses a solid cover while the other uses a vented cover. The vented cover is used on the end of the vault where the ventilation fan is located. Note that PG&E is installing solid covers that have the ability to vent combustible gases (Swivel Loc) in place of the vented covers in areas of high foot traffic. (See Manhole Cover Replacement Program.) Solid covers prevent additional water and debris going into the hole and clogging the sump pump. These covers also prevent people from throwing debris into the hole that could create a biohazard. Finally, solid covers raise the ambient temperature in the vault, reducing water accumulation. (PG&E network transformers are under loaded, and thus run cool and do not contribute to water evaporation.)

Figure 2: Vault ventilation fan

Figure 3: Sump pump and ventilation fan

For spot network vaults, PG&E provides the customer with specifications for the vault including the size, layout, placement of pulling eyes, ventilation requirements, sump pump requirement, lighting, grounding, auxiliary power, etc. The customer will also supply either a collector bus, or bus stubs for terminating secondary cables. The typical vault installation includes secondary cable trays terminating on customer supplied bus stubs. However, for 120/208V spot network locations, a secondary collector bus is sometimes required because of the number of cables.

Figure 4: Secondary cable trays

Figure 5: Secondary cables – customer bus stubs

PG&E’s standard calls for the vault ground to be separate from the building ground.

For fire protection and isolation, PG&E’s vault layout calls for no more than two transformers in any one enclosure without separation by firewall. Most PG&E spot network locations utilize three transformers. Consequently most vault designs include a firewall, with two units in one enclosure and the remaining unit in the other. PG&E monitors and alarms the vault temperature. They do not use smoke detection.

PG&E’s vault ventilation requirements call for a ventilation fan to be installed in each vault. These fans are thermostatically controlled.

PG&E requires a sump pump to be installed in each vault. Most pumps drain into the storm sewer. Note that PG&E is not requiring that its sump pumps be equipped with an automatic shutoff system in the presence of oil. However, the sump pumps are equipped with a sleeve that enables the crews to easily detect a sheen indicating the presence of oil in the water.

PG&E vaults are equipped with remote monitoring, and PG&E is in the process of upgrading the level of monitoring. The existing system uses “snap” switches to monitor things such as vault temperature. For example, when a given temperature is reached, the switch “snaps” closed, sending a temperature alarm. The new monitoring system (“Vault Gard” by Eaton ) will monitor and deliver actual temperature readings in addition to alarms.

Figure 6: Remote monitoring (Note CT’s on NP secondary)

Some of the items that planned to be monitored by the upgraded system include:

Two water level indicators. One at one foot and one at three feet in each vault
Temperature reading at the roof line
AC voltage
DC battery voltage
NP status
Oil level
Voltage
Current
Wave forms
Open and close - control of protector
Oil temp and pressure on all oil chambers
NP tank pressure

Technology

Figure 7: Temperature probe

^[1]Per Electric Rule 16 of the PG&E Tariff.

4.23.14 - Portland General Electric

Design

Vault-Manhole Design

People

A number of departments are involved in manhole and vault designs for the network, both for PGE owned facilities and in overseeing customer-owned facilities built to PGE specifications. The network includes many customer vaults, making it important to liaise with customers/contractors during the design process and ensure that all vaults fulfill regulations and PGE specifications.

PGE may use external contractors to fulfill the civil designs for vaults and manholes.

Distribution/Network Engineers: Three Distribution Engineers cover the underground network and work with customers to design customer-owned facilities to PGE specifications. The Distribution Engineers are not based in the Portland Service Center (PSC) or CORE group. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to perform certain planning tasks.

Network engineering develops and maintains the standards for the network, including vault standards, which are forwarded to the Standards Department for inclusion in company standards. Distribution Engineers assume responsibility as they have experience with network equipment.

Standards Department: The Manager of Distribution Engineering and T&D Standards oversees the Standards Department. The group recently underwent reorganization. It now employs one technical writer and four standards engineers.

Service & Design at PSC: Service & Design’s role is to work with new customers or existing customers with new projects, making it responsible for new connections, new buildings, and remodeling. The supervisor for Service & Design’s wider responsibility includes the downtown network. The supervisor reports to the Service & Design Manager, who is a peer of the Distribution Engineering and T&D Standards manager. Both of these positions report to the General Manager of Engineering & Design and directly to the vice president.

The Supervisor of Service & Design at PSC and its group undertakes capital work if initiated by the customer. The “Mapper/Designer” reports to the Supervisor of Service & Design at PSC and provides the computer-aided design (CAD), geographic information system (GIS), and design service.A Field Inspectormeets with contractors. Two inspectors work for the Service & Design organization, and one specializes in the network.

Service & Design Project Managers (SDPM): Because external projects drive much of the planning on PGE systems, the utility employs SDPMs. SDPMs have a defined role and work almost exclusively on externally-driven projects, such as customer service requests. They also liaise with new customers when designing services. At present, two SDPMs cover the network. SDPMs oversee projects from first contact with the customer to the final completion. They coordinate and manage construction designs and customer connections to ensure full compliance.

Ideally, a SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC), as well as the ability to use or learn the relevant information technology (IT) systems. PGE prefers to have a selection of SDPMs with a diverse range of experience and backgrounds, so the position does not necessarily require a four-year engineering degree. The managers can be degreed engineers, electricians, service coordinators, and/or designers [1].

PGE assigns SDPMs work on both CORE and non-CORE projects to assure that expertise is distributed and maintained across departmental and regional boundaries [1].The Project Managers are separate from Distribution Engineering and T&D Standards.

Key Customer Manager (KCM): PGE has nine KCMs reporting to Manager of the Business Group. Generally, they are geographically distributed, with three on the west side, one downtown, one in Salem, three on the east side, and one acting as a rover. KCMs liaise with large customers and communicate their needs. For large customers, the Major Accounts Department may also liaise with customers about the project.

Contract Services and Inspection (CS&I): At PGE, the CS&I department supervises contract management. Five Construction Managers work in the CS&I group, inspecting any work on PGE-owned infrastructure. Field Construction Coordinators (FCC) inspect facilities built by customers. When constructing facilities and vaults to house PGE equipment, customers can choose from two third-party vault contractors with certifications from PGE. For larger projects, PGE may outsource inspections to external experts, such as POWER Engineers, Inc.

Process

Manholes: PGE uses solid manhole covers in the network. The manhole covers are 32 in. (81 cm) in diameter and have venting holes. Note that city regulations restrict the use of manhole covers in sidewalks. At the time of the immersion, PGE was testing manhole lid retention systems for use in its network.

Figure 1: PGE solid manhole cover

Figure 2: Network vault entrance on sidewalk

PGE is investigating the use of extensions on underground ladders to make it easier to get in and out of a vault/manhole. This could take the form of a temporary extension that can slip on to the existing ladder to extend it when PGE is working on a vault/manhole. A challenge they face is that existing mounted ladders are of different styles, with some ladders over 40 years old. They are considering standardizing the ladder’s design and designing an extension that would fit onto this ladder.

Figure 3: PGE manhole with permanently mounted ladder

Vault Construction Standards: PGE’s Network Engineers are working with the Standards Department to formalize vault construction standards for network vaults. At present, PGE performs some of the designs on a case by case basis, with the designer, inspector, and customer discussing what is required and establishing the ultimate design. PGE noted that on the radial system, more Class A vaults are being constructed, so they are focusing on developing a more robust standards for these Class A vaults before formalizing standards for new network vaults.

See Attachment for Class A vault construction standard

Figure 4: Grounding details for Class A vaults

Developing Work Packages

PGE uses ArcFM as its current design product to create a materials list. The company hands over a “package” to the customer, inspector, and contractor. For each new vault, a package of the relevant information needed for vault construction includes:

Vault detail and butterfly drawing
A conduit plan/map
An electrical drawing
Standard construction specification
Notes (i.e., anything special for the construction) Most of the materials used for network construction already have man-hours details attached, so when an operator selects an asset, the system calculates the man hours/labor needed for installation. The information is available in Maximo and allows the operator to compare the estimated and actual labor costs.

Any projects over $75,000 enter a funding project approval process and require approval after entry in the Maximo asset management software, which is linked to ArcFM. In ArcFM, designers create the design, add the materials/assets needed, and perform the mapping. Once approved, they send it to Maximo and it can be viewed in a tabular format. One problem unique to the network is developing standardized compatible units (CUs) or macro units (MUs) for assets, because each work situation can vary. Accordingly, the design department adds additional labor units to develop an estimate for network jobs that reflect situational requirements.

Particularly for spot networks, some of the materials must be ordered well in advance because they have very long lead times for delivery. The Distribution Engineers have good coordination with their storerooms/material management to order and procure equipment and components.

The SDPM also assists in ensuring that job sites have temporary power during the construction period, which is usually fitted to a radial feed.

PGE Maps/Drawings [2]

Vault Detail (also called Butterfly Map): PGE produces a detailed drawing of the vault, incorporating the detail associated with each of the vault walls, including duct arrangements (see below). Note that these detailed drawings do not show cable joints or cable mole locations.

Figure 5: Vault construction drawing – 'Butterfly Map'

Conduit Plan: For a vault, the conduit plan may warrant its own sheet and plan if it is particularly complex. The city requires permits for major construction projects, so for any construction on the network, a separate conduit plan is created and serves as a permit map.

Crew Electrical Map: Designers produce another sheet for the crews containing an electrical map, which has proven useful for the crews.

While the design indicates details such as duct position availability, ultimately the crew selects which conduit to choose for a new feeder implementation. These and other as-built changes are noted so that they can be recorded in the permanent records (e.g., a GIS).

Mapping is performed in ArcFM GIS. When a field job is completed, it comes back to Service & Design to develop the “as-built” map. Once everything has been setup in the design draft version on the GIS, the final post is entered on the GIS. The electrical drawings and conduit plans are held on the GIS, while vault details are standalone. The GIS map shows the locations of secondary moles within the system.

Following the “as-built” finalization, the GIS Department sees the work order in Maximo and the design draft in ArcFM. The department performs some quality assurance/quality control (QA/QC) to ensure electrical connectivity in the plan/design and that the required attributes, such as operating voltage, are in the system. (The department also runs a reconciliation process to determine that nothing was missed due to other builds in the area.) This process ensures that the GIS contains the latest design.

PGE is starting to take pictures/images of vaults that can be included as part of the package.

PGE creates the design package and vault details for new construction. However, once the crew has visited an existing vault or location and finds discrepancies between the recorded and actual vault details, a corrected drawing is sent to mapping and design.

Vault Specifications: Most new PGE vaults are precast, and the majority of vaults on the network are larger than those used in a radial system, at 10 x 24 ft (3 x 7.6 m). All vaults need to meet the “Class A Vault” standard. Customer vaults are built to PGE specifications and integral to the building structure, though they are not usually precast. Spot network vaults are customer-owned and can be above or below grade. Very few vaults are above grade, although all must be accessible from the street. Vaults in buildings typically have two entrances, one from the street and the other through the building. If the building does not have a basement, then there are two entrances from the street to the vault.

All vault equipment is submersible, though the network has a few older installations with spot networks on the roof.

According to Class A vault design specifications:

Vaults with a minimum fire resistance of three hours should house all PGE transformers unless a smoke detection system is installed
PGE should control vault access and crews should have access 24 hours per day
Hatch doors in the sidewalk should have 30 ft (9.1 m) of vertical clearance to allow for equipment removal and installation
Vault walls and ceilings should be painted with at least two coats of non-toxic, waterproof masonry paint
Vaults should only contain equipment related to electrical service
The customer should include emergency lighting and 120 V electrical sockets inside the vault according to PGE/NEC specifications [3].

The city prohibits manholes in the sidewalks and prefers lift-outs and non-skid vault doors. The vault doors have hinges and shock absorbers.

The customer is not required to cool the vaults with air conditioning but is required to provide ventilation ducts. Some vaults include sprinkler systems in the vault depending on the building’s fire marshal. Temperature probes can tie in with this protection.

Figure 6: Vault Ventilation"

PGE uses sump pumps in all equipment vaults and an oil minder on the pumps to detect oil in the water.

Figure 7: Oil minder control unit

Figure 8: Vault sump pump

Vault Grounding: The butterfly maps show vault grounding requirements, which are used for discussions with customers and communicating vault design requirements. (Note that the distribution engineering department is working with designers to update these maps to include the specifications for cable racking.) When grounding a customer vault, the customer should provide an equipment grounding electrode, which consists of a 5/8 in. (1.6 cm) diameter rebar of at least 20 ft (6.1 m) in length, cast into the wall, and no less than 24 in. (61 cm) from the top or bottom of the vault. Concrete must completely encase the concrete, and pre-manufactured brass ground tap inserts with a steel rod connect to the grounding rebar at three points [4].

Vault Electrical Equipment: Network primary feeds connect to the transformer via a 200A straight Energy Services Network Association (ESNA) style connection. Straight connectors are used because PGE has historically brought the primary in from the ceiling. Straight connectors can also minimize the cable bend. PGE uses EPR cables to connect to the transformers. Where PGE may have installed PILC cable, it will transition to EPR to make the transformer connection.

Figure 9: Transformer primary connections

Figure 10: Primary cable joints in vault

For secondary connections, PGE uses Burndy Mole Connectors, which are engineered connectors that provide for multiple connections at a single junction point.

In approximately 16 locations, especially where the facilities are older and the vault is not big enough to fit a three-phase transformer, designers banked single-phase transformers together with a separate primary switch and wall-mounted network protector to comprise the network unit.

Ladder Extension: PGE wants to extend underground ladders above ground level to make it easier to get in and out of a vault/manhole. This could take the form of a temporary extension that can slip onto the existing ladder to extend it when PGE works on a vault/manhole. A challenge in finalizing a ladder standard is that the current ladders are of different designs and vintages. One possible solution is to first standardize all the ladders and then specify a device that would fit onto these new ladders.

Customer-Owned Vaults: Customers who accept PGE service need to install a vault where it is not possible to install a pad-mounted or pole-top transformer, and in locations to be served from network infrastructure. A structural engineer must submit final construction plans to the PGE Project Manager for final approval.

People involved include the following:

A contractor representing the customer
A PGE inspector who ensures compliance with PGE standards and specifications
A SDPM or distribution engineer

All conduits and vaults conform to the NEC, PGE’s Design and Construction Standards, City of Portland’s Bureau of Transportation (PBOT) regulations, and/or Oregon Department of Transportation (ODOT) regulations depending on jurisdiction for public highways and right of way.

Permission for access on private and public lands and roads is the responsibility of the contractor. The contractor complies with all street opening permits issued by PBOT and keeps a copy onsite. The contractor is responsible for the final execution of the work, and PGE has the final decision on whether materials, workmanship, equipment, and interpretation of the specifications are acceptable.

If any changes to plans are needed, the contractor should seek approval before the changes. After work completion, the contractor provides as-built drawings with conduit depths, conduit configuration (if altered), length of conduit installed or modified, the location and depth of other utility infrastructure crossing the conduit route, and the depth of the vaults installed.

Because most vaults are customized and unique, PGE designs the vault and conduit arrangement, or may suggest a prefabricated vault that will suit utility and customer needs. A 6 in. (1.8 cm) bed of compacted sand or gravel should smooth the base, and the excavation should leave a 6 in. (1.8 cm) gap around the walls of the vault for backfilling.

All vaults, covers, and doors should be flush and in alignment with curb and property line. Manhole covers should be set on riser rings to match the grade, and these rings will be grouted using approved vinyl, non-shrinking, waterproof grout with elastomeric coating. Vault doors set in the sidewalk should be slip-resistant, and adjustable lids should ensure that vault access doors meet the finished sidewalk grade. Any door access frame drains should be routed to the curb, and access doors in pedestrian areas should be SlipNOT® steel plate and made from Grade 3, hot-dipped galvanized metal. All door designs must meet the Americans with Disabilities Act (ADA) requirements for level surfaces and should conform to the American Association of State Highway and Transportation Officials’ (AASHTO) HS20 loading criteria.

Figure 11: Vault access doors

All transformer vaults require venting to remove excess heat created by submersible equipment. PGE will provide the venting requirements, and the vent piping should be installed and offset to maximize air flow. PGE supplies vent materials at the contractor’s expense. The installation requires core drilling and non-shrinking grout or concrete for larger vents over 10 in. (3 cm).Transformer vaults require a sump pump that should not connect to sewers in order to prevent leaking transformer oil from spreading. All seams and penetration points should be treated with a PGE-approved sealant to reduce water ingress.

Concrete used for vaults should conform to the American Society for Testing Materials (ASTM) C-150, Type II specifications. PBOT regulations specify a 28-day minimum compressive strength of 3000 psi (20,684 kPa).

A sprinkler system will be installed if recommended by the fire marshal and is intended to extinguish fires, not protect electrical equipment. It must not spill water if the sprinkler head is accidentally opened, and the system should have a control switch near the entrance for operation by PGE crews. Sprinkler heads should not be installed over the customer bus or transformer.

Post-Construction Auditing: PGE inspects and approves all customer equipment before electrical equipment is installed and service connected. The inspector is typically provided with the following:

A plan and elevation and section views of the vault showing all conduit penetrations, vent openings, access doors, and required hardware.
Ventilation design drawings
A collector bus cut sheet (if applicable)
A drawing showing the path of Ufer (concrete-encased electrode) ground connections
The PGE inspector will check the following:
Locations of pulling eyes
Locations of grounding inserts and the continuous #5 rebar loop
Metal equipment bonding
Continuous 250 MCM Ufer ground connection
Locations of ceiling anchors
Conduit penetrations (both primary and secondary)

A PGE representative will also inspect the following before installing PGE equipment:

36 x 78 in. (11 x 24 cm) main door with crash bar and PGE lock
three-way light switches at vault entry points
Access ladder
Lighting
Sump and grate
Receptacles
Fire suppression system shutoff valve (if applicable)
Interior paint
Removable sill across man door [5,6]

Technology

PGE uses ArcFM GIS software for designing network layouts and creating a package with details for relevant personnel. ArcFM builds upon ESRI’s ArcGIS and allows designers to produce an electrical map for construction crews. The system holds electrical drawings and conduit plans, although it does not store vault construction details.

The ArcFM is used with Maximo for Utilities 7.5, which creates work orders that linked to the circuit designs held in ArcFM.

Northwest Public Power Association. “Service & Design Project Manager Level II/III.” NPPA.com. https://www.nwppa.org/job/service-design-project-manager-level-iiiii/ (accessed November 28, 2017).
Portland General Electric, VT3802 - Butterfly – 712, internal document.
Portland General Electric, Customer Owned Class A Vaults, internal document.
Portland General Electric, Class A Vault Grounding Details Draft, internal document.
Portland General Electric, Customer Owned Class A Vaults Draft, internal document.
Portland General Electric, LD51030m Portland Core & Waterfront Districts Underground Core Standards, internal document.

4.23.15 - SCL - Seattle City Light

Design

Vault-Manhole Design

People

The design of the network vaults and manholes is performed by the Network Design Department, which is part of Energy Delivery Engineering. The Network Design Department performs all planning and design of SCL’s networks.

The Network Design Department is made up of eight “System” engineers, who do all of the design for the network, and eight “Services” engineers, who interface with the customers, gather load information, coordinate construction activity, etc. The individuals in this group are four-year degreed engineers. Some have their PE licenses.

The engineers at SCL are represented by a collective bargaining agreement (IBEW, Local 17).

Process

SCL installs multiple network transformers with network protectors in the same vault to supply a spot network load. Depending on the size of the load, SCL may install two separate vault locations in the building. See Attachment C for an SCL schematic and photograph of a typical spot network vault installation.

SCL’s grounding practice in building vaults is to tie the system ground in with the building steel / grounding system.

SCL runs a separate low-voltage secondary neutral (in addition to the tape shield) through each vault tied in with the substation ground. This neutral is necessary for two reasons: to maintain ground connectivity to maintain the same potential from one vault to another, and to carry the neutral currents experienced with system imbalances.

Technology

Fire Protection

SCL uses both fire protection heat sensors and temperature sensors in vault design.

The fire protection heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225 ˚ F. SCL has installed fire protection heat sensors in 95% of its building vaults. These sensors are not utilized in “street” vaults.

The temperature sensors, part of the DigitalGrid (Hazeltine) system, send an alarm to the dispatcher at 40 ˚ C – well before the network protector trip threshold is reached. SCL currently has completed installation of these sensors in about 20% of their vaults. They plan to install these sensors in all of their network vaults (both in building vaults and in “street” vaults).

Cable Cooling System

SCL has designed and installed a novel chilled-water heat-removal system to increase the ampacity of cables at a certain location that was identified as a thermal bottleneck due to the number of adjacent network primary feeders, depth of burial, and other factors.

They have been successful in increasing the ampacity of these cables by 40% through the installation of this water-cooling system. See Attachment D for a detailed description of the project

4.23.16 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 8.6 - Manholes, Vaults and Handholes

4.23.17 - Survey Results

Survey Results

Design

Vault Manhole Design

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 6 : Do you require a firewall between two pieces of equipment in one vault?

Question 9 : Please indicate where you use vented vault and manhole covers to prevent accumulation of gases. (Not including vented gratings for transformer cooling)

Question 10 : If you apply vented covers selectively, what criteria do you use to select locations?

Question 11 : Are you using manhole cover restraints in parts of your system?

Question 12 : If yes, what criteria do you use to select locations at which to apply a cover restraint?

Question 13 : Are you using arc proof tape in your network designs?

Question 14 : Do you use high flash point (less flammable) fluids in the fluid filled tanks of network equipment?

Survey Questions taken from 2015 survey results - Design

Question 51 : Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers) (check all that apply)

Question 57 : Have you incorporated skid free vault and manhole covers into your civil designs?

Question 58 : If so, are you retrofitting older existing covers with skid free ones?

Question 62 : Are you using manhole cover restraints in parts of your system?

Question 78 : Do you have a sump pump and discharge system inside your street vaults?

Survey Questions taken from 2012 survey results - Design

Question 4.3 : Does your network utilize vaults located

Question 4.4 : What type of design are you using for new civil structures such as manholes and vaults?

Question 4.6 : If your network utilizes subsurface vaults, do you use automatic sump pumps to clear water accumulation?

Question 4.7 : If Yes, does your standard design call for oil sensors on sump pumps in vaults that house oil containing equipment?

Question 4.8 : If yes, do these sensors function to prevent the pumping of oil into the street?

Question 4.9 : Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers)

Question 4.10 : In designing your network vault, what ground resistance do you require from the ground system inside the vault?

Question 4.15 : Have you incorporated skid free vault and manhole covers into your civil designs?

Question 4.16 : If so, are you retrofitting older existing covers?

Question 4.17 : Are you using manhole cover restraints in parts of your system?

Survey Questions taken from 2009 survey results - Design

Question 4.4 : Does your network utilize vaults located

Question 4.5 : What type of design are you using for new civil structures such as manholes and vaults?

Question 4.6 : If your network utilizes subsurface vaults, do you use automatic sump pumps to clear water accumulation?

Question 4.7 : If Yes, does your standard design call for oil sensors on sump pumps in vaults that house oil containing equipment?

Question 4.8 : If yes, do these sensors function to prevent the pumping of oil into the street?

Question 4.9 : Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers)

4.24 - Vault Design – Remote Trip Panel

4.24.1 - CenterPoint Energy

Design

Vault Design-Remote Trip Panel

People

CenterPoint designs each vault with a remote trip panel that enables an operator to operate breakers located in the vault remotely, from outside the vault. CenterPoint has a fabrication group that builds the panel boxes for the remote tripping units.

Process

Remote trip panel boxes are located outside of the vault, typically just outside the vault access doors^[1]. They enable an operator to operate breakers within the vault, such as primary disconnects feeding the vault transformer, remotely from outside the vault.

Figure 1: Picture of a remote panel box located outside the Vault (Door entrance)

CenterPoint also locates remote trip panels just below the outside opening in a surface access. These remote panels are tethered so that a worker who is entering a vault from the street level can pull the remote control box outside the hole to operate the breaker.

Figure 2: Picture of remote control box mounted below vault entrance at street level Note the tether enabling the operator to pull the box up out of the hole

Technology

Figure 3: Picture of the inside of a control box

^[1] Note that all transformer vaults have minimum two entrances.

5 - Maintenance

5.1 - Cable Testing - Diagnostics

5.1.1 - AEP - Ohio

Maintenance

Cable Testing - Diagnostics

People

The performance of cable testing and diagnostics at AEP Ohio is the responsibility of the field crews on site, who are Network Mechanics. Testing and diagnostics are performed by Network Mechanics and Network Crew Supervisors on-site. In the case of its extensive secondary cable replacement program (see Cable Replacement), AEP Ohio and its contractors have performed extensive inspection and assessment of secondary cables in the AEP Ohio network.

Process

AEP Ohio does not perform routine diagnostic testing of network cables. AEP Ohio performs a 45-minute AC VLF and tan delta withstand test (not a proof test) on network cables before restoring a repaired cable. The company does not perform this test on healthy cables that are taken out of service so as not to damage or accelerate breakdown of the cable. AEP Ohio is also working with NEETRAC to better understand and apply cable diagnostic techniques.

If a Network Mechanic or Network Crew Supervisor discovers a splice failure, a splice analysis is conducted at the site. Further analysis can be performed by the Network Engineers. The engineers may send failed joints to an outside source, such as the manufacturer or external laboratory.

Technology

All trucks assigned to Network Mechanics have on-board computers, and network crews can log into the AEP underground network (UGN) intranet for guidance, process and procedures, including links to diagnostic guides.

5.1.2 - Ameren Missouri

Maintenance

Cable Testing - Diagnostics

People

Ameren Missouri has not historically performed routine diagnostic testing of network cables other than fault location testing and, on rare instances, proof testing after cable repair where the situation suggests that there may be remaining trouble with the outaged feeder.

Distribution Service Testers perform cable testing for fault location using a DC Hi pot test.

At the time of the practices immersion, Ameren Missouri’s Underground Revitalization Department was developing a criterion for replacement of cables in the urban underground system. This criterion will provide for the testing, replacement, maintenance and improved utilization of cable systems within downtown St. Louis, and will include plans for non-jacketed and jacketed PILC cable, cloth covered secondary cable, and 15 kV solid dielectric cables. The strategy will also include guidelines for 15 kV bolted separable splices.

Ameren Missouri has joined the Cable Diagnostic Focused Initiative (CDFI)^[1] , and has recently performed some cable diagnostic tests working with the CDFI to evaluate test methods.

Technology

Note that Ameren Missouri uses a reduced-diameter cable, which is subject to stringent specifications, and is thus produced through a high quality manufacturing process to meet those specifications. Ameren Missouri believes that they are receiving a higher quality cable and noted that they have never had a true cable failure due to a manufacturer flaw in the cable itself.

^[1]CDFI is an initiative led by NEETRAC and supported by the US Department of Energy and utilities such as Ameren Missouri to understand how to effectively use the various diagnostic technologies to establish the condition of medium voltage underground cable circuits.

5.1.3 - CEI - The Illuminating Company

Maintenance

Cable Testing - Diagnostics

People

Cable Testing is performed by the UG Electricians within the Underground Network Cable Services Section. Testing is performed by a crew that includes more experienced Underground Electrician Leaders.

Process

Ideally, CEI would like to perform proactive cable diagnostic tests on one fifth of their system per year – about 240 circuits / year. However, resource constraints have limited them to proactively testing about 40 circuits per year using Very Low Frequency AC Hipot Testing (VLF Testing). Tests are performed on both all lead and lead – EPR hybrid circuits. The VLF test is a withstand test, revealing defects in the cable insulation. CEI has chosen VLF as a withstand test, because it does not cause insulation damage as does DC Hipot testing. In 2008, their testing revealed one failure at a cable end disconnect (no cable failures). See Attachment - J for a sample form for recording test results.

CEI also performs diagnostic testing after a cable repair, prior to re-energizing a circuit or circuit section. This testing is either a Megger test (DC insulation test) at a minimum, or preferably, a VLF test. CEI will opt for a low voltage (5kV) megger test in cases where they have older oil switches on the circuit, fearing that higher voltage testing methods, such as VLF, could damage or further shorten the life of these older devices.

Cable diagnostic testing is also used in fault location, including DC Hi Pot Testing and cable “thumping”.

The corporate Distribution Planning and Protection group, together with corporate Asset Management and Design Standards, is leading a “Predictive Cable Failure Initiative” aimed at developing and implementing a more formal cable diagnostics plan at FirstEnergy. The group has analyzed cable performance and has identified eight key factors that can be used to assess cable failure risk. They have researched various cable diagnostic alternatives, such as VLF testing, DC Hi pot testing, and VLF Tan Delta testing, and have documented the costs and benefits of various testing alternatives. They have laid out what a full cable testing program would look like, including an estimate of costs and system impacts. The group is in the process of developing a final recommendation.

Technology

CEI has specialized trucks that are equipped with cable diagnostic equipment, including DC hi pot testers, and VLF testers.

Figure 1: Fault Location Truck

Figure 2: Fault Location Truck (Inside View)

Figure 3: DC Tester – 110V

Figure 4: VLF Tester

5.1.4 - CenterPoint Energy

Maintenance

Cable Testing - Diagnostics

People

Cable diagnostic testing is performed by the Relay group within Major Underground. The Relay group is comprised of Network Testers, a bargaining unit position at CenterPoint. Network Testers report to a Crew Leader, a non bargaining unit position at CenterPoint. The Relay group is lead by an Operations Manager.

CenterPoint does not have dedicated cable diagnostic crews. All Network Testers are trained in performing cable diagnostics. Crews perform diagnostic testing without the involvement of a CenterPoint engineer.

Process

CenterPoint is not performing preventive diagnostic cable testing on circuits that have not experienced a fault. They are presently considering implementing some sort of proactive cable diagnostic testing, but have not yet decided on an approach. At one time, they would proactively take healthy circuits out of service and conduct VLF testing. However they found that this approach did not yield productive results.

CenterPoint uses Very Low Frequency AC hipot testing (VLF) testing to diagnose remaining cable condition after a fault. CenterPoint has been utilizing VLF testing longer than any utility in the nation.

The VLF test is a withstand test, revealing defects in the cable insulation by breaking down water and electrical trees in the insulation. When CenterPoint first began VLF testing, they were conducting a one hour test. They noticed that most failures revealed themselves in the first 15 minutes of the test, or in the final minutes of the test. They believe that the hour test was breaking down insulation in cable sections that still had significant remaining life. Consequently, they cut the duration of the VLF test to 15 minutes, and report that they have seen no increase in repeat failures of cables that tested OK with the 15 minute test over their experience of cables that tested OK with the one hour test; that is, the 15 minute test is effective for them.

CenterPoint performs VLF testing after locating a cable failure to “proof” the remaining existing cable sections before making the repairs and re-energizing the cable^[1] . They will VLF XLPE and EPR cables. If, during the VLF testing, they expose a failed section of the remaining cable, they will replace or repair it. (One CenterPoint employee estimated that the VLF test reveals additional bad cable sections in the remaining cables in about 15 -20% of the tests conducted)^[2] . CenterPoint has found this approach – testing remaining cable sections after a fault - to significantly reduce their experience of repeat cable failures.

After making the repairs, and installing new cable sections, CenterPoint does not test the repaired and replaced infrastructure before re-energizing.

Cable diagnostics are also used in fault location, including DC Hi Pot Testing and cable “thumping”, and in some cases, Time Domain Reflectometry (TDR) testing. (not used in networks systems). See Fault Location.

CenterPoint does not perform cable diagnostic testing on new cables being put into service, as their cable procurement quality control process includes tests of the cable. See Cable Quality Control.

Technology

CenterPoint has specialized trailers that are equipped with cable locating and diagnostic equipment, including thumper, TDR, and VLF testers. Network Testers will hook the trailer on their trucks and take it to the job site. CenterPoint is using test units by Cable Dynamics and by Centrex

Figure 1: Cable Testing Van - External

Figure 2: Cable Testing Van - External, generator

Figure 3 and 4: Cable Testing Van - Internal

Figure 5 and 6: Cable Testing Van - Internal

^[1] An exception would be certain very old cable that, through experience, they know has remaining life, but whose life would likely shortened by high voltage testing methods, such as the VLF test. Note that their repeat failure rate in this type of cable is only about 5%.

^[2] Note that if their VLF test results reveal three different failure locations on a cable section, CenterPoint will replace the entire feeder section. This standard is particularly applicable to the distribution in their outlying areas.

5.1.5 - Con Edison - Consolidated Edison

Maintenance

Cable Testing - Diagnostics

People

Cable diagnostic testing is performed by the Field Operating Department (FOD) (Also called the Field Operating Bureau). The Field Operating Department is part of Electric Distribution, and has responsibility for the emergency crews (the crews using the red emergency trucks), as well as the following accountabilities:

Fault locating (distribution and transmission)
High-tension switching (entering customer high-tension vaults and operating devices)
Feeder identification
Hi-pot testing

Cable Testing Laboratory

Con Edison has its own cable Testing Laboratory , which has been in operation since the 1970s. This laboratory has over 100,000 cable and accessory specimens. Sometimes the lab sends specimens to outside labs to obtain independent analysis and opinions.

Con Edison invests in keeping its laboratory staff current on the latest thinking in cable testing. They are active in industry groups. They invest in rotating new people into the cable department, including engineers from Con Ed’s Gold program (a mentoring program for high potential engineers and business professionals).

Process

Con Edison has historically performed regular Hi-pot testing of its network feeders (13.8 and 27 kV). Hi-pot testing is the application of a specific voltage ( High Potential) on its network cables for a specific period of time to expose/bring to fruition incipient faults in the distribution system. Con Edison has a clear procedure that documents its approach to regular Hi-pot testing.

NOTE that Con Edison is transitioning to the use of VLF AC Hi Pot withstand testing.

When Con Edison performs Hi-pot testing, the utility tests the feeders with all three phases together. Because of the length of Con Edison’s feeders (the largest feeder has more than 20 circuit miles), and the need to test all the phases together, crews use a very large test set developed by HDW, and mounted on a specially equipped truck.

Note that Hi-pot testing at Con Edison is always preceded by an Ammeter Clear Test, which is the application of low-voltage, 60-cycle, AC signal to a feeder to indicate the presence (or absence) of short circuits or grounds on the feeder conductors or on transformer secondaries.

Hi-pot testing is performed at Con Edison for two main reasons:

A routine test to ensure that feeder insulation meets acceptable limits before the feeder is put into service. This applies to both new feeders about to be put into service, and to failed feeders that have been repaired and are about to be returned to service.
Scheduled tests performed annually (Annual Testing Program) on selected feeders for the purpose of revealing incipient faults that need to be restored to the proper insulation level.

For the routine tests, the type and frequency of test required vary with the condition that caused the feeder outage. New feeders are tested before being put into service. In general, feeders that automatically trip are required to be tested depending on the historic reliability and criticality of the network they supply. Feeders that are manually opened may not need to be Hi-pot tested before re-energizing depending on the rationale for taking the feeder out of service. Con Edison’s written procedure fully describes the required testing type and frequency of the different cable types and scenarios.

For the scheduled feeders tested as part of the Annual Testing Program, Distribution Engineering develops a list of feeders that should be Hi-pot tested by the Customer Service Regions between October 1 and June 1 of the following year. This work is scheduled to be finished before the summer peak loading period. Con Edison tests about 50 circuits a year as part of this program.

Distribution Engineering selects the feeders to be tested as part of the annual Hi-pot program by considering three different factors: the Feeder Failure Index, OA History Factor, and Network Design Factor. Each of these factors is weighed equally in determining the feeders to be tested.

The Feeder Failure Index is derived by considering the failure rates of various components on the feeders, such a cables and joints during sustained high heating periods.

The OA History Factor is the number of total Open Autos (feeder lockouts), including dig-ins, from June 1 to August 31 of the two previous years.

The Network Design Factor is the total of two components, the Shift Factor and the Delta Factor. The Shift Factor is an indication of the importance of a feeder to the network, in terms of the load it can pick up (load shifted to it) during an emergency. The Delta Factor is a measure of how uniformly the load is distributed in the network.

Cable Failure Analysis

Con Edison’s goal is to perform a failure analysis on every cable and splice failure that occurs. The utility is able to perform an actual analysis on 80 – 90% of the problems that occur; the remainder represent problems that are destroyed or inaccessible.

In addition to testing cable that failed, the utility tries to expand testing to look at the condition of adjacent cable sections that did not fail. In the case of a splice failure, crews replace all three splices and perform diagnoses on the unfailed splices to aid in drawing conclusions about the cause of the failure.

A big challenge for Con Edison is failures that occur in transition joints (between PILC and non-PILC conductors). These transition joints are commonly referred to as “stop joints.” The failures they encounter typically occur on the paper side of the joint. The utility has implemented a replacement program to install cold shrink joints to replace them. They have had good success with the cold shrink joints.

Technology

Con Edison is presently evaluating the use of partial discharge testing as a future tool for performing cable diagnostics, and as a replacement for the potentially destructive DC Hi-pot test. In the past, Con Edison has taken periodic partial discharge measurements, but found that the readings varied greatly, causing them to think that something else was going on. The utility believes that, by monitoring partial discharge in “real time,” they can ascertain patterns and draw conclusions about cable condition. Con Edison has a spec in place with KEMA to install a partial discharge system for testing and evaluation.

The Field Operating Department is part of Electric Distribution, and has responsibility for the emergency crews (the crews using the red emergency trucks), as well as the following accountabilities:

5.1.6 - Duke Energy Florida

Maintenance

Cable Testing - Diagnostics

People

The Asset Managers within the PQR&I group at Duke Energy Florida determine when and how cable should be tested. Job Site Managers and Contractors perform this work for Duke Energy Florida. Contractors are involved in above-ground inspections and testing only. All underground work is performed by Duke Energy Florida craft personnel.

Cable Testing and diagnostic programs are determined by Asset Managers within the Power Quality, Reliability and Integrity (PQR&I) group. PQR&I has responsibility for all Asset Management at Duke Energy Florida. The asset managers work with the PQR&I Governance group, which supports different local operating jurisdictions.

Within PQR&I, a particular asset manager, an Engineering Technologist II, manages underground primary cable assets, including the cable testing program.

Note that this Asset Manager, responsible for cable assets, works closely with two other Asset Managers within the PQR&I group, one focusing on switchgear, and another on all other network equipment. All three act as a Network Asset Management team, with complete communication and collaboration. Even though asset responsibility has been divided up, all three members have the capability of stepping in to help in any area in case of vacations, leave, etc.

The PQR&I Governance organization works with the Asset Managers to shift funds between areas (switchgear, cable, and equipment, for example) as asset need dictates. If funds are underutilized in one area, they can be reallocated to another area in need.

Duke Energy Florida is utilizing the services of a cable diagnostic testing contractor to conduct routine cable diagnostic testing to determine the integrity of its primary cables. The contractor performs partial discharge testing, which they perform in different stages.

Duke Energy Florida is utilizing a contractor to perform their cable replacements in Clearwater and St. Petersburg. The contractor crews are overseen by two Network Specialists who have been designated to provide oversight and coordination to the contractor crew. The contractor performs all aspects of the work, including cable pulling and spicing. The contractor will obtain and hold clearances, though the work of executing the switching to obtain the clearance is performed by Duke Energy employees.

Duke Energy Florida is not performing cable diagnostic testing, other than fault locating, on the three primary feeders supplying the Clearwater network.

Process

Led by the Asset Manager responsible for primary cable systems, Duke Energy Florida conducts routine cable diagnostic testing to determine the integrity of its primary cables, utilizing the services of a cable diagnostic testing company. Cable testing is age-based – with cables selected for testing that are 25 years or older, or that are suspect based on performance. (For example, a college experienced two major outages despite having cable that was only 10-14 years old. Engineers had difficulty pinpointing the cause of the outages, and ordered integrity testing of the cable based on performance).

Duke Energy Florida tests 80 segments per month over a nine-month period per year. The diagnostic testing performed by the contractor is not feasible in all situations, depending on factors such as manhole placement, circuit configuration, circuit condition, or feeder operation. Feasibility is determined by field inspections to ensure that the pre-test conditions can be met, and that cable sections can be safely and efficiently isolated for testing. Duke Energy Florida crews will de-energize and isolate the cable so that the contractor can apply their testing equipment. The testing consists of a checklist of over 170 different aspects of cable health and industry comparisons, and the contractor will recommend cable sections for repair or replacement.

Cable replacement decisions are driven by diagnostic test results. Depending on test results, the PQR&I group will determine whether a cable has integrity and remaining life or needs replacement. If replacements need to be made, the other asset managers who deal with circuit components are consulted to identify equipment replacement needs on the identified circuits.

Duke Energy also performs routine cable replacements that are based on cable age and performance history, rather than on diagnostic testing results. This is the case in St. Petersburg, where older cables are being replaced based on age and performance history, as these cables were not appropriate candidates for diagnostic testing (because of significant branching of cable sections.) Note that the Integrity Engineer within PQR&I tracks cable outages even if customers are not affected. The PQR&I organization has decided that piece-meal repair or replacement of small sections of cable not an efficient way to rehab aging cable systems as this approach generates many small, and ultimately more expensive jobs. Rather, Asset Management seeks to replace who sections of cables systems identified for replacement by age, performance history or diagnostic test results.

As a result of the testing program and of routine cable replacements, approximately 1.5 million feet of cable has been replaced since the inception of the program. At the time of the practices immersion, Duke Energy Florida had not tested the three feeders supplying the Clearwater network.

Note that at Duke Energy Florida, the costs of the cable diagnostic testing program, including any expenses to de-energize, switch, or otherwise prepare the cable for testing, as well as the costs of any cable replacement based on testing results are capitalized based on a FERC agreement that requires that all cables that are aged and are candidates for testing are tested and / or replaced by 2019. The costs of the diagnostic testing are warrantied, such that if the testing deems a cable to be of satisfactory and then it fails, the testing company will perform an investigation to identify the cause of the cable failure.

Asset Management is in the process of incorporating cable testing prior to energization of new cables into their program. The company believes this commissioning testing to be a good quality control check that can forestall outages.

Secondary cable is not currently a part of the Duke Energy Florida cable testing program. The company has seen no need for testing secondary network cable in the St. Petersburg/Clearwater network at the time of this study.

Technology

Duke Energy Florida uses contractor cable testing that includes a checklist of over 170 cable conditions. The specific approach to diagnostics is proprietary, but utilizes offline partial discharge testing.

5.1.7 - Duke Energy Ohio

Maintenance

Cable Testing - Diagnostics

People

Duke Energy has a strong focus on performing cable diagnostic testing. They have been proactively performing cable diagnostic testing, including the use of VLF withstand and VLF Tan Delta testing, since 2007. Duke is a member of the Cable Diagnostic Focused Initiative (CDFI), and is working closely with NEETRAC^[1] on refining their cable diagnostic approach. Duke shares their testing results with NEETRAC.

Dana UG field crews perform the cable diagnostic tests for Duke Energy, Cincinnati. The Dana UG group has identified two crew leaders who routinely perform the testing and have thus become experts. When there is a question or something unusual, these crew leaders will reach out to the Project Engineer supporting the network operation.

Crews typically test two circuits per day – they schedule the testing for days in the middle of the week so that if they have issues they can repair them during the week.

When they first started the routine diagnostic testing, there was some trepidation among the work force. People are now believing in the diagnostic testing, as they have seen cables with bad test results undergo repair, and then look good upon a re test.

Duke has seen a sharp decrease (36-40%) in the number of power cable failures since implementing their diagnostic testing program. Why they can’t be sure that this decrease is due solely to the implementation of diagnostic testing, they believe that the testing program has been a significant contributor to the decrease.

Process

Duke performs cable diagnostic testing on from 50 – 80 circuits per year. They select “high risk” circuits for testing based on age, customer count, span lengths, customer criticality, and a “push” from a customer representative.

Note that the testing is focused primarily on non network 15kV feeders. Duke has not yet implemented proactive diagnostic testing of network feeders unless there is some question about the feeder, such as frequent outages in a given period of time. The reason network feeders are not tested is because of the number of branches on these feeders, making it difficult to identify the location of the problem area identified by testing. Moreover, the circuit to be tested must be opened, cleared and tagged before performing diagnostic testing. For network feeders, this can in some cases require a full day to perform switching to clear the feeder, a day to perform the testing, and a full day to restore the feeder. Duke is considering adding 600 A sectionalizing points on network feeders to be able to break the feeders up to perform testing.

To clear a feeder for diagnostic testing, Duke will submit an outage request, indicating the time frame, type of outage requested, etc. This request would first flow through the Planning group to identify anything else that may be happening on the feeder. The request then goes to a “Processor” who will write the switching procedures. Note that most of Duke’s system is looped enabling customers to be picked up by adjacent feeders.

Finally the request will go to the Trouble Desk. Mobile Operators will do any switching in substations, while field crews will perform any switching out on the line. All switching is completed and the line cleared before the DANA crews come out to do the testing.

Duke issues a report each morning that shows circuits that are out of service for testing (and other reasons).

Duke uses a multipronged approach to cable testing, using Time Domain Reflectometry (TDR), Very Low Frequency (VLF) Tan Delta (a dielectric loss test), and VLF AC withstand testing.

Duke will perform a VLF AC Tan Delta testing to get a general idea of the health of a particular cable. They perform the test in a stepped manner, using four steps held for three minutes. This test provides a measure of total cable system loss (power in versus, versus power used).

Duke also performs AC VLF withstand testing to identify any imminent cable failures and force them to failure. Duke normally uses a 15 minute test, but may hold for 30 minutes depending on the tan delta readings, or if the readings haven’t stabilized. The crew will stop the test if they identify any abnormalities. Also, the crew may stop short of performing the withstand test, if it is critical not to push a given feeder to failure for operating reasons. Depending on their findings, Duke may involve NEETRAC in the decision making.

Duke will use TDR to help identify the location of problem(s) that may be identified through their testing. This may trigger additional inspection activity do determine the overall condition of the feeder, and may trigger the feeder for replacement.

In addition to scheduled diagnostic testing, Duke will perform a VLF Tan delta test before putting a feeder back in service that was taken out for other reasons, such as to replace equipment, or to make repairs to a damaged feeder.

All data from the testing is kept in a spreadsheet.

Duke is also performing cable diagnostic testing as part of their process for accepting new cable. They are presently performing a DC hi pot on new cables, and performing an AC Tan delta test to establish a baseline. They are in the process of moving away from DC high pot test and moving to an AC VLF high pot test.

Technology

Duke uses specialized vehicles, such as cable testing trucks to aid them in performing cable diagnostic testing. They are in the process of obtaining a specialized truck with the Tan delta equipment.

^[1]NEETRAC, the National Electric Energy Testing, Research & Applications Center, is a research center in the School of Electrical and Computer Engineering at the Georgia Institute of Technology.

5.1.8 - Energex

Maintenance

Cable Testing - Diagnostics

Process

Energex does not perform routine cable testing or diagnostics of their 11 KV cable system. However, cable is tested in the field before commissioning. New cable is tested by the manufacturer and batch sample tested in-house at Energex before it is moved to its supply stock.

Energex has not found it necessary to perform routine cable tests as its CBD underground network has been highly reliable. The majority of cable failures are from “dig ins” at construction sites where proper caution was not taken to locate the buried electric power conduits. Energex has the view that unless there is a known problem on its 11 kV system, it is acceptable to “run to failure,” which has not been often.

Note that Energex does perform routine diagnostic testing of its 33 kV sub transmission cable system.

5.1.9 - ESB Networks

Maintenance

Cable Testing - Diagnostics

People

Cable diagnostics at ESB Networks are performed by Network Technicians, the journey worker position. The Network Technician is a multi-faceted position, performing both line work, such as building pole lines, and electrical work, such as making connections at a transformer. Network Technicians work on all voltages from LV through transmission voltages (110 kV). Note that ESB Networks created the Network Technician position in the 1990s by combining a former Line Worker position and Electrician position.

Work specialization for Network Technicians is by assignment. In Dublin, where the majority of the distribution infrastructure is underground, Network Technicians work mainly as cable jointers, installing underground cables and accessories. ESB Networks rotates Network Technician work assignments as business needs require.

The Training and Asset Management groups work closely with Network Technicians working as cable jointers to ensure that they understand the science of cable joints and have an appreciation for the importance to long-term joint reliability of performing the proper steps associated with cable joint preparation.

Process

ESB Networks has no formalized routine cable diagnostic testing policies for its 10-20 kV systems. Cables are tested in the field only if there is a problem, or suspected problem.

Note: The utility requested cost recovery for a program of proactive cable diagnostics from regulators, but the regulatory panel was against it due to cost. As a result, ESB Networks uses its “front line” Network Technicians in the field as its last line of cable inspection and diagnostics, with inspections of cables taking place at the job site.

5.1.10 - Georgia Power

Maintenance

Cable Testing - Diagnostics

People

Cable fleet management in the urban underground networks supplying metropolitan area customers in Georgia is the responsibility of the Network Engineering group within Network Underground. Organizationally, the Network Underground group is a separate entity responsible for all network infrastructures, reporting to the Network UG manager. The network engineering group is led by a manager and is comprised of four-year and two-year degreed engineers focused on electrical and civil design and feeder level planning.

Network standards, including standards for cable, are the responsibility of the Standards Group within the Network Underground group. The standards group is comprised of two principal engineers who work in the Network Underground group. One of these engineers reports to the Network UG Engineering group, and the other, directly to the Network UG Manager.

Cable Testing is performed by Network Test Engineers, part of the Network Operations and Reliability group.

Process

The Georgia Power Network Underground group has not historically performed routine diagnostic testing of network cables other than fault location testing and, on rare instances, proof testing after cable repair where the situation suggests that there may be remaining trouble with the feeder.

Network Test Engineers perform cable testing for fault location using a DC Hi pot test and through data received at its Network Operations Center, which collects near real-time data on network service through its extensive SCADA system.

If Network Test Engineers discover a splice failure, a splice analysis is conducted at the Network Test Center, typically by a senior or other principal engineer; the testers tear apart the failed joint and determine whether it was workmanship, a training issue, or what other factors caused the joint to fail. They perform the forensic analysis at the Network Underground facility. On occasion, the engineers may send failed joints to an outside source, such as National Electric Energy Testing Research and Applications Center (NEETRAC).

Technology

At the time of the practices immersion, Georgia Power was investigation the use of tan delta testing (dissipation factor) for network cables. This technique may offer benefits as a periodic qualitative check of cable condition.

5.1.11 - HECO - The Hawaiian Electric Company

Maintenance

Cable Testing - Diagnostics

People

Cable Testing is performed by the Cable Splicers within the C&M Underground Group. The Underground Group at HECO is part of the Construction and Maintenance organization. The group is comprised of two UG supervisors, fifteen Cable Splicers, 2 Utility Mechanics, and 2 Utility Assistants.

The HECO cable testing methodology is developed by the Technical Services Division within the Engineering Department.

Process

HECO uses Very Low Frequency AC Hi Pot withstand testing (VLF Testing). They have chosen VLF as a withstand test, because it does not cause healthy insulation damage as does DC Hi pot testing. VLF testing will identify unhealthy insulation, identifying and breaking down weaknesses so that they can be located by traditional methods such as cable thumping.

HECO is not performing cyclical, proactive cable withstand / diagnostic testing. Rather, HECO’s approach is “targeted” in that they perform proactive VLF withstand testing on cable sections that have had a history of failure (either cable failure or failures in separable connectors). They perform a one half hour test on each phase.

HECO has considered implementing a more comprehensive application of VLF testing, testing some percentage of their total cable plant each year, but has hesitated based on concerns that the VLF test could break down the insulation in cable sections that may actually have significant life left in the cable. This issue is currently under investigation and consideration at HECO.

Figure 1 and 2: Applying VLF Test Leads

Figure 3: Applying VLF Test Leads

Figure 4: VLF Test Kit

HECO also performs VLF diagnostic testing after finding a fault to “prove out” the remaining cable prior to re-energizing a circuit or circuit section.

Technology

HECO has specialized trucks that are equipped with cable diagnostic equipment, including DC hi pot testers, and VLF testers.

5.1.12 - National Grid

Maintenance

Cable Testing - Diagnostics

People

National Grid performs routine proactive VLF cable diagnostic withstand and tan delta testing of underground feeders. However, at the time of the practices immersion, they were considering, but had not yet applied this testing (routinely applied withstand and tan delta testing) to network feeders.

National Grid has prepared an Electric Operating Procedure (EOP) that defines when and what type of test is to be applied. For example, new cables are acceptance tested to assure the cable is suitable for service and to provide a benchmark for comparison of results from future testing.

VLF withstand testing is a dielectric withstand test that involves the application of a very low frequency AC voltage to the cable.

Tan Delta (dissipation factor) testing gives an indication of cable health, compared to previous or theoretical results. Regular testing can provide trending data and assist with identification and proactive replacement of cables in poor condition prior to service interruption from cable failure.

National Grid is also investigating the use of partial discharge testing, which can detect electrical trees, tracking and cable voids. However, the length of their system and its hybrid composition present challenges for using PD testing on network feeders. National Grid does not have a trained engineer or dedicated crew for regular use of PD testing equipment.

Process

The National Grid EOP provides recommendations for testing developed by Distribution Engineering Services. However, the final determination as to when to test a cable is the responsibility of the operating divisions.

National Grid may perform four types of tests:

Acceptance Test: A field test made after a new cable system installation, including terminations and joints, but before the cable system is placed in normal service.

Diagnostic (Withstand) Test: A test conducted during the operating life of a cable to determine and locate degradation that may cause cable and accessory failure. National Grid is using a 60 minute VLF AC test.

Installation Test: A test conducted after cable installation, but before jointing (splicing) or terminating where a problem is suspected with the cable (such as damage from cable pulling, for example).

Pick Up Test: A test applied to a cable circuit which has been repaired or modified, intended to locate gross problems which will most likely cause immediate failure of the circuit. National Grid uses VLF AC testing for 5 minutes for the Pick Up test.

Technology

National Grid’s newer VLF and Tan Delta testing equipment is from HV Diagnostics, and they have four (4) sets in operation, and two (2) sets in storage awaiting new vehicles. The equipment is modular, semi-portable (the largest piece is 300 lbs), and simple to operate with a menu driven system. Tan Delta analysis requires a laptop, and the system uses blue-tooth communication from HV unit to laptop so that no cables are required

National Grid also has an HV Diagnostics Partial Discharge unit. The unit uses the same VLF power supply that is already in operation with the other HV units. National Grid currently has one test set, which is not yet in operation.

Figure 1: VLF Test Set

Figure 2: Tan Delta Test Set

5.1.13 - PG&E

Maintenance

Cable Testing - Diagnostics

People

PG&E performs routine proactive cable diagnostic testing of underground feeders. For network feeders, the application of proactive diagnostic testing is relatively recent, beginning in 2010. PG&E performed diagnostic testing (VLF) of network feeders during the summer of 2010, and then suspended the testing in September to evaluate its efficacy. Based on this evaluation, they will recommence with proactive VLF testing of network cables in 2011. Note that PG&E performs VLF testing of non-network cables as well.

VLF testing is performed by the Applied Technology Services (ATS) group. This group employs technicians trained and equipped to perform VLF Hi Pot and VLF Tan Delta testing. The ATS group works closely with cable splicers to apply and perform the tests.

The selection of feeders to test is based on historic reliability performance data supplied by the network planning engineers.

Process

PG&E performs very low-frequency (VLF) AC withstand and tan delta testing of underground feeders. They do not use a routine cyclical approach; rather, they decide which feeders to test on a case-by-case basis based on reliability performance. The five worst performing network circuits were chosen for testing in 2010^[1] .

PG&E performs a VLF AC Tan Delta testing to get a general idea of the health of a particular cable. This test provides a measure of total cable system loss (power in versus, versus power used). PG&E also perform an AC VLF withstand test to identify any imminent cable failures and force them to failure. They conduct a one half hour withstand test, testing each phase at two times the voltage.

VLF testing is performed by the Applied Technology Services (ATS) group. This group employs technicians trained and equipped to perform VLF Hi Pot and VLF Tan Delta testing. Failed cable sections identified by the testing are troubleshot by field crews and replaced.

Because network feeders at PG&E are designed with sectionalizing switches, PG&E is able to narrow down the location of the breakdown revealed by the VLF withstand test to a cable section.

During the immersion, EPRI researchers were able to observe the performance of a VLF hi pot test on a network feeder to fail and locate the failure point. In this particular case, PG&E had earlier performed a proactive VLF withstand test on a network feeder, and the test revealed some breakdown of the installation one of the phases. The VLF withstand test was applied to circuit at the substation, and indicated a breakdown somewhere on the feeder. Because network feeders at PG&E are designed with sectionalizing points, PG&E was able to sectionalize the circuit and then retest from the substation. This second test revealed no breakdown of the cable insulation from the station to the first sectionalizing point, indicating that the problem with the cable was located further down the line (beyond the sectionalizing point).

Figure 1: VLF Test Set connected at Sectionalizing Switch

Figure 2: VLF Test Set connected at Sectionalizing Switch

In this case, the original VLF testing was performed by the ATS group, while the testing to find the fault was performed by cable crews, and supervised by the ATS group.

When PG&E removes a feeder from service to perform VLF testing, the M&C group will take advantage of this outage to perform other planned or corrective maintenance.

Note that PG&E is presently evaluating the merits of cable diagnostic testing for network feeders. They expressed some concern that the destructive nature of the breakdown test could force cables with significant remaining life to failure. After testing network cables during the summer of 2010, they suspended testing to evaluate the implications of the testing.

Technology

PG&E uses a specialized vehicle (minivan) equipped with cable diagnostic equipment, including a VLF test set, tan delta device and TDR kit. See Photographs below.

Figure 3: Specially equipped cable diagnostic minivan. Note ramp for loading / unloading VLF Test set

Figure 4: VLF Test set on a cart

Figure 5: Tan Delta device located in specially equipped cable diagnostic minivan

Figure 6: Hi Pot testing device located on back of truck

^[1]Network feeders selected for testing are taken out of service for the purpose of testing. PG&E has no standard that requires a cable diagnostic test prior to reenergizing an outaged feeder.

5.1.14 - Portland General Electric

Maintenance

Cable Testing - Diagnostics

People

For the CORE, cable testing and diagnostics are largely the responsibility of the Special Tester position, who is a journeyman lineman with additional training and technical skills. The Special Testers support the network department, with one individual embedded within the CORE group.

As part of its work, including performing cable diagnostic testing, the Special Tester usually partners with cable splicers, working as part of a crew. The “special testing” crew includes the Special Tester, a crew foreman (a cable splicer), a lineman/cable splicer, and a topman. The topman stays outside the hole and watches the manhole/vault entrance to ensure no accidents.

In addition to performing cable testing, such as direct current (DC) high potential (hipot) testing, the Special Tester crew will also perform NP testing and respond to power quality issues.

Process

PGE has experienced good reliability with its network cable fleet, having very few cable issues. It presently performs any routine diagnostic cable testing on network cables, although it has performed some diagnostic testing on primary network cables crossing the river in the past.

PGE does routinely not test new cables upon receipt from the manufacture. Before commissioning new cable or returning a de-energized primary circuit to service, crews perform a DC hipot verification test. In general, PGE policies advise against leaving cables de-energized for long periods of time. If the cable has been de-energized for several weeks, the cable failed and was repaired, or modifications were made to the cable, such as replacing a section. Then, crews perform a circuit verification test, which includes a DC hipot test. When replacing a T-body or major component, PGE also performs a DC hipot test.

PGE performs very low frequency (VLF) testing on the getaway cables at substations but does not record any tan delta measurements.

PGE does perform routine visual inspection of cables during vault and manhole inspections, looking for evidence of deterioration and adding fire resistance (wrap) when necessary. PGE does tong secondary cables to identify blown limiters as part of their maintenance.

Special Testers also perform infrared testing of some cable joints/bends on the system as part of their vault inspection program. According to standards, differences in temperature between 5 and 18oF (-15 and -8oC) are graded as medium with no corrective action needed, but the issue is recorded and re-inspected during the next inspection cycle. In practice, if inspectors find a difference in temperature between joints in a cable of over 10oF (-12oC), then they deal with it by repairing or replacing the joint within two weeks. Where the difference is between 20 and 28oF (-7 and -2oC), inspectors deal with the problem immediately.

Figure 1: Infrared(IR) thermography

Figure 2: Infrared thermography

To locate faults, crews use a DC hipot thumper and all special testing crews carry the equipment in their truck. When they receive clearance on a feeder, they switch the transformers and network protectors to the open position. At the substation, they ground the cable for safety, unground it, and connect the DC hipot equipment to each phase at the cable termination one at a time. Once they have isolated the problematic phase, crews use a hand-held impulse detector in conjunction with the thumper to detect the pulse. Testers go from manhole to manhole until they locate the fault.

5.1.15 - SCL - Seattle City Light

Maintenance

Cable Testing - Diagnostics

People

Organization

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations — Network) group, and a network Civil Services group. The Electrical Services group is made of 84 total people including the supervision and a five person cable-locate crew. This group performs all construction, maintenance, and operation of the network System, including cable diagnostic testing.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable splicers perform all electrical

aspects of network construction, operations, and maintenance, including perfroming cable diagnostic testing.

All electrical employees who work in the network are either crew chiefs, journeyman cable splicers, or apprentices in the mode of progression, working their way toward the journeyman level.

Cathodic protection inspections and testing for transmission cables are performed by network crews. Testing results are forwarded to Generation Engineering.

Technology

SCL uses DC Hi-pot proof testing (putting a high-voltage DC signal on the cable) when testing cable prior to energizing that cable. 15-kV cable is limited to 26 kV DC, and 26-kV cable is limited to 47 kV DC. SCL performs this test before energizing a new cable or prior to re-energizing an existing cable. Proof testing is conducted as part of feeder maintenance.

SCL crews do not have confidence in VLF (very low frequency) testing. The crews noted that there are many “Y” splices in their system that could confound VLF testing.

5.1.16 - Practices Comparison

Practices Comparison

Maintenance

Cable Diagnostic Testing

2015 Survey Results

Older Survey Results

5.1.17 - References

EPRI Unde rground Distribution Systems Reference Book (Bronze Book)

Chapter 10: Cable Diagnostic Testing

5.1.18 - Survey Results

Survey Results

Maintenance

Cable Testing and Diagnostics

Survey Questions taken from 2019 survey results - Practices Inspection survey

Question 16 : In what applications will you perform network primary cable diagnostic testing?

Question 18 : If you are performing periodic primary cable withstand testing, what is the frequency of the testing?

None of the companies that reported withstanding testing provided a response.

Question 20 : Please indicate / describe what testing techniques you use. Check all that apply

Survey Questions taken from 2018 survey results - Asset Management survey

Question 10 : If you perform periodic network primary cable diagnostic testing, please indicate / describe what testing techniques you use.

Question 11 : Are you using information from cable diagnostic testing to influence investment decisions, such as when to replace cable?

Question 12 : Do you perform cable limiter continuity checks (amp checks) as part of your preventive maintenance program?

Survey Questions taken from 2015 survey results - Design

Question 81 : In what applications will you perform the network primary cable diagnostic testing? (Check all that apply)

Question 82 : If you are performing periodic primary network cable withstand testing, what is the frequency of the testing?

Question 84 : Please indicate / describe what testing techniques you use.

Question 85 : Please indicate if your company performs the following activities on routine basis and at what frequency.

Survey Questions taken from 2012 survey results - Maintenance

Question 6.5 : In what applications will you perform cable diagnostic testing?

Question 6.6 : If you are performing periodic primary network cable withstand testing, what is the frequency of the testing?

Question 6.7 : If yes, please indicate / describe what testing techniques you use.

Question 6.13 : Do you regularly perform Primary cable and splice / connection infrared inspections?

Question 6.14 : If yes, what is the frequency of Infrared testing?

Question 6.15 : Do you regularly perform secondary cable and splice / connection infrared inspections?

Question 6.16 : If yes, what is the frequency of secondary infrared testing?

Question 6.17 : Do you regularly perform Secondary / Grid cable testing?

Question 6.18 : If yes, what is the frequency of secondary cable / grid testing?

Survey Questions taken from 2009 survey results - Maintenance

Question 6.7 : Do you regularly perform primary cable diagnostic testing?

Question 6.9 : In what applications will you perform cable diagnostic testing? (this question is 6.5 in the 2012 survey)

Question 6.10 : If yes, please indicate / describe what testing techniques you use. (this question is 6.7 in the 2012 survey)

Question 6.17 : Do you regularly perform Primary cable and splice / connection infrared inspections? (this question is 6.13 in the 2012 survey)

Question 6.18 : If yes, what is the frequency of Infrared testing? (this question is 6.14 in the 2012 survey)

Question 6.19 : Do you regularly perform secondary cable and splice / connection infrared inspections? (this question is 6.15 in the 2012 survey)

Question 6.20 : If yes, what is the frequency of secondary infrared testing? (this question is 6.16 in the 2012 survey)

Question 6.21 : Do you regularly perform Secondary / Grid cable testing? (this question is 6.17 in the 2012 survey)

Question 6.22 : If yes, what is the frequency of secondary cable / grid testing? (this question is 6.18 in the 2012 survey)

5.2 - Civil Maintenance

5.2.1 - AEP - Ohio

Maintenance

Civil Maintenance

People

Civil maintenance is coordinated by a Network Engineer within the Network Engineering group, and is typically performed by a contractor. AEP Ohio has a strong working relationship with its civil contractor, as the contractor employs a civil engineer with many years of experience working with AEP Ohio and thus has familiarity with its system.

All civil maintenance is driven by findings from inspections (see Vault and Manhole Inspection), which include an assessment of the condition of the civil infrastructure. Findings that require civil construction repairs are forwarded to the Network Engineering group, who will coordinate with the contractor to schedule repairs.

Process

When any crew member finds a civil maintenance problem, it is recorded and sometimes photographed. This information is sent to Network Engineering, which prioritizes civil maintenance projects and prepares work orders to engage the civil engineering contractor.

For new manholes and vaults, AEP Ohio is using precast structures – civil designs, plan, and profile drawings for these structures are also prepared by the contractor. For repairs, designs can involve poured in-place structures, and combination structures, where the bottom part of the structure is poured, and the middle and top of the structure are pre-cast.

Technology

Civil condition findings from inspection are also recorded in the AEP online NEED (Network Enclosure and Equipment Database) for tracking network assets and their conditions. Note that the NEED database was originally developed to track serialized assets, but has been expanded to support AEP in tracking non-serialized condition findings, civil condition, and operational conditions. The system is used to schedule orders to address corrective maintenance issues according to priority.

5.2.2 - Ameren Missouri

Maintenance

Civil Maintenance

People

Vault and Manhole inspections include an inspection of the civil condition of enclosure. Manhole inspections are performed by contractors. Network vault inspections are performed by Distribution Service Testers within the Service Test group.

Organizationally, the Service Test group is part of Distribution Operations, led by a manager. Within Distribution Operations, there is a Reliability Support Services group led by superintendent. Reporting to the Superintendent Reliability Support Services are both the Service Test group led by a supervisor and the Distribution Operating group, also led by a supervisor.

The Service Test group is made up of Service Testers and Distribution Service Testers. It is the Distribution Service Testers who perform vault inspections, as well as network protector maintenance and calibration, and transformer maintenance including oil testing.

Ameren Missouri has a Civil and Structural Design group, part of Energy Delivery Technical Services. The group is responsible for developing civil designs and standards for civil construction and repair, including deciding the best approach for making repairs to civil infrastructure, such as manholes and vaults.

Ameren Missouri has developed a Structural Inspection Training Manual for Vaults, a guideline that guides Distribution Service Testers in performing visual inspections of vault structures. See . .

Ameren Missouri uses contractors for making civil repairs to existing infrastructure. Repairs can range from epoxy injection to fill cracks, to replacing deteriorated vault roofs.

Process

Vault / Manhole inspections include an inspection of the civil condition of enclosure.

The visual inspection includes:

Visually inspect and photograph the vault and note the following structural and electrical information:
- Grating sits flush and is not worn or deformed
- Safety cage opens properly and sits well when opened
- Inspect the ceiling for any cracking, bulging and water leaks. Capture the total amount of cracks and describe the widest and longest crack
Inspect the walls for any cracking, bulging, water leaks or if any of the wall is missing. Capture the total amount of cracks and describe the widest and longest crack
The type of floor material, its finish, how it drains and any cracking.
Visually inspect the bus bars for rust or cracks and check to see that the supports are secured to the ceiling.
Note if the wall is painted and the condition of the epoxy paint.
Visually inspect that the cable supports are secured to the wall.
Inspect the network monitoring equipment for proper operation.
Note any excessive debris on the floor that could be due to collapsing walls or ceiling or if it is debris from public.
Record the type of lighting in the vault and replace any burnt out bulbs.

During the inspection of manholes and vaults, the inspectors (either contractors for manholes or Dist Service Testers for vaults) take photographs of the interior and record this information on computers.

Ameren Missouri has a well defined manhole inspection / repair process for performing manhole inspections that includes guidance for inspectors for action based on inspection findings. Structural findings are forwarded to the Civil and Structural Design group within Energy Delivery Technical Services for analysis, scheduling and repair.

Technology

Findings are recorded by the contractor on tough books into a Circuit and Device Inspection System (CDIS). The contractor provides a report that summarizes the findings. The CDIS utilizes an algorithm that assigns a “structural score” and an “electrical score” based on the inspection findings and weightings for various findings developed by Ameren Missouri. The scores are used to prioritize remediation. CDIS is also used to produce reports that summarize inspection findings and a dashboard that monitors inspection progress.

Sample photographs of manhole / vault deterioration:

Figure 1: Cracked Roof

Figure 2: Ceiling falling into conductors

5.2.3 - CEI - The Illuminating Company

Maintenance

Civil Maintenance

People

Civil maintenance at CEI is performed by contractors. CEI typically retains the services of five different contractors to perform civil work (construction and maintenance).

Process

The Underground Network Services group has one supervisor who runs the contractor crews who perform civil maintenance.

5.2.4 - CenterPoint Energy

Maintenance

Civil Maintenance

People

Civil maintenance at CenterPoint is performed by contractors.

Major Underground has one supervisor who runs the contractor crews. This individual works closely with the Lead Engineering Specialist of the Feeders group within the Major Underground Engineering organization.

Process

Civil maintenance at CenterPoint is performed by contractors. For example, CenterPoint has hired a contractor to rebuild deteriorated vault roofs they have identified during inspection.

Note that certain civil work near energized facilities, such as chipping concrete around energized conductors, is performed by CenterPoint crews – not the contractor.

CenterPoint has entered into a longer term relationship with their civil contractor – a 2 year term, with an option to continue for a third year. They have created an alliance relationship, which invests both parties in the other’s success. The parties will meet periodically to review performance, profits, and to establish future benchmarks.

Note that this contractor also performs non civil work on CenterPoint’s behalf. The terms of the alliance apply to all of the contractor’s work.

5.2.5 - Con Edison - Consolidated Edison

Maintenance

Civil Maintenance

People

Construction Group

Con Edison’s service territory consists of four regions: Manhattan, Brooklyn/Queens, Staten Island, and Bronx/Westchester. The Manhattan Region is made up of three districts, including one headquartered at the W 28th St. Work Out Center. The term Work Out Center refers to a main office facility to which field construction and maintenance resources report. To provide a perspective on the size of a workout center, about 300 people work at the W 28th Street Work Out Center, and they can field about 125 crews.

The construction department consists of several group, including the Subsurface construction (SSC) group. The SSC deals with vaults, conduit ducts, and other civil work. Much of this work is contracted.

5.2.6 - Duke Energy Florida

Maintenance

Civil Maintenance

People

Vault and manhole inspections are performed by craft workers, Network Specialists and Electrician Apprentices, within the Network Group, part of the Construction and Maintenance Organization. The Network Group is led by a supervisor, and consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position).

Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager.

The Network Group is organized functionally, and has responsibility for construction, maintaining and operating all urban underground infrastructure (ducted manhole systems), both network and non-network, in both Clearwater and St. Petersburg see Figures 1 and 2).

Figure 1: Old vault roof and grating

Figure 2: New vault roof and grating

Most civil work is performed by contractors. Duke Energy Florida will utilize ad hoc contractors for smaller work, and may enter into larger turnkey contracts for major civil work.

Network work crews at Duke Energy Florida perform duct line inspections when necessary in Clearwater and St. Petersburg.

Process

Vault and manhole inspections include an assessment and recording of civil conditions including the conditions of grates, covers and doors, ladders, ring bus, cable racks and supports, duct shoes, and transformer support beams. Duke Energy Florida does not routinely inspect and maintain duct lines. Duct lines are inspected only when necessary or observed conditions warrant.

Information from the inspection is recorded on an inspection form, including an assessment of the priority or severity of the finding. See Attachment I . Information from the inspection is entered into a computer system, and the hard copy form is maintained in a file. Duke Energy Florida has a “Further Work Ticket Process” which is initiated to pursue remediation for corrective maintenance items identified by inspection. The repair schedule is dictated by the priority of the finding. All but minor civil repairs are outsourced to a contractor.

Technology

Duke Energy Florida has much Orangeburg duct in the ground. They also have creosote paper duct in concrete duct bank. Duke Energy Florida crews will mandrill a duct if necessary.

Crews do have access to a duct camera, if needed. However, this type of inspection is rarely performed.

5.2.7 - Duke Energy Ohio

Maintenance

Civil Maintenance

People

Civil maintenance at Duke Energy Ohio is performed by both contractors and Duke field crews. Duke crews will perform most civil maintenance near energized facilities. Most civil maintenance, however, is performed by contractors.

The Dana Avenue Underground group has one supervisor, a T&D Construction Coordinator, who runs the civil contractor crews.

Process

Duke performs vault inspections occur 4 times a year, and manhole inspections every six years. These field inspections include identifying any structural or other potential civil deficiencies.

Duke will revisit the suspect manholes with either an in house civil expert or an external civil contractor to assess the civil condition and structural integrity of the manhole to identify high priority candidates for rebuild. (See Manhole and Vault Rehabilitation.

Other inspection findings are scheduled for repair using civil maintenance contractors.

5.2.8 - Energex

Maintenance

Civil Maintenance

People

Energex primarily sub-contracts civil maintenance to third-party contractors it has worked with for years and are certified, supervised, and work inspected by Energex.

Process

Civil maintenance that is subcontracted includes vegetation management, vault cleaning and repairs (where necessary), pole clearing, pit construction, and some substation and customer premises-based construction.

5.2.9 - ESB Networks

Maintenance

Civil Maintenance

Unspecified, See Civil Construction

5.2.10 - Georgia Power

Maintenance

Civil Maintenance

People

Civil maintenance is led by a by the Network Underground Engineering staff and its Standards Group. This group develops design standards for manholes, vaults, substations, duct lines, etc. The group is also involved in deciding the best approach for making repairs to civil infrastructure, such as manholes and vaults.

Routine inspections and maintenance of civil structures are handled by the Network Operations and Reliability group. Major initiatives such as replacements of brick roofs on manholes are handled by special assignment of engineers, construction crews, and contractor crews. The group often out-sources large civil maintenance projects to its preferred contractors, but all work must adhere to company standards, and is supervised by Georgia Power engineers.

Two examples of civil maintenance work performed at Georgia Power are the replacement of deteriorating brick vaults and the upgrading of manholes from standard, solid manhole covers to SWIVELOC manhole designs in select, high-traffic areas of downtown Atlanta (See Figure 1). The group is also contemplating moving to traffic-bearing vault grates in downtown areas (See Figure 2).

Figure 1: Old Brick and Beam ceiling

Figure 2: SWIVELOC manhole installation

All maintenance is driven by inspections (see Vault and Manhole Inspection in this report), which include an assessment of the condition of civil infrastructure. Findings that require civil remedies are forward to the supervising civil engineer.

Process

When an inspector finds a civil maintenance problem, he logs it into the Network Underground Access system used to record inspection findings, and a work order is generated to affect a repair. Information from the Access database is also passed to GIS, which can be accessed by civil repair crews. The information contained in GIS includes work order information. The civil maintenance crew must then schedule a date and time for repair, including notification to the city at least four hours prior to the civil work if there will be lane or sidewalk blockages involved. Using DistView in combination with GIS, the crew can find the repair location quickly.

Technology

Through the GIS system, the Maintenance Supervisor can call up work orders on computer in his truck, but all work orders are also issued on paper so that crews can take the paper orders into the manhole or vault.

5.2.11 - HECO - The Hawaiian Electric Company

Maintenance

Civil Maintenance

People

Civil maintenance at HECO is performed by contractors.

Process

The C&M Underground group has one supervisor who runs the contractor crews who perform civil maintenance.

5.2.12 - National Grid

Maintenance

Civil Maintenance

People

The National Grid network field resources (network crews) are part of the group responsible for the underground system in eastern New York, called Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground Lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Civil Group is comprised of Mechanics, Laborers, and Equipment Operators, and is led by a supervisor. This group includes a machine shop located in Albany. This group will perform minor civil projects, including maintenance and repairs. Much of the larger civil construction and maintenance work at National Grid is performed by external contractors.

Civil designs, if required, are performed by the Distribution Design group, part of the Engineering organization.

Process

National Grid performs vault inspections annually. These field inspections include identifying any structural or other potential civil deficiencies that may require maintenance (See Vault Inspection for more information on civil items included in inspections.)

Technology

All duct lines in the network at National Grid are concrete encased, including primary, secondary and fiber ducts

National Grid’s construction standards call for pre-cast manholes and vaults. Standard vault size is dictated by size of the network unit. , National Grid has detailed standards that describe their underground electric vault requirements.

5.2.13 - PG&E

Maintenance

Civil Maintenance

People

Civil maintenance at PG&E is performed by civil resources who are part of the Gas Department.

PG&E has a Civil Engineering group, part of the Substation Engineering Department, responsible for vault design.

Process

PG&E performs vault inspections annually as part of their network transformer maintenance, and manhole inspections every three years. These field inspections include identifying any structural or other potential civil deficiencies.

5.2.14 - Portland General Electric

Maintenance

Civil Maintenance

People

On the network, civil maintenance is generally outsourced to external contractors. During normal vault inspections, crews from the CORE group look for any structural problems in vaults and manholes.

The CORE group, led by an Underground Core Field Operations Supervisor, focuses specifically on the underground CORE, including both radial and network underground infrastructure in downtown Portland.

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault while the helper, typically a non-journeyman classification, usually stays above ground, carrying material and watching the barricades and street for potential hazards.

Historically, work crews have been assigned a variety of work types depending on needs, ranging from new construction to maintenance and operation of the system. Due to the large number of new construction projects underway in Portland, and to assure that the demand for resources to support that construction does not erode the focus on maintenance, the CORE group is considering creating a dedicated maintenance crew that will maintain a focus on network infrastructure inspection and maintenance.

To liaise with customers concerning civil maintenance issues, key customer managers (KCMs) organize vault inspections and maintenance.

Process

Inspections of the civil infrastructure are performed in conjunction with manhole and vault inspections.

PGE’s network has 1300 manholes/vaults. Of these, 529 are vault structures, with 280 vaults containing equipment.

For vaults that contain equipment, such as network transformers or network protectors, the frequency of inspection dovetails the performance of equipment maintenance, as a vault inspection accompanies the maintenance of equipment. For example, 480 V network protectors are maintained annually, so inspection of the vaults that house 480 V protectors are also performed annually.

For general-purpose structures, including vaults, manholes, and handholes that do not contain equipment, PGE attempts to inspect all underground enclosures annually, though manpower availability determines the exact cycle. At the start of every year, general work orders for inspection of manholes are created in Maximo for a particular geographical area, with each work order covering the manholes in a one- or two-block area. A crew receives these work orders and is expected to perform inspections of the general-purpose enclosures when it does not have any customer work. If there is little customer work on the network, inspections can be completed for all non-equipment manholes and vaults within a calendar year.

PGE employees, not contractors, perform all inspections of general-purpose structures, including both an electrical and civil (structural) review. Inspections include a visual inspection to identify leaks, assess vault cleanliness, etc., and may include the use of infrared (IR) thermography at the discretion of the inspection crew. Crews may take photographs during vault inspections, but this process has not been formalized. Any damaged ducts are inspected with a duct camera in an as-needed basis rather than as part of the regular inspection.

If vaults/manholes need civil or structural repairs, PGE uses an external Level III contractor. The company has a two-year contract with the outside contractors to undertake this type of work. For large, complex repairs, a structural engineer will be used.

Customer Vaults: The spot network vaults are customer-owned, and the key customer group coordinates with the customer on the repair of infrastructure issues identified during inspections. It relays the findings to the customer and ensures that action is taken to correct the issue.

Technology

Maximo: PGE uses the Maximo for Utilities 7.5 system to manage inspection reports and store details about any maintenance needed.

Figure 1: Use of radio-based distribution voltmeters

5.2.15 - SCL - Seattle City Light

Maintenance

Civil Maintenance

People

Organization

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations — Network) group, and a network Civil Services group. The Electrical Services group is made of 84 total people including the supervision and a five person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Process

Civil crew representatives participate in SCL’s bi-weekly crew coordination meetings. (See Construction - Project Management - Bi-weekly Crew Coordination Meeting)

SCL hired a consulting firm to audit their manholes to identify needed civil repairs. They currently have a $2.5 million budget to perform manhole civil repair. This work has been prioritized and is being spread over 40 years.

5.3 - Elevated Voltage Testing (Stray Voltage)

5.3.1 - Con Edison - Consolidated Edison

Maintenance

Elevated Voltage Testing(Stray Voltage)

Process

Con Edison performs annual elevated voltage (stray voltage) testing. This is performed in accordance with New York statewide standards to ensure the public safety of electric systems. The safety standards include requirements to annually test all publicly accessible transmission and distribution facilities for stray voltage and inspect all electric facilities at least once every five years. To ensure compliance with the safety standards, the Commission established strict record keeping, certification and reporting requirements, and rate adjustments for failure to achieve specific performance targets for the testing and inspection programs.

5.3.2 - National Grid

Maintenance

Elevated Voltage Testing(Stray Voltage)

People

National Grid has engaged 25 contractors to perform elevated voltage (stray voltage) testing on their distribution system in New York State. This testing is being performed on their entire distribution system on all facilities from ground level to eight feet above ground level, including the testing of manhole covers.

The program conforms to a New York State mandate to test for stray voltage in cities with populations over 500,000. National Grid is performing elevated voltage testing in Albany.

Process

National Grid performs annual elevated voltage (stray voltage) testing in New York State. This testing includes manhole covers.

Technology

Contractors utilize a handheld directional E- field tester to identify stray voltages.

National Grid does not bond vault grates and manhole covers to the grounding system. Ladders are bonded to the grounding system.

5.3.3 - Energex

Maintenance

Elevated Voltage Testing(Stray Voltage)

* Energex is not performing any stray voltage testing on the pit cover.

See Manhole (Pit) Entry

5.4 - Failure Analysis

5.4.1 - AEP - Ohio

Maintenance

Failure Analysis

People

Component and cable failures are first analyzed by Network Mechanics and Network Crew Supervisors and then turned over to the AEP Ohio Network Engineers. If engineers determine that the failure is due to sub-standard equipment or if the company’s standards were not met, then they will work with suppliers and crew supervisors to remedy the situation.

Important findings from these equipment failures are shared with the company-wide Network Standards Committee, which is comprised of representatives of all the AEP operating companies with network grids (see Network Standards).

Process

Engineers will review failed components and may perform a forensic analysis. Network Engineers may turn the failed equipment over to the manufacturer, commission an analysis at AEP’s Dolan laboratory, or send it to an outside, third-party analysis group, such as NEETRAC.

5.4.2 - Ameren Missouri

Maintenance

Failure Analysis

People

Ameren Missouri Standards Group engineers perform failure analysis on underground components such as cable and splices. They usually do the analysis in house, but may enlist the services of the manufacturer or external labs in some cases.

The Standards Group has implemented a formalized Unsatisfactory Performance Report (UPR) Process used by the field force to report problems with distribution materials. The process includes:

Claimant completes UPR form and submits to Supervisor of Standards - with sample of defective equipment if possible;
Supervisor enters in UPR database and assigns to Standards engineer;
Engineer reviews report and sample and determines response based on knowledge of item or report from manufacturer after submittal to manufacturer for analysis;
Engineer response to claimant and forwards to secretary;
Secretary distributes to distribution list and posts on Standards website

See Attachment B for a sample of the UPR form.

Process

Standards engineers will review failed components and perform a forensic analysis. When they do the dissection of a component, they attempt to involve the crew who installed that component if possible. This is so that the crew who installed the component can see the problem first hand as the engineers sees it.

If the analysis reveals a repetitive workmanship issue, the standards engineers will develop and deliver a training session to resolve the workmanship issue.

Technology

Analysis of failed underground equipment is performed by the Standards Group, Underground Engineering and the Underground Construction departments.

5.4.3 - CEI - The Illuminating Company

Maintenance

Failure Analysis

People

Failure analysis on failed cables, splices, connectors, and equipment is performed at the FirstEnergy Beta Laboratory (See “ BETA Lab” - Testing Laboratory). Field crews make the determination as to what equipment is sent to the lab, and what equipment is not based on their experience. For example, if the cause of a splice failure is obvious to the crew, such as a water damage due to an improperly prepared splice, and they believe there to be little if any incremental learning to be gained by sending the failed splice to the Lab for a forensic analysis, then the crew will not send it forward.

Process

When a PILC cable fault occurs in a manhole that is filled with water, field crews may perform a test of the paper to ascertain whether or not the paper is dry. The field crew will boil mineral oil and drop a few strands of paper into if it see if it bubbles, indicating the presence of water in the paper. Note – if the manhole is dry, the field crew may not perform this test. This same test may also be performed at FirstEnergy’s Beta Lab as part of a post failure forensic analysis.

Failures that are determined to be sent to the Beta Lab are bagged, tagged and send to the Lab.

After analysis, the Beta Lab will send a failure analysis report back to the UG department. See Attachment - Y.

5.4.4 - CenterPoint Energy

Maintenance

Failure Analysis

(Splice)

People

CenterPoint Training and Major Underground management resources perform analysis of failed splices.

Process

CenterPoint performs an analysis on each splice failure to understand what caused the failure. This analysis is performed in house, by CenterPoint Training and Major Underground management resources.

Normally, if CenterPoint experiences a splice failure within the first 2 years of its life, the failure is due to a workmanship issue.

Technology

CenterPoint uses hand taped splices. CenterPoint has experienced very few splice failures. (See Splicing )

5.4.5 - Con Edison - Consolidated Edison

Maintenance

Failure Analysis

People

Distribution Engineering Equipment Analysis Center (DEEAC)

Con Edison has recently launched a new team dedicated to the analysis of electric distribution equipment. The mission of the Distribution Engineering Equipment Analysis Center (DEEAC) is to optimize the performance of distribution equipment through a system safety approach that utilizes data trending and incident analysis. To support this mission, the team is focused on enhancing the safe operation of distribution equipment while also improving overall system reliability by proactively mitigating operational risk. These goals will be achieved through targeted forensic analysis, data characterization of all field-returned equipment, and quality assurance of distribution equipment. Con Edison is dedicated to supporting the mission of DEEAC with a shared focus on continuously improving system safety.

Process

Cable Failure Analysis

Con Edison’s goal is to perform a failure analysis on every cable and splice failure that occurs. The utility is able to perform an actual analysis on 80 – 90% of the problems that occur; the remainder represent problems that are destroyed or inaccessible.

In addition to testing cable that failed, the utility tries to expand testing to look at the condition of adjacent cable sections that did not fail. In the case of a splice failure, crews replace all three splices and perform diagnoses on the unfailed splices to aid in drawing conclusions about the cause of the failure.

A big challenge for Con Edison is failures that occur in transition joints (between PILC and non-PILC conductors). These transition joints are commonly referred to as “stop joints.” The failures they encounter typically occur on the paper side of the joint. The utility has implemented a replacement program to install cold shrink joints to replace them. They have had good success with the cold shrink joints.

Transformer Failure Analysis

Con Edison performs a root cause analysis of all network transformer removals including units that failed in service, units that were removed because of failed dissolved-gas-in-oil-analysis (DGOA), units that were removed because of failed oil temperature, pressure, or level indications from the RMS system, and units that failed during testing.

Removed units are sent to Con Edison’s Distribution Engineering Equipment Analysis Center (DEEAC), where they are taken apart for a thorough root cause analysis. Analysis includes detailed physical inspections and review of oil test results. Common findings include excess corrosion due to tank holes or porosity, primary bushing failures due to installation defects or mechanical strain, secondary bushing leaks due to manufacturer defects or loose flex straps, evidence of partial discharge from DGOA results or from physical evidence such as carbon deposits, and evidence of arcing, again from test results or physical evidence.

Con Edison keeps detailed statistics on transformer failure performance, including the number of removed units by failure category (failed in service, failed during testing, etc.), and statistics about the causes of those failures (corrosion, insulation failure, manufacturer defect, etc.). Con Edison’s largest single cause of transformer failure is corrosion.

By understanding the root cause of transformer failures, Con Edison has increased the number of units removed based on inspection findings, monitored information, and testing results. This has resulted in a significant decrease in the number of transformers that fail in service. For example, transformer-in-service failures went from being the cause of 9% of network feeder lockouts (Open Autos or OA’s in Con Edison’s lexicon) in 2005, to being the cause of only 4% of network feeder lockouts in 2007.

5.4.6 - Duke Energy Florida

Maintenance

Failure Analysis

People

Failed equipment identified by field crews is sent to the Standards group for analysis via an informal process. Within Standards, there is a component engineer who may perform forensic analysis on failed equipment to understand failure causes. Performance of the forensic analysis within Duke Energy Florida is dependent on the complexity of the failure and the backlog of work for the component engineer. If Duke Energy is not able to perform the failure analysis, Standards will engage external laboratories to assist with failed component analyses.

Process

While the process or reporting and performing analysis of failed components is informal, Duke Energy Florida does have formal process to communicate findings within the company. For material deficiencies, Duke Energy Florida will issue a Material Advisory to first line supervision to share with direct report field crews. The Material Advisory is a bulletin that describes the material deficiency and any appropriate action(s) for the component.

For events that are related to work methods, Duke Energy has a “Good Catch” reporting process, where work method issues are reported through an electronic mechanism, Plantview. After the “Good Catch” is captured in Plantview and an investigation is performed, findings are shared in the weekly safety communication, “Connection.” The Network Group provided the most “Good Catches” at Duke Energy Florida in 2015, which were identified as work methods issues that were corrected before any network problems resulted.

Technology

Duke Energy Florida has an extensive electronic system for reporting events, Near Misses, Good Catches and recording Events and event details through its PlantView system. PlantView is described in the Safety section of this report.

5.4.7 - Duke Energy Ohio

Maintenance

Failure Analysis

Process

When Duke Energy Ohio experiences a splice failure, or cable section failure, they will save the failed section or component, bag it, tag it, and involve the Standards department (Charlotte) in developing next steps.

In some cases they will send it to an external laboratory for forensic analysis. However, Duke Energy does not perform forensic analysis on all failed components.

Technology

Duke Energy Ohio has a laboratory testing facility at Queensgate, in Cincinnati. However, this laboratory does not perform forensic analysis on failed cables or failed cable splices.

Duke Energy Ohio utilizes external laboratories to perform forensic analysis on failed cable and cable splices.

5.4.8 - Energex

Maintenance

Failure Analysis

People

Energex has a Network Performance and Maintenance group, responsible for implementing the maintenance and policy standards, and for monitoring the performance of the system. Any failed equipment identified which has been in service greater than two years is sent to this group for evaluation.

The group is comprised of engineers who perform forensic analysis in failed equipment to determine root causes, such as cutting open and analyzing a failed joint. Note that failed equipment which has been in service less than two years is sent directly to the Standards group, as early failures could be indicative of a product issue, rather than a workmanship / aging / or other issue.

Some issues are referred to the Procurement group, especially if workers in the field feel there may be a quality problem with a part or piece of equipment. Procurement then liaises with the vendor to determine if there is a part/equipment quality control problem.

Process

The Network Performance and Maintenance group liaises with the Standards group as necessary. Any workmanship issues are normally shared with the OAC for investigation.

5.4.9 - ESB Networks

Maintenance

Failure Analysis

(Cable Forensics/Analysis)

People

ESB Networks has a forensic lab for analyzing failed cables and joints located within the ESB Networks training center in Portloaise. The failure analysis is performed by both the training coordinator within the training facility responsible for UG cables and the Asset Manager for cables and his team.

Process

ESB Networks performs analyses on all failed joints, other than situations already identified, such as cable dig-ins. About 70 percent of all failed joints for any cause end up being analyzed. It is notable that ESB Networks analyzes all failed transition joints. Results of the analysis are summarized in a report, and significant findings are communicated to the field force through bulletins know as Technical Notifications, or TNs.

A noteworthy practice at ESB Networks is interaction among the training coordinator for cables, the asset manager for cables, and the field force (Jointers). This interaction has resulted in close working relationships and good two way communication between the Jointers, engineering and training. As a result of this close relationship, the Jointers do not hesitate to bring information about problems with joints back to “the office.” Trainers noted that they try to help the Jointer understand the science of joint preparation so that the jointers have a better appreciation for the importance of the steps associated with the preparation (see Figures 1 and 2).

Figure 1: Cable Forensic Analysis

Figure 2: Joint preparation using ESB Networks specific cut back template

The Training and Asset Management groups have a close working relationship and share the process of performing forensic analysis and preparing summaries. As an example of the effectiveness of these working relationships, the Training and Asset Management groups worked with a manufacturer to include ESB Networks-specific instructions in its cable splice kits. Much of the feedback to customize these instructions came directly from feedback from a field Jointer.

5.4.10 - Georgia Power

Maintenance

Failure Analysis

People

Component and cable failures are first analyzed by job supervisors and then turned over to principal engineers in the Network Underground group. If engineers, based on the evaluation of the job site supervisor and their own evaluation, determine that the failure is due to sub-standard equipment or if the company’s standards were not met, then they will work with suppliers and with GPC supervisors and trainers as needed.

Process

Engineers will review failed components and perform a forensic analysis. When they dissect a component, they attempt to involve the crew who installed that component to gain additional information and for the education of the crew. If the analysis reveals a repetitive workmanship issue, the engineer may mandate a training session to resolve any workmanship issues.

Most forensic analysis is performed in-house. In the event a cause cannot be determined, the Network Underground engineers may turn the failed equipment over to the manufacturer or send it to an outside, third-party analysis group, such as NEETRAC (See Figure 1).

Figure 1: Failed joint

Technology

The Georgia Power Network Underground group has an extensive testing facility at its Atlanta headquarters where failed components, splices, cables and other equipment can be thoroughly examined.

Test Engineers and senior network underground engineers use the facility. The center utilizes the Network Standards that contains specifications on cables, splices, racking, and duct line, vaults, transformers, and virtually every component within the network underground system. The document is kept up-to-date by the Standards Group and is available online and in printed form.

5.4.11 - HECO - The Hawaiian Electric Company

Maintenance

Failure Analysis

(600 Amp “T” Body Failure Root Cause Analysis)

People

HECO has experienced failures with 600A “T” body assemblies in their underground system, particularly in water holes, and has embarked upon an extensive effort to identify the root causes and remediate identified issues.

The Technical Services Division within the Engineering Division performs root cause analysis on recurring equipment failures. This group has two engineers that focus on underground asset standards, practices and performance.

Process

HECO has performed forensic analysis on failed T bodies by sending failed samples to external labs, such as NEETRAC or the manufacturer, or CTL, for analysis. Also, through their collaboration with other utilities through EPRI, they have identified utility peer groups to compare and contrast practices associated with T body installations. For example, HECO has compared and contrasted splice practices with Con Edison.

An example contrasting practice is that ConEdison is using a pre - molded mechanical Y splice rather than a 600 A T body, used by HECO, to tap a network transformer from a main feeder run. On this Y splice, ConEdison uses a shear bolt connection, mastic sealant and a heat shrink sleeve on their flat strapped concentric neutral EPR cable. ConEdison has a low failure rate with these splices, even in water holes.

Post failure analysis has revealed that at least some of the failures HECO has experienced appear to be a result of installation workmanship issues. For example, in some cases, Cable Splicers may have over tightened the splice inserts (beyond the required torque) resulting in a cracking of the insert itself. Other failures may have been the result of moisture entry into the splice body due to inadequate sealing / taping of the splice.

See pictures below for example failed splice components.

Figure 1: Example of failed splice components

HECO has taken steps to assure that splice failures due to workmanship issues are reduced. They have re trained the Cable Splicers in proper splicing techniques, have issued splicing guidelines, and have assured that the field crews have adequate tools, such as spanner wrenches for properly torquing the splice inserts.

Technology

HECO has taken steps to assure that splice failures due to workmanship issues are reduced, including issuing proper tools for preparing splices, and training Cable Splicers on proper techniques. (See Separable Connector Installation for a brief description and photographs of a HECO 600 A T body installation.)

5.4.12 - National Grid

Maintenance

Failure Analysis

Process

National Grid does perform failure analysis of selected failed components. The person identifying the equipment defect initiates the failure analysis process by completing a Defective Equipment Report form and submitting it to the Standards Department. Information about failed equipment is also provided through the Work Methods representatives.

National Grid has an Electric Operations procedure, EOP UG009, which tracks splice and other equipment failures. In addition, a splice form is required to be filled out by the splicing crew for splices made in conventional duct and manhole systems (not URD). These forms are given to a clerk for database entry.

Engineers within the Standards Department decide which failures are to be analyzed and the method of analysis. This is an informal process administered by standards engineers.

Standards engineers maintain a file of selected received failure reports, and use them to make recommendations for working methods, material uses, project upgrades, standards, and other relevant areas. Engineers also conduct on-site examinations of failures, and collect materials to be sent to one of two National Grid testing laboratories, located in Syracuse NY, and Worcester, Mass. The laboratory analyzes failed equipment and materials, including items such as splices, fire damaged cables or equipment, and insulation (e.g. for water presence). External services are also used by National Grid as required for certain analyses. For example, National Grid may send a failed component to the manufacturer for analysis.

Process

Failures are inspected in the field by standards engineers or on site engineering crews. Field reports and material samples are provided to Standards for a complete analysis at either an internal or external laboratory.

Standards Engineering prepares a failure report describing all of the pertinent details of an incident, including the date, time, location, and equipment involved. The sequence of events is reconstructed, along with a damage report. The goal is to identify the root cause and make recommendations to mitigate the problem in the future. In particular, these reports identify issues with materials, workmanship and construction, standards compliance, and other relevant factors. These can include poor practices by field personnel or cases where company or regulatory standards were likely not followed.

Analysis reports include the following major sections: i) Event Description, ii) Description of Failed Equipment (and any reference material, if needed), iii) Failure Examination / Material Dissection, and iv) Analysis and Conclusions.

i) Event Description

A discussion of the specifics of the event, including the time since installation, is determined. The detailed breakdown of the sequence of events is presented, along with details of working personnel involved in both the event itself and any inspections conducted subsequently.

ii) Description of Failed Equipment

The equipment description includes the specific component(s) received for analysis (for example, a splice adapter with two segments of cut cable still attached), the equipment manufacturer and model number, the nature of the damage, age and catalogue numbers if appropriate, and references to instruction and operations manuals.

iii) Failure Analysis and Material Dissection

A Material Dissection or Failure Analysis goes into detail describing the conditions of the materials and projected reasons for the failure. For example, if instructions for a cable splice were not followed properly, or if other materials appear to have been used incorrectly, this will be discussed. Photographs are taken as needed to document and support the analysis. Indicators such as arc tracks, spots of electrical discharge, and etching can be identified along with a determination of how they were formed. Components in the vicinity of the assumed failure can be tested to see if and how they contributed to the failure. For example, a segment of cable connected to a failed dead break elbow can be tested for insulation failure or treeing.

iv) Analysis and Conclusions

The goal of the engineering analysis is to identify the reason for the failure, corrective measures that could or should be taken, and any other recommendations that would be useful. If the problem was caused by improper installation, the workmanship issues are identified and reported with a suggestion that they be corrected. If installation has been done properly but an equipment failure was the cause of the problem, a review of that equipment may be suggested. In some cases the engineering analysts recommend that the equipment no longer be used for a particular purpose.

See Attachment C for a sample Failure Analysis Report.

Mitigating or extenuating conditions are important and are discussed in these reports, along with suggestions to avoid future failures. For example, in a fire analysis report from 2009, it was found that the involved 4.16 kV cables were not fire wrapped in the vicinity of the failure. In this case, the failure occurred at the mouth of a duct, where the cables where not wrapped because of proximity to adjacent cable. National Grid initiated a dialogue with suppliers of fire-proofing materials to investigate the development of a new material such as a sealant that can be used as an alternative to fire wrap at duct mouth installations.

Technology

National Grid maintains equipment for performing failure analysis in its internal laboratories.

National Grid also utilizes the services of external laboratories as required.

5.4.13 - PG&E

Maintenance

Failure Analysis

Process

Historically, PG&E has used external laboratories to perform failure analysis. At the time of the EPRI practices immersion, PG&E was implementing a laboratory testing facility at their Livermore facility to perform forensic analysis on failed equipment such as cables and splices.

PG&E has a position called Senior Distribution Specialist, assigned to the underground, within the Electric Distribution Standards and Strategy group. This specialist is a subject matter expert, and acts as an interface between the Standards Department and field resources. (See Senior Distribution Specialist for more information). Specialists act as the “eyes and ears” of the Standards Department, and meet with standards engineers every two months to address issues.

The Electric Distribution Standards and Strategy group works closely with the Material Problem Report (MPR) process, a formal process used to report problems with components. This process is also supported by a separate group at PG&E that is responsible for the overall MPR process.

Process

When PG&E experiences a splice failure, or cable section failure, the field crew may save the failed section or component, bag it, tag it, and prepare a Material Problem Report (MPR), which will involve the cable experts within in Standards Department in developing next steps. The crew will make this decision depending on the situation. For example if a very old splice has failed, the crew may decide not to submit the splice for lab analysis.

The Material Problem Report process is a formal method for field employees to communicate material problems to management. When an employee encounters a problem with a piece of equipment, they will complete an electronic MPR form. (A lineman who may not have access to a computer during the day would complete the MPR form of computer returns to the opposite end of the day or ask a clerk to enter the information on his behalf).

For problems with underground equipment, the MPR forms will typically flow to the Senior Distribution Specialist, Underground. The MPR form will ultimately be routed to the individual in the company who is responsible for resolving the problem. The process itself is formal, and includes a requirement to respond to the individual who submitted the form in a prescribed number of days.

For example if the MPR were turned in for a failed splice, this would find its way to the cable standards engineer who deals with splices. This engineer may recommend forensic analysis, which could be performed at an external laboratory, or at PG&E’s Livermore facility, currently being developed.

PG&E noted that they don’t often see MPR forms on major network equipment. Typically when they do, these reports are related to equipment that applies to both network and not network underground such a transition joint.

Technology

PG&E is implementing a laboratory testing facility at their Livermore facility to be able to perform forensic analysis on failed equipment such as cables and splices. PG&E also uses and will continue to use external laboratories to perform failed component analyses.

5.4.14 - Portland General Electric

Maintenance

Failure Analysis

People

PGE has a documented process for reporting failed equipment called the Material Failure Reporting Procedure. The procedure defines roles for those involved in the process, including line crews, storeroom personnel, standards engineers, Distribution Engineers, and supply chain personnel.

Standards engineers coordinate failure analyses with a PGE Special Tester, a PGE lab technician, the manufacturer, a third-party tester, or a combination of these parties.

PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. The tester is an expert on network protectors within the organization and also works to resolve equipment problems. The Special Testers support the network department, and one individual is embedded with the network CORE group.

Although PGE has its own testing lab, it is no longer fully staffed and most failed components are tested externally by external laboratories and manufacturers. One major example is cable failures, which are sent to a third-party testing facility.

Process

PGE has a process for reporting equipment failures and prioritizing repairs. Its overarching philosophy for the network is to make immediate repairs. When urgent attention is needed for a manhole/vault, a repair and maintenance crew is dispatched as soon as possible.

For forensic analysis of failed components, PGE follows a material failure reporting process, fully documented in the Material Failure Reporting Procedure. The document includes the specific actions that an employee must take when encountering a faulty piece of material/equipment, and also lays out the forensic analysis process. The Standards Department periodically provides training to field line operations on the reporting process. See Construction – Equipment Failure Reporting for more information about this process.

Third-party laboratories or the manufacturer perform most of the analysis of failed components. Where possible, PGE seeks a refund or replacement for materials and components under warranty.

Once the failure analysis is completed, the resolution is shared with Distribution Engineers, line crews, and safety representatives. A TechNote article, Material News Alert, or other method communicates summaries of the findings, and the material failure is recorded in a Material Failure Database.

5.4.15 - SCL - Seattle City Light

Maintenance

Failure Analysis

Process

SCL is currently developing a process for following up on poly splice failures with a laboratory analysis.

Technology

SCL uses various types of splices including lead splices, heat-shrink splices, and cold-shrink splices. The majority of splices they use (80%) are heat-shrink, hand-taped splices. Less than 8% of their splices are lead. SCL prefers the heat-shrink splice to the cold-shrink splice, because they have had a low failure rate with heat-shrink splices.

Most of the splice failures they do experience are with poly splices. They have had very little failure of their lead splices.

5.4.16 - Survey Results

Survey Results

Maintenance

Failure Analysis (Cable, Transformers)

Survey Questions taken from 2018 survey results - Asset Management survey

Question 20 : Do you track cable and equipment failures?

Question 21 : If you track equipment failures, which of the following do you track?

Question 25 : Please describe your failure investigation process. Include a description, if applicable, of what drives corrective actions.

Survey Questions taken from 2012 survey results - Maintenance

Question 6.32 : Are you currently implementing replacement programs for any of your network equipment?

Question 6.33 : If Yes, Please indicate which equipment is being replaced.

Survey Questions taken from 2009 survey results - Maintenance

Question 6.38 : Are you currently implementing replacement programs for any of your network equipment?

Question 6.39 : If Yes, Please indicate which equipment is being replaced.

5.5 - Hot Phasing

5.5.1 - CEI - The Illuminating Company

Maintenance

Hot Phasing

People

“Hot phasing” is the process of bringing two hot cables together and use a phasing set to determine the proper phasing (match the phasing).

Hot phasing is performed by the UG Electricians of the Underground Network Services Department.

Process

Hot phasing is used often used where CEI is going to install a splice and is unable to change the phasing (roll phases) at the source. This is often the case when the cable originates from a 5kV oil switch where the phase rotation is set and cannot be changed. Also, the CEI has no standard phasing convention for their 5kV system. This requires the UG electrician to determine the proper phase order to prepare the splice.

After the faulty cable section has been removed, the three conductors that will make up each end of the splice are spread apart, and the cable stripped to the insulation (jacket, neutral, and semicon removed. CEI will then energize the conductors on one side of the splice in order to utilize the Hot Phasing Identifier tool.

The device utilizes CT’s that are placed on each leg of the cable attached to leads that connect to a phasing set situated above the ground on a dielectric blanket.

Figure 1: PILC Cables with phasing set leads attached (yellow)

Figure 2: EPRI cables with phasing set lead attached (black)

Figure 3: Phasing Set on Dielectric Blanket

Figure 4: Phasing Set

Each lead running from the phasing set to the conductor leg has a phase marker placed on it that is slid down to mark the conductor phase after it is determined.

Figure 5: Phase marker – slid down black cable to identify correct leg

Figure 6: Phase markers

Technology

A Phasing Identification set is a tool used to determining the phasing of the legs of a feeder. CEI utilizes a remote phasing set, with leads running from the unit positioned outside of the manhole, down to the individual conductor legs.

Figure 7 and 8: Phase Identifier

5.6 - Manhole Inspection - Maintenance

5.6.1 - AEP - Ohio

Maintenance

Manhole Inspection - Maintenance

People

Manhole inspections are performed on a four-year cycle, as well as in conjunction with the inspection of network equipment (normally, on a one-year cycle). Inspections may be performed by Network Mechanics, Network Crew Supervisors, and contractors. Contractors are used to make civil repairs identified through inspection.

Process

Manhole inspections include a visual inspection, cleaning of the vault, and tonging secondary cables to assure cable limiter continuity. More specifically, inspections include:

Clean manhole and drains.
Check for spalling or deterioration of concrete.
Check condition of manhole cover.
Check for contact voltage on manhole and ring before and after entering.
Inspect cable, racks and ties (tag as needed).
Inspect primary cables for any abnormalities (swelled or leaking splices, cracks, cuts, burns, etc.).
Check limiters.
Take load readings on mains larger than 350 and services larger than 4/0
Check manhole identification number (replace numbers as needed).
Check fireproofing on all cables and splices.
Check condition of ground connections.
Check termination insulation and waterproofing.

Inspectors record conditions and note any required follow-up activities. See
Attachment D for a copy of the manhole inspection form. Note that manholes are also inspected as part of the regularly scheduled network protector and transformer inspection schedule (yearly). Repairs of corrective maintenance issues identified are performed based on a prioritization of the findings.

Most deteriorated manhole structures are repaired by replacing the manhole top. Some are repaired by pouring the bottom section according to specifications, then using precast middle and top sections. These civil repairs are performed by a contractor.

Technology

Crews use a modified bread truck for inspections, which includes vacuum equipment for pumping out any water in manholes. A practice of note is the organized and well-equipped features of these trucks. AEP Ohio has configured and modified these trucks to their own specifications (see Figures 1 and 2).

Figure 1: AEP Ohio 'bread' truck with easy-access, low tailgate

Figure 2: AEP Ohio 'bread' truck – interior view

Crews have computers in every truck. Printed and online forms are available. Conditions of the manhole are captured in the AEP NEED (Network Enclosure and Equipment Database). When information is entered into NEED, repair or replacement priorities are noted.

AEP Ohio performs an inspection using infrared thermography (IR) every time a worker enters a vault (see Figures 3 and 4). This inspection is being performed as a manhole entry safety practice and has been in place for about five years. IR cameras are used to identify hot spots in the vault, with inspectors “shooting” joints, crabs, and cables. The rule of thumb for action is if a spot on a joint, for example, shows a difference of 40 degrees C or more, then crews will replace the joint. AEP Ohio employees noted that early on, they identified and rectified problems, but that now, they rarely encounter hot spots.

Figure 3: AEP Ohio Network Mechanic using infrared camera

Figure 4: Infrared camera

5.6.2 - Ameren Missouri

Maintenance

Manhole Inspection - Maintenance

People

Ameren Missouri inspects manholes on a four year cycle, comporting with a Missouri PSC requirement. Inspections are performed by two person contractor inspection crews.

A supervisor within Ameren Missouri’s Resource Management group is responsible for oversight of the contractors performing the manhole inspections.

Ameren Missouri has developed and delivered a training manual for the contractor that guides the manhole inspection process. This document includes instructions for addressing emergency situations, work area and personal protection, and for conducting a visual inspection of the manhole including the lid & ring, ceiling, walls and floor of the manholes. (See Attachment G)

Process

Ameren Missouri provides plat maps associated with the manholes to be inspected in a given year to the contractor at the beginning of the year. The contractor inspectors utilize the plat maps to establish their inspection routes and locate manholes. They divide the territory into sections and distribute the work among their inspectors. In general, the contractor attempts to get to the older manholes where they expect a higher number of problems earlier in the year so that they can identify those problems as early as possible.

The contractor will send one person out in advance to scout the hole to be inspected to find its location, and to assure that it is at street level. In some cases where manholes may be paved over, the contractor may use ground penetrating radar to locate the manholes.

The manhole inspections are performed by two man inspection crews using a video camera that is lowered into the manhole. (In cases where water must be pumped out of the manhole, they will use a three man crew). Inspectors use the video camera to perform a visual inspection without having to enter the manhole. The visual inspection is performed by looking at hand held monitors. At the time of the practices immersion, Ameren Missouri was considering adding the performance of infrared inspections to their manhole inspection program.

Ameren Missouri has a well defined manhole inspection / repair process for performing manhole inspections that includes guidance for inspectors for action based on inspection findings. For example, non emergency electrical issues identified by inspection are forwarded to the UG Construction department who creates a corrective maintenance order (DOJM Job) that is scheduled for repair. Structural findings are forwarded to the Civil and Structural Design group within Energy Delivery Technical Services for scheduling and repair. See Attachment E for a flow diagram of the Ameren Missouri Manhole Inspection / Repair Process.

Findings are recorded by the contractor on tough books into a Circuit and Device Inspection System (CDIS). The contractor provides a report that summarizes the findings. The CDIS utilizes an algorithm that assigns a “structural score” and an “electrical score” based on the inspection findings and weightings for various findings developed by Ameren Missouri. The scores are used to prioritize remediation.

CDIS is also used to produce reports that summarize inspection findings and a dashboard that monitors inspection progress. See Attachment F and Attachment H for a sample of the Ameren Missouri project dashboard for the manhole inspection program, and a sample of the inspection finding report provided by the contractor.

Technology

Information from inspections of network manholes vaults and service compartments (adjacent manholes with bus work) is recorded on laptops (tough books).

Ameren Missouri includes the taking and recording of photographs of manhole and vault infrastructure as part of its inspection programs.

The contractor vehicle is a half ton survey truck with a camper shell and a 100 foot cable for the camera.

The contractor who is performing a manhole inspection utilizes a camera that is attached to a tripod positioned above the hole and is lowered into the hole from the top. The visual inspection of the infrastructure within the manhole is performed by using this camera.

Distribution service testers who are performing vault inspections take photographs while in the vault.

Figure 1: Contractor Vehicle and Camera Tripod

Figure 2: Camera Tripod

5.6.3 - CEI - The Illuminating Company

Maintenance

Manhole Inspection - Maintenance

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who inspect and maintain the underground system.

Process

Manholes are inspected and maintained on a five year cycle. This includes both network and non-network manholes. CEI develops a schedule that indicates the number of units to be inspected and maintained each month.

The manhole inspection is comprehensive, including inspecting and recording the “as found” and “as left” condition of the manhole itself and all equipment contained therein. This includes:

Manhole condition, including cable racks and arms, ladders, etc.
Cable bonding and splice condition
Cleaning and debris removal
Oil switch condition

Inspectors are to take amperage readings of secondaries on the load side of cable limiters to assure cable limiter continuity. In practice, this is sometimes done, and sometimes overlooked.

Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

Technology

Manhole inspection results are recorded manually on the manhole inspection sheet. See Attachment L

Note: Manhole inspections do not include the infrared thermography. Inspectors will take temperature readings with a temperature “gun” only if something is suspected to be running hot.

5.6.4 - CenterPoint Energy

Maintenance

Manhole Inspection - Maintenance

People

Distribution Manhole Inspections are performed by the Cable group within Major Underground. The Major Underground organization includes Key Accounts, Engineering and Design resources, Support Services, and the field force responsible for all construction, operations and maintenance activities. The field force is divided into two main groups, the Relay group and the Cable group.

Both the Relay group and Cable group perform maintenance and inspection activities. The Relay group focuses on most of the non cable equipment inspection and maintenance, including performing vault equipment inspections, network protector testing, and other inspections and maintenance on devices with relays or motor operators. The Cable group focuses on manhole inspections that include inspections of cable, cable accessories and major equipment.

The Cable group is comprised of Cable Splicers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. The Cable group is led by two Operations Managers.

CenterPoint does not have dedicated maintenance crews. Rather, maintenance and inspection work is assigned to crews based on work priorities and resource availability.

Process

The Cable Splicers within the Cable group perform manhole inspections on either a 1, 5, or 10 year cycle, depending on the manhole priority. At locations where there are dedicated UG circuits (meaning three phase circuits that are entirely underground), the manhole inspection frequency is yearly.

Manhole inspections include a visual and infrared inspection. At some locations, the Cable Splicers will take load readings.

CenterPoint is using an inspection checklist to guide inspectors through the various items included in the inspection. This same checklist, entitled MUDG Functional Location Inspection Sheet is used to record findings from all inspection types. An inspection sheet is completed for every location inspected.

Inspection findings that require follow up corrective maintenance are noted and recorded by the Crew Leaders who schedule this work for completion. If the solutions to the findings require the involvement of other groups, the Crew Leaders will solicit their help. For example, corrective maintenance activities that require a customer outage will require the assistance of the Key Accounts group to coordinate with the customer to schedule the outage.

The inspection sheets are filed by work center (each manhole location is considered a work center), so that CenterPoint has a record of the historic findings.

Technology

Manhole inspection results are recorded manually on the MUDG Functional Location Inspection Sheet See Attachment I.

Manhole inspections include the performance of infrared thermography.

5.6.5 - Con Edison - Consolidated Edison

Maintenance

Manhole Inspection - Maintenance

People

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including:

Inspections/manhole inspections
Post-construction inspections to determine to adherence to specifications
Safety inspections
Critical manhole inspections, performed in any manhole on the immediate block of a substation, and inspected on a three-year cycle
Regular manhole/vault inspections, scheduled every five years
- Infrared inspections of transformers/network protectors/substations
- Infrared is a four-year cycle for 277/480-V installations.
- Infrared is not programmatic, but is performed randomly, or by exception at 120/208 V. Infrared inspections are performed more frequently at sensitive customer locations such as hospitals and museums.
- Substation infrared is annual.
- Use strategically placed site glasses to obtain infrared views of some locations.
- Use outside contractor to perform infrared training.
Cable and Joint failure analysis specimen retrieval and tracking
Fill-in work, special requests
Check out erroneous readings monitored through the RMS system
Map verification; that is, comparing what is on the mapping system to what is in the field
Random spot checks, focused on workmanship
Random equipment checks
- For example, the Field Engineering group performs random monthly spot checks of primary splice packs to be sure that the kit is complete.
Respond to voltage complaints

Note: This group does not routinely inspect design versus build, or as-built versus mapped.

The department is made up primarily of Splicers. People are chosen for jobs in the department by seniority.

Process

Inspection and Maintenance

Con Edison performs periodic maintenance and inspection of network distribution equipment, including network feeders, transformers, network protectors, grounding transformers, shut and series reactors, step-down transformers, sump pumps and oil minder systems, remote monitoring system (RMS) equipment, and vaults, gratings, and related structures.

Con Edison’s approach to performing an inspection is to inspect all the equipment and structures associated with a particular vault ID at a location regardless of category or classification, and even if the particular equipment associated with a particular vault ID resides within different compartments (for example, a transformer and network protector may be located in separate physical compartments even though they both share the same vault ID). This type of inspection is referred to as a CINDE Inspection, based on the name of their maintenance management system (Computerized Inspection of Network Distribution Equipment).

Con Edison performs inspections energized; crews do not take a feeder outage to perform inspections, perform pressure drop testing, or take transformer oil samples. Con Edison does not routinely exercise feeder breakers.

In an effort to more efficiently use their resources, and when nonpriority conditions allow, Con Edison takes advantage of situations where they have to enter a vault or manhole for a reason other than a scheduled inspection, and perform a nonscheduled inspection while they are in the vault. When the record of this nonscheduled inspection is recorded in CINDE, the system “resets the clock” for the next inspection date.

Network equipment at 208 V is generally inspected on a 5-year cycle. 460-V facilities, sensitive customers, facilities in flood areas, and other more critical locations are inspected more frequently, often annually. Con Edison establishes network equipment inspection cycles depending on two factors: the inspection category and the inspection classification .

The inspection category refers to the type of inspection, and includes a Visual Inspection, a 120/208-V Test Box Inspection, and a 460-V Test Box Inspection. The Visual Inspection includes activities beyond visually assessing condition and recording information, such as pressure drop testing and taking transformer oil samples. The test Box inspections involve specialized testing of network protectors with the network relay installed. Note that all of the elements of a Visual Inspection are performed along with the Test Box Inspections.

The inspection classification refers to characteristics of the inspection site that dictate the inspection cycle. For example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a “tidal” area would be visually inspected annually. Con Edison considers the following classifications in determining inspection cycles:

Routine
Back-feed: banks installed on a feeder involved in a back-feed incident
Candidate for Replacement: commonly due to corrosion damage
Essential Services: critical customers
Flooded Bank: nonsubmersible equipment that has experienced high water levels
208-V Isolated Bank: units that require more frequent inspection than distributed secondary grid units
Remote Monitoring System(RMS), Non RMS, Unit Not Reporting (UNR): Con Edison varies inspection cycles based on the level of remote monitoring installed
Tidal, Water, and Storm Locations

Note that Con Edison requires employees to perform at least a quick visual inspection (QVI) anytime an individual enters a network enclosure, even if the reason for entering an enclosure does not warrant a CINDE Inspection. This type of inspection (QVI) differs from the CINDE inspection category of Visual Inspection described above, in that it is not a full, accredited inspection.

“Cut and Rack” Manholes

In the course of performing work, such as reinforcing secondary networks, or responding to a burnout, Con Edison crews periodically encounter manholes where they identify a need to reconfigure the facilities in the manhole to improve their safety, operability, and long-term reliability. These facilities are reconfigured by cutting and re-racking facilities within the manhole, referred to as a “Cut and Rack.”

This practice is noteworthy in that it demonstrates Con Edison’s ongoing commitment to investing in infrastructure to improve operations, reliability, and worker safety.

Technology

Inspection and Maintenance Software

Con Edison uses legacy maintenance management software called CINDE, which is an acronym for Computerized Inspection of Network Distribution Equipment. CINDE is a system that records inspection data and initiates inspections based on predetermined cycles. These cycles depend on the category of inspection (for example, a visual inspection versus a “Test Box” inspection) and various predetermined classifications of inspections (for example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a tidal area is visually inspected annually).

Con Edison inspectors record inspection data on hand-held devices (Tough Books). The utility requires that the inspection data be downloaded into the CINDE – Mainsaver system (Mainsaver is the part of the CINDE system used to record data) within three days following the inspection. Inspection data that is entered into the CINDE system includes:

Equipment serial numbers
As-found and abnormal conditions, such as transformer oil level, state of corrosion, and water in the vault
Defective equipment or structures
Repairs or change-outs undertaken
As-left condition, such as transformer pressure and liquid level, and pressure of housing

The CINDE – Mainsaver system is also used by Con Edison to prioritize follow-up work, or outstanding defects to be corrected that are identified through inspection or other visits to network enclosures. The Electric Operations Region is responsible for prioritizing follow-up work by considering the location of the work with respect to risk to public safety, reliability impact, the type of installation, age of the outstanding defect, and the efficient use of resources.

5.6.6 - Duke Energy Florida

Maintenance

Manhole Inspection - Maintenance

People

Manhole inspections are performed by craft workers, Network Specialists and Electrician Apprentices, within the Network Group, part of the Construction and Maintenance Organization. The Network Group is led by a supervisor, and consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position).

Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager.

The Network Group is organized functionally, and has responsibility for construction, maintaining and operating all urban underground infrastructure (ducted manhole systems), both network and non-network, in both Clearwater and St. Petersburg.

Process

Manholes are inspected on a five-year cycle in both Clearwater and St. Petersburg. Duke Energy Florida employees noted that because of the small size of the network infrastructure in Clearwater, they do enter manholes rather frequently for various reasons – often more frequently than the five-year inspection cycle.

Manhole entry procedures, detailed in the Manhole Entry section of this report, include the establishment of work area protection, the obtaining of a “Hot line” clearance which changes the instantaneous trip setting of substation relay to a fast trip (6 cycles, rather than the normal 30 cycles), continuous air monitoring, installation of a rescue apparatus over the manhole opening, and tethered workers.

Duke Energy Florida has high confidence in their manhole drawings. The drawings, which are maintained by the Network Group, are available to field crews on-line, and can be printed from truck mounted printers. The Manhole Drawings contain detailed information about the manhole configuration, including dimensions and components. See Attachment E.

The manhole inspections include a visual inspection of all electrical facilities and assessment of the condition of the civil infrastructure. Inspections include mapping updates to assure that the maps are accurate. Inspections also include load checks to ensure cable limiter continuity. The inspection scope is detailed on Attachment H.

Information from the inspection is recorded on an inspection form, including an assessment of the priority or severity of the finding. See Attachment H . Information from the inspection is entered into a computer system, and the hard copy form is maintained in a file. Duke Energy Florida has a “Further Work Ticket Process” which is initiated to pursue remediation for corrective maintenance items identified by inspection. The repair schedule is dictated by the priority of the finding.

Technology

Duke Energy Florida is investigating the application of self -ventilating manhole systems, though hadn’t installed any at the time of the practices immersion. Duke Energy Florida has begun a manhole lid retrofit program with 40 installations of East Jordan technology scheduled for 2016.

Duke Energy Florida is not performing infrared inspections as part of their manhole inspections. However, they have recently implemented a policy to perform an IR inspection as part of the manhole entry process in advance of performing work in the manhole.

5.6.7 - Duke Energy Ohio

Maintenance

Manhole Inspection - Maintenance

People

Duke Energy Cincinnati has implemented a manhole inspection program on a six year cycle. The inspections are performed by Dana Avenue field crews, who record findings on either an Excel form or a lap top computer.

In practice, Duke Energy Ohio is able to inspect about 250 manholes per year. They are currently working to expand that number to 400 manholes per year.^[1]

Duke Energy Ohio does not vary its inspection cycle based on an assessment of the manhole criticality (high risk holes versus low risk holes).

Process

Crews utilize Cable and Conduit (C&C) maps as part of the inspection and compare the information shown on the map with what they encounter in the manhole. The maps do not always accurately reflect what’s in the field. Also, inspections occasionally reveal additional manholes not shown on the maps. (This is particularly true in the suburban areas.) Correction and update of the C&C maps is one of the outcomes of the manhole inspection.

Manhole inspections include a visual inspection of the manhole looking for evidence of network burnouts, racking issues, roof issues, grading issues, leaks, swollen splices, etc. Note that thermal readings are not presently being done as part of a routine manhole inspection.

Crews utilize a checklist, which is an Excel form (either paper or on a lap top). Crews also utilize a digital camera, taking pictures of any issue identified during inspection. This enables Duke to review and discuss the findings of the inspection to recommend remediation.

As inspection crews identify potential structural issues, they will normally revisit the manhole accompanied by a civil contractor who can recommend remediation. On occasion, safety professionals are included in the inspection to help prioritize the repairs based on safety. Should structural repairs be required, this may initiate a capital rebuild of the manhole.

Duke’s most commonly encountered findings include roof issues, racks off the wall, and leaking splices.

Electrical repairs are prioritized by the crews and Dana Avenue supervision in conjunction with the Network Engineer. Duke does not have a written guide for prioritizing repairs. Rather, repair priority is driven by the experience of Dana Avenue personnel. In general, any deformation of a splice (swollen or bulging, for example) is treated as a priority.

Structural issues with manhole roofs are a high priority, with Duke rebuilding about 25 manholes per year. Maintenance issues identified in these holes will be addressed as part of the manhole rebuild.

Repair schedules are driven by priority and are often customer driven. Work in downtown Cincinnati must be scheduled between 9 and 3:30 to comply with City requirements.

Technology

Duke Cincinnati has 3418 manholes on their system.

Manhole Inspection Sheets are presently created in Excel. See Attachment F for a copy of the manhole inspection sheet. Duke will shortly be implementing an Emax system, which will make inspection forms available on line.

Inspection findings are recorded by crews either onto the forms or directly into the Excel form using lap top computers. Inspection findings are recorded in Excel and kept in a manual file by the Network Engineer.

Duke is planning to expand its manhole testing to include the use of an infrared camera to identify hotspots.

^[1] Having a total of 3418 manholes, Duke will ultimately need to inspect approximately 570 manholes per year to adhere to a six year cycle.

5.6.8 - Energex

Maintenance

Manhole Inspection - Maintenance

Energex is not performing routine pit (manhole) inspections.

See Preventative Maintenance and Inspection

5.6.9 - ESB Networks

Maintenance

Manhole Inspection - Maintenance

See Preventative Maintenance and Inspection

5.6.10 - Georgia Power

Maintenance

Manhole Inspection - Maintenance

People

Depending on availability, manhole inspections are performed by Senior Duct Line Mechanics or Senior Cable Splicers and a supervisor, who report to the Maintenance supervisor, within Network Operations and Reliability. Although the Georgia Power Network Underground group does not have specific crews assigned to manhole inspections, the Maintenance group will pull available crew members to maintain its inspection schedule for manholes.

Process

Manholes are inspected on a six-year cycle throughout the state of Georgia. Prior to inspections, the supervisor uses an Access database program to generate a blank form already populated with some specifics about the configuration of the particular manhole or vault to be inspected if a crew has filled out the information during construction or during a previous inspection. The printed inspection form does not have previous findings pre populated, assuring that the field crews must perform and record an updated inspection. Appropriate crews and maintenance trucks are dispatched to the field (See Figure 1 and Figure 2). Once completed, the form is populated into the Access system. Forms are retained in hard copy for seven years.

Figure 1: Typical truck used by inspection and maintenance crews

Figure 2: Truck used for manhole cleaning

The inspection form has a well-organized checklist of items that must be inspected, including sections that deal with:

Initial inspection of overall condition (water in the hole, cleanliness)
Structural Inspection, including inspection of the manhole cover, neck, floor and wall condition, racking, ducts, etc.
Electrical equipment inspection of secondary / street mains
Electrical equipment inspection of primary facilities including cable and splice condition.

(See Attachment A )

Nearly 20 percent of all inspections occur outside the Atlanta metro area in other regions where Georgia Power has network underground installations. In the Savannah network, designed with cable limiters, inspectors routinely tong the secondary cables to check for cable limiter continuity.

If work needs to be performed, the supervisor of the crew determines whether the maintenance can be performed on-the-spot; otherwise, a maintenance work order is sent in by the supervisor, including notes and a prioritization of the maintenance. It is up to the supervisor to determine how critical the maintenance or repair is, and the inspection form reflects the priority, as well as direct communication with the appropriate workgroup within the Network Underground.

Georgia Power’s Operation and Test procedure for Manhole and Vault Maintenance specifies three levels of priority for inspection times. The procedure does not specific time frames for completion of corrective maintenance.

Priority # 1 - the most urgent, and requires immediate attention

Priority # 2- needs attention very soon

Priority # 3- needs attention when it can be scheduled

Technology

When a supervisor enters inspection information into the Access database, and the inspector(s) indicates that something needs repair, the system will create a maintenance order automatically. Inspectors only need to fill in what is required, such as a structural repair or manhole cleaning. The inspector receives a monthly report of the pending corrective maintenance jobs.

Where possible, the inspection information can also be entered into the DistView software system. With DistView, inspectors can log onto the company intranet with a wireless laptop and enter data about inspections into pre-determined fields and also add notes as findings are top-of-mind at the site and time of the inspection.

Georgia Power does not perform an infrared inspection as part of its routine manhole inspection. However, infrared thermography is performed at high profile locations.

Georgia Power does not routinely take and record photographs of inspection findings.

Georgia Power is piloting the use of secondary cable load monitoring in selected manhole locations in Savannah.

5.6.11 - HECO - The Hawaiian Electric Company

Maintenance

Manhole Inspection - Maintenance

People

HECO Substation resources perform maintenance and inspection of network equipment.

HECO currently is not performing any programmatic inspection and maintenance of their non-network underground facilities.

Process

Network system preventive maintenance and inspection programs include:


Program	Cycle or other Trigger
Manhole Inspection, including amp readings of molimiters.	Annual^[1]
Network Vault Inspection	2-3 years – inspected during transformer and NP maintenance
Network Transformer Maintenance (Includes Oil Sampling and Pressure Testing)	2-3 years
Network Protector Maintenance	2-3 years

Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

^[1] HECO’s desired schedule is to perform these inspections and take amp readings annually. In practice, they have not adhered to this schedule.

5.6.12 - National Grid

Maintenance

Manhole Inspection - Maintenance

People

Network manhole inspections in Albany are performed by the UG field resources (network crews) that are part of Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground Lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Electrical Group, comprised of Cable Splicers, Maintenance Mechanics, is led by three supervisors. Maintenance Mechanics perform network vault inspections and maintenance of network equipment contained in the vaults such as transformers and network protectors. Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. Cable Splicers are also responsible for performing manhole inspections.

In addition, National Grid has a company-wide Inspections Department, led by a manager, responsible for completing regulatory required inspection programs. This group consists of supervisors assigned to the National Grid regions, and a union workforce to perform routine inspections. Note, however, that network manhole inspections within Albany are performed by two- person Cable Splicer crews from Underground Lines East.

National Grid does not use dedicated full time maintenance crews; rather, they schedule maintenance as a work assignment along with other work types.

Process

Regulatory mandates in the State of New York require National Grid to inspect their distribution plant on a five-year cycle. Network manholes comport with this requirement, and are thus inspected on a five year cycle. (Note that network vaults are inspected annually.)

Manhole inspections include a visual inspection of the both the civil and electric condition of the manhole. All separable connections are checked with an infrared thermometer. Inspectors also confirm the use of fireproof tape on cables, a standard at National Grid.

National Grid is also performing elevated (stray) voltage testing using hand held E-field directional testers of all manhole locations on an annual basis. National Grid is using contractors to accomplish this testing. (Stray voltage testing is mandatory in New York in cities with populations over 500,000; National Grid is performing this testing in Albany)

National Grid has developed an Electrical Operating Procedure (EOP) which provides guidelines for prioritizing issues identified during inspection for repair. This EOP provides guidance to the inspectors as to how to categorize certain findings. The inspector is free to “upgrade” the severity of the finding based on his field assessment. For example, the guidelines may indicate that a leaking joint should be a “Level 2”. The inspector may elect to upgrade to a “Level 1” based on field conditions.

Various turnaround times for repair are specified depending on the categorization.

Level 1: Emergency - must be made safe within 7 days.

Level 2: One year

Level 3: Three year

Level 4: Information purposes only

These levels were developed by asset and engineering groups based on past history and basic knowledge. Note that except for emergencies (Level 1), inspections are not repaired immediately but are reported so that the inspection process can stay on task.

Inspection information is entered directly into a hand held device using Computapole software. A work order to perform follow up corrective maintenance can be generated by the interface between Computapole and National Grid’s STORMS work management software (See Technology, below).

Technology

Crews use handheld devices (Symbol Units, part of Motorola) to record inspection information. This unit has the required inspection information built into it, and a mapping feature. It also contains the most up-to-date system data and previous inspection results. Appropriate codes for the inspection are entered directly into the unit and returned to the supervisor for entry into the computer database. These codes alert GIS of changes in the field.

Computapole is a mobile utilities software platform that runs on handheld devices and is customized to meet National Grid’s specific needs. Computapole is used for inspections and mapping functions on handheld devices. Once information is entered in the Computapole system, work is managed by an interface with STORMS (below) to create work requests.

Severn Trent Operational Resource Management System (STORMS) is National Grid’s work management system. The work management system includes tools to initiate, design, estimate, assign, schedule, report time/vehicle use, and close distribution work. Computapole sends inspection information to STORMS to create work requests as needed.

Inspectors do not take photographs of condition issues identified during inspection.

National Grid Underground does not routinely use duct line cameras. In specific incidents in the past (blocked ducts or stuck cables), the Underground Department has had the National Grid Gas Department or contractors use duct line cameras. .

5.6.13 - PG&E

Maintenance

Manhole Inspection - Maintenance

People

PG&E has implemented a manhole inspection program on a three year cycle. The inspections are performed by UG inspectors who are part of the Compliance Department, within the M&C Electric network organization. The Compliance Department performs and reports on regulatory required inspections and patrols (CPUC GO 165) of distribution infrastructure.

The UG Inspector position is typically filled with former journeyman cable splicers.

PG&E has good documentation of the procedures for performing underground equipment inspections contained within their Electric Distribution Preventive Maintenance Manual.

Process

UG Inspectors utilize Route Sheets and Duct Maps when performing inspections. Inspectors also utilize an underground inspection job aid form that lists the types of abnormal conditions that must be recorded. Manhole inspections include a visual inspection of the manhole looking for evidence of network burnouts, racking issues, roof issues, grading issues, leaks, swollen splices, etc.

PG&E performs infrared inspections as part of the manhole inspections. They have established guidelines for assisting inspectors in determining the corrective maintenance priority based on the measured temperatures and temperature differentials.

Corrective maintenance items result in the creation of an EC Tag (or EC Notification^[1] ), which must be prioritized and scheduled for repair by the M&C Electric network group. Lower priority EC notifications may be grouped by feeder, and competed during a scheduled feeder outage.

Technology

Inspectors will take photographs of condition issues identified during inspection, including thermal images revealed through IR testing, and save them as part of the EC notification. Note that PG&E does not use duct line cameras.

^[1] The EC Notification is an SAP created blanket order for performing corrective maintenance.

5.6.14 - Portland General Electric

People

Manhole inspections on the network are the responsibility of CORE group. The CORE group, which is a part of the Portland Service Center (PSC), focuses specifically on the underground CORE, including both radial and network underground infrastructure in downtown Portland. Its responsibility includes inspection and maintenance of the network infrastructure, including manholes. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault while the helper, typically a non-journeyman classification, usually stays above ground, carrying material and watching the barricades and street for potential hazards.

Process

PGE attempts an annual inspection for general-purpose structures such as manholes, though manpower availability determines the exact cycle. At the start of every year, general work orders for inspection of manholes are created in Maximo for a particular geographical area, with each work order covering the manholes in a one- or two- block area. A crew receives these work orders and is expected to perform inspections when lacking customer work. If there is little customer work on the network, inspections can be completed for all non-equipment manholes and vaults within a calendar year.

PGE employees, not contractors, perform all inspections of manholes, including both an electrical and civil (structural) review. Inspections also include a visual inspection to identify leaks, assess vault cleanliness, etc., and may include the use of infrared (IR) thermography at the discretion of the inspection crew. As part of the inspection, crews clean the manhole.

PGE does not perform routine, periodic inspections of duct lines. If a crew notices damaged ducts during vault inspections, they may be inspected with a duct camera.

Crews may take load readings on the secondary system to try to identify open limiters when inspecting vaults. Because some of the secondary feeders are difficult to access, this continuity testing is restricted to accessible secondary feeders.

PGE does not use a formal inspection sheet for manhole inspections, although a crew completes a Field Action Report if it finds issues for follow-up corrective action. If no action is needed, crews do not fill out any paperwork and the completion of the inspection is noted in Maximo.

If a crew is able to repair a problem without the need for engineering or design services, such as replacing a damaged ladder, they will do so while it is there. The CORE keeps limited documentation of these informal fixes as part of its “fix-it-when-you-find-it” approach. For repairs that are not done right away, the Field Action Report prioritizes them based on urgency. Electrical issues receive a “1,” the highest priority. A lid that is shattered or needs to replacement receives a “2” priority. Priority “3” work is rarely undertaken because the crew tends to repair such small issues at the site. The priorities guide the urgency of the repair but are not accompanied by specific deadlines for accomplishment. They try to be as expedient and efficient as possible, scheduling work as soon as circuits are available.

Engineering generally responds to electrical problems and Service & Design Project Managers (SDPMs) handle the other tasks, including coordination with external contractors for civil repairs.

Technology

Maximo: PGE uses the Maximo for Utilities 7.5 system to manage inspection reports and store details about any maintenance needed.

5.6.15 - SCL - Seattle City Light

Maintenance

Manhole Inspection - Maintenance

People

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable Splicers perform all electrical aspects of network construction, operations, and maintenance. All electrical employees who work in the network are either Crew Chiefs, journeyman Cable Splicers, or apprentices in the mode of progression, working their way towards the journeyman level.

Crew Makeup

A network crew is normally made up of one Crew Chief, one or two Cable Splicers, and one apprentice. The type of work to be done and SCL work rules will dictate the appropriate crew makeup. For example, performing switching in a vault requires at least two journeyman-level employees to be in the vault. These and other work rules and safety practices are spelled out in the Washington State Safety Standards for Electrical Workers, Chapter 296-45 WAC.

Process

Network Feeder Maintenance – Manhole Drill

SCL’s goal is to accomplish maintenance on their feeders every four years. They budget specific dollars each year to accomplish this maintenance. They attempt to tie this maintenance in with capital work when practical, so that they can take advantage of feeder outages to accomplish both the capital (system reinforcement) and maintenance activities. See Maintenance - Network Vault Inspection / Maintenance - Network Feeder Maintenance

Before taking a feeder out for maintenance, SCL performs a “manhole drill.” The manhole drill involves an inspection crew, usually made up of two journeyman Cable Splicers (or one working crew chief and one journeyman) and one apprentice going into each manhole on the feeder planned to be maintained, and performing an inspection. If inspectors identify a problem in the manhole that can be fixed on the spot, they do it. If the fix cannot be fixed on the spot, or must be engineered, they notify the Network Electrical Crew Coordinator, who creates a trouble ticket or urgent maintenance slip to complete the work as part of the feeder maintenance. If the inspection crew discovers a civil problem, they notify the civil crews of the need for a repair.

All post-inspection corrections are scheduled to be performed in conjunction with the feeder maintenance.

During the manhole drill, the crews perform heat gun readings in each manhole to identify any problems. Crews also look for problems on adjacent feeders in the same hole, and may postpone performing the feeder maintenance until addressing any identified problems on the adjacent feeders (in other words, address problems on adjacent feeders before moving to an n-0 condition). Heat gun checks are performed both at the front end, before the maintenance is accomplished, and at the back end, after maintenance is complete.

SCL does not perform cable limiter continuity checks as part of the manhole drill unless there is a specific problem, outage, etc. that they are following up on. These checks are usually performed as part of the troubleshooting of a problem.

All of the corrective work identified during the inspections are planned to be completed during the feeder maintenance, so that by the time the feeder is put back into service, all of the maintenance items and deficiencies will have been completed and corrected.

Civil Maintenance

SCL hired a consulting firm to audit their manholes to identify needed civil repairs. They currently have a $2.5 million budget to perform manhole civil repair. This work has been prioritized and is being spread over 40 years.

5.6.16 - Survey Results

Survey Results

Maintenance

Manhole Inspection and Maintenance

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 7 : Please indicate if your company performs the following Inspection activities on a routine basis and at what frequency.

Survey Questions taken from 2018 survey results - Asset Management survey

Question 8 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Question 9 : Do you have any maintenance programs where the maintenance frequency or approach is dependent, at least in part, on a risk or condition assessment of the assets to be maintained (For example, a higher risk vault inspected more frequently than a lower risk vault)?

Survey Questions taken from 2015 survey results - Maintenance

Question 85 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Question 94 : Are you using infrared (iR) technology as part of your manhole and vault assessment process?

Question 95 : If you use iR technology, what technologies do you use?

Question 96 : If you perform iR testing, which activities do you perform ir testing?

Question 97 : If yes, which equipment are you using iR on?

Question 99 : Are you using cameras as part of your manhole inspections?

Survey Questions taken from 2012 survey results - Maintenance

Question 6.10 : Do you regularly perform Manhole inspections?

Question 6.11 : If yes, what is the frequency of the Manhole inspections?

Question 6.30 : Are you using cameras as part of your manhole inspections?

Question 6.34 : Do your crews utilize tablets or laptop computers for maintenance

Question 6.35 : Is your record keeping done electronically or manually?

Survey Questions taken from 2009 survey results - Maintenance

Question 6.15 : Do you regularly perform Manhole inspections?

Question 6.16 : If yes, what is the frequency of the Manhole inspections?

5.7 - Network Protector Maintenance

5.7.1 - AEP - Ohio

Maintenance

Network Protector Maintenance

People

Network Mechanics perform network protector inspections on a one-year cycle and perform full network protector maintenance on a four-year cycle.

Process

Network protector annual inspections are an “open door” check, primarily to test for moisture. Inspectors do not de-energize or rack out the protector (see Figure 1). After inspection and closing the door, inspectors will apply 3 lbs of pressure to confirm the door seal. Specifically, this inspection involves:

Check for moisture and oil in the case
Check for loose parts in the bottom of the case
Inspect control wiring
Perform a visual inspection
Check for odor
Compare the relay status with contact position
Verify counter operation
Record counter readings
Check the door gasket
Pressure test the enclosure
Check the interlock type on CM52 protectors. Any early version interlocks should be scheduled for upgrade
Conduct both a mechanical and relay calibration check utilizing a NP test set.

Figure 1: AEP engineer inspecting a network protector

Also, for CMD protectors, AEP is checking the contact pressure one month after a unit is placed in service. In addition, AEP Ohio performs annual trip (or drop) checks of each circuit to assure that protectors open as required. This test involves:

Check all single contingency spot networks as normal (so no customers are outaged by the execution of the test)
Open the circuit breaker
Confirm potential light out or use other means to confirm that the circuit is de-energized
Record the time opening interval (less than 10 seconds)
Close the circuit breaker
Check that all protectors are closed
Record counter readings
- Check, clean, and lube mechanism.
- Inspect control wiring (visual and odor)
- Check for broken strands.
- Check for loose parts in the bottom of the case.
- Check for moisture and oil in the case.
- Check insulator end caps – CM22
- Check the mechanism close roller for free movement – CM22
- Check the air damper breather hole – large CM22
- Check the insulator bar for cracks/checks – GE, CM22
- Check/lube finger clusters – CMD
Check nuts, bolts, screws, and connections for tightness.
Check internal fuses (rock test)
Check, clean, and align contacts.
- Check arcing contacts – replace if worn
- Check and set contact pressure – CMD
Measure the contact resistance with a DLRO meter. 25 micro-ohm all models and sizes
Check, clean, arc chutes
Check and clean phase barriers. Replace if broken.
Check the motor contacts and brushes
Check and clean motor control contacts.
Check/clean the motor brake (two-wire motor) CM22
Check and clean auxiliary switch contacts.
- Check for Z bracket stop – CMD (install if missing, 1989 and earlier)
- Check auxiliary switch timing – CM22, MG8/9
Check the type of CMD trip circuit.
- Replace cap if necessary (1996 – 2002)
- Replace the DTA if it is an older black unit with CTA.
- Check the capacitor charge – two trips minimum.
Check anti-close circuit operation – CMD, CM52
Remove relays for cleaning and calibration
Replace electromechanical relays.
Check the minimum voltage trip and close – Mechanical test
Reinstall relays and calibrate/program (see protector maintenance test sheet).
Megger motor with 500-V megger.
After disconnecting ground connections and motor leads, megger upper and lower protector bus with 1000-V megger (phase-to-phase and phase-to-ground) – CM22, MG8/9, MG14, and CMR8.
Check the door gasket – pressure test enclosure.
Check automatic close/open operation.
Check CMD/CM52 interlocks.
Check the CM52 handle adjustment (trip form wire alignment).
Check counter operation and record readings.
Document follow-up work needed.

Technology

AEP Ohio is standardizing on Eaton CM52 network protectors, although older protectors are still in the field. Inspections and maintenance documentation is recorded on NP Inspection and NP maintenance forms (see Attachment F and Attachment G).

Crews have computers in every truck. Printed and online forms for network protector maintenance are available. Conditions and scheduled maintenance performed are then captured in the AEP NEED (Network Enclosure and Equipment Database). Network crews can also log into the AEP UGN (Underground Network) intranet for guidance, process, and procedures, including links to learning/diagnostic guides.

5.7.2 - Ameren Missouri

Maintenance

Network Protector Maintenance

People

The majority of the maintenance and inspection programs associated with network equipment, including network protector maintenance, are performed by resources within the Service Test group.

Organizationally, the Service Test group is part of Distribution Operations, led by a manager. Within Distribution Operations, there is a Reliability Support Services group led by superintendent. Reporting to the Superintendent Reliability Support Services are both the Service Test group led by a supervisor and the Distribution Operating group, also led by a supervisor.

The Service Test group is made up of Service Testers and Distribution Service Testers. It is the Distribution Service Testers who perform periodic network protector maintenance and calibration, as well vault maintenance and transformer maintenance including oil testing. The Service Testers perform low-voltage work only, such as voltage complaints, RF interference complaints, and testing and maintaining batteries.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. As part of this group’s role, they are examining Ameren Missouri’s practices for inspecting and maintaining network infrastructure, and developing recommendations for optimal approaches. They have developed a draft document which details strategies for inspection and maintenance of network units, cable systems, vaults, manholes, indoor rooms and customer switchgear. In addition, they have developed a criteria used to evaluate and prioritize replacement of network transformers and protectors. These criteria are based on key considerations such as the transformer’s age, location, physical condition, loading, history with similar transformers styles, and oil quality. (See Network Transformer Replacement Criteria for more information) for more information)

Ameren Missouri has a repair shop that rehabilitates older network units and receives, assembles and tests new units. This repair shop, part of Supply Services, is located in Ameren Missouri’s Dorsett facility. This group mounts the network protector onto the transformer and performs protector testing on new units to assure the protector trips as expected.

See Network Protector Design

Process

Ameren Missouri performs network protector maintenance and calibration on a two - year cycle.

Ameren Missouri performs network protector maintenance with the primary feeder energized. Note that at the time of the immersion, Ameren Missouri was revisiting their approach to maintaining 480V protectors in light of changing arc flash requirements.

The network protector maintenance includes the following steps, excerpted from the Ameren Missouri Distribution Service Man training manual and Maintenance and Inspection guideline developed by Ameren Missouri’s Downtown St. Louis Underground Revitalization group.

Verify nameplate data of protector and compare to inspection sheet. Note any discrepancies.
Use an infrared thermometer or infrared camera to measure temperatures of secondary side bushings. If there are any anomalies, or the readings seem high, call a Supervisor. Record readings on the inspection form.
Use ammeter to record current running through secondary side cables. Take phase-to-ground voltage readings and record all readings (current and voltage) on the inspection form.
Check and record the protector’s switch position as either “open” or “closed.”
The normal position of a protector should be “closed.” If switch is open, perform phase check as described above before manually closing the switch.
Check and record the position of the operating handle as either “automatic,” “open,” or “closed.” Protectors will normally be found in the “automatic” position.
Check operation of protector by moving operating handle to the “open” position. Place the handle back to “automatic” to make sure the protector recloses.
Move the protector handle back to “open” and lock it in that position. Take readings to make sure the protector is indeed open.
Use the sight glass to inspect the physical condition of the protector’s interior. If there are signs of damage or scorching, leave the vault immediately and call a Supervisor.
Open / Remove the protector door by removing the retaining bolts. OPEN / REMOVE THE DOOR SLOWLY AND CAREFULLY.
Make a quick visual inspection of the protector interior, making note of any component that looks damaged or scorched.
Record the operation counter number as found.
Inspect and remove the fuses and THEN the transformer links. FUSES MUST BE REMOVED FIRST.
Replace the “close” and “open” bulbs as needed.
Rack out (slide) the protector and perform the following tasks:
- Inspect fuses and transformer links for wear, melting and structural integrity.
- Inspect motor and brake for oil leakage and water and then clean the brake.
- Check for play of motor/shaft operation.
- Remove arc chutes (also called “arc quenchers”) and clean main and arcing contacts and arc chutes. If the arc chutes are asbestos, be careful to clean them in such a way that does not create friable material. If there is a lot of carbon build-up on the chutes, they should be replaced.
- Check and clean motor control device contacts.
- Check tightness of screw connections and tighten as needed.
- Check physical condition of wiring and barriers.
- Lubricate any moving parts with light oil.
- Remove and replace any broken components.
- Check for any leaks coming in from the transformer.
- Refer to manufacturer’s instructions and manuals for more detailed procedures, calibrations and adjustments.
Examine the relay and relay tag. The relays should be changed every two years and sent back to System Relay Services for testing and calibration.
Perform the Variac tests. The Variac tests apply voltage to the relays in order to determine if they are functioning correctly.
Rack in (slide) the protector and reinstall mounting bolts, links, and fuses (in that order).
Check transformer and network voltages with protector open.
Record the operation counter number and remount the door.
Add 3 lbs of Nitrogen and monitor for 30 minutes. Leave at 1.5 lbs. Record results on the inspection form.

Maintenance information is captured and recorded on a Network Transformer Inspection form, which is used to record information from both the network transformer and network protector inspection and maintenance. (See Attachment J) for a copy of the Network Transformer Inspection form.

Ameren Missouri has a remote monitoring system in place that provides network protector status. Ameren Missouri does not perform routine operational tests (drop tests).

Ameren Missouri Service Test department resources noted that they believe their system to be well maintained and that they do not have problems with false protector trips or protectors hanging up.

Technology

Ameren Missouri has about 265 network protectors on their system. Their current standard is for the network protector to be throat mounted to the transformer secondary. Standard network protector sizes are 1875, 2000, 2250, 2825, and 3000 amp units.

Ameren Missouri uses protectors from both Eaton and Richards. At the time of the practices immersion, Ameren Missouri was in the process of moving to the CM52 network protector. This decision was based on an analysis performed by Ameren Missouri, and driven by certain attributes of the CM52, including the dead front design, modular replacement, and remote racking capability, which enables them to rack the breaker of the bus with the NP door closed.

Ameren Missouri uses the ETI electronic relay as part of its remote monitoring system. Using this system, they are monitoring various points including voltage by phase, amps by phase, protector status, transformer oil top temp and water level in the vault. The monitoring points are aggregated at a box mounted on the vault wall that communicates via wireless.

From the remote monitoring system, the Service Test supervisor, as well as a predetermined group of other recipients, receives a computer system generated Email that indicates when a network protector has opened. So, when a feeder locks out for example, the supervisor would immediately be notified by the system through an email indicating that the protectors on the feeder have opened. In addition, the department supervisor receives a report each morning that indicates which feeders were out the night before.

Figure 1: Network Protector

Figure 2: Network Protector site glass

5.7.3 - CEI - The Illuminating Company

Maintenance

Network Protector Maintenance

(Relay Maintenance)

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who inspect and maintain the underground system. Underground electricians perform the network protector inspections, including the network relay maintenance.

Process

Network protector maintenance is scheduled for a 6 year cycle. The inspection includes an external and internal inspection, as well as contact resistance tests, Megger tests, and relay calibration and functional tests using a test kit.

CEI will de-energize the primary feeder when working on the network protector. The Underground Electrician will also open the disconnect switch on the transformer primary before performing Network protector maintenance in a given vault.

CEI acknowledged that in practice, because the network is lightly loaded, they will sometimes subordinate performing this inspection in a certain year to performing network protector trip testing, and maintenance of manholes with older facilities more likely to fail.

Technology

Network protector inspection data is recorded manually on the vault inspection form, See Attachment - N , and on the Network Protector Inspection Form, (See Attachment O. Information about network protectors is kept in a manual file within the Underground Network Services department. . Information about network protectors is kept in a manual file within the Underground Network Services department.

Electricians perform relay calibration and functional tests (trip / close settings) by applying a network protector test kit to the protector.

5.7.4 - CenterPoint Energy

Maintenance

Network Protector Maintenance

People

Network Protector Maintenance is performed by Network Testers of the Relay group within Major Underground. The Major Underground organization includes Key Accounts, Engineering and Design resources, Support Services, and the field force responsible for all construction, operations and maintenance activities. The field force is divided into two main groups, the Relay group and the Cable group.

Both the Relay group and Cable group perform maintenance and inspection activities. The Relay group focuses on most of the non cable equipment inspection and maintenance, including performing vault equipment inspections, network protector testing, and other inspections and maintenance on devices with relays or motor operators. The Cable group focuses on inspections of cable, cable accessories and major equipment.

The Relay group is comprised of Network Testers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. The Relay group is led by an Operations Manager.

CenterPoint does not have dedicated maintenance crews. Rather, maintenance and inspection work is assigned to crews based on work priorities and resource availability.

Process

Network protector maintenance is performed on a 5 year cycle. The maintenance includes an external and internal inspection of network protectors, as well as contact resistance tests, relay calibration and functional tests using a test kit. In addition, as part of this testing, Network Testers will perform cable limiter continuity tests of the cable limiters that supply the street grid.

CenterPoint does not de-energize the primary feeder when working on the network protector. Also, they do not remove the network protector fuses which are located external to the Network Protector cabinet on the CMD type protector used at CenterPoint.

When racking out a network protector breaker, Network Testers wear personal protective equipment. At 480V, this includes FR clothing, hard hat, safety glasses, a face shield, a Kevlar jacket, and appropriate rubber goods protection, such as 600V gloves.

CenterPoint does not perform network protector drop tests. This is in part because CenterPoint serves radial customers from network feeders; consequently, de-energizing feeders for the purpose of testing the protectors would result in customer outages. Also, CenterPoint has remote monitoring of network protector status.

Technology

About ten years ago, CenterPoint embarked on a network rehabilitation effort that included replacing all of their network protectors with new units. They chose to replace their older units with CMD style network protectors. They believe that the dead-front, draw-out, spring-closed breaker mechanism and the externally mounted fuses make this is a safer design than some other network protector styles. They noted that the CMD units are larger than some other styles.

All CenterPoint network protectors are equipped with communication enabled relays. (MPCV relays). This technology enables them to remotely monitor current, voltage and status, as well as remotely operate the units. However, CenterPoint has not yet implemented the remote control (operation) of these devices, because to do so, would require them to re-examine and revise their clearance procedures to assure continued safe system operation.

CenterPoint is using an inspection checklist to guide inspectors through the various items included in the Network Protector Test. Network Protector inspection data is recorded manually on this same checklist, entitled MUDG Functional Location Inspection Sheet (See Attachment I ). An inspection sheet is completed for every location inspected. ). An inspection sheet is completed for every location inspected.

Network Testers perform relay calibration and functional tests (trip / close settings) by applying a network protector test kit to the protector.

5.7.5 - Con Edison - Consolidated Edison

Maintenance

Network Protector Maintenance

People

I&A Mechanics within the Construction Group maintain network equipment, including transformers and network protectors.

Construction Group

Con Edison’s service territory consists of four regions: Manhattan, Brooklyn/Queens, Staten Island, and Bronx/Westchester. The Manhattan Region is made up of three districts, including one headquartered at the W 28th St. Work Out Center. The term Work Out Center refers to a main office facility to which field construction and maintenance resources report. To provide a perspective on the size of a workout center, about 300 people work at the W 28th Street Work Out Center, and they can field about 125 crews.

The construction department consists of several groups:

Underground group
- The underground group is made up of splicers, who splice cable of all voltages.
I&A group (includes a services group)
- The I&A group installs and maintains network equipment, including transformers and network protectors. Within I&A in Manhattan, there is a services group dedicated to connecting customers to the distribution network. In other locations, the services group sits in a different part of the organization. This group does the splicing on the secondary system and deals with customer connection issues.
Subsurface construction (SSC) group
- The SSC deals with vaults, conduit ducts, and other civil work. Much of this work is contracted.
Cable group
- The cable group pulls in new cable and retires cable.

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including performing infrared inspections of network protectors. See Manhole Inspection and Maintenance - Field Engineering Group

Process

Network Protector Inspection

Network Protectors are inspected on various cycles depending on the inspection classification, as part of the CINDE Visual Inspection and Test Box Inspections.

Inspection and Maintenance

Con Edison performs periodic maintenance and inspection of network distribution equipment, including network feeders, transformers, network protectors, grounding transformers, shut and series reactors, step-down transformers, sump pumps and oil minder systems, remote monitoring system (RMS) equipment, and vaults, gratings, and related structures.

Con Edison’s approach to performing an inspection is to inspect all the equipment and structures associated with a particular vault ID at a location regardless of category or classification, and even if the particular equipment associated with a particular vault ID resides within different compartments (for example, a transformer and network protector may be located in separate physical compartments even though they both share the same vault ID). This type of inspection is referred to as a CINDE Inspection, based on the name of their maintenance management system (Computerized Inspection of Network Distribution Equipment).

Con Edison performs inspections energized; crews do not take a feeder outage to perform inspections, perform pressure drop testing, or take transformer oil samples. Con Edison does not routinely exercise feeder breakers.

In an effort to more efficiently use their resources, and when nonpriority conditions allow, Con Edison takes advantage of situations where they have to enter a vault or manhole for a reason other than a scheduled inspection, and perform a nonscheduled inspection while they are in the vault. When the record of this nonscheduled inspection is recorded in CINDE, the system “resets the clock” for the next inspection date.

Network equipment at 208 V is generally inspected on a 5-year cycle. 460-V facilities, sensitive customers, facilities in flood areas, and other more critical locations are inspected more frequently, often annually. Con Edison establishes network equipment inspection cycles depending on two factors: the inspection category and the inspection classification .

The inspection category refers to the type of inspection, and includes a Visual Inspection, a 120/208-V Test Box Inspection, and a 460-V Test Box Inspection. The Visual Inspection includes activities beyond visually assessing condition and recording information, such as pressure drop testing and taking transformer oil samples.

The test Box inspections involve specialized testing of network protectors with the network relay installed. Note that all of the elements of a Visual Inspection are performed along with the Test Box Inspections.

Routine test box inspection of 208 V with RMS — not performed cyclically, inspection driven by other factors.
Routine test box inspection of 208 V without RMS — 6 year cycle.
Routine test box inspection of 460 V with RMS — 4.5 year cycle.
Routine test box inspection of 460 V without RMS — 18 months.
Non-routine inspections performed more frequently depending on vault classification based on vault location, nature of customer, and equipment type, age, and condition. Non-routine inspection locations are predefined.

Note that Con Edison does not perform routine network protector drop tests.

The inspection classification refers to characteristics of the inspection site that dictate the inspection cycle. For example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a “tidal” area would be visually inspected annually. Con Edison considers the following classifications in determining inspection cycles:

Routine
Back-feed: banks installed on a feeder involved in a back-feed incident
Candidate for Replacement: commonly due to corrosion damage
Essential Services: critical customers
Flooded Bank: nonsubmersible equipment that has experienced high water levels
208-V Isolated Bank: units that require more frequent inspection than distributed secondary grid units
Remote Monitoring System(RMS), Non RMS, Unit Not Reporting (UNR): Con Edison varies inspection cycles based on the level of remote monitoring installed
Tidal, Water, and Storm Locations

Note that Con Edison requires employees to perform at least a quick visual inspection (QVI) anytime an individual enters a network enclosure, even if the reason for entering an enclosure does not warrant a CINDE Inspection. This type of inspection (QVI) differs from the CINDE inspection category of Visual Inspection described above, in that it is not a full, accredited inspection.

Technology

Inspection and Maintenance Software

Con Edison uses legacy maintenance management software called CINDE, which is an acronym for Computerized Inspection of Network Distribution Equipment. CINDE is a system that records inspection data and initiates inspections based on predetermined cycles. These cycles depend on the category of inspection (for example, a visual inspection versus a “Test Box” inspection) and various predetermined classifications of inspections (for example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a tidal area is visually inspected annually).

Con Edison inspectors record inspection data on hand-held devices (Tough Books). The utility requires that the inspection data be downloaded into the CINDE – Mainsaver system (Mainsaver is the part of the CINDE system used to record data) within three days following the inspection. Inspection data that is entered into the CINDE system includes:

Equipment serial numbers
As-found and abnormal conditions, such as transformer oil level, state of corrosion, and water in the vault
Defective equipment or structures
Repairs or change-outs undertaken
As-left condition, such as transformer pressure and liquid level, and pressure of housing

The CINDE – Mainsaver system is also used by Con Edison to prioritize follow-up work, or outstanding defects to be corrected that are identified through inspection or other visits to network enclosures. The Electric Operations Region is responsible for prioritizing follow-up work by considering the location of the work with respect to risk to public safety, reliability impact, the type of installation, age of the outstanding defect, and the efficient use of resources.

Trucks

Con Edison provides its employees with the specialized tools and equipment that they need to do their jobs, including trucks outfitted for the different types of work that they perform. Employees stated that they believed Con Edison provides them with good quality trucks, appointed with the equipment they need to perform their work. People demonstrated a sense of pride in their trucks and associated equipment.

Con Edison’s network resources use specially equipped box trucks. Each department truck is outfitted to meet the needs of that group, including multiple storage bins for housing the onboard equipment. For example, I&A mechanics use a box truck equipped with the specialized equipment they need to perform their job duties, such as network protector test kit, outriggers, and a hydraulic boom with a winch for lifting equipment.

5.7.6 - Duke Energy Florida

Maintenance

Network Protector Maintenance

People

Maintenance of network protectors are performed by craft workers, Network Specialists and Electrician Apprentices, within the Network Group, part of the Construction and Maintenance Organization. The Network Group is led by a supervisor, and consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position).

Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager.

The Network Group is organized functionally, and has responsibility for construction, maintaining and operating all urban underground infrastructure (ducted manhole systems), both network and non-network, in both Clearwater and St. Petersburg. Resources are assigned to either Clearwater or St. Petersburg based on work needs. Being a small group of resources, Duke Energy Florida rotates work assignments to assure that Network Specials are “jacks of all trades”. However, even with this rotation, the work of network protector maintenance is typically done by Clearwater resources, in part because of their maintenance approach as described below, and in part because the test kit itself is located in Clearwater. Duke Energy Florida has recognized the need to provide St. Petersburg employees with on the job training to assure that protector maintenance expertise is incorporated throughout the team.

Process

Duke Energy Florida has a unique approach to maintaining network protectors. Rather than maintaining the protectors in the field, they replace the network protector with a new or refurbished unit. The removed protector is taken into the shop and is tested, maintained and refurbished if necessary in the repair shop. The maintained unit would then be used to replace another network protector. The work done “on the bench” is the same as the kind of maintenance that is performed by many companies in the field (see Figures 1 and 2). Units are taken apart and inspected for obvious damage and wear, they assure that the protector opens and closes properly both electrically and mechanically, the unit is cleaned, the relay settings are checked, and the unit is Megger tested.

Figure 1: CM22 Network Protector, maintained and ready for replacement

Figure 2: CM22 on the bench to be maintained

Duke Energy Florida keeps just a few spare units in stock.

In Clearwater, Duke Energy Florida replaces all network protectors every two years, during load check (vault) inspections, prior to the summer peak demand period. It takes approximately one month to perform all the network protector replacements in Clearwater. Part of the rationale for the two-year replacement cycle is the significant number of network protector operations they experience, as they supply their network feeders from different substation busses and have historically comingled network and non - network loads on portions of their distribution system, leading to issues such as protector cycling and pumping. The only exception to the two-year replacement cycle would be units with an unusually high number of operations.

When Duke Energy Florida performs the network protector replacements, they do not de – energize the transformer. They remove the blocks on the bottom side of the protector, between the protector and the transformer secondary, and they remove the network protector fuses, isolating the protector from both secondary sources.

In St. Petersburg, Duke Energy Florida does not replace network protectors on a two-year cycle, as they do in Clearwater. Rather, at their spot network locations, they inspect the network protectors (17 in total) annually during vault inspections, including load checks, and make maintenance decisions based on inspection findings. They recently completed a detailed inspection of all the network protectors on St. Petersburg and replaced units found to be in need.

At the Clearwater supply and maintenance facility, Network Specialists test, maintain and rehabilitate network protectors and NP relays. They also acceptance test new protectors as they arrive from the manufacturers. Duke Energy Florida underground experts feel this acceptance testing of new equipment is critical and noted that they had two new network protectors fail their acceptance testing in recent years.

Duke Energy Florida is in the process of replacing the electromechanical protector relays with microprocessor based protector relays. Once all protectors have been upgraded, they plan to implement a new maintenance program. The group is looking at peer practices, industry best practices, and internal processes to create the new network protector maintenance program.

Duke Energy Florida does not perform drop tests. They do have a remote monitoring system implemented which remotely communicates protector status.

During vault inspections, Duke Energy Florida performs load checks.

Technology

The CM 22 is the standard protector at 125/216 (typically, a 1600A unit).

The CM 52 is their standard at 277/480.

Duke Energy Florida is in the process of replacing the electromechanical protector relays with microprocessor based protector relays.

Duke Energy Florida has a network protector kit at their test shop in their Clearwater supply and maintenance facility. All protector testing, maintenance and rehab is performed at this facility. They do plan to procure an additional test kit for the St. Petersburg office.

5.7.7 - Duke Energy Ohio

Maintenance

Network Protector Maintenance

People

Duke Energy performs weekly network protector drop tests to assure the protectors are operating properly.

The drop tests are performed every week, on a Tuesday, Wednesday and Thursday evening, by Mobile Operators working night shift.

The Mobile Operator position at Duke is one whose role includes operating devices in a substation. For example, this position will perform feeder clearances at night, including performing switching, isolation, and tagging in the substation, in advance of work to be done the next day. Mobile Operators also coordinate with crews doing switching out on overhead and underground circuits.

Performing network protector drop tests each week is part of the Mobile Operators’ normal routine, and a long standing practice at Duke, Cincinnati.

Process

Duke Energy performs weekly network protector drop tests on all network protectors to assure they are operating properly (See Attachment H for a description of the test procedure and schedule). Duke has 28 total network feeders and 400 network protectors.

The mobile operator will open the breaker on a primary feeder supplying the network. Duke is using voltage potential indicator lights to monitor any back feed on the system that could be caused by a network protector not opening properly. The test exercises the network protector breakers, and helps to identify any network protectors that are hung up.

Figure 1: Network circuit panel

If they find a potential indicator light lit, they notify the Supervisor – Construction and Maintenance in the Network group who would mobilize crews to respond.

Note that weekly tests will be cancelled by the Control Center if Duke is already operating in a first contingency situation (another network feeder is already out of service). Duke does not perform the tests on holidays.

Note that Duke is not performing formal periodic network protector testing and maintenance beyond the weekly drop tests. They will utilize a network protector test set when changing network protector relays, but do not apply the test set as part of a formal maintenance program.

Technology

As Duke Energy applies remote monitoring to network protectors so that they can remotely know the status of every protector, they acknowledge that they may have to revisit their weekly test approach. However, they believe in the value of regularly exercising the breaker, and their field crews feel safer that there is some routine validation that the network protectors open and close properly.

5.7.8 - Georgia Power

Maintenance

Network Protector Maintenance

People

The Georgia Power Network Underground group has two full-time Test Technicians responsible for Network Protector Testing and Maintenance who report to the Network UG Reliability Manager of the Network Operations and Reliability Group. The Network Operations and Reliability group is also responsible for remotely monitoring and operation the network system.

The Operations and Reliability Group is part of the Network Underground group at Georgia Power, a centralized organization responsible for all design, construction, maintenance and operation of the network infrastructure for the company. The Network Operations and Reliability Group works closely with the Network Standards Group to determine the best means of implementing network protectors for remote monitoring and maintenance on the network underground system, statewide.

The Test Technicians, recruited from the ranks of Senior Cable Splicers, are responsible for the five-year inspection and maintenance cycle for the network protector fleet, about 2000 units, and maintain between 300-400 protectors a year, on average. Test Technicians receive on the job training (OJT) from more senior technicians, and may take evening classes and/or network protector vendor training classes before becoming Test Technicians. Georgia Power recruits the Test Technicians by identifying Senior Cable Splicers who are interested in the work, and may assign on the job training where the cable splicer is partnered with a Test technician in the field, or may fill a spot when a Test Technician is on vacation. The Test Technician is a non-bargaining, non-exempt position.

All Test Technicians are responsible for identifying, troubleshooting and resolving problems with network protectors. Within the group of Test Technicians, some people may gravitate to setting up and maintaining the wireless and fiber optic network connections to the Georgia Power SCADA system from the network protector, while others may work more closely on the electronics of the network protectors themselves. Georgia Power does a good job of fitting the right people with the proper skill-sets to particular jobs. The organization does its best to pass down positions to personnel based on interest, skills, and OJT experiences.

Process

Test Technicians work in two person teams to perform NP maintenance. They perform a visual inspection of the network protector, the condition of its external fuse, and the area surrounding the network unit (see Figure 1 through Figure 3). The Test Technicians properly de-energizes the protector, and then attaches a test kit to the network protector to calibrate and test the units, typically a two-hour procedure. It is the standard for Georgia Power to mount network protectors on the transformer tank (though Georgia Power does have a few old wall mounted units still in service).

As a part of its SCADA modernization program, the crew will replace any network protector electromechanical relaying with solid state components. The group also upgrades any network protector that does not have external fuses by adding external current limiting fuses, mounted on top of the protector, outside the case.

Figure 1: Test Technician performing network protector maintenance

Figure 2 and 3: Test technician using test kit located in specialized van above the vault

One notable practice is a change in the procedure for racking out a network protector as a function of the arc flash rule changes. The Standards group has implemented steps that reduce the potential arc energy that workers could be exposed to during network protector maintenance. In the past, crews would go out to work with the protector energized, and then open the protector. In this situation, when a crew removed the protector fuses, there would still be energized conductors above on the secondary side and an unprotected zone between the transformer secondary and the bottom of the protector.

In the new maintenance procedure for performing protector maintenance, the Test Technician crew will take the primary feeder out of service, thus de-energizing the transformer supplying the protector. In addition, on the unit on which they are performing maintenance, they will open the network transformer primary switch so that the transformer cannot contribute fault current if a fault occurs inside the protector. For this reason, the crew will typically schedule protector maintenance when the primary feeder may be out of service for other maintenance. If the primary feeder must be put back in service, they’ll still have the transformer switch open, and the protector isolated from the primary. Thus the protector is energized only from the secondary bus, through current-limiting fuses.

Georgia power has developed a guideline that a field crew can use to estimate the incident arc energy that is available in the vault to assure that they are using appropriate personal protective equipment and procedures. The guideline includes a table that provides the incident arc flash energy based in the vault type, number of energized transformers, size of the transformers, and presence of current limiting fusing.

(See Attachment G for the guideline for arc flash exposure in a 480V spot network vault).

The Standards Group has done calculations that show in most of the GPC vaults, even at 480 V, a worker can be protected by a level 2 fire retardant (FR) clothing system by disconnecting the protector from the secondary bus work, and separating the protector from the transformer as previously described.

Test Technician and Cable Splicer crewmembers are expected to refer to the Georgia Power Network Protector Arc Flash Guideline Table before any network protector maintenance.

In 480V network protector locations, Georgia Power places external current limiting fuses on the cables leaving the protector and supplying the secondary collector bus. These fuses are effective in limiting the current during a fault. However, these fuses have a current range, so there must be enough of a fault current for the fuses to operate. Where vaults have less fault current available, then the current limiting fuse might not be effective. Therefore, the largest vaults, with the greatest potential arc energy do not pose the greatest risk to workers, because in those vaults the current limiting fuse would act very quickly, in less than half a cycle, and extinguish the arc with the worker(s) not exposed to any long-duration event. In the smaller vaults, with one or two smaller transformers and where the available arc energy is too low for the current limiting fuse to work effectively, workers might be required to don a flash suit or use other incremental fire or arc-flash protection.

When they are putting a network protector back in service, Georgia Power does not perform any sort of a “fuse test” in the protector, such as placing a low amperage fuse in the protector so that if there is a problem, the fuse will open. They don’t like the idea of exposing a worker to that condition. Their process is to close the network protector remotely - if there is a problem on the system, the worker would be out of the hole. Note that they are examining other options for safely closing protectors such as a device (by EDM) that uses timing to check for proper phasing.

Technology

Georgia Power uses both Richards and Eaton network protectors. Engineers have standardized on submersible protectors with a dual 208 V or 480 V rating. They deploy mainly Eaton CM 22 and Richards 313 and 314s. Engineering has bought and installed a few CM 52s for trial, but are concerned with stored energy in the unit spring. Once that issue is resolved, Georgia Power may move to this model or some other model.

Some older protectors have internal fuses, but Georgia Power is moving to protectors with outside fuse boxes mounted on the top of the protectors (See Figure 4 and Figure 5.).

Figure 4: New network protectors. Note outside fuse boxes on top of the protectors

Figure 5: Current limiting fuse used on protector cables

All network protectors are connected to the Network Operations center by a SCADA system, ESCA (Alstom). This is the same SCADA system used for substation control and their distribution automation system (See Figure 6 and Figure 7.). The system communicates by DSL, radio frequency, or a fiber network connection to the network operations center where protectors are monitored by the Network Operations staff. Remote monitoring has been in place at Georgia Power for 15 years.

Figure 6: View of inside of SCADA control box mounted on vault wall

Figure 7: Information displayed in network control room SCADA

The Network Operations center typically monitors the following information from the network protectors:

Current
Voltage
Protector Open or Closed
Fluid in the vault
Fluid in the protector

5.7.9 - HECO - The Hawaiian Electric Company

Maintenance

Network Protector Maintenance

People

Note that the Underground group does not install or maintain network equipment such as network transformers or network protectors. Network equipment construction and maintenance is the responsibility of the Substation group at HECO. The Substation group is part of the Technical Services Division of the System Operations Department.

Process

Network system preventive maintenance and inspection programs include:


Program	Cycle or other Trigger
Manhole Inspection, including amp readings of molimiters.	Annual
Network Vault Inspection	2-3 years – inspected during transformer and NP maintenance
Network Transformer Maintenance (Includes Oil Sampling and Pressure Testing)	2 -3 years
Network Protector Maintenance	2-3 years

Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

5.7.10 - National Grid

Maintenance

Network Protector Maintenance

People

Network protector inspection and maintenance in Albany is performed by the UG field resources (network crews) who are part of Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground Lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics, and is led by three supervisors. Maintenance Mechanics perform inspection and maintenance of network equipment such as transformers and network protectors.

In addition, National Grid has a company-wide Inspections Department, led by a manager, responsible for completing regulatory required inspection programs. This group consists of supervisors assigned to regions, and a union workforce to perform routine inspections. Note, however, that network protector inspections and maintenance in Albany are performed by Underground Lines East maintenance mechanics

Process

National Grid performs network protector Visual and Operational (V&O) inspections annually as part of an annual network vault inspection. National Grid has a well documented procedure that describes the annual V&O inspection (See Attachment A ). Inspections include a visual inspection of the protector condition and performing activities such as monitoring loading and the number of counts on the protectors, checking the cabinet and protector bushing for temperature issues using an infrared thermometer, verifying operating handle position, inspecting the cabinet for moisture and water, door gasket deterioration, and paint and rusting issues, and monitoring secondary current on all 3 phases with a clamp-on ammeter.

National Grid has developed an Electrical Operating Procedure (EOP) which provides guidelines for prioritizing issues identified during inspection for repair. Various turnaround times for repair are specified depending on the categorization.

Level 1: Emergency - must be made safe within seven days.

Level 2: One year

Level 3: Three year

Level 4: Information purposes only

These levels were developed by asset and engineering groups based on past history and basic knowledge. Except for emergencies, inspections are not repaired immediately but are reported so that the inspection process can stay in task. Inspection information is entered directly into a mobile device using Computapole software, and a work order can be generated by the interface between Computapole and National Grid’s STORMS work management software (See Technology, below).

National Grid performs network protector diagnostic tests on a five-year cycle. The only exception to this is in vaults with CMD style protectors

a diagnostic test is performed on these network protectors on a two-year cycle. National Grid has a well-documented procedure that describes the activities associated with the diagnostic inspection. For these inspections, the protector is racked out and the racking mechanism lubricated. Fuses are checked for signs of overheating or damage. Other parts and contacts are also checked for signs of pitting, corrosion, heat, carbon deposits, cracking, or other damage. The operating mechanism is checked and lubricated. Insulation resistance is checked with a Mega-ohm meter. Operational tests are performed with the network test set according to test set directions.

Maintenance crews carry a bottle of pressurized nitrogen and a regulator to test the protector compartment. The compartment is pressurized to 3 PSI, and it should not drop more than 2 PSI in 24 hours.

National Grid Albany performs network protector maintenance and diagnostic testing on the 120/208V system with the primary feeder energized. At 277/480V spot locations, National Grid (in NYE, a local practice) performs network protector maintenance with the primary feeder de-energized. Note that National Grid procedures do not require the primary feeder to be de-energized to perform network protector maintenance. However, NY east, as a local practice, does de-energize the network transformer (and therefore the exposed bus work in the protector case) when doing maintenance on 277/480V protectors. A clearance is issued from the Regional Operator with the limits being the primary switch on the transformer and the protector fuse openings.

National Grid performs a routine operational test (drop test) annually. They de-energize each network feeder and use potential lights at the station to identify any back feed from hung up protectors.

For a checklists associated with the V&O inspection and maintenance of network protectors, (See Attachment B).

Technology

Crews use handheld devices (PDAs) to record inspection information. This unit has the required inspection information built into it as well as a mapping feature. It also contains the most up-to-date system data and previous inspection results. Appropriate codes for the inspection are entered directly into the unit and returned to the supervisor for entry into the computer database. These codes alert GIS of changes in the field.

Computapole is a mobile utilities software platform that runs on handheld devices and is customized to meet National Grid’s specific needs. Computapole is used for inspections and mapping functions on handheld PDAs. Once information is entered in the Computapole system, work is managed by an interface with STORMS (below) to create work requests.

Severn Trent Operational Resource Management System (STORMS) is National Grid’s work management system. The work management system includes tools to initiate, design, estimate, assign, schedule, report time/vehicle use, and close distribution work. Computapole sends inspection information to STORMS to create work requests as needed.

Test equipment includes a network protector test set, a Mega-ohm meter, and a fused jumper lead with Busman CC KTK-R-2 200KA interrupting fuse used to test for grounds before replacing NP fuses.

Figure 1: NP Test Set

Figure 2: NP Relay

Figure 3 and 4: NP Maintenance

5.7.11 - PG&E

Maintenance

Network Protector Maintenance

People

The Maintenance & Construction crews operating in San Francisco and Oakland are responsible for performing network protector (NP) maintenance. These crews are made up of Cable Splicers who perform the actual NP maintenance.

In the San Francisco network, this work is performed on the night shift by the Night Cable Splicers. In Oakland, day shift Cable Splicers perform the protector maintenance.

Process

PG&E performs network protector testing on a three year cycle. They adopted the 3-year cycle after performing an extensive study that included:

Industry benchmarking (EPRI, AEIC)
Evaluations and analysis undertaken by 3^rd party consultants
Manufacturers recommended guidelines

The 3-year cycle replaced a former 1 year cycle program that was deemed overly conservative from their analysis.

In addition, any network protectors that show unusual operations, are particularly critical, or have exceeded 200 operations before the 3-year cycle is completed, are inspected, and maintained out of cycle, as conditions warrant.

PG&E performs network protector maintenance with the primary feeder de-energized.

The program calls for

Cleaning and internal inspection of Network Protector
Relay testing & setting (with test kit)
External inspection of Network Protector, including pressure testing.

Maintenance information is captured and recorded on a maintenance form. See Attachment I for a copy of the Network Protector Maintenance checklist .

If, during maintenance, the crew identifies a corrective maintenance issue with the network protector that cannot be immediately repaired, a follow up notification tag (called an EC notification) is created and a priority is assigned to the corrective maintenance by the crew.

PG&E does not perform routine operational tests (drop tests) to assure the protectors are operating properly. However, they de-energize each network feeder at least once per year for their transformer maintenance, providing them an opportunity to assess protector operation.

Maintenance information is captured and recorded on a maintenance form.

For a detailed list of the work procedures related to the installation, maintenance and repair of Network Protectors see Attachment J.

Technology

PG&E uses a variety of NP types from both Richards Mfg and Eaton, including CM52, GE Style, Westinghouse Style and CMD protectors. .

PG&E has remote monitoring at all of their network protectors. This monitoring provides voltage, current and status indication. They are currently in the process of implementing more advanced remote monitoring and control, using the Eaton MPCV relays.

Figure 1: CT’s on top of NP

Argon Research – Network Protectors

PG&E, in collaboration with EPRI, is researching the use of Argon gas instead of Nitrogen inside network protector cases. Argon provides some positive attributes such as;

Non-reactive – may help to extend life of internal components
Good thermal stability – Used for manufacturing and welding applications.
Inexpensive – 3rd most common element in the atmosphere.
Doesn’t mix well with other gases – heavy – provides for method of easily evacuating gases from Network Protectors.

The research and testing is on-going effort, and to-date has shown some very positive results. PG&E hopes to publish the results of its research in the coming year.

5.7.12 - Portland General Electric

Maintenance

Network Protector Maintenance

People

On the network, inspecting and maintaining network protectors is largely the responsibility of the Special Tester. The Special Tester is a journeyman lineman with additional training and technical skills, including specific training of network protectors. PGE has embedded one Special Tester within the CORE group. This individual has received specialized training in network protectors from the manufacturer, Eaton, and serves as the CORE group expert on network protectors.

The Special Tester usually partners with cable splicers, working as part of a crew. The “special testing crew” includes the Special Tester, a crew foreman (a cable splicer), a lineman/cable splicer, and a topman, a non-journeyman helper. For NP testing, the topman sits in the truck with the equipment controls and watches the manhole/vault entrance for potential hazards.

In addition to NP testing and settings, the Special Tester focuses on power quality issues, including customer complaints about voltage.

Network Protector Crew: The CORE group has recently created a dedicated crew that deals with network protectors, as well as performs other construction work. This crew is comprised of cable splicers who receive formal training and attend conferences to gain experience with network protectors. This crew includes a foreman (a working journeyman), a journeyman (who rotates every three months to assure a breadth of expertise in the department), and a Special Tester. A non-journeyman helper may supplement the crew as required.

Reliability Technicians: Reliability Technicians perform infrared (IR) thermography inspections on primary systems and network protectors as part of the Quality and Reliability Program (QRP), a reliability improvement program targeted at key infrastructure. PGE has three IR specialists, who mainly focus on the transmission system but also work on high priority distribution systems. Organizationally, the Reliability Technicians belong to the same group as the Special Testers and report to the Testing Supervisor.

Process

PGE has approximately 230 network protectors on the system, with half included in the 480 V spot networks, and half in the 120/208 V area grid systems.

Network protectors are maintained annually for 480 V protectors at spot network locations, and every two years for the 216 V protectors supplying the area networks. As part of the network protector testing, crews also undertake a general vault inspection, including an inspection of other equipment in the vault and civil condition. This includes inspection of the network transformer, checking and recording transformer information (oil sampling and testing is performed as part of a separate program), and performing a general IR inspection of the vault.

NP Test Crew Procedure: When testing network protectors, three crew members work in the vault: the Special Tester, the crew foreman, and a journeyman. The helper usually operates the test kit, located in the truck outside the vault.

PGE performs network protector testing with the primary feeder energized. The basic steps include the following:

Set the protector to the open position
Vent the network protector (because it is filled with nitrogen)
Open the door of the protector
Rack the breaker out
Apply the test kit. The crew follows a test protocol passed down from others, with very little written down.

The test procedure verifies that the NP operates as expected under various conditions, including tripping on back feed, and closing based on a predetermined voltage differential between the network side and the transformer side. If the NP does not perform as expected, the crew checks that the relay settings are correct and troubleshoots the various components.

Crews re-pressurize the units once they are closed with nitrogen at 2-3 psi (14 to 21 kPa) to ensure no leaks around the enclosure.

PGE does not perform periodic drop testing, which involves opening the feeder to verify that all the network protectors will open. However, it periodically takes a circuit out for transformer maintenance and utilizes the remote monitoring system to verify that protectors are opening as expected.

In particular, with vaults that have very tight spacing between conductors or other characteristics that could create hazards, PGE requests a shutdown order and takes the feeder out of service before entering the vault.

Monitoring Network Protectors: PGE has installed a remote monitoring system in its network. This system utilizes information provided by the Eaton MCPV relay in the protector. All field workers have access to this system.

The remote monitoring system is a separate system from the energy management system (EMS) used by dispatchers. This monitoring system is known internally as the “blue wire” system[1] and resides on the “Pi” system (OSIsoft). PGE developed Pi front-end screens.

Network protector monitoring includes the voltage, all three-phase currents on the transformer and bus side of the unit, the power factor, the temperature, and the position of the contact breaker (open or closed). Part of the feeder clearance process involves checking the monitored values. If after opening a feeder breaker, the remote monitoring system indicates that one of the protectors is still closed, a crew goes out to the vault to troubleshoot.

The monitoring system is only used for monitoring, not remote control. The monitoring system is reliable, though PGE has experienced some communications issues with the Pi system.

Network Protector IR Program: The Special Tester is performing a targeted IR inspection of the network protectors as part of the QRP, a target reliability program aimed at key infrastructure.

Network Protector Quality Assurance: Crews bring new protectors to the warehouse where they are tested based on initial settings. This is an initial quality assurance check to ensure no issues when the unit is installed. In addition, the Special Tester also checks the equipment before it enters service.

Technology

All in-service PGE network protectors are either CMD or CM52 units from Eaton. These are both dead front units. The current standard is the CM52, used in both 125/216 and 277/480 volt Y connected secondary network systems at PGE [1].

The CM52 includes an air circuit breaker with an operation mechanism, network relays, and control equipment. The network protector door includes a window that allows crews to see the internal hardware [2].

The PGE protector installation includes externally-mounted, silver-sand fuses to interrupt fault currents if the networker fails to trip.

PGE is not using remote racking technology or arc flash reduction technologies.

Remote Monitoring: PGE utilizes the Eaton Mint II system with a PowerNet server platform interface. The optic fiber to the Mint II monitors is set in an H&L Fiber Loop configuration. The H&L Instruments system converts the fiber communications to the protocol used on the NPs, and vice versa. PGE is considering the use of the Eaton VaultGard system to harden the system, using the looped fiber optic communications already installed throughout the downtown area. The reason for looking at VaultGard is that it is a web-based protocol with integrated software that allows a higher degree of control.

Most of the information is sent to an OSIsoft Pi system. Pi allows engineers to view the load flows at each network protector. The Pi system can collect large volumes of data from multiple sources and helps users view, analyze, and share information [3]. OSI Pi is a real-time data historian application that can record and store information data from a number of systems, as well as compress the data for easy storage in the database. PGE uses this system to operate the Blue Wire system used to monitor network protectors.

At present, PGE only uses the system for monitoring and not for control.

Network Protector Inspection and Maintenance: All critical network protector spares are either stored on the network truck or in easily accessible locations. A plan exists to replace the truck with a flat-bed version fitted with a gantry crane for lifting, and a bread truck for the other equipment and for testing.

Personal Protective Equipment: PGE requires workers to don a 40-calorie suit and facemask when opening 480 V protectors.

[4]Field crews call this “blue wire” because the twisted pair wires feeding into each protector are blue. Information from the protectors is converted to and communicated on PGEs looped fiber system.

Eaton. “CM52.” Eaton.com. http://www.eaton.com/Eaton/ProductsServices/Electrical/ProductsandServices/ElectricalDistribution/SpecialtyPowerDistributionSystems/SecondaryNetworkSolutions/CM52Protectors/CM52/index.htm (accessed November 28, 2017).
Instructions for the Eaton Type CM52 Network Protectors 800 to 4500 Amperes. Eaton, Moon Township, PA: 2010. http://www.eaton.com/ecm/groups/public/@pub/@electrical/documents/content/ib52-01-te.pdf (accessed November 28, 2017).
The PI System. OSIsoft, San Leandro, CA: 2015, https://www.osisoft.com, (accessed November 28, 2017).
Portland General Electric. “Quick Facts.”PortlandGeneral.com. https://www.portlandgeneral.com/our-company/pge-at-a-glance/quick-facts (accessed November 28, 2017).

5.7.13 - SCL - Seattle City Light

Maintenance

Network Protector Maintenance

People

Certain Cable Splicers are assigned to focus on network protector construction, operations, and maintenance, and thus become experts in these areas. These individuals are selected for this focus based on their interest level and mechanical aptitude. They retain their Cable Splicer position.

Process

Network protector maintenance is performed on a four-year cycle and is performed independently of the feeder maintenance. Network protector trip / close settings are tested using a network protector test kit.

Primary feeders remain energized during this maintenance. SCL maintains a network protector by simply opening the protector and removing the fuses. They leave the primary switch closed (energized), such that the source side of the protector remains energized. Note that they do not necessarily tag it, nor is a clearance required from the dispatcher in order to maintain a network protector. See Attachment J.

Operations Practices — Vault / Network Fires

SCL’s current design standard calls for fire protection heat sensors and temperature sensors in their vaults. The heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225°F. The temperature sensors send an alarm to the dispatcher at 40°C. (SCL utilizes temperature sensors in about 20% of their network transformer locations. They are actively adding locations, with a goal of 100% coverage.)

SCL does not have a written procedure for responding to a vault fire. Although their operators do have the authority to drop load in an emergency, they do not have a protocol to guide them as to whether or when they should drop load in response to a fire. Note that because of the “sub-network” design, with each secondary network completely separated from the other, a complete network outage due to a fire would be limited to the customers served by that one sub-network, with the other networks unaffected.

5.7.14 - Practices Comparison

Practices Comparison

Maintenance

Network Protector Maintenance

2015 Survey Results

5.7.15 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Excerpts from Chapter 9: Network Operations and Maintenance

Chapter Section 9.3.8: Test Procedures and Schedules

Chapter Section 9.3.9: Network Protector Inspection and Maintenance

5.7.16 - Survey Results

Survey Results

Maintenance

Network Protector Maintenance

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 25 : Please indicate if your company performs the following Maintenance activities on a routine basis and at what frequency.

Survey Questions taken from 2018 survey results - Asset Management survey

Question 8 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Survey Questions taken from 2015 survey results - Maintenance and Operations

Question 85 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Question 93 : When you perform network protector maintenance, please indicate which of the following you do. (check all that apply)

Question 98 : Does your network protector maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for backfeed voltage to assure that the network protectors function correctly (automatically open)?

Question 99 : Are you using cameras as part of your manhole inspections?

Question 113 : For 480 V network protectors, do you de-energize the network transformer before removing the network protector fuses?

Question 114 : For 208 V network protectors, do you de-energize the network transformer before removing the network protector fuses.

Survey Questions taken from 2012 survey results - Maintenance and Operations

Question 6.25 : Do you regularly perform Network protector maintenance and testing?

Question 6.26 : If yes, what is the frequency of testing?

Question 6.27 : When you perform Network Protector maintenance, please indicate which of the following you do.

Question 6.29 : Does your NP maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for back feed voltage to assure that the network protectors function correctly (automatically open)?

Question 7.13 : For 480 V network protectors, do you de-energize the primary before removing the network protector fuses?

Question 7.14 : For 208 V network protectors, do you de-energize the primary before removing the network protector fuses.

Survey Questions taken from 2009 survey results - Maintenance

Question 6.32 : Do you regularly perform Network protector maintenance and testing?

Question 6.33 : If yes, what is the frequency of testing?

Question 6.34 : When you perform Network Protector maintenance, please indicate which of the following you do.

Question 6.35 : Does your NP maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for back feed voltage to assure that the network protectors function correctly (automatically open)?

5.8 - Network Protector Operational Test

5.8.1 - AEP - Ohio

Maintenance

Network Protector Operation Test

Process

AEP Ohio performs annual trip (or drop) checks of each circuit to assure that protectors open as required. This test involves:

Check all single contingency spot networks as normal (so no customers are outaged by the execution of the test)
Open the circuit breaker
Confirm potential light out or use other means to confirm that the circuit is de-energized
Record the time opening interval (less than 10 seconds)
Close the circuit breaker
Check that all protectors are closed
Record counter readings

Results of trip checks are recorded on an on line form.

Technology

AEP does have a remote monitoring system installed and can ascertain protector status remotely.

5.8.2 - Ameren Missouri

Maintenance

Network Protector Operational Test

Process

Ameren Missouri does not perform network protector drop tests. See Network Protector Maintenance.

5.8.3 - CEI - The Illuminating Company

Maintenance

Network Protector Operational Test

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. Underground Electricians perform the network protector operational test, working with the Dispatcher to take the feeder out of service.

Process

Network protector operational tests are performed annually, to assure the protectors are operating properly.

A primary feeder supplying the networked is opened manually by a crew or switchman at the station. An underground crew would visit each vault that houses a network protector fed by that feeder to assure that the protector opened properly to prevent feedback from the meshed secondary network on to the primary. Note that CEI is not using neon indicators at the station or other monitoring to sense backflow on the primary due to a faulty protector.

When the feeder is re-energized, the crew would revisit each protector vault to assure that the protector has closed properly.

Technology

Information about network protectors is kept in a manual file within the Underground Network Services department.

5.8.4 - CenterPoint Energy

Maintenance

Network Protector Operational Test

Process

CenterPoint does not perform network protector drop tests. See Network Protector Maintenance.

5.8.5 - Con Edison - Consolidated Edison

Maintenance

Network Protector Operational Test

People

Installation and Apparatus (I & A) Group (includes a services group) The I&A group installs and maintains network equipment, including transformers and network protectors. Within I&A, in Manhattan, there is a services group dedicated to connecting customers to the distribution network. In other locations, the services group may sit in a different part of the organization. This group does the splicing on the secondary system and deals with customer connection issues.

Process

Con Edison does not perform routine network protector drop testing. See Network Protector Maintenance

Technology

I&A mechanics use a box truck equipped with the specialized equipment they need to perform their job duties, such as network protector test kit, outriggers, and a hydraulic boom with a winch for lifting equipment.

5.8.6 - Duke Energy Florida

Maintenance

Network Protector Operation Test

Process

Duke Energy Florida does not perform drop tests. They do have a remote monitoring system implemented which remotely communicates protector status.

5.8.7 - Duke Energy Ohio

Maintenance

Network Protector Operational Test

People

Duke Energy performs weekly network protector drop tests to assure the protectors are operating properly.

The drop tests are performed every week, on a Tuesday, Wednesday and Thursday evening, by Mobile Operators working night shift.

The Mobile Operator position at Duke is one whose role includes operating devices in a substation. For example, this position will perform feeder clearances at night, including performing switching, isolation, and tagging in the substation, in advance of work to be done the next day. Mobile Operators also coordinate with crews doing switching out on overhead and underground circuits.

Performing network protector drop tests each week is part of the Mobile Operators’ normal routine, and a long standing practice at Duke, Cincinnati.

Process

Duke Energy performs weekly network protector drop tests on all network protectors to assure they are operating properly (See Attachment H for a description of the test procedure and schedule). Duke has 28 total network feeders and 400 network protectors.

The mobile operator will open the breaker on a primary feeder supplying the network. Duke is using voltage potential indicator lights to monitor any back feed on the system that could be caused by a network protector not opening properly. The test exercises the network protector breakers, and helps to identify any network protectors that are hung up.

Figure 1: Network circuit panel - note circuit potential lights

If they find a potential indicator light lit, they notify the Supervisor – Construction and Maintenance in the Network group who would mobilize crews to respond.

Note that weekly tests will be cancelled by the Control Center if Duke is already operating in a first contingency situation (another network feeder is already out of service). Duke does not perform the tests on holidays.

Note that Duke is not performing formal periodic network protector testing and maintenance beyond the weekly drop tests. They will utilize a network protector test set when changing network protector relays, but do not apply the test set as part of a formal maintenance program.

Technology

As Duke Energy applies remote monitoring to network protectors so that they can remotely know the status of every protector, they acknowledge that they may have to revisit their weekly test approach. However, they believe in the value of regularly exercising the breaker, and their field crews feel safer that there is some routine validation that the network protectors open and close properly.

5.8.8 - Georgia Power

Maintenance

Network Protector Operational Test

Georgia Power does not perform routine operational (drop) testing, as they have a remote monitoring system installed and can thus, ascertain protector status remotely. See Remote Monitoring - SCADA

5.8.9 - National Grid

Maintenance

Network Protector Operational Test

Process

National Grid performs a routine operational test (drop test) annually. They de-energize each network feeder and use potential lights at the station to identify any back feed from hung up protectors.

5.8.10 - PG&E

Maintenance

Network Protector Operational Test

Process

PG&E does not perform routine operational tests (drop tests) to assure the protectors are operating properly. However, they de-energize each network feeder at least once per year for their transformer maintenance, providing them an opportunity to assess protector operation.

5.8.11 - Portland General Electric

Maintenance

Network Protector Operational Test

People

System Control Center (SCC): The SCC is usually referred to as Load Dispatch, and operators are known as load dispatchers, who are managed by the Transmission and Distribution (T&D) Dispatch Manager. The SCC has two distribution control regions, and dispatchers are assigned geographically. From Monday to Friday, two dispatchers cover each of the two PGE regions.

One of the regions and therefore one of the dispatch desks includes downtown Portland and the CORE network. Dispatchers rotate between the two desks so that all dispatchers gain experience working with the network. The SCC employs eight dispatchers total who rotate between the desks on 12-hour shifts. Dispatchers are salaried employees (non-bargaining).

PGE employs load dispatchers from a range of backgrounds. Some are electrical engineers, some are ex-lineman, and others are SCADA technicians or truck drivers. This approach provides a diverse range of experience. PGE does not have a formal training program for load dispatchers. Training is primarily “on the job.” The load dispatcher position is not considered entry level, so PGE prefers to hire people with prior experience and qualifications.

Load dispatchers perform switching according to checked and verified plans drawn up by engineers. Dispatchers then communicate with crews to carry out the switching in the field.

Load dispatchers have SCADA installed on network feeder breakers. At one of its two network substations, a feeder lockout results in an alarm and page being sent to a preset distribution list, including the Distribution Engineers and CORE group supervisor. If a breaker locks out on a network feeder, the dispatcher calls both the duty engineer and the duty general foreman (DGF) in the CORE underground group. The DGF assembles the appropriate crew to respond to the alarm, isolate the fault, and resolve the issue.

Dispatching has alarms on the feeder breaker and some loading alarms based on predetermined thresholds for feeder loading.

Though PGE has a remote monitoring system installed at each network protector location, this system is not connected to the dispatch SCADA. PGE does not bring alarms or other information from this monitoring system back to the dispatch center. Dispatchers can call up the network monitoring system on custom screens developed in Pi (OSIsoft).

Note that at one point, PGE patched the NP monitoring to the SCC. However, PGE had so many alarms—mostly from normal operation, such as protectors opening under light load conditions—that it decided to keep the alarming of the network information separate from the dispatchers. Accordingly, PGE’s approach to network equipment is proactive, as individual alarms are not presented in real time through either alarms or pages. Rather, Distribution Engineers check the network monitoring system daily for any issues. In addition, the network monitoring system is checked regularly by the Special Tester and Network Foremen for issues. Dispatchers can also access the remote monitoring system as required.

Load dispatchers know a range of systems, including Maximo, ARM Scheduler, and ArcFM. They should understand the PGE-IBEW work rules and related Oregon Public Utility Commission (OPUC) regulations. Line dispatchers must have an associated degree or 1-3 years of experience in a related field.

Training at the SCC: There is no formal SCC network training. All dispatcher training of the network system is on the job. A company called SOS Computer Training Specialists makes computer-based training for the North American Electric Reliability Corporation (NERC) system operators, including one module that relates to secondary networks and feeders. This training is optional.

Process

Energy Management System (EMS): On the underground system, the SCC uses the network protector to gather the majority of information concerning the secondary system, although there is no remote control of the system at this stage. The remote monitoring system on the protectors is a separate system from the EMS used by dispatchers. The remote monitoring system is known internally as the “blue wire” system.[1] Load dispatchers have access to this system, which resides on the “Pi” system (OSIsoft). They can select any network and see all the flows on each NP, as well as determine whether they are open or closed. PGE developed Pi front-end screens.

If the dispatch center is executing a shut-down order and sees that a protector still shows as closed on the monitoring system when it should be open, the SCC contacts the individual listed on the shut-down order to let them know that a particular protector still shows as closed. That individual will send a crew to the location to check on the network protector status.

Monitoring Reliability: PGE’s Outage Management System (OMS) tracks and logs outages, and is integrated with the Customer Information System (CIS), GRID (an electronic map-based connectivity system), outage histories, and interactive voice response (IVR). All of this information is collated and a monthly evaluation ensures accurate data. This verified data is used to calculate System Average Interruption Duration Index (SAIDI), System Average Interruption Frequency Index (SAIFI), and other data presented in PGE’s Annual Reliability Report.

Momentary outages (MAIFIe) are logged and recorded at substations equipped with SCADA and MV90, a system that collects data at meters. Of PGE’s 146 distribution substations, 59% are fitted with SCADA, and 35% with MV90. The remaining 5% of substations with neither system will have readings taken monthly [1].

Planned Outages: Planned outages follow a structured process, which can take up to a week to organize. For a planned outage, the Network Engineering Department creates a shut-down order document requesting the feeder outage that the dispatcher must complete. Load Dispatch receives a three-day lead time for planned shutdowns.

The remote monitoring system on the network protectors is a separate system from the EMS that the dispatchers use. This monitoring system is known internally as the “blue wire” system. Load dispatchers have access to this system, which resides on the “Pi” system (by OSIsoft). They can select any network and see all the flows on each NP, as well as whether they are open or closed. PGE developed Pi front-end screens. The system is not being utilized to remotely operate equipment.

At one of the substations supplying the network, four transformers supply the multiple substation busses supplying the network. This station has a load follower scheme, a master/slave configuration so that every bus follows the master to maintain consistent voltage at the bus. In the event of a bus section outage, Dispatch will lock the regulation so that it does not try to regulate but maintains voltage, as it has had some historic problems with current flow.

Grounding and Switching: PGE grounds feeders at the substation using either CORE group employees or substation operators. Feeders are only grounded at the substation, and PGE’s practice on the network is not to set up a tighter zone of grounding. The SCC relies on the CORE group to isolate faults and provide recommendations about what switches need to be opened. SCC still authorizes the switching but works closely with the crew to make sure that it understands exactly what process and order to follow.

Network Shutdown: At present, PGE has no formal guidelines governing dictated conditions that would warrant a network shutdown.

Power Restoration: To restore power, there is a simultaneous close capability, which closes all four network feeder breakers at the same time and is operated remotely via the SCADA. The SCC calls the general foreman before closing any breaker to ensure that crews are not working in any the vaults on that feeder. The foreman confirms with the crews whether it is safe to close.

Fault Location and Analysis: If a feeder breaker opens for a network feeder due to a fault rather than planned work, the SCC calls the duty general foreman in the network group. The SCC leaves it up to the general foreman to determine whether the issue can wait until the following day or needs to be dealt with immediately. Single feeder losses are often left for the following day unless the outage occurs in a period of heavy loading, or other conditions exist that would raise the risk of operating in a N-1 condition.

Smoking Manholes: If a smoking manhole is reported, the SCC calls the duty general foreman. In this situation, the load dispatcher may elect to dump the network, which has been done in the past. The load dispatcher normally confers with distribution engineering to make that decision.

Accident Response: During an accident, the procedures dictate that the crew should call the SCC with the relevant information. In addition, the crew or SCC contacts emergency services. The SCC completes an online form that is distributed to approximately 150 people automatically, and calls out the safety coordinator responsible for the network. In addition, PGE has a Crisis Response Team that responds to situations of employee injury. Representatives of this team travel to the hospital with the injured employee and notify the family. Using this team removes the burden from the SCC. This protocol was implemented approximately 10 years ago.

Drills: PGE conducts system-wide outage restoration drills once a year, prior to the fall storm season. In the past, this included some scenarios that involved the CORE network system. For example, a recent drill was substation-centric. The tested scenarios simulated the outage of one of the stations supplying the network.

PGE also conducts annual earthquake drills, which are tabletop exercises organized by the Business Continuity Group. These drills do not always involve the network depending on the scenario chosen.

PSC has no written guidelines specifically related to unforeseen events occurring on the network.

During an emergency,PGE follows the principals of the incident command system (ICS) at the management level.

Technology

Outage Management System (OMS)/Oracle NMS

The redundant design of the network prevents customers from experiencing outages in most conditions. The information that follows is a discussion of the OMS technology utilized at PGE, though this technology is rarely leveraged in a network application.

PGE migrated to an Oracle NMS outage management system, which is based on WebSphere technology [2]. Oracle NMS is a scalable distribution management system that manages data, predicts load, profiles outages, and supports automation and grid optimization. The system combines the Oracle Utilities Distribution Management and Oracle Utilities Outage Management systems in a single platform. The system supports outage response and the integration of distributed resources [3].

Oracle NMS blends SCADA function and geographic information system (GIS) models to combine as-built and as-operated views of the system. The application includes a number of advanced distribution management functions, including network status updates in real time, monitoring and control of field devices, switch planning and management, and load profiling. Oracle NMS can integrate with other SCADA and GIS systems, and it monitors network health using data from a number of systems. The NMS includes a simulation mode for training and supports switch planning and control.

Oracle NMS maintains a network model that handles the whole grid, includes every device, and integrates with existing systems using standards-based protocols such as Inter-Control Center Communications Protocol (ICCP), Common Information Model (CIM), and MultiSpeak-based web services. The system can also integrate with a range of GIS and Advanced Meter Infrastructure (AMI) systems [4].

PGE’s NMS/OMS integrates outage information and location, switching functions, and work management. The system allows operators to see present system status and other operational data, and a data model predicts outage locations [3]. During outage events, operators can manage outage calls, assign and manage crews, and use the Maximo database to locate assets in relation to customers without power. The OMS also integrates with the GIS and CIS, which allows outage information to be accessed by customers [5,2]. Other functions within the OMS include:

Automatic Vehicle Location (AVL): As part of the new OMS, the AVL allows crew locations to be shown on the NMS map. This allows operators to dispatch the closest crew to an outage.
Asset Resource Management (ARM): PGE can now route service work and design construction orders through Maximo to WebSphere, and from there to the ARM system. Crew information from laptops can be sent to the system for retrieval.
Oracle Utilities Analytics (OUA): Using OUA, operators can view if a crew dispatch is successful, and the system allows crews to view any pending work orders in their feed.
Safety functions: The OMS uses the AMI to improve safety during outages. The AMI pings meters to determine on/off status during an outage event, allowing operators to determine if outages can be cleared from the OMS and free crews for other restoration priorities. In addition, meters send a “last gasp” message to the AMI system when they are about to run out of power.

System Installation: The 2020 Vision/Next Wave projects used 40-50 fulltime employees to implement the systems and included partnerships with Oracle for product support, as well as Accenture for expert system integration understanding. The implementation included change management and embedded technical and information technology (IT) teams to ensure smooth implementation.

OSIsoft Pi

PGE has a remote monitoring system implemented that monitors information from the network protector relay. PGE’s looped fiber system communicates information from this system, which can be viewed on customer screens developed within the OSIsoft Pi system. This information is available to load dispatchers, engineers, and field crews. The Pi system can collect large volumes of data from multiple sources and helps users view, analyze, and share information [5,6].

[1] Field crews call this “blue wire” because the twisted pair wires feeding into each protector are blue. Information from the protectors is converted to and communicated on PGEs looped fiber system.

Seven-Year Electric Service Reliability Statistics Summary 2007-2013. Oregon Public Utility Commission, Salem, OR: 2014. http://www.puc.state.or.us/safety/14reliab.pdf (accessed November 28, 2017).
D. Handova, “PGE: Driving Customer Value With Network Management Systems.” EnergyCentral.com. http://www.energycentral.com/c/iu/pge-driving-customer-value-network-management-systems(accessed November 28, 2017).
Modernize Distribution Performance All the Way to the Grid Edge. Oracle, Redwood Shores, CA: 2015. http://www.oracle.com/us/industries/utilities/network-management-system-br-2252635.pdf(accessed November 28, 2017).
Modernize Grid Performance And Reliability With Oracle Utilities Network Management System. Oracle, Redwood Shores, CA: 2014. http://www.oracle.com/us/industries/utilities/046542.pdf(accessed November 28, 2017).
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).
Marquam Substation Project Quick Facts. Portland General Electric., Portland, OR: 2017. https://www.portlandgeneral.com/-/media/public/our-company/energy-strategy/documents/marquam-substation.pdf?la=en (accessed November 28, 2017).
Portland General Electric. “Quick Facts.”PortlandGeneral.com. https://www.portlandgeneral.com/our-company/pge-at-a-glance/quick-facts (accessed November 28, 2017).

5.8.12 - SCL - Seattle City Light

Maintenance

Network Protector Operational Test

People

Certain Cable Splicers are assigned to focus on network protector construction, operations, and maintenance, and thus become experts in these areas. These individuals are selected for this focus based on their interest level and mechanical aptitude. They retain their Cable Splicer position.

Process

SCL does not perform routine network protector drop testing. See Network Protector Maintenance

Technology

Network Tools

SCL crews believe their tools to be of top quality. An example would be the network protector test kits (Richards) that the crews use to perform network protector maintenance.

5.8.13 - Survey Results

Survey Results

Maintenance

Network Protector Operational Test

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 22 : For your network system, do you perform a “Drop test”, where a network feeder is opened at the station and network protectors are tested to assure that they are functioning correctly (automatically open on backfeed)?

Survey Questions taken from 2015 survey results - Maintenance

Question 85 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Question 93 : When you perform network protector maintenance, please indicate which of the following you do. (check all that apply)

Question 98 : Does your network protector maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for backfeed voltage to assure that the network protectors function correctly (automatically open)?

Survey Questions taken from 2012 survey results - Maintenance

Question 6.25 : Do you regularly perform Network protector maintenance and testing?

Question 6.26 : If yes, what is the frequency of testing?

Question 6.27 : When you perform Network Protector maintenance, please indicate which of the following you do.

Question 6.28 : During your network Protector testing, do you know/record how fast the NP opens (in terms of cycles usually) when it sees a reverse power flow?

Question 6.29 : Does your NP maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for back feed voltage to assure that the network protectors function correctly (automatically open)?

Survey Questions taken from 2009 survey results - Maintenance

Question 6.32 : Do you regularly perform Network protector maintenance and testing?

Question 6.33 : If yes, what is the frequency of testing?

Question 6.34 : When you perform Network Protector maintenance, please indicate which of the following you do.

Question 6.35 : Does your NP maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for back feed voltage to assure that the network protectors function correctly (automatically open)?

5.9 - Network Transformer Maintenance

5.9.1 - AEP - Ohio

Maintenance

Network Transformer Maintenance

People

Network transformer inspection and maintenance is performed by the Network Mechanic position. Network transformers are inspected annually, and oil sampling and testing is performed on a three-year basis. Transformer maintenance activities are driven by findings from both the visual inspection and oil test results. Inspection and maintenance are scheduled by AEP Ohio network engineers. It is notable that all AEP operating companies conform to the same transformer inspections and maintenance approach.

Process

Maintenance crews, comprised of Network Mechanics, inspect all network transformers yearly, in conjunction with annual vault inspections. Inspection activities include:

Check for oil leaks of each fluid-filled tank (main tank, high voltage switch, and termination compartment), especially at the flanges, valves and other joints. Clean the valves if necessary.
Inspect and record the physical condition of the transformer/transformer support (rails). Minor rust spots can be “touched up.”
Record transformer temperature readings and oil level readings. If oil levels are low, maintenance crews will add oil.
Load readings are taken, normally before the summer load period.
Inspect the switchgear at the site.
Nameplate data on the transformer is captured, as well as its serial number and vault location.

Transformer temperature, pressure, and oil levels are provided by sensors. AEP Ohio is in the process of standardizing on generic gauges and sensors so that they can stock fewer transformer-specific parts.

At present, AEP Ohio has a mix of GE, Carte, and ABB transformers. The company had historically used a three-chamber design, with the termination chamber and high-voltage primary switch chamber integrated into the network unit. The company has moved to the use of a separate wall-mounted solid dielectric high-voltage vacuum switch (see Figure 1), along with a transformer unit with ESNA-style bushings.

Figure 1: Network transformer – single tank design, for use with separately wall-mounted, high-voltage switch

On a three-year cycle, AEP Ohio performs oil sampling and testing of each network transformer compartment. The following tests are performed:

Perform a dielectric test using ASTM 1816 (filter if below 22 kV)
Check moisture content
Perform a dissolved gas in oil analysis (DGA).
- Note that DGA is performed after the first month of service, then annually unless trends are stable or if results are within acceptable levels. Then, the unit will move to the three-year cycle.

Overall transformer condition(s) is recorded and corrective maintenance actions identified are prioritized on the Transformer Inspection Form (see Attachment H ). Transformer maintenance activities are a function of the results of the oil testing (results of the DGA). Maintenance performed includes:

High Voltage (HV) Switch
- Drain, inspect, and clean the HV switch compartment.
- Inspect, clean, and adjust the HV switch.
- Measure the contact resistance with a DLRO meter as follows:
  - With the switch in the closed position, measure all three-phase-cable-to-transformer contacts (50 micro-ohms is acceptable)
  - With the switch in the ground position, measure the resistance of all three phases from cable side of the switch to the transformer ground pad (1250 micro-ohms is acceptable)
  - Clean the contacts with “scotch bright” as necessary.
- Check the compartment gasket and replace if necessary.
- Refill with new oil and let set for 24 hours (settle time) before re-energizing.
High Voltage Cable Termination Compartment.
- Drain, inspect, and clean the HV termination compartment.
- Inspect cable stress relief. Install if necessary.
- Check the compartment gasket and replace if necessary
- Refill with new oil and let set for 24 hours (settle time) before re-energizing.
Transformer Main Tank.
- Check and replace the throat gasket as needed.
- Perform a Doble Test
  - Disconnect the primary cables if possible to test through the cable termination compartment.
- Perform a TTR Test

AEP Ohio has identified four conditions that describe transformer condition and drive maintenance. Each condition is based specifically on predefined levels of various dissolved gasses identified through testing, and comporting with IEEE guidelines:

Condition 1 – Indicates transformer operating satisfactorily.
Condition 2 – Indicates greater than normal combustible gas level. Action should be taken to establish a trend. Fault may be present.
Condition 3 – Indicates a high level of decomposition. Immediate action should be taken to establish a trend. Fault(s) are probably present.
Condition 4 – Indicates excessive decomposition. Continued operation could result in transformer failure. Proceed immediately and with caution. Consider removing from service.

At AEP Ohio, the decision to replace a network transformer is based on condition, not age.

Technology

Crews have computers in every truck. Printed and online forms for transformer maintenance are available. Conditions and scheduled maintenance performed are then captured in the AEP NEED (Network Enclosure and Equipment Database).

AEP uses sensors to monitor transformer temperature, pressure, and oil levels. These sensors are being tied in with the NP microprocessor-based relays and can be remotely monitored through its SCADA system.

The AEP Ohio Network Engineering Supervisor is considering installing advanced SCADA connected sensors in selected vaults (a group of 480-V units) for dissolved gas monitoring and rapid transformer pressure rise monitoring, and is developing a criterion for selecting locations. With the new SCADA system (see Remote Monitoring), AEP Ohio has the resources to pilot these sensors at the highest risk transformer vaults. The pilot installation will enable the company to gain knowledge and assess the sensor’s usefulness in other parts of the AEP system.

5.9.2 - Ameren Missouri

Maintenance

Network Transformer Maintenance

(Oil Testing)

People

The majority of the maintenance and inspection programs associated with network equipment, including network transformer maintenance, are performed by resources within the Service Test group.

Organizationally, the Service Test group is part of Distribution Operations, led by a manager. Within Distribution Operations, there is a Reliability Support Services group led by superintendent. Reporting to the Superintendent Reliability Support Services are both the Service Test group led by a supervisor and the Distribution Operating group, also led by a supervisor.

The Service Test group is made up of Service Testers and Distribution Service Testers. It is the Distribution Service Testers who perform periodic network transformer maintenance and oil sampling, as well vault maintenance and network protector maintenance and calibration. The Service Testers perform low-voltage work only, such as voltage complaints, RF interference complaints, and testing and maintaining batteries.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. As part of this group’s role, they are examining Ameren Missouri’s practices for inspecting and maintaining network infrastructure, and developing recommendations for optimal approaches. They have developed a draft document which details strategies for inspection and maintenance of network units, cable systems, vaults, manholes, indoor rooms and customer switchgear. In addition, they have developed a criteria used to evaluate and prioritize replacement of network transformers and protectors. These criteria are based on key considerations such as the transformer’s age, location, physical condition, loading, history with similar transformers styles, and oil quality. (See Maintenance: Network Transformer Replacement Criteria for more information)

Ameren Missouri has a repair shop (Dorsett) that rehabilitates older network units and receives, assembles and tests new units. This group performs inspection and testing of new units including checking taps, and performing TTR tests.

Process

Ameren Missouri performs network transformer maintenance and oil sampling on a two year cycle. Ameren Missouri performs network transformer maintenance in conjunction with network vault inspection and network protector maintenance. This maintenance is performed with the primary feeder energized.

The network transformer maintenance includes inspection and maintenance of both the transformer and primary switch. The following steps are excerpted from the Ameren Missouri Distribution Service Man training manual and the Maintenance and Inspection guideline developed by Ameren Missouri’s Downtown St. Louis Underground Revitalization group.

Transformer Primary Switch

The Primary voltage switch is located on the opposite end of the network transformer from the protector and has to be inspected as part of the annual inspection. The primary switch can only be operated de-energized. It is interlocked such that it cannot be operated if the primary cable is energized.

The primary switch is inspected as follows:

Inspect primary cables and associated components for signs of physical wear and damage.
Make sure tags are clearly labeled and in good condition.
Check for oil leaks and for “Non-PCB” label. If there is no label, contact a supervisor immediately.
Check operating handle and mechanism.
Check oil level and oil temperature. Record on inspection form. If the oil level is not below “low,” take a sample (50mL sample in the syringe and about a quarter full of a plastic quart bottle) . If the oil level is below “low,” write up a trouble ticket. Replace gauges if necessary.
Add 3 lbs of Nitrogen and monitor for 30 minutes. Leave at 1.5 lbs. Record results on the inspection form.

Network Transformer

Network transformers are delta wye three-phase transformers designed for underground usage. In the St. Louis network system, the primary winding is 13.8 kV (13.2 units with taps to support 13.8) Secondary winding is 216 / 125 V (network grid units). These transformers are usually rated at 500 to 750 KVA.

Check for oil leaks, especially at the flanges, valves and other joints. Clean the valves if necessary.
Inspect the physical condition of the transformer. Make sure the top is clean and check for rust and the condition of the paint.
Verify nameplate data on transformer and compare to inspection sheet. Note any discrepancies.
Check for “Non-PCB” label. If there is no label, contact a supervisor immediately.
Check oil level and oil temperature. Record on inspection form. If the oil level is not below “low,” take a sample (50mL sample in the syringe and about a quarter full of a plastic quart bottle). If oil is below “low,” write up a trouble ticket. Replace gauges if necessary.
Obtain an oil sample for dissolved gas analysis. Submit the oil sample to the chemistry laboratory for analysis. Make sure that the oil temperature at the time the sample is taken is recorded on the form submitted to the chemistry laboratory.
Add 3 lbs of Nitrogen and monitor for 30 minutes. Leave at 1.5 lbs. Record results on the inspection form.

The results of the inspections are recorded on the Network Transformer Inspection form. (See Attachment J). ).

The oil samples from the transformer tank and primary switch compartment are sent to the Ameren Missouri Chem laboratory. Ameren Missouri performs the following oil tests:

Dissolved Gas Analysis
Water Content
Acid content (TAN)
Interfacial Tension (IFT)
Dielectric testing

Ameren Missouri has a separate program for sampling oil from the transformer primary termination chamber, also on a 2 year cycle. These samples are drawn with the primary feeder de-energized.

Figure 1: Oil Sampling kit

Technology

Ameren Missouri has 265 network units.

Information from the transformer inspections is updated in the Ameren Missouri’s Circuit and Device Inspection System (CDIS) by the Dist Service Testers.

The CDIS includes an algorithm that assigns a “structural score” and an “electrical score” based on the inspection findings and weightings for various findings developed by Ameren Missouri. The scores are used to prioritize remediation. See Transformer Replacement Criteria for more information.

CDIS is also used to produce reports that summarize inspection findings and a dashboard that monitors inspection progress.

Ameren Missouri uses the ETI electronic relay as part of its remote monitoring system. Using this system, they are monitoring various points including voltage by phase, amps by phase, protector status, transformer oil top temp and water level in the vault. The monitoring points are aggregated at a box mounted on the vault wall that communicates via wireless.

Figure 2: Network Transformer

Figure 3: Network Transformer

5.9.3 - CEI - The Illuminating Company

Maintenance

Network Transformer Maintenance

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who inspect and maintain the underground system.

Process

Network transformers are inspected on a six month basis as part of the Network Vault Inspection / Maintenance.

CEI performs transformer maintenance on a two year cycle. This inspection includes a visual inspection and recording of information such a the presence of any oil leaks, tank corrosion, top cleanliness, as well as recording the oil temperature, oil level, and pressure. In addition, the inspector will take temperature readings at the transformer terminals using a heat gun, looking for hot spots.

Inspectors will also take oil samples – the samples are drawn with the transformer energized.

CEI will do an Oil Screen test, which includes a Neutralization Number (acidity), Color, and Visual Examination, a Dissolved Gas Analysis (DGA) test, and an Oil Dielectric breakdown test on the transformer oil. Laboratory analysis is performed “in house” at FirstEnergy’s Beta laboratory. (The Oil Dielectric test is performed on site, while the DGA and Oil screen are performed in the (BETA Lab. ).

Technology

Transformer inspection data is recorded manually on the vault inspection form. See Attachment N.

Transformer oil test results are kept manually in a file at CEI. (This is also true of test results performed on CEI transformers that are located in customer vaults – normally non-network installations.)

The fact that the unit has been inspected is recorded in SAP, but not the specific information. This information may ultimately go into the Cascade system presently being implemented by FirstEnergy.

5.9.4 - CenterPoint Energy

Maintenance

Network Transformer Maintenance

People

Network transformer maintenance is performed as part of vault inspection and maintenance at CenterPoint. Vault Inspections are performed by the Relay group within Major Underground. The Major Underground organization includes Key Accounts, Engineering and Design resources, Support Services, and the field force responsible for all construction, operations and maintenance activities. The field force is divided into two main groups, the Relay group and the Cable group.

Both the Relay group and Cable group perform maintenance and inspection activities. The Relay group focuses on most of the non cable equipment inspection and maintenance, including performing vault equipment inspections, network transformer inspections, network protector testing, and other inspections and maintenance on devices with relays or motor operators. The Cable group focuses on inspections of cable, cable accessories and major equipment.

The Relay group is comprised of Network Testers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. The Relay group is led by an Operations Manager.

CenterPoint does not have dedicated maintenance crews. Rather, maintenance and inspection work is assigned to crews based on work priorities and resource availability.

Process

The Relay group performs periodic vault inspections, with most inspections on an annual period. Some high priority locations are inspected two or three times per year. The inspections are performed without de-energizing the vaults.

Network vault inspections include a visual inspection of the network transformer for oil leaks, corrosion, etc. Inspectors will also record peak temperature from the transformer temperature gauge. CenterPoint does not test network transformer oil as part of their network vault inspections, unless there is an indication of a potential problem such as a high temperature reading.

CenterPoint is using an inspection checklist to guide inspectors through the various items included in the inspection. This same checklist, entitled MUDG Functional Location Inspection Sheet is used to record findings from all inspection types, including the network vault inspections. An inspection sheet is completed for every location inspected.

Inspection findings that require follow up corrective maintenance are noted and recorded by the Crew Leaders who schedule this work for completion. Non urgent corrective maintenance actions that are identified during inspection may be held to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

If the solutions to the findings require the involvement of other groups, the Crew Leaders will solicit their help. For example, corrective maintenance activities that require a customer outage will require the assistance of the Key Accounts group to coordinate with the customer to schedule the outage.

The inspection sheets are filed by work center (each vault is considered a work center), so that CenterPoint has a record of the historic findings.

Technology

Vault inspection results are recorded manually on the MUDG Functional Location Inspection Sheet, See Attachment I

Vault inspections include the performance of infrared thermography.

5.9.5 - Con Edison - Consolidated Edison

Maintenance

Network Transformer Maintenance

People

I&A Mechanics within the Construction Group maintain network equipment, including network transformers and network protectors.

Construction Group

Con Edison’s service territory consists of four regions: Manhattan, Brooklyn/Queens, Staten Island, and Bronx/Westchester. The Manhattan Region is made up of three districts, including one headquartered at the W 28th St. Work Out Center. The term Work Out Center refers to a main office facility to which field construction and maintenance resources report. To provide a perspective on the size of a workout center, about 300 people work at the W 28th Street Work Out Center, and they can field about 125 crews.

The construction department consists of several groups:

Underground group
- The underground group is made up of splicers, who splice cable of all voltages.
I&A group (includes a services group)
- The I&A group installs and maintains network equipment, including transformers and network protectors. Within I&A in Manhattan, there is a services group dedicated to connecting customers to the distribution network. In other locations, the services group sits in a different part of the organization. This group does the splicing on the secondary system and deals with customer connection issues.
Subsurface construction (SSC) group
- The SSC deals with vaults, conduit ducts, and other civil work. Much of this work is contracted.
Cable group
- The cable group pulls in new cable and retires cable.

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including performing infrared inspections of network transformers. See Manhole Inspection and Maintenance - Field Engineering Group

Process

Inspection and Maintenance

Con Edison performs periodic maintenance and inspection of network distribution equipment, including network feeders, transformers, network protectors, grounding transformers, shut and series reactors, step-down transformers, sump pumps and oil minder systems, remote monitoring system (RMS) equipment, and vaults, gratings, and related structures.

Con Edison’s approach to performing an inspection is to inspect all the equipment and structures associated with a particular vault ID at a location regardless of category or classification, and even if the particular equipment associated with a particular vault ID resides within different compartments (for example, a transformer and network protector may be located in separate physical compartments even though they both share the same vault ID). This type of inspection is referred to as a CINDE Inspection, based on the name of their maintenance management system (Computerized Inspection of Network Distribution Equipment).

Con Edison performs inspections energized; crews do not take a feeder outage to perform inspections, perform pressure drop testing, or take transformer oil samples. Con Edison does not routinely exercise feeder breakers.

In an effort to more efficiently use their resources, and when nonpriority conditions allow, Con Edison takes advantage of situations where they have to enter a vault or manhole for a reason other than a scheduled inspection, and perform a nonscheduled inspection while they are in the vault. When the record of this nonscheduled inspection is recorded in CINDE, the system “resets the clock” for the next inspection date.

Network equipment at 208 V is generally inspected on a 5-year cycle. 460-V facilities, sensitive customers, facilities in flood areas, and other more critical locations are inspected more frequently, often annually. Con Edison establishes network equipment inspection cycles depending on two factors: the inspection category and the inspection classification .

The inspection category refers to the type of inspection, and includes a Visual Inspection, a 120/208-V Test Box Inspection, and a 460-V Test Box Inspection. The Visual Inspection includes activities beyond visually assessing condition and recording information, such as pressure drop testing and taking transformer oil samples. The test Box inspections involve specialized testing of network protectors with the network relay installed. Note that all of the elements of a Visual Inspection are performed along with the Test Box Inspections.

The inspection classification refers to characteristics of the inspection site that dictate the inspection cycle. For example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a “tidal” area would be visually inspected annually. Con Edison considers the following classifications in determining inspection cycles:

Routine
Back-feed: banks installed on a feeder involved in a back-feed incident
Candidate for Replacement: commonly due to corrosion damage
Essential Services: critical customers
Flooded Bank: nonsubmersible equipment that has experienced high water levels
208-V Isolated Bank: units that require more frequent inspection than distributed secondary grid units
Remote Monitoring System(RMS), Non RMS, Unit Not Reporting (UNR): Con Edison varies inspection cycles based on the level of remote monitoring installed
Tidal, Water, and Storm Locations

Note that Con Edison requires employees to perform at least a quick visual inspection (QVI) anytime an individual enters a network enclosure, even if the reason for entering an enclosure does not warrant a CINDE Inspection. This type of inspection (QVI) differs from the CINDE inspection category of Visual Inspection described above, in that it is not a full, accredited inspection.

Transformer Inspection

Transformers are inspected on varying schedules, depending on the inspection classification, but typically no longer an interval than six years. Transformer inspections are performed as part of the CINDE visual inspection.

Transformer inspections include:

Visually inspecting for leaks
Measuring pressure
Reading oil temperatures and levels
Taking oil samples for dielectrics and dissolved gas analysis
Performing pressure drop testing
Assessing condition of anodes and replacing if necessary
Performing a corrosion assessment
Checking bus condition
Checking condition of gaps/limiters and connections
For 460-V units, inspect low-voltage bushing boots for debris and seal integrity

Con Edison performs approximately 8,000 inspections annually.

Transformer Failure Analysis

Con Edison performs a root cause analysis of all network transformer removals including units that failed in service, units that were removed because of failed dissolved-gas-in-oil-analysis (DGOA), units that were removed because of failed oil temperature, pressure, or level indications from the RMS system, and units that failed during testing. See Maintenance - Failure Analysis - Transformer Failure Analysis for more information.

5.9.6 - Duke Energy Florida

Maintenance

Network Transformer Maintenance

People

Network transformer maintenance is performed by craft workers, Network Specialists and Electrician Apprentices, within the Network Group, part of the Construction and Maintenance Organization. The Network Group is led by a supervisor, and consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position).

Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager.

The Network Group is organized functionally, and has responsibility for construction, maintaining and operating all urban underground infrastructure (ducted manhole systems), both network and non - network, in both Clearwater and St. Petersburg. Resources are assigned to either Clearwater or St. Petersburg based on work needs. Being a small group of resources, Duke Energy Florida rotates work assignments to assure that Network Specials are “jacks-of-all -trades”.

Process

Duke Energy Florida utilizes network transformers, mostly 500 kVA units, to supply its Clearwater network grid, a small network supplied by three feeders through about twenty network transformers. Duke Energy Florida also utilizes network transformers, mostly 750 kVA units, to supply its eight spot network locations in St. Petersburg.

Network transformer inspection and maintenance is performed in conjunction with the vault inspection. The vault inspection cycle varies depending on location and on equipment housed in the vault. For vaults that are part of the Clearwater network and house the network unit, Duke Energy Florida inspects each vault three times per year. In St. Petersburg, the spot network vaults are inspected annually.

Transformer inspections include a visual condition inspection and recording of oil level and temperature. Vault inspections also include infrared thermography (IR) and recording of IR measurements.

Information from the inspection is recorded on an inspection form, including an assessment of the priority or severity of the finding. See Attachment I . Information from the inspection is entered into a computer system, and the hard copy form is maintained in a file. Duke Energy Florida has a “Further Work Ticket Process” which is initiated to pursue remediation for corrective maintenance items identified by inspection. The repair schedule is dictated by the priority of the finding. For example, a leaky transformer must be reported to the environmental group within 24 hours of discovery and repaired within 30 days.

Duke Energy Florida is not performing network transformer oil sampling and testing as part of their vault maintenance process. They are considering reinstating oil sampling and testing and are experimenting with transformer dissolved gas sensing tied in with their Qualitrol system at one location.

Technology

Duke Energy Florida uses submersible network transformers to supply network customers. Transformer sizes range from 500 to 1500 kVA wye-wye, with most units in Clearwater being 500kVA units, and most in St. Petersburg being 750 kVA units (see Figures 1 and 2). The transformer nameplate voltage rating is 12470 GRD.Y / 7200 - 208Y/120.

Figure 1: Network transformer supplying the grid (below grade vault)

Figure 2: Network transformers supplying a spot (building vault)

Duke Energy Florida specifies units that are designed to eject fluids to the floor in the event of a transformer tank rupture.

Duke Energy Florida monitors network transformer and vault information in Clearwater using a system by Qualitrol. Using the Qualitrol transformer sensor module, they monitor transformer oil level and temperature, as well as the Oil Minder system associated with the vault sump pump, which can detect the presence of oil in the water and cease pump operation. Duke Energy has recently teamed with Qualitrol to pilot an installation using a dissolved gas monitor at one transformer location. The monitor itself fits into the drain port of the transformer and is tied into the Qualitrol receiver. Their goal is to build an algorithm that considers transformer vintage, DGA results, etc., and uses that information to trigger replacement.

5.9.7 - Duke Energy Ohio

Maintenance

Network Transformer Maintenance

(Network Transformer Oil Testing)

People

Duke Energy Ohio performs an inspection and samples oil from network transformers on a four year cycle^[1] . The extracting and testing of the oil sample is performed by Network Service persons.

The inspection includes a visual inspection of the unit and the recording of information such a the presence of any oil leaks, tank corrosion, as well as recording the oil temperature, oil level, and pressure. In addition, the inspector will take temperature readings at the transformer terminals using a heat gun, looking for hot spots.

Process

Duke Energy Ohio de-energizes the primary feeder before taking the transformer oil samples. They try to coordinate the feeder outage so that they can perform other corrective maintenance work while the feeder is out of service.

At the time of the EPRI immersion, Duke was performing only dielectric tests of the transformer oil samples from network transformers. Samples are taken of both terminal chamber oil and transformer tank oil. Two samples of each are tested. This testing is being performed by Dana Avenue Network Service persons.

Duke Energy Ohio is considering adding Dissolved Gas Analysis testing for network transformers, and performing both the dielectric and DGA testing at their Queensgate laboratory, where they perform substation transformer oil testing.

Technology

Information from inspection is stored in Duke Energy’s Emax system.

^[1] Distinct program from the vault inspection program

5.9.8 - Energex

Maintenance

Network Transformer Maintenance

People

See Preventative Maintenance and Inspection

Process

Energex has trained operators (substation mechanics) who are focused on performing routine substation inspections (RSIs) in relay operated substations, both the 110-kV:11 kV substations, and the C/I substations (11 kV: low voltage) that are supplied by the three-feeder meshed system in the CBD. There is a periodic visual inspection, and then there is also cyclical maintenance performed by these resources. Energex has approximately 30 substation mechanics in a group who perform this work. Energex is moving to performing a visual “security” inspection on a six-month cycle (assuring that the station is secure), and a full inspection, including a visual inspection and taking readings, once every 18 months (see Table 6-1). The inspector records the information on a manual form. The information is then given to a clerk and entered into the system. At the time of the immersion, Energex was developing a tool for substation inspectors to enter information on-site into a tablet, but have not yet implemented this system-wide.

For non-relay operated substations, such as a transformer with a ring main unit, the inspections are performed by joint fitters who work in the hub locations. As the inspector identifies findings, he categorizes it, and records the information on a form. The information is entered into the Ellipse system on return to the office.

Technology

See Preventative Maintenance and Inspection

5.9.9 - ESB Networks

Maintenance

Network Transformer Maintenance

(Oil Testing)

People

See Preventative Maintenance and Inspection

Process

ESB Networks uses sealed transformers in the MV-LV system, and therefore does not test oil levels at transformers. (Note that ESB Networks does sample and test oil on the larger transformers.)

At older MV substations, ESB Networks Network does have installed indoor oil ring main units. They have implemented a capital replacement program to systematically identify and replace all older style oil filled switchgear in their medium voltage stations with SF6 units. Their goal is to have only two types of gear installed - Magnefix and SF6 – by 2015.

Switchgear SF6 gases are checked on a routine basis as part of their MV substation inspection program.

Technology

See Preventative Maintenance and Inspection

5.9.10 - Georgia Power

Maintenance

Network Transformer Maintenance

People

The Georgia Power Network Underground group has maintenance crews who are responsible for performing vault inspections, including performing network transformer testing and maintenance. A typical maintenance crew is comprised of a Senior Cable splicer, Cable Splicer and a WTO. The maintenance crews report to a Distribution Supervisor, who is part of the Network Operations and Reliability group. The Network Operations and Reliability group is responsible for maintenance and operation of the network system.

The Operations and Reliability Group is part of the Network Underground group at Georgia Power, a centralized organization responsible for all design, construction, maintenance and operation of the network infrastructure for the company.

Transformer inspections are performed as part of the vault inspection program, performed on a 5 year cycle. Note, the network protector maintenance program is a separate program from the vault inspection.

Process

Georgia Power reports very good reliability of its installed transformers. Georgia Power primarily uses 500 / 1000 / and 2000kVA transformers at 208 /480V, with 3000kVA units where they have 4KV secondary.

Maintenance crews inspect and maintain the transformers on a five-year cycle, including the following:

Check for oil leaks, especially at the flanges, valves and other joints. Clean the valves if necessary.
Inspect the physical condition of the transformer. Make sure the top is clean and check for rust and the condition of the paint. The condition of the network protector is noted as well, but Georgia Power has a separate network protector inspection and maintenance cycle, and this transformer inspection does not re-set the network protector inspection clock.
Record transformer temperature readings and oil level readings. If oil levels are low, maintenance crews will add oil.
Inspect the switchgear at the site.
Verify the nameplate data on transformer and compare it to the inspection sheet. Note any discrepancies.

Georgia Power does not normally take oil samples and perform oil testing on network transformers unless there are unusual circumstances. They noted that they used to take routine samples, and found that the process of sampling the oil was introducing moisture and contaminants and leading to additional failures. For example, they believe that the inadvertent mixing of silicone, historically used in the switch compartment, with mineral oil, historically used in the termination compartment, may have resulted in failures of some terminations of oil-filled PILC cable. Georgia Power engineers noted that if implementing a process to sample and test transformer oil, it must be a clean process, with appropriate tools to filter the oil and avoid introducing contaminants into the transformer. Georgia Power has had good performance of their transformer fleet, with few failures over the past ten years.

Technology

Georgia Power uses an access data base for tracking inspection findings and triggering maintenance orders. When inspection information is entered into the Access database indicating a finding needing repair, system will create a maintenance order automatically based on the priority of the finding. The inspector receives a monthly report of the pending corrective maintenance jobs.

5.9.11 - HECO - The Hawaiian Electric Company

Maintenance

Network Transformer Maintenance

People

At HECO, underground maintenance work is performed by both Cable Splicers from the Underground group, and Lineman from the Overhead C&M groups.

The Underground Group at HECO is part of the Construction and Maintenance Division. The group is comprised of two UG supervisors, fifteen Cable Splicers, 2 Utility Mechanics, and 2 Utility Assistants. The Cable Splicer is the journeyman position in the department.

Note that the Underground group does not install or maintain network equipment such as network transformers or network protectors. Network equipment construction and maintenance is the responsibility of the Substation group at HECO. The Substation group is part of the Technical Services Division of the System Operations Department.

The Overhead C&M groups at HECO also perform maintenance work with underground facilities (normally, URD facilities). The journeyman position in the Overhead groups is a lineman.

HECO has an organization focused on performing inspections. This group is part of the C&M Planning group within the UG C&M Division.

HECO also employs a position known as a Primary Trouble Man (PTM) who performs most of the switching and clearance operations on the system. The PTM, Cable Splicer and Lineman are all bargaining unit positions.

Process

Network system preventive maintenance and inspection programs include:


Program	Cycle or other Trigger
Manhole Inspection, including amp readings of molimiters.	Annual
Network Vault Inspection	2-3 years – inspected during transformer and NP maintenance
Network Transformer Maintenance (Includes Oil Sampling and Pressure Testing)	2 -3 years
Network Protector Maintenance	2-3 years

Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

5.9.12 - National Grid

Maintenance

Network Transformer Maintenance

People

Network transformer inspection and maintenance in Albany is performed by the UG field resources (network crews) that are part of Underground Lines East. This group is lead by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics, is led by three supervisors. Maintenance Mechanics perform inspection and maintenance of network equipment such as transformers and network protectors.

In addition, National Grid has a company-wide Inspections Department, led by a manager, responsible for completing regulatory required inspection programs. This group consists of supervisors assigned to the National Grid regions, and a union workforce to perform routine inspections. Note, however, that network transformer inspections and maintenance in Albany are performed by Underground Lines East maintenance mechanics.

Process

National Grid performs network transformer Visual and Operational (V&O) inspections annually as part of an annual network vault inspection. National Grid has a well documented procedure that describes the annual V&O inspection (See Attachment A). Inspections include a visual inspection of the transformer condition and performing activities such checking primary bushings and connectors for surface contamination, cracked porcelain, tracking, damaged or overheating cable elbows, checking transformer oil level and temperature, and a general condition assessment for leaks, signs of overheating, rust, and other problems or indicators. Various components are checked for overheating with an infrared thermometer.

Note that historically, transformer oil has not been sampled except when there are other indications of problems. At the time of the practices immersion, National Grid was considering implementing a five year oil sampling program to perform DGA on each fluid filled compartment of network transformers.

National Grid also obtains loading data during vault inspections.

National Grid has developed an Electrical Operating Procedure (EOP) which provides guidelines for prioritizing issues identified during inspection for repair. Various turnaround times for repair are specified depending on the categorization.

Level 1: Emergency - must be made safe within seven days.

Level 2: One year

Level 3: Three year

Level 4: Information purposes only

These levels were developed by asset and engineering groups based on past history and basic knowledge. Except for emergencies, inspections are not repaired immediately but are reported so that the inspection process can stay on task. Inspection information is entered directly into a mobile device using Computapole software, and a work order can be generated by the interface between Computapole and National Grid’s STORMS work management software (see Technology, below).

Technology

Crews use handheld devices (PDAs) to record inspection information. This unit has the required inspection information built into it, and a mapping feature. It also contains the most up-to-date system data and previous inspection results. Appropriate codes for the inspection are entered directly into the unit and returned to the supervisor for entry into the computer database. These codes alert GIS of changes in the field.

Computapole is a mobile utilities software platform that runs on handheld devices and is customized to meet National Grid’s specific needs. Computapole is used for inspections and mapping functions on handheld PDAs. Once information is entered in the Computapole system, work is managed by an interface with STORMS (below) to create work requests.

Severn Trent Operational Resource Management System (STORMS) is National Grid’s work management system. The work management system includes tools to initiate, design, estimate, assign, schedule, report time/vehicle use, and close distribution work. Computapole sends inspection information to STORMS to create work requests as needed.

5.9.13 - PG&E

Maintenance

Network Transformer Maintenance

(Network Transformer Oil Testing)

People

PG&E’s Maintenance & Construction Department is responsible for the maintenance of the underground network system in San Francisco and Oakland. All routine maintenance is undertaken at night in San Francisco in order to minimize the traffic disruption and congestion that could result from crews parking on city streets. Routine maintenance in Oakland is performed during the day.

There are normally four 3-man maintenance crews on the night shift in San Francisco, and a single 3 – man maintenance crew on the day shift in Oakland. The typical crew complement includes a Journeyman and two Transmission & Distribution (T&D) Assistants. In addition, there are crew foremen who oversee the maintenance work.

Transformer maintenance and oil sampling is performed by the maintenance crews,

PG&E has a well documented procedure for maintaining network transformers. (See Attachment G .)

Process

PG&E’s maintains and performs oil sampling and analysis annually on every network transformer. PG&E has been performing annual transformer maintenance since 2007, as part of a strategy to minimize the probability of a severe event in the network. Prior to the implementation of this strategy, PG&E had maintained transformers on a five year cycle, and did not routinely sample oil.

Since 2007, PG&E has examined sampled oil from over 3800 chambers annually. (The majority of transformers on the network system are designed with 3 chambers – the primary termination chamber, the primary ground switch chamber, and the main transformer tank chamber).

Network transformer maintenance and oil sampling are performed with the feeder de-energized.

The annual network transformer maintenance process is comprised of the following major steps:

Job Preparation
External Inspection
Oil Sampling
Pressure Testing
Completion of the Network Transformer Maintenance checklist.

The Job preparation step involves assembling appropriate materials and following all required safety precautions associated with entering the vault, such as conducting a job site tailboard, and monitoring air quality.

The external inspection begins with an inspection of the vault conditions, including the manhole cover, access ladder, vault lights, ventilation fan, sump pump, and vault floor for debris and water. This is followed by an inspection of the network transformer to check for any leaks, corrosion, ground connection issues, ground switch issues, as well as recording the temperature, oil level, and pressure (if available) of the main tank and the ambient vault temperature. (See Attachment G for a more detail on the transformer maintenance procedure.)

Oil samples are taken from each oil-filled compartment in bottles and syringes. Crews are carefully trained to follow the correct procedure for drawing oil samples so as not to contaminate the samples. For routine maintenance, information about the oil samples is entered into the Network Transformer Maintenance Checklist (See Attachment H) and will accompany the oil samples when they are submitted to the testing lab. Finally, before conducting a pressure test, the chambers are refilled, if necessary, and securely sealed. ) and will accompany the oil samples when they are submitted to the testing lab. Finally, before conducting a pressure test, the chambers are refilled, if necessary, and securely sealed.

Figure 1: Extracting an Oil Sample

Figure 2: Oil Sampling

Pressure testing of the chambers is conducted to detect internal leaks between the chambers as well as external leaks. The crews allow for a 15 minute interval between pressurizing any chamber and pressurizing the next chamber to detect internal leaks. Once all three chambers are pressurized, the crews wait for an hour to verify whether there are any external leaks. After the one hour period, pressure is reduced on all three chambers to approximately 1-2 psig.

Figure 3: Topping off a chamber

Figure 4: Pressure testing

Throughout the performance of the network transformer maintenance, findings are recorded on the Network Transformer Maintenance Checklist. (For a detailed description of the work procedures and the checklist refer to attachment G and attachment H .)

(Note: If the oil is being replaced, PG&E follows a separate procedure. An internal inspection of the chamber in which the oil is being replaced is performed, including a visual inspection of the all bushings, flanges, gaskets and hardware connections. At the conclusion of the procedure, the crews will take an oil sample that will be used as a “baseline” for future evaluations and trending for the particular chamber in question.

Oil Testing Process

The oil samples are sent to an external laboratory for analysis. At the conclusion of the testing, the laboratory forwards the results via an electronic copy both to the PG&E asset owner, and a copy is sent and recorded in a centralized PG&E database. (See Attachment k for an example of laboratory report). for an example of laboratory report).

PG&E performs the following tests:

Dissolved gas analysis (DGA)
Moisture content
Dielectric test (using ASTM D1816)
Fluid analysis to determine the percentage of oil by type in the sample

The asset owner analyzes each of the test reports, and assesses what further action is necessary. Should further action be necessary, a request is communicated to the Maintenance and Construction Department for scheduling and resolution. PG&E assigns a priority code to each request. The oil within transformer units with a high priority code is scheduled for replacement within 30 days, or where necessary, the entire transformer is replaced.

Due to the importance of the oil sampling program PG&E has undertaken additional steps to align the organization with the program. This includes:

Beginning in 2010, PG&E will begin to test the oil samples at their research and development center in San Ramon. During the transition phase to the internal laboratory, PG&E will test both internally and in an outside laboratory. This parallel testing ensures the consistency of results and provides verification for the work undertaken by PG&E’s laboratories.
Last year, the asset owner instituted an added oil identification test to identify the percentages of oils of different types in any one chamber. Historically, some chambers may have been topped off with oils of different types. This has the potential to create micro-bubbling that can generate partial discharge and prematurely breakdown the units. This oil mix also impacts the trigger levels at which action should be taken.
PG&E has contracted with an external vendor to review and make recommendations for oil sampling “triggers”. These “triggers” are the critical thresholds at which actions should be taken when certain elevated levels of gases are present in the oil. Much of the current industry thinking on these levels is based on higher voltage substation transformers. PG&E intends to develop a set “triggers” for both gas and moisture levels for lower voltage network distribution transformers that takes into consideration the type of unit as well as the type of insulating fluid used.

Technology

PG&E presently uses a manual checklist to record transformer maintenance information. They are planning to implement the use of tablet computers, where crews will enter information directly. Information would later (end of the shift) be downloaded into the main asset database.

PG&E is also planning to utilize bar codes on all of the transformer oil chambers and the network protectors. These bar codes would be used on the oil sample bottles and syringes to identify the chamber from which the sample was drawn.

PG&E is using an oil analysis system called Delta X to record and analyze oil data.

Maintenance work orders are now generated manually from PG&E’s SAP system. At the time of the immersion, PG&E was installing a work management system. This system will be tied directly to SAP, and will generate maintenance orders automatically based on network equipment maintenance procedures.

5.9.14 - Portland General Electric

Maintenance

Network Transformer Maintenance

People

The underground crews and Special Tester working in the CORE group perform inspection and maintenance of network transformers. Transformer inspections are typically performed at the same time as network protector maintenance, annually for locations with 480 V protectors, and every two years at 208 V locations.

The craft workers assigned to the CORE group, which is a part of the Portland Service Center (PSC), focus specifically on the underground CORE, including both radial underground and network underground infrastructure in downtown Portland. Their responsibility includes operations and maintenance of the network infrastructure. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

The Special Tester is a journeyman lineman with additional training and technical skills. Outside the network, Special Testers work with reclosers and their settings, and perform cable testing and cable fault location. Within the network, the Special Tester works closely with the network protectors, becoming the department expert with this equipment. PGE has embedded one Special Tester within the CORE group, who is involved in NP maintenance and in performing associated network transformer inspections.

The Special Tester usually partners with cable splicers, working as part of a crew. The “special testing” crew includes the Special Tester, a crew foreman (a cable splicer), a lineman/cable splicer, and a topman, a non-journeyman helper. The topman stays outside the hole and watches the manhole/vault entrance for potential hazards.

If crews find any significant electrical problems during inspection, they normally involve the Distribution Engineers.

Process

The typical transformer sizes on the grid network are 500 kVA or 750 KVA units. For spot networks, transformers sizes range can be 500, 750, 1000, or 1500 kVA. The spot network vaults are customer-owned and can be above or below grade, with very few above grade although all are accessible from the street as a requirement. All the equipment is submersible, and PGE uses EPR cables to the transformers. (Where lead primary cables exist, PGE uses transitions to EPR to tie into network transformers.) The network has a few older installations with spot networks on the roof. PGE has not had any catastrophic failures of transformers, attributing this in part to a lightly loaded system and the fact that it does not utilize road salts in Portland. PGE does not remotely monitor the network transformers in any way, although a system for remotely monitoring transformer temperatures is planned.

Figure 1: Spot network transformer

PGE’s network has 280 vaults that contain network transformers. Transformer inspections are typically performed at the same time as network protector maintenance, annually for locations with 480 V protectors, and every two years at 208 V locations. The inspection involves a visual inspection, recording of information from the transformer such as top oil temperature, and performing an IR scan to identify any hot spots. PGE does not use a formal inspection sheet, although readings from the protector and transformer are recorded in index cards. A crew also completes a Field Action Report if it finds issues with the vault that need follow up. If no action is needed, crews do not fill out any paperwork but notes the inspection in Maximo.

PGE is actively replacing lead cable terminations at the network transformer with Energy Services Network Association (ESNA) style connections. Crews modify the transformer termination chambers using a new conversion kit on site. First, they establish clearance. After that, crews cut the plate off the termination chamber, place a new termination, weld it, rewire the transformer, and re-energize. Crews have performed 6-12 of these conversions.

Transformer Oil Inspections: In addition to the periodic visual inspections described above, PGE does routinely sample and test oil in the network transformers. The CORE crews take the samples from all fluid-filled chambers and an external laboratory performs the analysis. Crews de-energize the primary circuit at the feeder breaker before performing oil sampling. They are not taking a clearance, as this is not considered performing physical work on the system. They try to schedule the pulling of oil in conjunction with feeder outages that may be scheduled for other reasons.

Historically, they performed oil sampling and testing on a four-year cycle, but they believe that the frequency should be more often so that they can spot trends rather than react to individual high readings. They are in the process of accelerating the sampling period and have not yet decided on a timeframe.

The type of oil analysis performed on transformer samples includes oil analysis, dissolved gas analysis (DGA), power factor testing, and polychlorinated biphenyls (PCB). PGE has started using FR3 type oil (ester) on all equipment other than the network transformers, although the change has not yet been completed. PGE will consider changing its network transformer specifications to the use of flame retardant oil alternatives in the future.

When entering the vault to perform transformer oil sampling, crews also perform a vault inspection, including a visual inspection and the use of IR.

Infrared (IR): As part of their transformer inspection program, crews perform an IR inspection of the major components with a FLIR camera. The Special Tester has more sophisticated equipment, so if the crews identify an issue, they call the Special Tester to undertake a more in-depth assessment. Crews use a feeder testing form, known as the Feeder Inspection Form,” to document any anomalies. If they find an IR anomaly, they record the load to rule out overloading as the cause.

The Special Tester also performs IR inspections of network feeders on a four-year cycle as part of the Quality and Reliability Program (QRP), a reliability-focused initiative aimed at critical infrastructure. The IR is undertaken on every component and joint, and the inspector looks for anything that shows a high temperature. The inspection is performed on every manhole and vault with cable running through it, and an inspection sheet is completed even if everything is found to be within limits. If the tester finds something abnormal, the inspector takes a picture and creates a report. The issue will be fixed within a week, and all reporting is by exception, with reports passed to the network engineering group. Most of the issues identified through IR inspection on the network have been associated with the primary terminations on the transformer.

In order to be more efficient, vault IR inspections are scheduled for the same time as the network protector/transformer inspections.

Technology

Maximo: PGE uses the Maximo for Utilities 7.5 system to manage inspection reports and store details about any maintenance needed.

Esters: PGE recently started using synthetic ester oils in transformers because they have better thermal conductivity, higher flash point, and higher temperature stability. They are miscible (a homogeneous mixture), with mineral oils and retrofitting transformers, which during service could bring longer-term cost benefits. These include higher flash point temperatures, lower fire risks, and being biodegradable, bringing environmental benefits. In addition, asset lifetime could be extended because the cellulose paper used in transformers will deteriorate more slowly. PGE plans to extend the use of synthetic ester oils to their network transformer fleet.

Remote Monitoring: PGE is not remotely monitoring transformer information. A system for remotely monitoring transformer temperatures is planned.

5.9.15 - SCL - Seattle City Light

Maintenance

Network Transformer Maintenance

People

Field crews perform network transformer maintenance as part of their network feeder maintenance

Field Crews complete a Network Transformer and Vault Inspection form, See Attachment I , for each transformer or switch vault inspected.

Process

Network Feeder Maintenance

When the field crews are sent out on feeder maintenance, they are issued a “maintenance package” that may include:

copies of a feeder map from their NetGIS system
“cut sheet,” which is a written description of the equipment in the vault produced from NetGIS, SCL’s in-house Oracle database
job orders for the work to be performed
field copy of the clearance contract
any urgent maintenance slips documenting items for maintenance that had been previously identified, but not resolved
Network transformer and switch vault inspection forms
Oil test report form, for recording information associated with the oil tests of the transformer switch and terminal chambers
maintenance checklist
copy of the previous device maintenance reports, or for newer equipment, a copy of the device install card (this allows crews to identify and track any ongoing problems or repairs form prior maintenance)
insulating oil test report (during feeder maintenance, crews take main tank oil samples. These are tested by SCL’s in-house lab, and an oil test report is issued and returned to the maintenance crew before the feeder is reenergized)
Earthquake Anchors for Network transformer order form, used to replace older I-beam supports with earthquake rails
prior Hi-pot test reports

Feeder maintenance includes a general inspection of the condition of the vaults, as well as performing network transformer inspection and maintenance. The maintenance requirements are defined in the SCL Vault and Transformer Maintenance Manual. See Attachment H .

Crews complete a Network Transformer and Vault Inspection form for each transformer or switch vault inspected.

Crews perform tests on each network transformer during feeder maintenance. Crews take oil samples from the transformer and the primary switch chamber. SCL maintains its own oil testing laboratory. They perform an acid test, interfacial tension testing, and dielectric testing of the oil. They do not do dissolved gas analysis.

Air switches and SF ₆ switches are visually inspected. A vacuum pressure test is performed on vacuum switches (only five of them are in the system).

Technology

Maintenance records are kept in an Oracle-based database developed by SCL. This database is tied in with NetGIS, their network records and mapping database. This allows SCL to access feeder maps, vault information, inspection and maintenance records, and photographs of the vaults.

5.9.16 - Practices Comparison

Practices Comparison

Maintenance

Transformer Oil Testing

5.9.17 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 9.3.8 - Test Procedures and Schedules

5.9.18 - Survey Results

Survey Results

Maintenance

Network Transformer Maintenance

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 25 : Please indicate if your company performs the following Maintenance activities on a routine basis and at what frequency.

Question 26 : If you perform distribution transformer oil sampling and testing (network and non-network), have you established trigger points for action based on oil sampling results?

Survey Questions taken from 2018 survey results - Asset Management survey

Question 8 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Survey Questions taken from 2015 survey results - Maintenance

Question 85 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Question 90 : If you perform equipment fluid sampling and testing, please indicate which of these tests are performed? (check all that apply)

Survey Questions taken from 2012 survey results - Maintenance

Question 6.20 : Do you perform Equipment Fluid sampling and testing (such as transformer oil) as part of your maintenance?

Question 6.21 : If yes, what is the frequency of sampling?

Question 6.22 : If yes, please indicate which tests you perform

Question 6.23 : Do you regularly perform pressure testing to identify leaks in the primary termination chamber, ground switch chamber, and/or transformer tank?

Question 6.24 : If yes, what is the frequency of testing?

Survey Questions taken from 2009 survey results - Maintenance

Question 6.26 : Do you perform Equipment Fluid sampling and testing (such as transformer oil) as part of your maintenance? (This question is 6.20 in the 2012 survey)

Question 6.27 : If yes, what is the frequency of sampling? (This question is 6.21 in the 2012 survey)

Question 6.28 : If yes, please indicate which tests you perform (This question is 6.22 in the 2012 survey)

Question 6.30 : Do you regularly perform pressure testing to identify leaks in the primary termination chamber, ground switch chamber, and/or transformer tank? (This question is 6.23 in the 2012 survey)

Question 6.31 : If yes, what is the frequency of testing? (This question is 6.24 in the 2012 survey)

5.10 - Network Transformer Replacement Criteria

5.10.1 - Ameren Missouri

Maintenance

Network Transformer Replacement Criteria

People

Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. As part of this group’s role, they are examining Ameren Missouri’s practices for inspecting and maintaining network infrastructure, and developing recommendations for optimal approaches.

They have developed a draft criteria used to evaluate, manage, and prioritize replacement of network transformers and protectors within downtown St. Louis. These criteria are based on key considerations such as the transformer’s age, location, physical condition, loading, history with similar transformers styles, and oil quality. Note that at the time of the EPRI practices immersion these criteria were in draft form.

See Network Revitalization

Process

As part of its transformer replacement criteria, Ameren Missouri has developed a Network Transformer Replacement Criteria Scorecard, used to score the relative severity of non-field repairable issues identified in Ameren Missouri’s biennial network transformer inspections.

Each time a network transformer is inspected, data from the inspection is recorded on a network transformer inspection form. This information is entered into the scorecard contained within a database.

Each transformer’s scorecard in the database is updated when any criteria change as identified through inspection or any other means. Note that this database also contains engineering data for the network transformer and protector, such as dimensions, serial numbers, etc.

The scorecard itself enables an Ameren Missouri asset manager to assign a score to each of 12 different categories based on inspection findings. Each category is weighted, and the scorecard provides guidance to the Ameren Missouri inspector or asset manager in assigning an appropriate score.

As an example, one of the categories to be considered on the scorecard is the transformer age. The scorecard provides guidance to the inspector in assigning an “age score" based on the transformer’s age by providing the following criteria:


Score	Observation
10	If > 60 years or age is unknown
9	If 51 to 60 years old
6	If 41 to 50 years old
3	If 31 to 40 years old
1	If 21 to 30 years old
0	If = or < 20 years old

The age score is weighted and combined with the other inspection scores to produce an aggregate score which is used to prioritize replacement of transformers.

The categories which are included in the scorecard, and are thus considered in determining an overall transformer score are:

DGA & Oil Quality Analysis Results (oil quality analyses include Total Acid Number (TAN), Interfacial Tension (IFT), oil dielectric, and water content).
Leaking
Primary switch problems
Located in high traffic area
Corrosion
Loading
Age
Protector Problems or Protector Technology Change
Lead-cable termination compartments
Exposed to high fault current
Non-Standard Voltage Taps
Oil Type

The Ameren Missouri criteria document and scorecard provides guidance for scoring each of these categories based on inspection findings.

Technology

Information from the transformer inspections performed by the Distribution Service Testers is updated in the Ameren Missouri’s Circuit and Device Inspection System (CDIS) by the Underground Engineering group. The CDIS includes an algorithm that assigns a “structural score” and an “electrical score” based on the inspection findings, scoring, and weightings for various findings developed by Ameren Missouri. The scores are used to prioritize remediation.

CDIS is also used to produce reports that summarize inspection findings and a dashboard that monitors inspection progress

See the Attachment for draft copy of the Ameren Missouri Network Transformer Replacement Criteria Scorecard^[1] .

^[1] from Ameren Missouri Transformer Replacement Criteria Draft , developed by the Downtown St. Louis Underground Revitalization Team.

5.10.2 - Duke Energy Florida

Maintenance

Network Transformer Replacement Criteria

People

Power Quality, Reliability and Integrity (PQR&I) has responsibility for all Asset Management at Duke Energy Florida. Within that department, network assets within Florida, including network transformers, are managed by three Asset Managers.

Process

Duke Energy Florida uses a Qualitrol transformer sensor module to monitor transformer oil level and temperature, as well as the Oil Minder system associated with the vault sump pump.

Duke Energy has recently teamed with Qualitrol to pilot an installation of a dissolved gas monitor at one transformer location. The monitor itself fits into the drain port of the transformer and is tied into the Qualitrol receiver. Their goal is to build an algorithm that considers transformer vintage, DGA results, etc., and uses that information to trigger replacement.

Technology

Duke Energy Florida monitors network transformer and vault information in Clearwater using a system by Qualitrol.

5.10.3 - Energex

Maintenance

Network Transformer Replacement Criteria

See Network Underground Refurbishment

5.10.4 - ESB Networks

Maintenance

Transformer Replacement Criteria

People

Network design at ESB Networks, including transformer replacement criteria, is performed by planning engineers within the Network Investment groups – one responsible for planning network investments in the North, and the other for planning in the South.

Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Network design standards and transformer replacement criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

As a part of its five-year planning cycles, ESB Networks has multiple capital replacement programs to identify and replace aging transformers. It is also systematically modernizing and standardizing its systems. For example, it is in the process of replacing rural 10-kV transformers with 20-kV transformers as part of its conversion to 20kV.

Also, although most of Dublin’s transformers are pad-mounted or located in building vaults, it must still replace a few remaining submersible transformers in the Dublin area.

5.10.5 - Survey Results

Survey Results

Maintenance

Network Transformer Replacement Criteria

Survey Questions taken from 2018 survey results - Asset Management survey

Question 26 : Are you implementing targeted replacement programs for any of the following equipment?

Question 27 : If Yes, are any of your replacement programs Aged based, such as replacing all transformers >50 years old?

Question 28 : If Yes (to question 26), are any of your replacement programs Design based, such as replacing all high rise fluid filled transformers with dry type units, or replacing a certain type of cable?

5.11 - Network Vault Inspection - Maintenance

5.11.1 - AEP - Ohio

Maintenance

Network Vault Inspection - Maintenance

People

Vault inspections are performed on a one-year cycle and are normally combined with inspection of network equipment, which is also inspected on a one-year cycle. Inspections may be performed by Network Mechanics, Network Crew Supervisors, and contractors. Contractors are used to make civil repairs identified through inspection.

Process

All vaults are inspected on a yearly basis as part of the AEP Ohio electrical equipment inspection schedule. More specifically, inspections include:


Clean and inspect	1 year
Power wash as needed	As needed
Check ventilation fans	Between May and September
Check and pump water	After a major rain storm
Check for equipment oil leaks	1 year
Take counter/oil level/temp readings	First month, then 1 year
Check limiters (current readings)	1 year
Perform infrared inspection	1 year – 20% of vaults

(See Attachment E for a sample Vault Inspection Form.)

Technology

Crews use a modified bread truck for inspections, which includes equipment for pumping out any water in manholes. A practice of note is the organized and well-equipped features of these trucks. AEP Ohio has configured and modified these trucks to its own specifications (see Figures 1 and 2).

Figure 1: AEP Ohio 'bread' truck with easy-access, low tailgate

Figure 2: AEP Ohio 'bread' truck – interior view

Crews have computers in every truck. Printed and online forms are available. Conditions of the manhole are captured in the AEP NEED (Network Enclosure and Equipment Database). When information is entered into NEED, repair or replacement priorities are noted.

AEP Ohio performs an inspection using infrared thermography (IR) every time a worker enters a vault (see Figures 3 and 4). This inspection is being performed as a manhole entry safety practice, and has been in place for about five years. IR cameras are used to identify hot spots in the vault, with inspectors “shooting” joints, crabs, and cables. The rule of thumb for action is if a spot on a joint, for example, shows a difference of 40 degrees C or more, then crews will replace the joint. AEP Ohio employees noted that early on they identified and rectified problems, but that now, they rarely encounter hot spots.

Figure 3: AEP Ohio Network Mechanic using infrared camera

Figure 4: Infrared camera

5.11.2 - Ameren Missouri

Maintenance

Network Vault Inspection - Maintenance

People

The majority of the maintenance and inspection programs associated with network equipment, including vault inspections, are performed by resources within the Service Test group.

Organizationally, the Service Test group is part of Distribution Operations, led by a manager. Within Distribution Operations, there is a Reliability Support Services group led by superintendent. Reporting to the Superintendent Reliability Support Services are both the Service Test group led by a supervisor and the Distribution Operating group, also led by a supervisor.

The Service Test group is made up of Service Testers and Distribution Service Testers. It is the Distribution Service Testers who perform vault inspections, as well as network protector maintenance and calibration, and transformer maintenance including oil testing. The Service Testers perform low-voltage work only, such as voltage complaints, RF interference complaints, and testing and maintaining batteries.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. As part of this group’s role, they are examining Ameren Missouri’s practices for inspecting and maintaining network infrastructure, and developing recommendations for optimal approaches. They have developed a draft document which details strategies for inspection and maintenance of network units, cable systems, vaults, manholes, indoor rooms and customer switchgear.

Process

The Missouri Public Service Commission (PSC) requires that a visual inspection of vaults in urban areas be performed on a four year cycle. Ameren Missouri prepares reports and issues reports to the PSC that document its performance of regulatory required inspection programs.

For network vaults, Ameren Missouri is exceeding this requirement, entering each vault annually to perform and record cable limiter continuity measurements, and entering each vault every two years to perform a detailed inspection in conjunction the performance of transformer and network protector maintenance.

Each spring, prior to the summer heating season, Distribution Service Testers (2 man crews) enter each network vault to conduct secondary cable load and voltage measurements in order to identify open limiters. Crews also record temperature readings. Information is recorded on an inspection form. Note that at the time of the practices immersion, Ameren Missouri was considering, but not performing infrared scans as part of this inspection.

Every two years, Distribution Service Test crews enter each network vault to perform a detailed visual inspection as well as perform network transformer and network protector maintenance.

The visual inspection includes the following steps:

Record the vault number, address/location.
Visually inspect and photograph the vault and note the following structural and electrical information:
- Grating sits flush and is not worn or deformed
- Safety cage opens properly and sits well when opened
- Inspect the ceiling for any cracking, bulging and water leaks. Capture the total amount of cracks and describe the widest and longest crack
Inspect the walls for any cracking, bulging, water leaks or if any of the wall is missing. Capture the total amount of cracks and describe the widest and longest crack
The type of floor material, its finish, how it drains and any cracking.
Visually inspect the bus bars for rust or cracks and check to see that the supports are secured to the ceiling.
Note if the wall is painted and the condition of the epoxy paint.
Visually inspect that the cable supports are secured to the wall.
Inspect the network monitoring equipment for proper operation.
Note any excessive debris on the floor that could be due to collapsing walls or ceiling or if it is debris from public.
Record the type of lighting in the vault and replace any burnt out bulbs.

Ameren Missouri has developed a Structural Inspection Training Manual for Vaults, a guideline that guides Distribution Service Testers in performing visual inspections of vault structures. See Attachment I

When performing the biennial inspection of network vaults, Distribution Service Testers take photographs of the vault interior and record this information on computers.

The biennial inspection also includes transformer maintenance and oil sampling from the transformer and switch compartment tanks, and protector maintenance and calibration.

Ameren Missouri has a separate program for sampling the oil of the primary termination compartment on the network unit. These samples are taken with the primary feeder de-energized.

Indoor Rooms, which are building vaults supplied with non - network service types typically fed with dual feeds (preferred / reserve schemes), are inspected on a 4 yr cycle. These inspections include visual inspections of the transformers, switches and vault condition. The inspections also include heat gun checks to identify any hot spots.

Information from the indoor room inspections are recorded on inspection forms.

Ameren Missouri is not performing transformer oil testing of non-network transformers.

Technology

Inspection of Network Vaults and Service Compartments (adjacent manholes with bus work) is recorded on laptops or on paper forms by the Distribution Service Testers. Pictures and inspection findings recorded on manual forms are entered into both local databases and into the Circuit and Device Inspection System (CDIS) by the Service Test department. (This is the same software used by contractors to record information from Ameren Missouri’s manhole inspection program)

The CDIS includes an algorithm that assigns a “structural score” and an “electrical score” based on the inspection findings and weightings for various findings developed by Ameren Missouri. The scores are used to prioritize remediation.

CDIS is also used to produce reports that summarize inspection findings and a dashboard that monitors inspection progress.

Ameren Missouri has installed a remote monitoring system within their network vaults. This system uses ETI electronic metering in the network protector relay with monitoring points aggregated in a vault wall mounted box that communicates via wireless. Their monitoring includes voltage by phase, amps by phase, protector status, transformer oil top temperature, and water level in the vault. Note that Ameren Missouri is not using fire alarm systems within their network vaults.

Information from the vault can be accessed on the computer, provided by a third party service provider (Telemetric). The system also enables Ameren Missouri to request status by polling the protectors. Finally, the system provides the ability to look at historical readings for analysis.

At the time of the practices immersion, Ameren Missouri was piloting the use of an arc detection tool (the Exactor. 80 of their network manholes were surveyed with the tool. Ameren Missouri had previously used this technology on their overhead system. Initial findings showed three of the 80 locations with some level of arc emissions.

Figure 1: Indoor Room transformer

Figure 2: Indoor Room primary switch (S\&C Metal Enclosed Mini-Rupter Switch

Figure 3: Typical Network Vault - Primary side

Figure 4: Typical Network Vault - Secondary

Figure 5: Wireless communication box for network monitoring system

Figure 6: ETI Microprocessor NP Relay

5.11.3 - CEI - The Illuminating Company

Maintenance

Network Vault Inspection - Maintenance

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who inspect and maintain the underground system.

Process

Network vaults are being inspected every six months. The inspection is similar to the manhole inspection in that it includes a visual inspection of the equipment contained with in the vault, such as cables, splices, moles, and sump pumps, as well as the condition of the vault itself.

The network transformer will be inspected for oil leaks, corrosion, etc.

Inspectors are to take amperage readings of secondaries on the load side of cable limiters to assure cable limiter continuity. In practice, this is sometimes done, and sometimes overlooked.

During the inspection, the vault will be cleaned of any debris.

Any urgent findings are immediately addressed. Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service.

Technology

Vault inspection / maintenance results are recorded manually on a Network Vault inspection/maintenance forms.

(See Attachment M) and Attachment N). ).

5.11.4 - CenterPoint Energy

Maintenance

Network Vault Inspection - Maintenance

People

Vault Inspections are performed by the Relay group within Major Underground. The Major Underground organization includes Key Accounts, Engineering and Design resources, Support Services, and the field force responsible for all construction, operations and maintenance activities. The field force is divided into two main groups, the Relay group and the Cable group.

Both the Relay group and Cable group perform maintenance and inspection activities. The Relay group focuses on most of the non cable equipment inspection and maintenance, including performing vault equipment inspections, network protector testing, and other inspections and maintenance on devices with relays or motor operators. The Cable group focuses on inspections of cable, cable accessories and major equipment.

The Relay group is comprised of Network Testers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. The Relay group is led by an Operations Manager.

CenterPoint does not have dedicated maintenance crews. Rather, maintenance and inspection work is assigned to crews based on work priorities and resource availability.

Process

The Relay group performs periodic vault inspections, with most inspections on an annual period. Some high priority locations are inspected two or three times per year. The inspections are performed without de-energizing the vaults.

The inspections include a visual inspection of the vault, infrared inspection of all connections including bus connections and cable connections, load measurements; and operating equipment that can be operated without interrupting customers, such as tripping and closing network protectors.

Network vault inspections will include a visual inspection of the network transformer for oil leaks, corrosion, etc. They will also record peak temperature from the transformer temperature gauge. CenterPoint does not test network transformer oil as part of their network vault inspections, unless there is an indication of a potential problem such as a high temperature reading.

During the inspection, the vault will be cleaned of any debris.

CenterPoint is using an inspection checklist to guide inspectors through the various items included in the inspection. This same checklist, entitled MUDG Functional Location Inspection Sheet is used to record findings from all inspection types, including the network vault inspections. An inspection sheet is completed for every location inspected.

Inspection findings that require follow up corrective maintenance are noted and recorded by the Crew Leaders who schedule this work for completion. Non urgent corrective maintenance actions that are identified during inspection may be held to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

If the solutions to the findings require the involvement of other groups, the Crew Leaders will solicit their help. For example, corrective maintenance activities that require a customer outage will require the assistance of the Key Accounts group to coordinate with the customer to schedule the outage.

The inspection sheets are filed by work center (each vault is considered a work center), so that CenterPoint has a record of the historic findings.

Technology

Vault inspection results are recorded manually on the MUDG Functional Location Inspection Sheet, See Attachment I .

Vault inspections include the performance of infrared thermography.

5.11.5 - Con Edison - Consolidated Edison

Maintenance

Network Vault Inspection - Maintenance

People

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including:

Inspections/manhole inspections
Post-construction inspections to determine to adherence to Specifications
Safety inspections
Critical manhole inspections, performed in any manhole on the immediate block of a substation, and inspected on a three-year cycle
Regular manhole/vault inspections, scheduled every five years
- Infrared inspections of transformers/network protectors/substations
- Infrared is a four-year cycle for 277/480-V installations.
- Infrared is not programmatic, but is performed randomly, or by exception at 120/208 V. Infrared inspections are performed more frequently at sensitive customer locations such as hospitals and museums.
- Substation infrared is annual.
- Use strategically placed site glasses to obtain infrared views of some locations.
- Use outside contractor to perform infrared training.
Cable and Joint failure analysis specimen retrieval and tracking
Fill-in work, special requests
Check out erroneous readings monitored through the RMS system
Map verification; that is, comparing what is on the mapping system to what is in the field
Random spot checks, focused on workmanship
Random equipment checks
- For example, the Field Engineering group performs random monthly spot checks of primary splice packs to be sure that the kit is complete.
Respond to voltage complaints

Note: This group does not routinely inspect design versus build, or as-built versus mapped.The department is made up primarily of Splicers. People are chosen for jobs in the department by seniority.

Process

Inspection and Maintenance

Con Edison performs periodic maintenance and inspection of network distribution equipment, including network feeders, transformers, network protectors, grounding transformers, shut and series reactors, step-down transformers, sump pumps and oil minder systems, remote monitoring system (RMS) equipment, and vaults, gratings, and related structures.

Con Edison’s approach to performing an inspection is to inspect all the equipment and structures associated with a particular vault ID at a location regardless of category or classification, and even if the particular equipment associated with a particular vault ID resides within different compartments (for example, a transformer and network protector may be located in separate physical compartments even though they both share the same vault ID). This type of inspection is referred to as a CINDE Inspection, based on the name of their maintenance management system (Computerized Inspection of Network Distribution Equipment).

Con Edison performs inspections energized; crews do not take a feeder outage to perform inspections, perform pressure drop testing, or take transformer oil samples. Con Edison does not routinely exercise feeder breakers.

In an effort to more efficiently use their resources, and when nonpriority conditions allow, Con Edison takes advantage of situations where they have to enter a vault or manhole for a reason other than a scheduled inspection, and perform a nonscheduled inspection while they are in the vault. When the record of this nonscheduled inspection is recorded in CINDE, the system “resets the clock” for the next inspection date.

Network equipment at 208 V is generally inspected on a 5-year cycle. 460-V facilities, sensitive customers, facilities in flood areas, and other more critical locations are inspected more frequently, often annually. Con Edison establishes network equipment inspection cycles depending on two factors: the inspection category and the inspection classification .

The inspection category refers to the type of inspection, and includes a Visual Inspection, a 120/208-V Test Box Inspection, and a 460-V Test Box Inspection. The Visual Inspection includes activities beyond visually assessing condition and recording information, such as pressure drop testing and taking transformer oil samples. The test Box inspections involve specialized testing of network protectors with the network relay installed. Note that all of the elements of a Visual Inspection are performed along with the Test Box Inspections.

The inspection classification refers to characteristics of the inspection site that dictate the inspection cycle. For example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a “tidal” area would be visually inspected annually. Con Edison considers the following classifications in determining inspection cycles:

Routine
Back-feed: banks installed on a feeder involved in a back-feed incident
Candidate for Replacement: commonly due to corrosion damage
Essential Services: critical customers
Flooded Bank: nonsubmersible equipment that has experienced high water levels
208-V Isolated Bank: units that require more frequent inspection than distributed secondary grid units
Remote Monitoring System(RMS), Non RMS, Unit Not Reporting (UNR): Con Edison varies inspection cycles based on the level of remote monitoring installed
Tidal, Water, and Storm Locations

Note that Con Edison requires employees to perform at least a quick visual inspection (QVI) anytime an individual enters a network enclosure, even if the reason for entering an enclosure does not warrant a CINDE Inspection. This type of inspection (QVI) differs from the CINDE inspection category of Visual Inspection described above, in that it is not a full, accredited inspection.

Technology

Inspection and Maintenance Software

Con Edison uses legacy maintenance management software called CINDE, which is an acronym for Computerized Inspection of Network Distribution Equipment. CINDE is a system that records inspection data and initiates inspections based on predetermined cycles. These cycles depend on the category of inspection (for example, a visual inspection versus a “Test Box” inspection) and various predetermined classifications of inspections (for example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a tidal area is visually inspected annually).

Con Edison inspectors record inspection data on hand-held devices (Tough Books). The utility requires that the inspection data be downloaded into the CINDE – Mainsaver system (Mainsaver is the part of the CINDE system used to record data) within three days following the inspection. Inspection data that is entered into the CINDE system includes:

Equipment serial numbers
As-found and abnormal conditions, such as transformer oil level, state of corrosion, and water in the vault
Defective equipment or structures
Repairs or change-outs undertaken
As-left condition, such as transformer pressure and liquid level, and pressure of housing

The CINDE – Mainsaver system is also used by Con Edison to prioritize follow-up work, or outstanding defects to be corrected that are identified through inspection or other visits to network enclosures. The Electric Operations Region is responsible for prioritizing follow-up work by considering the location of the work with respect to risk to public safety, reliability impact, the type of installation, age of the outstanding defect, and the efficient use of resources.

5.11.6 - Duke Energy Florida

Maintenance

Network Vault Inspection - Maintenance

People

Vault inspections are performed by craft workers, Network Specialists and Electrician Apprentices within the Network Group, part of the Construction and Maintenance Organization. The Network Group is led by a supervisor, and consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position).

Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager.

The Network Group is organized functionally, and has responsibility for construction, maintaining and operating all urban underground infrastructure (ducted manhole systems), both network and non - network, in both Clearwater and St. Petersburg.

Process

The vault inspection cycle varies depending on location and on equipment housed in the vault. For vaults that are part of the Clearwater network and house the network unit, Duke Energy Florida inspects each vault three times per year. In St. Petersburg, the spot network vaults are inspected annually. For vaults that contain network feeder sectionalizing switches, or automatic transfer switches in Clearwater and St. Petersburg, the inspection frequency varies from annually to up to six times a year, based on the vault condition and criticality of the devices (for example, switchgear associated with hospitals are inspected and maintained from three to six times per year).

Vault inspections are comprehensive, and include vault cleaning, assessment of the civil infrastructure, visual inspection and recording of information from the network transformer and network protector including loading, and visual inspection of cables and other components. Vault inspections also include infrared thermography (IR) and recording of IR measurements. See Attachment I .

Information from the inspection is recorded on an inspection form, including an assessment of the priority or severity of the finding. See Attachment I . Information from the inspection is entered into a computer system, and the hard copy form is maintained in a file. Duke Energy Florida has a “Further Work Ticket Process” which is initiated to pursue remediation for corrective maintenance items identified by inspection. The repair schedule is dictated by the priority of the finding. For example, a leaky transformer must be reported to the environmental group within 24 hours of discovery and repaired within 30 days.

Technology

Duke Energy Florida is not performing network transformer oil sampling and testing as part of their vault maintenance process. They are considering re instating oil sampling and testing and are experimenting with transformer dissolved gas sensing tied in with their Qualitrol system at one location.

5.11.7 - Duke Energy Ohio

Maintenance

Network Vault Inspection - Maintenance

People

Duke Energy Ohio performs network vault inspections quarterly. The inspections are performed by Dana Avenue Network Service Person field crews.

Inspection findings are recorded on a vault inspection sheet.

Duke does not vary its inspection cycle based on an assessment of the Vault criticality (high risk holes versus low risk holes). However, Duke Energy Ohio will, at times, restrict its inspection to a review of the high-priority items within the vault.

Process

In advance of performing the vault inspection, Duke will provide the inspection crew a copy of the vault inspection sheet, which is a form pre-populated with certain information about the vault, its contents, and its condition. See Attachment G for a sample blank Vault Inspection Sheet.

The vault inspection includes an assessment of the general condition of the vault, recording of the readings from the gauges on the transformer, checking the protector readings, and counting the protector trips. The quarterly inspections do not include taking current or voltage readings, or obtaining transformer oil samples. Note that Duke Energy Ohio is sampling transformer oil as part of a separate, four year program.

Technology

Vault inspection forms and findings are maintained in an Excel file. This is an interim file, with inspection findings them being installed in the Emax system.

5.11.8 - Georgia Power

Maintenance

Network Vault Inspection - Maintenance

People

Vault Inspections may be performed by either Duct Line Mechanics or Cable Splicers who report to the Maintenance supervisor (a Distribution supervisor), within Network Operations and Reliability. Although the Georgia Power Network Underground group does not have specific crews assigned to vault inspections, the maintenance group will pull available crew members to maintain its inspection schedule for vaults. A typical maintenance crew is comprised of a Senior Cable splicer, Cable Splicer and a WTO. The maintenance crews report to a Distribution Supervisor, who is part of the Network Operations and Reliability group. The Network Operations and Reliability group is responsible maintenance and operation of the network system.

Process

All vaults are inspected on a five-year basis, throughout the state of Georgia. Prior to inspections, the supervisor uses an Access database program to generate a blank form already populated with some specifics about the configuration of the particular vault to be inspected, if a crew has populated the data base with information during construction or during a previous inspection. The printed inspection form does not have previous findings pre populated, assuring that the field crews must perform and record an updated inspection. Once completed, the form is populated into the Access system. Forms are retained in hard copy for seven years.

The inspection form has a well-defined checklist of items that must be inspected, including the following:

Inspection of the vault grates, where applicable.
Structural inspection of the roof slab, duct base, and duct lines.
Air Quality check to make certain there are no toxins or gas buildup.
Transformer inspection and maintenance (See Transformer Maintenance)
Electrical inspection, including any street mains / secondary cables. If cables are not tagged or tags are missing, the inspection crew tags them on the spot. Street mains are not tagged. Cable tags are placed on the primary cables and on customer services.
Network protector may be inspected as well, although a separate crew is responsible for protector inspection and maintenance, as part of a distinct maintenance program. (See Network Protector Maintenance)
Condition of cable splices is noted.

(See Attachment F)

A notable exception to the vault inspection frequency is the Atlanta airport, which is inspected yearly, along with other select high-priority sites. Nearly 20 percent of all inspections occur outside the Atlanta metro area in other regions where Georgia Power has network underground installations.

If the vault contains water, crews must pump out the water prior to entry. Most vaults have sump holes, and a portable pump can be dropped into the hole. Water is typically pumped through a special filter sock to trap any oil in the water before pumping it into the street. Georgia Power has very few vaults with permanent sump pump installations (See Figure 1.).

Figure 1: Sump hole in vault

If work needs to be performed, the supervisor of the crew determines whether the maintenance can be performed on-the-spot; otherwise, a maintenance work order is sent in by the supervisor, including notes and a prioritization of the maintenance. It is up to the supervisor to determine how critical the maintenance or repair is, and the inspection form reflects the priority, as well as direct communication with the appropriate workgroup within Network Underground.

Georgia Power’s Operation and Test procedure for Manhole and Vault Maintenance specifies three levels of priority for inspection times. The procedure does not specify time frames for completion of corrective maintenance.

Priority # 1 - the most urgent, and requires immediate attention

Priority # 2- needs attention very soon

Priority # 3- needs attention when it can be scheduled

Technology

When a supervisor enters inspection information into the Access database, and the inspection indicates that something needs repair, the system will create a maintenance order automatically.

The inspector receives a monthly report of the pending corrective maintenance jobs.

Where possible, the inspection information can also be entered into the DistView software system. With DistView, inspectors can log onto the company intranet with a wireless laptop and enter data about inspections into pre-determined fields and also add notes as findings are top-of-mind at the site and time of the inspection.

Georgia Power does not perform an infrared inspection as part of its routine vault inspection. However, infrared thermography is performed at high profile locations. Georgia Power does not routinely take and record photographs of inspection findings.

5.11.9 - HECO - The Hawaiian Electric Company

Maintenance

Network Vault Inspection - Maintenance

People

HECO Substation resources perform maintenance and inspection of network equipment.

HECO currently is not performing any programmatic inspection and maintenance of their non-network underground facilities.

Process

Network system preventive maintenance and inspection programs include:


Program	Cycle or other Trigger
Manhole Inspection, including amp readings of molimiters.	Annual^[1]
Network Vault Inspection	2-3 years – inspected during transformer and NP maintenance
Network Transformer Maintenance (Includes Oil Sampling and Pressure Testing)	2 -3 years
Network Protector Maintenance	2-3 years

Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

^[1] HECO’s desired schedule is to perform these inspections and take amp readings annually. In practice, they have not adhered to this schedule.

5.11.10 - National Grid

Maintenance

Network Vault Inspection - Maintenance

People

Network vault inspections in Albany are performed by the UG field resources (network crews) who are part of Underground Lines East. This group is led by a Manager, and includes a group focused on civil aspects of the underground system and a group focused on the electrical aspects. The Underground Lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics is led by three supervisors. Maintenance Mechanics perform network vault inspections and maintenance of network equipment contained in the vaults such as transformers and network protectors.

In addition, National Grid has a company-wide Inspections Department, led by a manager, responsible for completing regulatory required inspection programs. This group consists of supervisors assigned to the National Grid regions, and a union workforce to perform routine inspections. Note, however, that network vault inspections within Albany, as well as inspection and maintenance of network equipment contained within the vaults, is performed by two- person Maintenance Mechanic crews from Underground Lines East.

National Grid is not using dedicated full time maintenance crews; rather, they schedule maintenance as a work assignment along with other work types.

There are 251 network vaults within New York East.

Process

Regulatory mandates in the State of New York require National Grid to inspect their distribution plant on the five-year cycle. Network vaults however, because of their criticality, are inspected annually.

National Grid has a well documented procedure that describes the annual vault inspection, performed as part of the Visual and Operating inspection of the network transformer and protector (See Attachment A ). The inspection includes a visual inspection of the network unit, described more fully in the Network Protector Maintenance and Network Transformer Maintenance sections of this report, as well an inspection of the vault itself including items such as:

Lighting
Condition of Primary and Secondary Cables
Ground/Neutral Wires and Connections
Emergency Escape Hatch, if equipped.
Vault Roof
Blowers/Fans
Vent Stacks
Anode System
Structure
Gratings
Ladders
Water
Buss Work
Cleanliness
Sump pumps, including assuring that automatic sump pumps are equipped with a filter and an oil sensor that shuts off the pump in the presence of oil

All separable connections are checked with an infrared thermometer.

National Grid also obtains loading data during vault inspections.

National Grid also performs elevated (Stray) voltage testing using hand held E-field directional testers during the annual inspection. Stray voltage testing is mandatory in New York in cities with populations over 500,000; National Grid is performing this testing in Albany)

National Grid has developed an Electrical Operating Procedure (EOP) which provides guidelines for prioritizing issues identified during inspection for repair. This EOP provides guidance to the inspectors as to how to categorize certain findings. The inspector is free to “upgrade” the severity of the finding based on his field assessment. For example, the guidelines may indicate that a leaking joint should be a “Level 2”. The inspector may elect to upgrade to a “Level 1” based on field conditions.

Various turnaround times for repair are specified depending on the categorization.

Level 1: Emergency - must be made safe within 7 days.

Level 2: One year

Level 3: Three year

Level 4: Information purposes only

These levels were developed by asset and engineering groups based on past history and basic knowledge. Note that except for emergencies (Level 1), inspections are not repaired immediately but are reported so that the inspection process can stay on task. Inspection information is entered directly into a hand held device using Computapole software. A work order to perform follow up corrective maintenance can be generated by the interface between Computapole and National Grid’s STORMS work management software (see Technology, below).

For checklists associated with the V&O Inspections, see Attachment B .

Technology

Crews use handheld devices (Symbol Units, part of Motorola) to record inspection information. This unit has the required inspection information built into it, and a mapping feature. It also contains the most up-to-date system data and previous inspection results. Appropriate codes for the inspection are entered directly into the unit and returned to the supervisor for entry into the computer database. These codes alert GIS of changes in the field.

Computapole is a mobile utilities software platform that runs on handheld devices and is customized to meet National Grid’s specific needs. Computapole is used for inspections and mapping functions on handheld devices. Once information is entered in the Computapole system, work is managed by an interface with STORMS (below) to create work requests.

Severn Trent Operational Resource Management System (STORMS) is National Grid’s work management system. The work management system includes tools to initiate, design, estimate, assign, schedule, report time/vehicle use, and close distribution work. Computapole sends inspection information to STORMS to create work requests as needed.

Figure 1: Network unit in vault

Figure 2: Sump pump installation

5.11.11 - PG&E

Maintenance

Network Vault Inspection - Maintenance

People

PG&E’s Maintenance & Construction Electric Networks department is responsible for the maintenance of the underground network system in San Francisco and Oakland. All routine maintenance, including vault inspections, is undertaken at night in San Francisco in order to minimize the traffic disruption and congestion that could result from crews parking on city streets. Routine maintenance in Oakland is performed during the day.

There are normally four 3-man maintenance crews on the night shift in San Francisco, and a single 3 – man maintenance crew on the day shift in Oakland. The typical crew complement includes a journeyman and two Transmission & Distribution (T&D) Assistants. In addition, there are crew foremen who oversee the maintenance work.

Vault inspections, performed by the maintenance crews, are conducted in conjunction with the transformer maintenance and oil sampling program. See Transformer Maintenance / Oil Sampling.

PG&E has a well documented procedure for maintaining network transformers that includes vault inspection. ( See Attachment G.)

Process

PG&E inspects network vaults annually as part of the network transformer maintenance process. That process consists of the following major steps:

Job Preparation
External Inspection
Oil Sampling
Pressure Testing
Completion of the Network Transformer Maintenance Checklist.

The job preparation step involves assembling appropriate materials and following all required safety precautions associated with entering the vault, such as conducting a job site tailboard, and monitoring air quality.

Step two, external inspection, begins with an inspection of the vault conditions, including the manhole cover, access ladder, vault lights, ventilation fan, sump pump, and vault floor for debris, and water. This is followed by an inspection of the network transformer to check for any leaks, corrosion, ground connection issues, ground switch issues, as well as recording the temperature, oil level, and pressure (if available) of the main tank as well as the ambient vault temperature.

Information from the vault inspection is recorded on the Network Transformer Maintenance Checklist. (See Attachment H .)

Technology

PG&E presently uses a manual checklist ( Attachment H ) to record transformer maintenance information. They plan to implement the use of tablet computers, where crews will enter information directly. Information would be later (end of the shift) downloaded into the main asset database.

PG&E also plans to utilize bar codes on all of the transformer oil chambers and network protectors. These bar codes would be used on the oil sample bottles and syringes to identify the chamber from which the sample was drawn.

Maintenance work orders are now generated manually from PG&E’s SAP system. At the time of the immersion, PG&E was installing a work management system. This system will be tied directly to SAP, and will generate maintenance orders automatically based on network equipment maintenance procedures.

Figure 1: Network unit with vault

Figure 2: Vault ventilation fan and sump pump

5.11.12 - Portland General Electric

Maintenance

Network Vault Inspection - Maintenance

People

Crews working in the CORE group perform vault inspections in the network. The CORE group, part of the Portland Service Center (PSC), focuses specifically on the underground CORE, including both radial and network underground infrastructure in downtown Portland. Its responsibility includes inspection and maintenance of the network infrastructure, including vaults. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

In general, the CORE group applies a philosophy of repairing issues when they arise. If crews find any significant electrical problems, they may engage Distribution Engineers for support. Civil issues usually outsource to external contractors for repair. Service & Design Project Managers (SDPMs) address structural problems in customer-owned facilities and coordinate with the customer to make the required repairs.

Crew

The craft workers assigned to the CORE group, which is a part of the PSC, focus specifically on the underground CORE, including operations and maintenance of the network infrastructure.

Currently, the following 16 people work in CORE:

Four non-journeymen
Eleven journeymen (e.g., assistant cable splicers, cable splicers, foremen)
One Special Tester

Resources in the CORE include:

Crew foreman: Crew foreman (a working, bargaining unit position), required to be a cable splicer
Cable splicer: This is the journey worker position in the CORE.To become a cable splicer in CORE, an employee must spend one year in the CORE area as a cable splicer assistant.
Cable splicer assistant: A person entering the CORE as a cable splicer assistant must be a journeyman lineman. All cable splicers start as assistant cable splicers for one year to learn the system and network. The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault while the helper, typically a non-journeyman classification, usually stays above ground, carrying material and watching the barricades and street for potential hazards.

Special Tester: PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. Outside the network, Special Testers work with reclosers and their settings, and perform cable testing and cable fault location. Within the network, the Special Tester works closely with the network protectors, becoming the department expert with this equipment. PGE has embedded one Special Tester within the CORE group. This individual receives specialized training in network protectors from the manufacturer, Eaton.

The Special Tester usually partners with cable splicers, working as part of a crew. The “special testing” crew includes the Special Tester, a crew foreman (a cable splicer), a lineman/cable splicer, and a topman, a non-journeyman helper. The topman stays outside the hole and watches the manhole/vault entrance for potential hazards.

In addition to NP testing and settings, the Special Tester focuses on power quality issues, including customer complaints about voltage.

Reliability Technicians: Reliability Technicians perform infrared (IR) thermography inspections on primary systems and network protectors as part of the Quality and Reliability Program (QRP), a reliability improvement program targeted at key infrastructure. PGE has three IR specialists, who mainly focus on the transmission system but also work on high-priority distribution systems. Organizationally the Reliability Technicians belong to the same group as the Special Testers and report to the Testing Supervisor.

Process

Vault Inspections

Inspection Frequency: PGE’s network has 1300 manholes/vaults. Of these, 529 are vaults, with 280 vaults containing transformers and network protectors.

For vaults that contain equipment, such as network transformers or network protectors, the frequency of inspection dovetails the performance of equipment maintenance, as a vault inspection accompanies the maintenance of equipment. For example, 480 V network protectors are maintained annually, so inspection of the vaults that house 480 V protectors is also performed annually. The crew performing the NP maintenance, which is typically comprised of a foreman, journeyman cable splicer, Special Tester, and non-journeyman helper, performs these inspections.

PGE attempts to inspect general-purpose structures annually, including vaults that do not contain equipment, but manpower availability determines the exact cycle. At the start of every year, general work orders for inspection of these vaults, as well as manholes, are created in Maximo for a particular geographical area. Each work order covers the manholes/vaults in a one- or two- block area. A crew receives these work orders and is expected to perform inspections of the general-purpose enclosures when it does not have any customer work. If there is little customer work on the network, inspections can be completed for all non-equipment vaults within a calendar year.

PGE employees, not contractors, perform all inspections of general-purpose structures, including both an electrical and civil (structural) review. Inspections also include a visual inspection to identify leaks, assess vault cleanliness, etc., and may include the use of IR thermography at the discretion of the inspection crew. All crew have been issued IR guns. If it identifies something amiss, it may bring in the Special Tester, who has a more sophisticated IR camera and has received special training in interpreting IR readings.

Crews may take load readings on the secondary system to try to identify open limiters when inspecting vaults. Because some of the secondary feeders are difficult to access, this continuity testing is restricted to accessible secondary feeders.

As part of the inspection, crews clean the vault. Crews clean vaults ahead of time if they know that they will visit a specific vault for maintenance work.

PGE does not use a formal inspection sheet for the inspections of general-purpose vaults, though a crew completes a Field Action Report if it finds issues with a manhole/vault to be repaired at a later date. The Field Action Report is records follow-up corrective action identified during inspection. If no action is needed, or if the crew can repair a problem without the need for engineering or design services, such as replacing a damaged ladder, it does not fill out any paperwork and notes completion of the inspection in Maximo.

The CORE utilizes a “fix-it-when-you-find-it” approach and keeps limited documentation of informal repairs. For repairs that are not done right away, the Field Action Report prioritizes repairs based on urgency. Electrical issues receive “1,” the highest priority. Structural issues, such as a broken lid, receive a “2” priority. Priority “3” work is rarely undertaken because a crew tends to repair such small issues while at the site. The priorities guide the urgency of the repair but are not accompanied by specific deadlines for accomplishment. They try to be as expedient and efficient as possible, scheduling work as soon as circuits are available. Engineering works closely with the CORE management to assure that these repairs are addressed. PGE notes that it has little backlog of electrical repairs, though it does have some backlog of structural repairs.

Engineering generally responds to electrical problems while SDPMs handle the other tasks, including coordination with external contractors. If vaults need civil or structural repairs, PGE uses an external Level III contractor. The company has a two-year contract with the outside contractors to undertake this type of work. For large, complex repairs, a structural engineer is used.

For vaults that contain equipment, vault inspections are performed in conjunction with the performance of equipment maintenance. For example, when a Special Tester performs protector maintenance, the crew also performs a visual inspection of the electrical facilities and structural condition, inspects the other components of the network unit, inspects other vault equipment, such as the sump pump, and performs an IR inspection of the entire vault.

Inspection of the vaults is annual for spot network vaults with 480 V protectors, and every two years for network vaults with 216 V protectors. Inspections are not formally documented, but readings obtained from the equipment are recorded on index cards. PGE is presently undertaking a project to convert the manual cards to an electronic format.

Crews may take load readings on the secondary system when inspecting vaults. Because some of the secondary feeders are difficult to access, this continuity testing is restricted to accessible secondary feeders.

Infrared (IR): As part of their vault inspections associated with equipment maintenance, crews perform IR inspections of the major components in the vault with regular FLIR cameras. The Special Tester has more sophisticated equipment, so if the crews identify an issue, they call the Special Tester to undertake a more in-depth assessment. Crews have started to undertake IR checks as part of manhole and vault entry, but this is informal and not part of the formal manhole entry requirements.

Crews document any anomalies using the Feeder Inspection Form. If they find an IR anomaly, they record the load to rule out overloading as the cause.

The Special Tester or Reliability Technician also performs IR inspections of network feeders on a four-year cycle, as part of a maintenance and inspection program separate from the vault inspections, and performed in conjunction with transformer and network protector maintenance. This program is part of the QRP, a heightened inspection program for key infrastructure, including the network. In order to do this, the inspector, either the Special Tester or Reliability Technician, partners with a crew, and at least a topman and a journeyman, because inspectors usually must enter the vaults.

The IR is undertaken on every component and primary joint, and the inspector looks for components that show a high temperature. Where resources permit, the inspector may also IR-test some secondary systems. If the inspector finds any abnormal conditions, the inspector takes a picture and creates a report. The issue will be fixed within a week, and all reporting is by exception, with reports passed to the Network Engineering Group. Most of the issues identified through IR inspection on the network have been associated with the primary terminations on the transformer.

In order to be more efficient, PGE attempts to schedule the QRP-driven vault IR inspections at the same time as network protector maintenance is being performed.

Technology

Maximo: PGE uses the Maximo for Utilities 7.5 system to manage inspection reports and store details about any maintenance needed.

5.11.13 - SCL - Seattle City Light

Maintenance

Network Vault Inspection - Maintenance

People

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable Splicers perform all electrical aspects of network construction, operations, and maintenance. All electrical employees who work in the network are either Crew Chiefs, journeyman Cable Splicers, or apprentices in the mode of progression, working their way towards the journeyman level.

Crew Makeup

A network crew is normally made up of one Crew Chief, one or two Cable Splicers, and one apprentice. The type of work to be done and SCL work rules will dictate the appropriate crew makeup. For example, performing switching in a vault requires at least two journeyman-level employees to be in the vault. These and other work rules and safety practices are spelled out in the Washington State Safety Standards for Electrical Workers, Chapter 296-45 WAC.

Process

Preventive Maintenance and Inspection

SCL performs two main programmatic inspection and maintenance programs on network equipment:

Four-year maintenance cycle for network feeders. (Note: Network feeder maintenance includes transformer inspection and maintenance and manhole and vault inspection and maintenance.)
Four-year maintenance cycle for network protectors. (This program is completely independent of the feeder maintenance program.)

Network Feeder Maintenance

When the field crews are sent out on feeder maintenance, they are issued a “maintenance package” that may include:

copies of a feeder map from their NetGIS system
“cut sheet,” which is a written description of the equipment in the vault produced from NetGIS, SCL’s in-house Oracle database
job orders for the work to be performed
field copy of the clearance contract
any urgent maintenance slips documenting items for maintenance that had been previously identified, but not resolved
Network transformer and switch vault inspection forms
Oil test report form, for recording information associated with the oil tests of the transformer switch and terminal chambers
maintenance checklist
copy of the previous device maintenance reports, or for newer equipment, a copy of the device install card (this allows crews to identify and track any ongoing problems or repairs form prior maintenance)
insulating oil test report (during feeder maintenance, crews take main tank oil samples. These are tested by SCL’s in-house lab, and an oil test report is issued and returned to the maintenance crew before the feeder is reenergized)
Earthquake Anchors for Network transformer order form, used to replace older I-beam supports with earthquake rails
prior Hi-pot test reports

Feeder maintenance includes a general inspection of the condition of the vaults, as well as performing network transformer inspection and maintenance. The maintenance requirements are defined in the SCL Vault and Transformer Maintenance Manual. See Attachment H.

Crews complete a Network Transformer and Vault Inspection form, See Attachment I , for each transformer or switch vault inspected.

Crews perform tests on each network transformer during feeder maintenance. Crews take oil samples from the transformer and the primary switch chamber. SCL maintains its own oil testing laboratory. They perform an acid test, interfacial tension testing, and dielectric testing of the oil. They do not do dissolved gas analysis.

Air switches and SF ₆ switches are visually inspected. A vacuum pressure test is performed on vacuum switches (only five of them are in the system).

Maintenance records are kept in an Oracle-based database developed by SCL. This database is tied in with NetGIS, their network records and mapping database. This allows SCL to access feeder maps, vault information, inspection and maintenance records, and photographs of the vaults.

Modified Maintenance Approach

While SCL’s goal is to maintain feeders on a four-year cycle, they have fallen behind on their maintenance because of the construction workload. To address this, they have implemented two types of feeder maintenance. The first type is the “full maintenance,” which means they do a full and complete inspection and maintenance during the scheduled feeder outage. The second type is an abbreviated version of maintenance called a “modified maintenance.” This type of inspection includes a thorough inspection of any transformer exposed to the elements, such as a subsurface vault, but a shorter maintenance on a transformer housed in a surface or other dry vault. Note: any feeder that has not been maintained within six years must have full maintenance performed.

Technology

Monitoring

SCL does not use distribution-level SCADA on their network, but they do have access to the remote monitoring system (DigitalGrid). They have a separate console for accessing this remote information, and alarms from this system are available at each dispatcher console.

The SCL Dispatchers have access to the NetGIS system through a network viewer. This viewer enables them to view the contents and configuration of each network vault.

5.12 - Non-Network Vault Inspection - Maintenance

5.12.1 - HECO - The Hawaiian Electric Company

Maintenance

Non-Network Vault Inspection- Maintenance

People

At HECO, underground maintenance work is performed by both Cable Splicers from the Underground group, and Lineman from the Overhead C&M groups.

The Underground Group at HECO is part of the Construction and Maintenance Division. The group is comprised of two UG supervisors, fifteen Cable Splicers, 2 Utility Mechanics, and 2 Utility Assistants. The Cable Splicer is the journeyman position in the department.

Note that the Underground group does not install or maintain network equipment such as network transformers or network protectors. Network equipment construction and maintenance is the responsibility of the Substation group at HECO. The Substation group is part of the Technical Services Division of the System Operations Department.

The Overhead C&M groups at HECO also perform maintenance work with underground facilities (normally, URD facilities). The journeyman position in the Overhead groups is a lineman.

HECO has an organization focused on performing inspections. This group is part of the C&M Planning group within the UG C&M Division.

HECO also employs a position known as a Primary Trouble Man (PTM) who performs most of the switching and clearance operations on the system. The PTM, Cable Splicer and Lineman are all bargaining unit positions.

Process

HECO is not performing programmatic inspection and maintenance of their non-network underground distribution system^[1] other than at the substations. They do perform corrective maintenance as problems are identified. They also perform diagnostic testing aimed at areas where they have had reliability problems, and perform equipment replacements as needed.

Technology

HECO has a home developed Strategic Inspection and Maintenance System (SIMS) used to record inspection findings, including photographs, as well as the work performed to address those findings. The system is also used to prioritize any corrective maintenance work. (Note: Prioritization of underground findings is under development).

HECO is using a work management system called Ellipse, by Mincom.

^[1] HECO is programmatically inspecting their 138 KV transmission system.

5.12.2 - CEI - The Illuminating Company

Maintenance

Non-Network Vault Inspection

(Maintenance (11kV))

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who inspect and maintain the underground system.

Process

11kV vaults that house CEI transformers and equipment are inspected every six months. The inspection includes a visual inspection of the equipment contained with in the vault, such as cables, connectors, and transformers, as well as the condition of the vault itself.

11kV vault inspections also include batteries, disconnects, and throw over switches (manual or automatic). During the inspection, the vault will be cleaned of any debris.

Also, the inspector will take temperature readings at the transformer terminals.

And, during maintenance in a customer owner vault, CEI will check the vault ventilation system to assure it is functioning. If not, they will send a letter to the vault owner, requesting that the ventilation system be repaired.

Technology

Vault inspection / maintenance results are recorded manually on a Network Vault inspection/maintenance form.

(See Attachment M)

5.12.3 - CenterPoint Energy

Maintenance

Non-Network Vault Inspection- Maintenance

People

Vault Inspections (network and non-network) are performed by the Relay group within Major Underground. The Major Underground organization includes Key Accounts, Engineering and Design resources, Support Services, and the field force responsible for all construction, operations and maintenance activities. The field force is divided into two main groups, the Relay group and the Cable group.

Both the Relay group and Cable group perform maintenance and inspection activities. The Relay group focuses on most of the non cable equipment inspection and maintenance, including performing vault equipment inspections, network protector testing, and other inspections and maintenance on devices with relays or motor operators. The Cable group focuses on inspections of cable, cable accessories and major equipment.

The Relay group is comprised of Network Testers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. The Relay group is led by an Operations Manager.

CenterPoint does not have dedicated maintenance crews. Rather, maintenance and inspection work is assigned to crews based on work priorities and resource availability.

Process

The Relay group performs periodic vault inspections, with most inspections on an annual period. Some high priority locations are inspected two or three times per year. The inspections are performed without de-energizing the vaults.

The inspections include a visual inspection of the vault, infrared inspection of all connections including bus connections and cable connections, load measurements; and operating equipment that can be operated without interrupting customers, such as tripping and closing network protectors.

Network vault inspections will include a visual inspection of the network transformer for oil leaks, corrosion, etc. Inspectors will also record peak temperature from the transformer temperature gauge. CenterPoint does not test network transformer oil as part of their network vault inspections, unless there is an indication of a potential problem such as a high temperature reading.

During the inspection, the vault will be cleaned of any debris.

CenterPoint is using an inspection checklist to guide inspectors through the various items included in the inspection. This same checklist, entitled MUDG Functional Location Inspection Sheet is used to record findings from all inspection types, including the network vault inspections. An inspection sheet is completed for every location inspected.

Inspection findings that require follow up corrective maintenance are noted and recorded by the Crew Leaders who schedule this work for completion. Non urgent corrective maintenance actions that are identified during inspection may be held to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

If the solutions to the findings require the involvement of other groups, the Crew Leaders will solicit their help. For example, corrective maintenance activities that require a customer outage will require the assistance of the Key Accounts group to coordinate with the customer to schedule the outage.

The inspection sheets are filed by work center (each vault is considered a work center), so that CenterPoint has a record of the historic findings.

Technology

Vault inspection results are recorded manually on the MUDG Functional Location Inspection Sheet, See Attachment I .

Vault inspections include the performance of infrared thermography.

5.12.4 - Duke Energy Florida

Maintenance

Non-Network Vault Inspection - Maintenance

See Network Vault Inspection - Maintenance

5.12.5 - Energex

Maintenance

Non-Network Vault Inspection- Maintenance

See Preventative Maintenance and Inspection

5.12.6 - ESB Networks

Maintenance

Non-Network Vault Inspection - Maintenance

See Preventative Maintenance and Inspection

5.13 - Oil Switch Maintenance - Replacement

5.13.1 - CEI - The Illuminating Company

Maintenance

Oil Switch Maintenance - Replacement

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. Underground Electricians perform oil switch maintenance and replacement

Process

CEI’s non - network underground system operating at 5kV was designed with oil switches (many are older Phoenix switches) that can be used to sectionalize in no load conditions.

These switches are scheduled to be maintained on a 5 year cycle. The inspection is to include an assessment of the switch condition and performing any identified repairs.

The current policy is to replace the switches as the cable sections feeding through the switches are replaced. They devices are being replaced with an electrically operated vacuum switch.

At one time, CEI had embarked upon a proactive, systematic replacement of these devices because of the potential hazard created by the possible failure of the devices upon operation. However, CEI has implemented operational and technical changes to the method of operating these devices that minimize the risks associated with their operation, and has thus ceased the replacement program (see Operating a 5KV Underground Oil Switch).

Technology

Inspection information is to be gathered on a manual form and retained in the UG Network Services department. See Attachment P . In practice however, CEI is not performing these inspections.

Oil switches are not serialized. The Underground Network Services department maintains a data base of information on the oil switches, such as location, manufacturer, type, rating, remote controlled, etc. Some of this information is replicated in CEI’s GIS system.

5.13.2 - Duke Energy Florida

Maintenance

Oil Switch Maintenance - Replacement

Process

In Clearwater, Duke Energy Florida has designed its network feeders with primary sectionalizing switches. They have historically used three-way (feeder in, feeder out, and alternate feeder) oil switches that can be used to sectionalize, transfer loading from circuit to another, or tie feeders together. Devices can be opened, closed, or put in the ground position. The older devices are motor operated, and can be operated from outside of the vault or manhole using a tethered control box, or from SCADA. Part of the normal process for troubleshooting a network feeder is to sectionalize and restore service to the non-affected part of the network feeder.

Duke Energy Florida is in the process of replacing the oil filled sectionalizing devices (RA switches) used on the Clearwater network feeders with a new switch design that will involve solid dielectric vacuum switches. Drivers for this replacement effort include the fact that the devices are a 1980s vintage device and are near their end of life, and it is becoming more difficult to obtain parts. In addition, the replacement is part of an effort by the Duke Corporation to move away from oil or gas insulated switchgear. As Duke Energy Florida pursues a permanent replacement, they are seeking a device that provides a visible open.

The replacement solid dielectric vacuum devices, under design specification at the time of the practice immersion, are slightly larger than the oil filled devices and will be placed in sidewalk vaults. These devices, which do not have fault interruption capability, will be equipped with remote reporting faulted circuit indicators (FCIs) that communicate via SCADA to the DCC. The devices will provide a visible open through an interlinked system where the vacuum bottle must be open before you can open the visible break. The new devices will be placed on an angled stand so that the switch faces the vault exit and can be easily operated with a hot stick from outside the hole. The switches will also have the ability to be operated from above ground using a hand held pendant control that is hardwired to the switch. The decision to proactively replace the older oil gear with the new solid dielectric switches was collaborative, involving the component engineer within the PQR&I group, the Standards engineer and the Network Group.

In St. Petersburg, most of the infrastructure is supplied by a primary and reserve feeder loop scheme, with automated transfer switches (ATS). Outside the network, the primary and reserve looped feeder scheme is used in Clearwater as well. The ATSs are motor operated and most are tied in with SCADA and can be monitored and controlled from the DCC via a 900 MHz radio communications system. Many of the in service ATSs are oil-filled devices, with two oil-filled tanks with a bus tie between them. Duke Energy has prioritized ATSs with two oil-filled tanks located in building vaults for replacement. The replacement design utilizes two three phase solid dielectric vacuum switchers (MVS) looped together (jumpered from one to the other), with the transformers supplied radially off of the T bodies using load reducing 200 amp taps (see Figure 1).

Figure 1: Solid dielectric design for a three-way 3 Φ switch utilizing Elastimold MVS switches. This switch can be used as the high side disconnect for a network transformer, with the 200 A interface on the back of the 600 A T bodies (left side) used to supply the transformer

Technology

Duke Energy Florida is in the process of replacing the oil filled sectionalizing devices (RA switches) used on the Clearwater network feeders with a new solid dielectric vacuum switch design. Drivers for this replacement effort include the fact that the in service devices are a 1980s vintage device and are near their end of life, and it is becoming more difficult to obtain parts. In addition, the replacement is part of an effort by the Duke Corporation to move away from oil or gas insulated switchgear. As Duke Energy Florida pursues a permanent replacement for the RA switch, they are seeking a device that provides a visible open (see Figures 2 through 5).

Figure 2: Network Feeder primary sectionalizing switch (RA) switch

Figure 3: Network Feeder primary sectionalizing switch (RA) switch

Figure 4: Control Box for network feeder primary sectionalizing switch

Figure 5: Example of an RA switch replacement considered by Duke Energy Florida. The switch depicted is a vacuum switch with the breaker under oil. Duke Energy Florida is planning to move to a solid dielectric vacuum switch

5.13.3 - PG&E

Maintenance

Oil Switch Maintenance - Replacement

Process

Within San Francisco, PG&E uses primary sectionalizing devices on network feeders (historically, the G&W T Ram). San Francisco’s experience is that when they open a network feeder, they often have network protectors that “hang up”; that is, do not open properly. Their primary feeder design with switches gives them the ability to isolate the section of the feeder where the bad protector is located, enabling them to complete their work on the fully de-energized section. This design also facilitates obtaining clearances and troubleshooting.

PG&E has been moving from using oil switches as network feeder sectionalizing switches to a solid dielectric switch. One driver for this change is a concern over the failure of the switch and the environmental and other hazards associated with oilfield gear. One challenge faced by PGE in the network application is that the fault duty in the network may exceed the rating of the dielectric switch. PG&E is currently working on ways to reduce the fault duty of their networks to be able to apply these devices.

5.13.4 - Survey Results

Survey Results

Maintenance

Oil Switch Maintenance - Replacement

Survey Questions taken from 2012 survey results - Maintenance

Question 6.32 : Are you currently implementing replacement programs for any of your network equipment?

Question 6.33 : If Yes, Please indicate which equipment is being replaced.

Survey Questions taken from 2009 survey results - Maintenance

Question 6.38 : Are you currently implementing replacement programs for any of your network equipment?

Question 6.39 : If Yes, Please indicate which equipment is being replaced.

5.14 - Organization

5.14.1 - AEP - Ohio

Maintenance

Organization

People

Maintenance and Operations activities at AEP Ohio are performed by Network Mechanics, which is a bargaining unit position responsible for performing all network field activities, including inspection, maintenance and operations activities. Network Mechanics are members of the union (IBEW) and are categorized as D, C, B, or A-level grades, with Network Mechanic “A” being the highest rank. Each position has certain work duties associated with it.

Organizationally, network field resources are centralized, with the field resources who work with the AEP Ohio networks reporting organizationally out of one network service center (Grandview). Most resources report physically out of this center, though several crews who work with the Canton networks physically report out of another center close to Canton. This service center is led by a Distribution System Supervisor and consists of Network Crew Supervisors, the front line leadership position, and the Network Mechanics. Organizationally, the network service center is part of Regional Operation, which reports ultimately to the Vice President of Distribution Regional Operations.

The Network Engineering group works closely with the field personnel at the service centers to develop and coordinate operations and maintenance activities. Network Engineering is led by the Network Engineering Supervisor and is organizationally part of the Distribution Services organization, which reports ultimately to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Network Engineering Supervisor and the distribution services organization – which report to the AEP Vice President of Customer Services, Marketing and Distribution Services – support all AEP networks throughout its operating companies, including Texas, Indiana, Michigan, Oklahoma, and other locations.

While the majority of the routine maintenance and inspection of network equipment is performed by AEP Ohio Network Mechanics, some work is performed by contractors.

Process

New Network Mechanics receive training in working with network systems through eight separate formal two-week long training courses spread over a four-year time period as they advance to the journey worker level. Some classes are led by a formal training supervisor, while other specialized courses are taught by Network Engineers or other experts. Training includes network operations and training activities. In addition to formal training, “on the job” training (OJT) is also an advancement requirement. Field employees are expected to develop a “jack-of-all-trades” skillset. To foster this job competency, roles and responsibilities are regularly rotated on the crews, giving employees the opportunity to experience and hone their skills in a variety of job situations and have ample hands-on experience with a number of tasks.

Training Center

A notable practice at AEP Ohio is its use of a dedicated network systems training center. This center, located within a broader training center that focuses on non-network systems as well, includes a number of demonstration workstations and a system monitoring station as a teaching aide (see Safety: Training Center).

5.14.2 - Ameren Missouri

Maintenance

Organization

People

Organizationally, Ameren Missouri field resources who construct, maintain, and operate the network infrastructure fall primarily within three groups, all part of Energy Delivery Distribution Services. One is the Underground Construction group, one is the Service Test group, and one is the Distribution Operating group.

Underground (UG) construction crews, consisting of resources who install cable and cable systems including civil construction, cable pulling and cable splicing, fall within an underground construction department that is organizationally part of the Underground Division, responsible for all underground infrastructure within a defined geographic territory that includes downtown St. Louis, and thus, the St. Louis network infrastructure. The Underground Construction department consists of Cable Splicers, Construction Mechanics, and System Utility Workers.

Cable Splicers and Construction Mechanics are journeymen positions. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Construction Mechanics perform the civil aspects of the work. System Utility Workers serve as helpers to the other two positions, and perform duties such as cable pulling and manhole cleaning. Note that at the time of the practices immersion, Ameren Missouri was implementing a new position, called the System Journeyman, which combines the duties of Cable Splicers and Construction Mechanics. System Journeyman are responsible for performing cable work, civil construction, and operating network equipment..

The majority of the maintenance and operations of network equipment, such as network transformers and network protectors, are performed by resources within the Service Test group and Distribution Operating group. Organizationally, both the Service Test group and Distribution Operating group are part of Distribution Operations, led by a manager. Within Distribution Operations, there is a Reliability Support Services group led by superintendent. Reporting to the Superintendent, Reliability Support Services are both the Service Test group led by a supervisor and the Distribution Operating group, also led by a supervisor.

The Service Test group is made up of Service Testers and Distribution Service Testers. Service Testers perform low-voltage work only. They focus on things such as voltage complaints, RF interference complaints, and testing and maintaining batteries. Distribution Service Testers perform network protector maintenance, transformer maintenance including oil testing, and fault location. It is the Distribution Service Tester position who works routinely with network infrastructure.

The Distribution Operating group is made up of Traveling Operators, who perform switching on the system, including placing tags and obtaining clearances, and act as first responders and troubleshooters^[1] for the network.

Process

Ameren Missouri has a mandatory mode of progression for Distribution Service Testers, with employees expected to reach the journeyman level in 22 weeks. The Distribution Service Tester program consists of formal training, testing and on the job training.

Distribution Service Test employees receive significant on-the-job training both as they advance to the journeyman level, and on an ongoing basis. The department manager rotates crews on four month assignments to assure that employees get exposure to various work types including network maintenance, capacitor maintenance, and fault location.

^[1] Traveling operators will perform visual troubleshooting, looking for indications such as a smoking manhole. More technical troubleshooting in the network is performed by either Cable Splicers or Distribution Service Testers.

5.14.3 - CEI - The Illuminating Company

Maintenance

Organization

People

CEI has one Underground Network Services Center responsible for maintaining the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who maintain, construct, and operate the underground system.

The Underground Electrician family of jobs is represented by collective bargaining – UWUA Local 270.

Process

The Underground Network Services manager assigns at least one two – man crew around the clock (20 of 21 shifts) to perform maintenance work or trouble. (Only on Tuesday, day shift, is there no specific two man maintenance / trouble crews assigned) These crews are available to respond to trouble, and perform maintenance when there is no trouble.

CEI faces a similar challenge to many utilities, in that resources are often pulled from maintenance activities to perform other, more time imminent work. Also, CEI’s UG Network Services workforce staff level has been reduced by about 50% over the past five years due to attrition. In addition, the department includes newer resources that lack training, and cannot be assigned certain maintenance activities until they have gained sufficient expertise. These factors can and have resulted in slippages in adhering to the desired maintenance schedules.

Because FirstEnergy is comprised of distinct operating companies, such as the Illuminating Company, with different histories and whose construction and maintenance practices evolved separately, they are in the process of developing common preferred maintenance practices for underground ducted systems (network and non-network). The practices are being drafted by the corporate substation group, as the accountability for ducted systems in most FirstEnergy operating companies lies with the substation group. At CEI, because of the size of the ducted system infrastructure, the UG network Services Department stands independently from the Substation group.

Technology

FirstEnergy’s SAP system is used to establish maintenance plans for preventive maintenance activities.

5.14.4 - CenterPoint Energy

Maintenance

Organization

People

CenterPoint’s underground organization is centralized, with the resources that maintain and operate the major underground infrastructure reporting organizationally to one group - Major Underground. At CenterPoint, the term “major underground” is used to describe the three phase underground system that supplies the urban portions of the Houston metropolitan area using ducted manhole systems, and including the secondary network systems. It consists of mostly three phase facilities supplying commercial and industrial customers (with the exception of the network, which serves residential load as well). URD installations and single phase underground line extensions are not considered part of Major Underground, and are managed by other CenterPoint service centers.

The Major Underground organization, comprised of 208 total resources, includes Key Accounts, Engineering and Design resources, support services, and the field force responsible for all construction, operations and maintenance activities. In addition, where other departments have resources focused on supporting Major Underground, many of these groups have physically stationed resources, 36 in total, within Major Underground, reporting in a matrixed^[1] manner.

Most Major Underground resources physically report to the same location, the Service Center – Underground Operations, located in Houston. In addition, a training facility and equipment yard for Major Underground are stationed at the Service Center.

Field resources are split into two high level groups, “Cable” and “Relay”. The Cable group is comprised of people in the Cable Splicer classification who do all cable work, including installation, maintenance, splicing and removal. The Relay group is comprised of people in the Network Tester classification, who work with testing and locating underground cable and equipment, including maintenance and inspection of transformers, switches and network protectors. This group does all system protection and relay panel work.

Field resources are further broken into groups of about 15, each reporting to a Crew Leader, a non-bargaining position at CenterPoint.

^[1] The term “matrix” employee refers to an employ from another department having a dual reporting relationship, one a solid line to his supervisor, and the other a dotted line to the supervisor in the department to which he is assigned.

5.14.5 - Con Edison - Consolidated Edison

Maintenance

Organization

People

Operations Control Centers

Con Edison has one main System Operations Control Center, and Regional Control Centers, such as the Manhattan Control Center.

The System Operations Control Center is the main operating authority, responsible for operating the system and for the protection of the workers for the entire Con Edison system. The System Operations Control Center controls and operates Generation, Transmission, and Distribution.

Employees called District Operators (DO’s) report to the System Operations Control Center. District Operators work in shifts (several DO’s per shift), and provide 24-hour a day, 7 days a week, 52 weeks a year coverage. District Operators have exclusive operating authority and control of all distribution feeders, including circuit breakers within the substation, and all equipment and cable runs up to and including the points of termination in the field. District Operator operating authority includes issuance of approval for status change, application of protection, and issuance of work permits and test permits on distribution feeders. (Distribution feeders include all network feeders and all non-network “cable” feeders including aerial cable, and some open wire on 33 kV in Staten Island.)

Con Edison network workers (in the Work Out Centers or in the Field Operating Department [FOD]) don’t place and check their own protection; they rely on the District Operator. Con Edison has a methodical, tightly controlled clearance process, where the District Operator (DO) directs the activities to provide clearance on a feeder. If field personnel encounter a situation that doesn’t match what they expect to find, or if there is any lack of clarity in the clearance steps, the job stops immediately.

The Regional Control Centers interface between the System Operations Control Center and the Work Out Centers to get the work done. Following a strict protocol, after fault location, positive feeder identification and application of protection, the District Operator at the System Operations Control Center delegates the responsibility for work on cable or equipment to the “Feeder Control Representative” in a Regional Control Center. Again, following strict protocols, the Feeder Control Representative “signs on” each work crew at each work location and “signs them off” after they complete or partially complete their assigned work. When all work is completed and all workers are signed off, again following a strict protocol, the Feeder Control Representative reports the work completed and all sign-off’s to the District Operator, who then takes back full control of the distribution feeder, orders it tested, prepared for service, and finally orders it restored (cut in).

Overhead feeders (open wire, bare wire, tree or covered wire, and self-supporting wire) plus underground radial spurs fed from the overhead wire are under the control of the appropriate Regional Control Center. Strict but different protocols are followed for those feeders as well.

Field Operating Department (FOD) (Also called the Field Operating Bureau)

The Field Operating Department is part of Electric Distribution, and has responsibility for the emergency crews (the crews using the red emergency trucks), as well as the following accountabilities:

Fault locating (distribution and transmission)
High-tension switching (entering customer high-tension vaults and operating devices)
Feeder identification
Hi-pot testing

Fault Location Knowledge Retention

The biggest issue faced by the Fault Locating group is the loss of knowledge as experienced resources leave the department. Their biggest challenge is to find ways to retain people and knowledge.

Con Edison is currently rewriting the Field Operating Department (FOD) manual; however, this manual will provide a general overview, not specifics. Con Edison believes that much of performing fault location is based on experience and “feel.” Because each situation is different, fault-locating techniques are not skills that can be learned from books alone. Fault-locating skills must be developed through work experience.

Con Edison is bringing young employees into the department to learn. General Utility workers (GU’s) who enter the department must go through formal training, testing, OJT, and Field Operating Department (FOD) school. It takes 3-4 years to become a journeyman. Even after an employee becomes a journeyman Field Operator, Con Edison typically waits until that employee is more experienced before assigning certain duties, such as high-tension switching.

The performance of fault locating is a 24-hour-a-day, 7-day-a-week operation. Con Edison, on average, locates three faults a day. Their average time to locate a fault is two hours.

One of the challenges faced by many companies is that fault locating is shared with other duties. Consequently, it is difficult to develop experts and retain expertise. At Con Edison, the fault-locating group is a dedicated group, enabling them to become very proficient in fault-locating techniques. Con Edison has been called on by other utilities numerous times to aid in fault location.

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including:

Inspections/manhole inspections
Post-construction inspections to determine to adherence to Specifications
Safety inspections
Critical manhole inspections, performed in any manhole on the immediate block of a substation, and inspected on a three-year cycle
Regular manhole/vault inspections, scheduled every five years
- Infrared inspections of transformers/network protectors/substations
- Infrared is a four-year cycle for 277/480-V installations.
- Infrared is not programmatic, but is performed randomly, or by exception at 120/208 V. Infrared inspections are performed more frequently at sensitive customer locations such as hospitals and museums.
- Substation infrared is annual.
- Use strategically placed site glasses to obtain infrared views of some locations.
- Use outside contractor to perform infrared training.
Cable and Joint failure analysis specimen retrieval and tracking
Fill-in work, special requests
Check out erroneous readings monitored through the RMS system
Map verification; that is, comparing what is on the mapping system to what is in the field
Random spot checks, focused on workmanship
Random equipment checks
- For example, the Field Engineering group performs random monthly spot checks of primary splice packs to be sure that the kit is complete.
Respond to voltage complaints

Note: This group does not routinely inspect design versus build, or as-built versus mapped.

The department is made up primarily of Splicers. People are chosen for jobs in the department by seniority.

Cable Testing Laboratory

Con Edison has its own cable testing laboratory, which has been in operation since the 1970s. This laboratory has over 100,000 cable and accessory specimens. Sometimes the lab sends specimens to outside labs to obtain independent analysis and opinions.

Con Edison invests in keeping its laboratory staff current on the latest thinking in cable testing. They are active in industry groups. They invest in rotating new people into the cable department, including engineers from Con Ed’s Gold program (a mentoring program for high potential engineers and business professionals).

Distribution Engineering Equipment Analysis Center (DEEAC)

Con Edison has recently launched a new team dedicated to the analysis of electric distribution equipment. The mission of the Distribution Engineering Equipment Analysis Center (DEEAC) is to optimize the performance of distribution equipment through a system safety approach that utilizes data trending and incident analysis. To support this mission, the team is focused on enhancing the safe operation of distribution equipment while also improving overall system reliability by proactively mitigating operational risk. These goals will be achieved through targeted forensic analysis, data characterization of all field-returned equipment, and quality assurance of distribution equipment. Con Edison is dedicated to supporting the mission of DEEAC with a shared focus on continuously improving system safety.

5.14.6 - Duke Energy Florida

Maintenance

Organization

People

Organizationally, the Duke Energy Florida resources that inspect, maintain, and operate the urban underground and network infrastructure fall within the Network Group which is part of the Construction and Maintenance Organization. More broadly, Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager. The region consists of various Operation Centers, organized either geographically or functionally throughout the Region.

The Network Group is organized functionally, and has responsibility for construction, maintain and operating all urban underground infrastructure (ducted manhole systems), both network and non - network, in both Clearwater and St. Petersburg. The Network Group is led by a supervisor who reports to the Region General Manager. The group consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position), all part of the Network Specialist job family.

The Network Specialist is a jack-of-all-trades, position, responsible for all facets of UG work, including cable pulling, splicing, and inspecting, maintaining and operating equipment such as cables, joints, network switches, transformers and network protectors. Network Specialists also work with the installation and maintenance of automation associated with the equipment they manage. For example, Duke Energy Florida recently completed a major project to add automation (remote monitoring and control) to field located primary distribution switches, such as automatic throw over switches (ATSs) that are commonly used to provide a primary and alternate feed to larger customers. It is the Network Specialist craft that installed the automation on the switches, and led an effort to troubleshoot and resolve an implementation issue associated with the design.

The Network Group at Duke Energy Florida has close ties with peers within Duke Energy sister companies throughout the country, and regularly shares information, lessons learned, and network standards with them.

Process

The 10 craft workers within the Network Group are responsible for maintenance and operation of all major underground (ducted manhole systems) infrastructure in both Clearwater and St. Pete. Three resources are assigned to Clearwater, and seven are assigned to St. Petersburg, but resources are moved freely to both areas based on work needs. Network Specialists, the journey worker craft position, may be designated to an oversight position, depending on work needs. For example, at the time of the practices immersion, a Network Specialist was designated to provide oversight to contractor crews.

As the two systems (Clearwater and St. Petersburg) have different designs, the approach used to maintain the two areas differs in some areas.

5.14.7 - Duke Energy Ohio

Maintenance

Organization

People

Duke Energy Ohio’s organization for maintaining and operating their network infrastructure is centralized, with the resources reporting to the Dana Avenue Construction and Maintenance facility. This organization, referred to as “Network Services” or the “Dana Avenue”, does all work associated with the Cincinnati network, as well as certain functions, such as fault location, for the entire division.

The Dana Avenue Construction and Maintenance organization^[1] , led by Manager, is comprised of 59 total resources, including a Field Work Coordinator, Project Manager, T & D Construction Coordinators, and three Construction and Maintenance Supervisors, two of which lead field employees (46) focused on the network.

Duke Energy Ohio has two primary job families for underground field resources – Cable Splicers and Network Service Persons.

Cable Splicers do all cable work, including installation, testing, locating, maintenance, splicing and removal. Underground Service Persons work with non - cable underground equipment, including maintenance and inspection of transformers, switches and network protectors. This group also sets network protector relays based on settings determined by the Network Planning and Network Project engineers.

Note that in Duke’s Terre Haute network, network equipment maintenance is performed by substation maintenance mechanics who work on both substations and network systems.

^[1]Official title of the organization is DD OH/KY – Joint Trench Operations. It is referred to as “Dana Avenue” or “Network Services”.

5.14.8 - Energex

Maintenance

Organization

People

Establishing network maintenance programs is the responsibility of the Network Maintenance and Performance group, led by a group manager, and part of Asset Management. This group works closely with the Standards group and with other Asset Management organizations to develop the maintenance and inspection plan.

5.14.9 - ESB Networks

Maintenance

Organization

People

Maintenance programs are developed and managed by the Asset Management group.

The development of maintenance and inspection programs is performed by engineers in close conjunction with a Strategy Manager who works as part of the Finance & Regulation group within Asset Management. This individual also works closely with the regulator, developing and submitting for approval a 5 year program of maintenance. The strategy works closely with the other groups in Asset Management to identify risks and prioritize programs.

The management of the execution of approved maintenance and inspection program is performed by the Program Management group, also part of Asset Management.

The execution of maintenance and inspection programs is performed by resources within Operations. ESB Networks has two operations centers, one north and one south.

Technology

ESB Networks manages its maintenance and inspection programs using the SAP system. Maintenance orders, or MOs. are assigned to a specific supervisor (by number) who has constant visibility of all MOs and their status.

5.14.10 - Georgia Power

Maintenance

Organization

People

Organizationally, the Georgia Power Network Underground field resources who construct, maintain, and operate the network infrastructure fall primarily within two groups that are part of the Network Underground group. One is the Network Construction group, and the other is the Network Operations and Reliability group.

Underground Construction crews, consisting of resources who install cable and cable systems including civil construction, cable pulling and cable splicing, fall within the Network Construction group, responsible for construction activities for all underground network infrastructure, and construction and maintenance activities for the ducted manhole system infrastructure throughout the state of Georgia. The Network Construction department is led by a manager, and consists of Cable Splicers, Duct Line Mechanics, Civil/Electrical Engineers, and field supervision.

The Network Construction group is responsible for civil maintenance activities, such as performing civil repairs and replacements including duct line rebuilds, and manhole construction and maintenance. In many cases, new construction is out-sourced to preferred contactors that have worked with Georgia Power over a number of years, thereby relieving construction crews for use in ongoing repair, inspections of infrastructure, and maintenance work.

Cable Splicers and Duct Line Mechanics are the journeymen positions. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. They also install transformers and network protectors and any other electrical equipment. Duct Line Mechanics perform the civil aspects of the work, such as duct line, substation vault, and manhole construction and repair. Winch Truck Operators also serve as helpers to the other two positions, and perform duties such as delivering supplies and manhole cleaning.

The majority of the routine maintenance and inspection of network equipment, such as network transformers and network protectors, are performed by resources within the Network Test group, part of the Network Operations and Reliability group. The Network Operations and Reliability group is led by a manager and consists of Test Engineers, Test Technicians, Cable Splicers and WTO’s and field supervision. The group consists of Test Engineers, Technicians, and maintenance crews who perform routine inspections of cable and cable systems, transformers, protectors, and other network infrastructure. There are two Test Technicians, drawn from the ranks of Cable Splicers, who perform routine inspections and maintenance of network protectors. The Test Technicians who perform NP testing are non-bargaining, non-exempt employees. Depending on the work activity, field crews may report to Distribution Supervisor, or to a Test Engineer.Maintenance Crews, comprised of Cable Splicers, do other maintenance work including connecting services, disconnecting splices, transformer testing, transformer oil sampling, working with secondary collector busses.

Network Operations is headed by Test Engineers within the Network Operations Center and report to the Network Operations and Reliability Group. The Test Engineer is a non-exempt, non-bargaining position responsible for system operations, including running the network control center, operating the system, and serving as first responders in the event of trouble on the network underground system. Some Test Engineers have 4 year degrees, while others have 2 year degrees. Network Operations collects and monitors network underground performance and operations through its centralized SCADA systems. Data is collected in near-real time. The group is responsible for reporting faults, re-routing network service when necessary, and de-energizing network segments during repairs, inspections, and/or maintenance.

Process

Both Cable Splicer and Duct Line Mechanic job groups assigned to Construction or Maintenance have a three-year job progression. Both require training, consisting of six-month modules, at the Georgia Power Network Underground training center taught by senior personnel. Each module has three weeks of classroom training and requires extensive on-the-job training (OJT).

As a part of formal training, Apprentices must pass a test at the end of each six-month module before proceeding to the next level. Apprentices have two opportunities to pass each test. Apprentices receive a salary increase as they pass each level. (See Job Progression )

Test Technicians perform network protector inspections and maintenance and are non-degreed personnel drawn from the ranks of Senior Cable Splicers. Two Test Technicians are responsible for an inspection of 200-300 network protectors per year. The Test Technicians learn the work through OJT with senior personnel and through network protector classes provided by the network protector manufacturers.

Test Engineers are responsible for all other aspects of the network underground electrical equipment testing, including transformers. Test Engineers direct the work of field crews in performing maintenance and testing activities.

Network Operations personnel are Test Engineers. Test Engineers must take network underground training if they do not have specific network experience; many are drawn from the ranks within the Network Underground group.

5.14.11 - HECO - The Hawaiian Electric Company

Maintenance

Organization

People

At HECO, underground maintenance work is performed by both Cable Splicers from the Underground group, and Lineman from the Overhead C&M groups.

The Underground Group at HECO is part of the Construction and Maintenance Division. The group is comprised of two UG supervisors, fifteen Cable Splicers, 2 Utility Mechanics, and 2 Utility Assistants. The Cable Splicer is the journeyman position in the department.

Note that the Underground group does not install or maintain network equipment such as network transformers or network protectors. Network equipment construction and maintenance is the responsibility of the Substation group at HECO. The Substation group is part of the Technical Services Division of the System Operations Department.

The Overhead C&M groups at HECO also perform maintenance work with underground facilities (normally, URD facilities). The journeyman position in the Overhead groups is a lineman.

HECO has an organization focused on performing inspections. This group is part of the C&M Planning group within the UG C&M Division.

HECO also employs a position known as a Primary Trouble Man (PTM) who performs most of the switching and clearance operations on the system. The PTM, Cable Splicer and Lineman are all bargaining unit positions.

Process

HECO is not performing programmatic maintenance of their non-network underground distribution system^[1] other than at the substations. They do perform corrective maintenance as problems are identified. They also perform diagnostic testing aimed at areas where they have had reliability problems, and perform equipment replacements as needed.

HECO faces a similar challenge to many utilities, in that corrective maintenance issues that have been identified may not get repaired in a timely fashion as this work is often subordinated to other, more urgent work. This results in a backlog of corrective maintenance items to be worked. HECO does not have clear written guidelines that define the expected period in which these issues must be remedied.

Technology

HECO has a home developed Strategic Inspection and Maintenance System (SIMS) used to record inspection findings, including photographs, as well as the work performed to address those findings. The system is also used to prioritize any corrective maintenance work. (Note: Prioritization of underground findings is under development).

HECO is using a work management system called Ellipse, by Mincom.

^[1] HECO is programmatically inspecting their 138 KV transmission system.

5.14.12 - National Grid

Maintenance

Organization

People

Maintaining and operating the Albany network system is the responsibility of Underground Lines East. This group is led by a manager, and includes field resources focused on civil aspects of the underground system and a field resources focused on the electrical aspects. The Underground Lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network. The total UG Electric East group has 29 field resources.

The Civil Group is comprised of Mechanics, Laborers, and Equipment Operators, and is led by a supervisor. This group includes a machine shop located in Albany. The group has 23 field resources.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics, is led by three supervisors. Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. Cable Splicers are also responsible for performing manhole inspections. Maintenance Mechanics perform network switching, fault location, minor vault maintenance, and inspection and maintenance of network vaults and equipment such as transformers and network protectors.

The Electrical Group field classifications are represented by a collective bargaining agreement. (Union IBEW in New York, multiple unions in NE). Advancement in union positions in UG East is through an automatic progression to a journeyman.

UG Lines East also includes resources such as Schedulers and Work Coordinators. These resources work closely with field supervisors to schedule and resource plan the work.

In addition, National Grid has a company-wide Inspections Department, led by a manager, responsible for completing regulatory required inspection programs. This group consists of supervisors assigned to the National Grid regions, and a union workforce to perform routine inspections. Note, however, that network inspections within Albany are performed by crews from Underground Lines East.

National Grid does not use dedicated full time maintenance crews; rather, they schedule maintenance as a work assignment along with other work types.

National Grid also has a Regional Control Center that operates the eastern New York distribution system. The system is operated in four geographic areas, including one that serves Albany. Each operating desk in the center is manned by regional operators, responsible for both load dispatch and trouble dispatch. The operator responsible for Albany operates both the radial and network systems.

Switching in the substation, including opening network feeder breakers and placing tags, is performed by a substation operator. Note that all network feeders in NY East can be operated remotely. Switching on the network system beyond the primary feeder breaker is typically performed by the underground crews, part of UG Lines East.

Troubleshooting and restoration of outages may involve multiple groups at National Grid.

Maintenance Mechanics within NY Underground East are responsible for troubleshooting network feeders, performing switching on the network (outside the substation), and and in performing fault location.

The National Grid Regional Control Center includes Regional Operators who provide switching orders to direct switching and tagging, and issue clearances, and Substation Operators who perform switching at the substations. Field switching is directed by the Regional Operators and performed by the Maintenance Mechanics within the UG group.

Restoration activities may involve the planning engineers, who may be consulted for guidance to reconfigure the system to restore service.

Process

Advancement in union positions in UG East is through an automatic progression to a journeyman, whereby employees must move through a program of formal training, on the job training (OJT) and testing and become a journeyman within a 42 month period. (See Crew Makeup / Job Progression)

Upon entry, a candidate becomes an “A” employee (Cable Splicer A or Maintenance Mechanic A) for 12 months. Then they move to “B” level for 24 months, and finally advance to a “C”, which is the journeyman level. Progression through the levels involves a combination of formal training and on-the-job training. Employees are expected to fully advance to the “C” level in 42 months.

For each step of the progression, the employee must pass the training school for that step and pass a review by a panel of his/her supervisors. Those that do not pass the formal testing for advancement the first time do get a second chance. If they fail a school or supervisory review, employees are allowed time to upgrade their knowledge and offered a second chance at the school or review. The progression is automatic in terms of time, but they must pass the schools and reviews and advance to the “C” level in 42 months. If an employee does not pass on the second try, he is given a time period to bid out to another department.

5.14.13 - PG&E

Maintenance

Organization

People

The PG&E network field resources (network crews) are part of the Maintenance and Construction - Electric Network organization. The group is led by a Superintendent, VP, who is responsible for the secondary network infrastructure in the Bay Area Region, including San Francisco and Oakland. Note that this individual’s responsibility includes radial distribution in San Francisco and Oakland as well.

Reporting to the superintendent, VP are three Distribution Supervisor positions who supervise the network field resources, two in San Francisco and one in Oakland. In addition, there is a distribution supervisor who leads the Network Protector Maintenance/ Repair shop, and a supervisor of the compliance group, responsible for quality compliance.

The field groups are comprised of cable splicers, a bargaining unit position (IBEW). Cable splicers perform both cable work, such as cable installation and splicing, and network equipment work, such as network protector and transformer maintenance. Advancement in the Cable Splicer job family is through an automatic mode of progression.

In San Francisco, PG&E network crews who perform preventive maintenance work the night shift^[1] . The decision to work at night is driven by two main factors. First, regulations for working in San Francisco issued by the San Francisco Municipal Transportation Agency, prevent utilities from blocking traffic during the day. Second is that loading is lower at night, enables PG&E to clear feeders and maintain adequate capacity to meet loading. Note that in Oakland, PG&E performs network preventive maintenance with day shift crews.

In San Francisco, they typically run four 3- man crews in the evening to perform maintenance. A crew is normally made up of a journeyman cable splicer, who does most of the network protector maintenance work, and two helpers (usually Apprentice Cable Splicers).

PG&E also has three cable crew foremen on the night shift. The cable crew foreman is a working position, with one foreman typically taking clearances and installing grounds, and the others overseeing the crews.

PG&E also uses a position called a Cableman which is a troubleshooter for the underground system, part of PG&E’s Restoration group (not part of the M&C electric Network organization). There a six Cableman who work for the company. They work a rotating shift , and have 24/7 coverage.

PG&E has a General Construction group, also comprised of cable splicers, who work with both the radial and network cable infrastructure. Resources in this group are roving, and act as “internal contractors”, moving to where they are needed and supporting the Maintenance and Construction- Electric Network organization.

Process

PG&E has a 30 month automatic mode of progression whereby employees must move through a program of formal training, on the job training (OJT) and testing. The employee then becomes a journeyman within the 30 month period. (See Crew Makeup / Job Progression)

Employees enter the department as Apprentice Cable Splicers.

^[1] Note that Cable Splicers are assigned during the day to work on San Francisco’s radial underground system. These crews can be redirected to address network issues that may arise during the day. However, all planned work on the network is performed at night.

5.14.14 - Portland General Electric

Maintenance

Organization

People

System Control Center (SCC): The SCC is usually referred to as Load Dispatch, and operators are known as load dispatchers, who are managed by the Transmission and Distribution (T&D) Dispatch Manager. The SCC has two distribution control regions, and Dispatchers are assigned geographically. From Monday to Friday, two dispatchers cover each of the two PGE regions.

One of the regions and therefore one of the dispatch desks includes downtown Portland and the CORE network. Dispatchers rotate between the two desks so that all dispatchers gain experience working with the network. The SCC employs eight dispatchers total who rotate between the desks on 12-hour shifts. Dispatchers are salaried employees (non-bargaining).

PGE employs load dispatchers from a range of backgrounds. Some are electrical engineers, some are ex-lineman, and others are SCADA technicians or truck drivers. This approach provides a diverse range of experience. PGE lacks a formal training program for load dispatchers. Training is primarily on the job. The load dispatcher position is not considered entry level, so PGE prefers to hire people with prior experience and qualifications.

Load dispatchers perform switching according to checked and verified plans drawn up by engineers. Dispatchers then communicate with crews to carry out the switching in the field.

Distribution/Network Engineers: Three Distribution Engineers cover the underground network and are responsible for supporting the maintenance and operation of the network, including working with dispatchers on operational issues and determining maintenance approaches for network equipment. The Distribution Engineers are not based in the Portland Service Center (PSC) or CORE group. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to perform certain civil maintenance tasks.

Crews

The craft workers assigned to the CORE group, part of the PSC, focus specifically on the underground CORE which includes both radial underground and network underground infrastructure in downtown Portland. Their responsibility includes operations and maintenance of the network infrastructure. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

Currently, the following 16 people working in CORE:

Four non-journeymen
Eleven journeymen (e.g., assistant cable splicers, cable splicers, foremen)
One Special Tester

Resources in the CORE include the following:

Crew foreman: Crew foreman (a working, bargaining unit position), required to be a cable splicer
Cable splicer: This is the journey worker position in the CORE.To become a cable splicer in CORE, an employee must spend one year in the CORE area as a cable splicer assistant.
Cable splicer assistant: A person entering the CORE as a cable splicer assistant must be a journeyman lineman. All cable splicers start as assistant cable splicers for one year to learn the system and network.

The Cable Splicer position is a “jack-of-all-trades” position with work including the following:

Cable pulling
Splicing
Cable and network equipment maintenance
Cleaning
Pulling oil samples from transformers

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault, while the helper usually stays above ground, carrying material and watching the barricades and street for potential hazards.

In addition, a crew may include an equipment operator to operate the cable puller, vacuum truck, or other equipment. Note that some work, such as backhoe work, is usually performed by external contractors.

Other Crews and Positions

Special Tester: PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. Outside the network, Special Testers work with reclosers and their settings, and perform cable testing and cable fault location. Within the network, the Special Tester works closely with the network protectors, becoming the department expert with this equipment. PGE has embedded one Special Tester within the CORE group. This individual receives specialized training in network protectors from the manufacturer, Eaton.

The Special Tester usually partners with cable splicers, working as part of a crew. The “special testing” crew includes the Special Tester, a crew foreman (a cable splicer), a lineman/cable splicer, and a topman. The topman stays outside the hole and watches the manhole/vault entrance to ensure no accidents.

In addition to NP testing and settings, the Special Tester focuses on power quality issues, including customer complaints about voltage.

Network Protector Crew: The CORE group has created a dedicated crew that deals with network protectors and performs other construction work. This crew is comprised of cable splicers who receive formal training and attend conferences to gain experience with network protectors. This crew includes a foreman, journeyman (who rotates every three months), and Special Tester.

PGE has approximately 230 network protectors on the system, with half included in the 480 V spot networks, and half in the 120/208 V area grid systems. Presently, it has three construction/maintenance crews and will add the dedicated crew protector crew.

Journeyman Locator: The CORE has a cable splicer/journeyman in charge of “locate” requests, and this role is never outsourced. The network had 1600 locates last year, and ideally the locator works with the Mapper to ensure accurate maps.

Infrared (IR) Tech: IR techs inspect primary systems and network protectors as part of the Quality and Reliability Program (QRP). PGE has three IR techs, who mainly focus on the transmission system. They also work on high-priority secondary systems.

None of the IR techs are dedicated solely to the CORE.

5.14.15 - SCL - Seattle City Light

Maintenance

Organization

People

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable Splicers perform all electrical aspects of network construction, operations, and maintenance. All electrical employees who work in the network are either Crew Chiefs, journeyman Cable Splicers, or apprentices in the mode of progression, working their way towards the journeyman level.

Mode of Progression

SCL uses a three-year automatic mode of progression. This mode includes 8000 hours of On the Job Training (OJT) and testing. They have experienced a very low dropout rate from the program. This is in part because they administer a highly selective front end test and interview process to accept apprentices into the program. Also, a Cable Splicer position at SCL is a highly sought-after position.

Training

In addition to the training associated with the mode of progression, SCL provides network crews with opportunities for training including mandatory safety training for processes such as manhole entry and manhole rescue. SCL also periodically sends personnel to conferences and specialized training sessions such as the Cutler Hammer School, etc.

Crew Makeup

A network crew is normally made up of one Crew Chief, one or two Cable Splicers, and one apprentice. The type of work to be done and SCL work rules will dictate the appropriate crew makeup. For example, performing switching in a vault requires at least two journeyman-level employees to be in the vault. These and other work rules and safety practices are spelled out in the Washington State Safety Standards for Electrical Workers, Chapter 296-45 WAC.

Process

Network Protector Maintenance

Certain Cable Splicers are assigned to focus on network protector construction, operations, and maintenance, and thus become experts in these areas. These individuals are selected for this focus based on their interest level and mechanical aptitude. They retain their Cable Splicer position.

Manhole Drill

Before taking a feeder out for maintenance, SCL performs a manhole drill. The manhole drill involves an inspection crew, usually made up of two journeyman cable splicers (or one working crew chief and one journeyman) and one apprentice going into each manhole on the feeder planned to be maintained, and performing an inspection. If inspectors identify a problem in the manhole that can be fixed on the spot, they do it. If the fix cannot be fixed on the spot, or must be engineered, they notify the Network Electrical Crew Coordinator, who creates a trouble ticket or urgent maintenance slip to complete the work as part of the feeder maintenance. If the inspection crew discovers a civil problem, they notify the civil crews of the need for a repair.

5.14.16 - Survey Results

Survey Results

Maintenance

Organization

Survey Questions taken from 2012 survey results - Maintenance

Question 6.3 : Is network maintenance, inspection and testing performed by (Check One)?

Question 6.4 : If using contractors, what % of your total network maintenance work is contracted?

Survey Questions taken from 2009 survey results - Maintenance

Question 6.5 : Is network maintenance, inspection and testing performed by (Check One)? (This question is 6.3 in the 2012 survey)

Question 6.6 : If using contractors, what % of your total network maintenance work is contracted? (This question is 6.4 in the 2012 survey)

5.15 - Padmounted Transformer Inspection

5.15.1 - CenterPoint Energy

Maintenance

Padmounted Transformer Inspection

People

Inspections of three phase pad mounted transformers are performed by both the Relay group and Cable group within Major Underground. In general, transformer locations with associated auto switches, breakers or reclosers are performed by the Relay group. Transformer locations with manual switches or without switches are inspected by the Cable group.

The Major Underground organization includes Key Accounts, Engineering and Design resources, Support Services, and the field force responsible for all construction, operations and maintenance activities. The field force is divided into two main groups, the Relay group and the Cable group.

Both the Relay group and Cable group perform maintenance and inspection activities. The Relay group focuses on most of the non cable equipment inspection and maintenance, including performing vault equipment inspections, network protector testing, and other inspections and maintenance on devices with relays or motor operators. The Cable group focuses on inspections of cable, cable accessories and major equipment.

The Relay group is comprised of Network Testers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. The Relay group is led by an Operations Manager. The Cable group is comprised of Cable Splicers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. The Cable group is led by two Operations Managers.

CenterPoint does not have dedicated maintenance crews. Rather, maintenance and inspection work is assigned to crews based on work priorities and resource availability.

Process

Inspections of three phase padmounted transformers without associated switches or reclosing devices are performed on a five year cycle by Cable group. Inspections of units with associated switches and devices, conducted by the Relay group, are generally performed on a one year cycle, thought the inspection period varies based on the criticality of the location.

The three phase padmounted unit inspections include a visual inspection of the units, infrared inspection of all connections and potential stress points such as cable bends, and taking load and voltage measurements.

CenterPoint is using an inspection checklist to guide inspectors through the various items included in the inspection. This same checklist, entitled MUDG Functional Location Inspection Sheet is used to record findings from all inspection types, including the network vault inspections. An inspection sheet is completed for every location inspected.

Inspection findings that require follow up corrective maintenance are noted and recorded by the Crew Leaders who schedule this work for completion. Non urgent corrective maintenance actions that are identified during inspection may be held to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

If the solutions to the findings require the involvement of other groups, the Crew Leaders will solicit their help. For example, corrective maintenance activities that require a customer outage will require the assistance of the Key Accounts group to coordinate with the customer to schedule the outage.

The inspection sheets are filed by work center (each vault is considered a work center), so that CenterPoint has a record of the historic findings.

Technology

Three phase transformer inspection results are recorded manually on the MUDG Functional Location Inspection Sheet, See Attachment I

Transformer inspections include the performance of infrared thermography.

5.15.2 - Survey Results

Survey Questions taken from 2020 survey results - Commercial Distribution survey

Question 11 : Please indicate if your company performs the following Inspection activities on a routine basis and at what frequency.

5.16 - Pipe Cable System Maintenance

5.16.1 - CEI - The Illuminating Company

Maintenance

Pipe Cable Inspection Maintenance (138kV)

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. Electricians within this group perform the 138 kV pipe cable system maintenance and cathodic protection maintenance.

Process

The 138kV pipe cable system supplies key substations, including the Hamilton sub which sources the network. CEI inspects and maintains this system, including the cathodic protection system on a 6 month cycle.

Technology

Information about the inspection and maintenance is recorded on manual forms. See Attachment R and Attachment S

5.16.2 - Duke Energy Ohio

Maintenance

Pipe Cable Inspection Maintenance (138kV)

People

Substation maintenance personnel are responsible for the maintenance and inspection of the pressurized oil system and terminations.

Network crews perform visual inspections of the 138kV pipe type cable route. They will periodically or incidentally drive the route, identifying situations that could potentially damage the system (a backhoe, for example).

Contractor resources are used to make required repairs to this system.

Process

Duke Energy Ohio hired an expert contractor to assess the condition of their 138 kV pipe cable system and recommend modifications an procedural changes. At the time of the EPRI immersion, Duke Energy Ohio was assessing the recommendations.

Technology

Duke Energy Ohio has two area substations that supply their Cincinnati network. The substations are physically located close together, and are supplied by parallel 138 kV pipe type cable feeders.

Information about the inspection and maintenance is recorded on manual forms.

5.16.3 - HECO - The Hawaiian Electric Company

Maintenance

Pipe Cable Inspection Maintenance (138kV)

Process

The 138kV pipe cable system supplies key substations. HECO inspects and maintains this system, including the cathodic protection system on a 6 month cycle.

Technology

Information about the inspection and maintenance is recorded on manual forms.

5.16.4 - SCL - Seattle City Light

Maintenance

High Pressure Fluid - Filled Cable System Maintenance

People

High-pressure fluid-filled cable inspections are performed by substation operators as part of the substation inspection program.

Cathodic protection inspections and testing for transmission cables are performed by network crews.

Process

Testing results are forwarded to Generation Engineering.

5.17 - Preventive Maintenance and Inspection

5.17.1 - AEP - Ohio

Maintenance

Preventative Maintenance and Inspection

People

Preventive maintenance and inspections of network equipment are conducted by Network Mechanics and Network Crew Supervisors on a regular basis. AEP Ohio uses a cyclical approach, with predefined inspection and maintenance frequencies for network components. Most network maintenance programs have been in place for about ten years.

AEP Ohio performs inspections of structures, such as vaults and manholes, and of equipment, such as network transformers and network protectors. Where possible, inspections are grouped so that the performance of a structure and equipment within that structure are performed together. AEP Ohio utilized contractors, particularly civil engineers, to inspect the civil conditions of vaults and manholes.

Process

AEP Ohio inspections and maintenance of network equipment are performed on a rigorous, regular schedule (see Table 1). Findings are recorded on inspection forms for manholes, vaults, network protectors, and transformers, and are available in hard copy and an online form (see Attachment D for a sample online manhole inspection form). Note that if a Network Mechanic enters a manhole/vault to inspect a piece of equipment, an inspection is performed and documented of both the equipment and the manhole/vault.

Network Maintenance Programs


Inspection	Period or Cycle
Manhole Inspection	4-year cycle. Inspections are also performed as part of ongoing equipment inspections on a 1-year cycle.
Vault Inspection	1-year cycle (as part of network protector and transformer inspections)
Network Protector Inspection (open door)	1-year cycle
Network Protector Maintenance (on the rail)	4 year cycle (full maintenance)
Transformer Inspection	1-year cycle
Transformer Maintenance	3 year cycle (oil sampling and testing). Full maintenance activities are driven by oil test findings
Trip Checks (Drop Tests) of Network Feeders	1-year cycle

Table 1

Technology

Conditions identified through inspection are recorded in the AEP NEED (Network Enclosure and Equipment Database). When information is entered into NEED, repair or replacement priorities are noted. Inspection forms provide guidance to the inspector in prioritizing and recording findings. For example, the following codes are used for assessing corrosion/rust of network equipment:

Corrosion/rust

normal, good condition
surface rust
rust with metal flaking
severe rust allowing “seeping” oil leak
severe rust allowing severe oil leak

Note that all network trucks are equipped with on-board computers.

5.17.2 - Ameren Missouri

Maintenance

Preventative Maintenance and Inspection

People

The majority of the maintenance and inspection programs associated with network equipment, such as inspection and maintenance of network transformers and network protectors, are performed by resources within the Service Test group.

Organizationally, the Service Test group is part of Distribution Operations, led by a manager. Within Distribution Operations, there is a Reliability Support Services group led by superintendent. Reporting to the Superintendent Reliability Support Services are both the Service Test group led by a supervisor and the Distribution Operating group, also led by a supervisor.

The Service Test group is made up of Service Testers and Distribution Service Testers. Service Testers perform low-voltage work only. They focus on things such as voltage complaints, RF interference complaints, and testing and maintaining batteries. Distribution Service Testers perform vault inspections, network protector maintenance and calibration, and transformer maintenance including oil testing.

Manhole inspections, performed on a four year cycle and required by the PSC (commission), are performed by a contractor, typically, two-man crews.

Recently, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. As part of this group’s role, they are examining Ameren Missouri’s practices for inspecting and maintaining network infrastructure, and developing recommendations for optimal approaches. They have developed a draft document which details strategies for inspection and maintenance of network units, cable systems, vaults, manholes, indoor rooms and customer switchgear. See . .

Process

Maintenance and inspection frequencies vary depending on the type of equipment and the location.

Network Maintenance Programs


Program	Period or Cycle
Network protector maintenance and testing	Two years. Primary feeder energized.
Network transformer oil testing Including ground switch, and main tank	Two years, done at the same time as the NP maintenance. Primary feeder energized.
Network transformer oil testing	Two years, primary feeder de-energized.
Secondary Service Compartment Inspections	Two years, includes secondary cable limiter continuity testing.
Vault inspections	Network vaults inspected every two years in conjunction with network unit inspections In addition, network vaults are entered annually to conduct secondary limiter continuity checks. Detailed inspection of non- network vaults every four years
Indoor Room Inspections	Four Year Cycle. No transformer oil testing. Includes heat gun inspection.
Manhole inspections	Detailed inspection every four years. Conforms to a Missouri PSC requirement. Performed by contractors.
Customer Owned Switchgear	Annual General Inspection.
Pad mounted switchgear and transformers	Inspection on four year cycle

Technology

Information from inspections of network manholes, vaults and service compartments (adjacent manholes with bus work) is recorded on laptops (tough books). (Note that this is a relatively recent change. Historically, information was captured on paper forms and entered into computer systems.)

Inspections may be performed by either contractors (manhole inspections) or Distribution Service Testers (vault inspections).

The inspection information from manhole inspections is recorded in a Circuit and Device Inspection System (CDIS). Information from the vault inspections is entered into both Ameren Missouri developed databases used by the Service Test department to manage the inspections, and into the CDIS, the permanent repository for inspection information.

Ameren Missouri includes the taking and recording of photographs of manhole and vault infrastructure as part of its inspection programs. At the time of the practices immersion, Ameren Missouri was considering augmenting the inspection photography with infrared.

The contractor who performs the manhole inspections utilizes a camera that is attached to a tripod positioned above the hole and is lowered into the hole from the top. The visual inspection of the infrastructure within the manhole is performed by using this camera.

Distribution Service Testers who are performing vault inspections take photographs while in the vault.

Contractors performing manhole inspections utilize a half ton survey truck with a camper shell.

^[1] Note that the PSC requirement for urban underground structures is for a general inspection (patrol) on a 4 year cycle, and a detailed inspection on an 8 year cycle. Ameren Missouri has elected to perform a detailed inspection on a four year cycle.

5.17.3 - CEI - The Illuminating Company

Maintenance

Preventative Maintenance and Inspection

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who inspect and maintain the underground system.

Process

Network system preventive maintenance and inspection programs include:


Program	Cycle or other Trigger
Manhole Inspection / Maintenance Program	5 years
Network Vault Inspection / Maintenance	6 months
Network Transformer Maintenance (Oil Sampling)	2 years
Network Protector Maintenance	6 years
Network Relay Maintenance	6 years
Network Protector Operational Test	yearly

Other non-network maintenance programs include 5kV oil switch maintenance, 11kV non-network vault maintenance, 37kV terminator maintenance, and 138KV Pipe Type Cable System maintenance.

Each Program will be discussed in more detail in the sections that follow. See Attachment K for a summary of Underground Ducted Systems Maintenance practices at CEI.

Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

Technology

SAP is the repository for inspection records for equipment at CEI. Each facility type, such as a manhole, has a maintenance plan assigned in CEI’s SAP system that defines the cycle or other trigger for maintenance. This system automatically initiates maintenance by moving work to the CEI scheduling system – CREWS.

A Planner would then create a work request to perform a specific inspection or maintenance task out of the CREWS system. Note that the progress is tracked manually, and the inspection findings or records of the maintenance performed are not being stored in SAP at this time; rather, they are being kept manually (or recorded in the CAD system) at CEI.

FirstEnergy is in the process of installing Cascade, a system that will house all inspection data and will interface with other key systems such as CREWS, their outage management system (Power On), etc. Cascade will track inspection and maintenance accomplishment and provide CEI with record of what field inspectors are finding. They will be able to perform inspections using hand held devices and the data collected will feed cascade.

5.17.4 - CenterPoint Energy

Maintenance

Preventative Maintenance and Inspection

People

Major underground preventive maintenance and inspection is performed by the Relay and Cable groups within Major Underground. The Major Underground organization includes Key Accounts, Engineering and Design resources, Support Services, and the field force responsible for all construction, operations and maintenance activities. The field force is divided into two main groups, the Relay group and the Cable group.

Both the Relay group and Cable group perform maintenance and inspection activities. The Relay group focuses on most of the non cable equipment inspection and maintenance, including performing vault equipment inspections, network protector testing, and other inspections and maintenance on devices with relays or motor operators. The Cable group focuses on inspections of cable, cable accessories and major equipment.

The Relay group is comprised of the Network Testers, and the Cable group, Cable Splicers. These field resources report to Crew Leaders, a non bargaining unit position at CenterPoint. Both the Relay and Cable groups are led by Operations Managers.

CenterPoint does not have dedicated maintenance crews. Rather, maintenance and inspection work is assigned to crews based on work priorities and resource availability.

Process

At CenterPoint the inspection frequency varies depending on the type of equipment and the location. CenterPoint gives priority to equipment supplying key customers, such as the automatic transfers for medical centers and airports. In the dedicated underground areas, CenterPoint is performing much rehabilitation work, including equipment replacements and upgrades. Over the past two years, 70% of the work they have been doing is rehab, and the remaining 30%, maintenance.

CenterPoint establishes maintenance plans, and works to accomplish these plans. Like many companies, conflicting priorities can affect this accomplishment. They will adjust their approach as needed, focusing on the maintenance areas where they get the most “bang for the buck”.

Preventive maintenance and inspection programs include:


Program	Normal Cycle
Manhole Inspection/Maintenance	1 year, 5 year, or 10 year depending on the manhole criticality
Vault Inspection / Maintenance	Normally 1 year, although maintenance may be performed more or less frequently depending on the vault criticality.
Network Protector Maintenance	5 years testing / I year inspection

Padmount Transformer Inspection	Normally 1 year, although maintenance may be performed more or less frequently depending on the padmount location criticality and whether or not the pad transformer has a switch associated with it.

See Attachment H for a copy of a complete list of their Preventive Maintenance Programs. Maintenance plans are entered into their SAP system. This system will generate maintenance orders and issue to the Crew Leaders. Crew Leaders prioritize and schedule this work. They describes their approach to maintenance as a “rifle approach” rather than a “shot gun” approach, in that they target specific locations based on priority.

CenterPoint is using an inspection checklist to guide inspectors through the various items included in the inspection. This same checklist, entitled MUDG Functional Location Inspection Sheet is used to record findings from all inspection types See Attachment I . An inspection sheet is completed for every location inspected. Inspection findings that require follow up corrective maintenance are noted and recorded by the Crew Leaders who schedule this work for completion. If the solutions to the findings require the involvement of other groups, the Crew Leaders will solicit their help. For example, corrective maintenance activities that require a customer outage will require the assistance of the Key Accounts group to coordinate with the customer to schedule the outage. The inspection sheets are filed by work center, so that CenterPoint has a record of the historic findings.

CenterPoint works closely with manufacturers to resolve product issues identified during inspection. They cited an example of there they had a problem with a certain network protector and were able to resolve it working with the manufacturer.

CenterPoint has installed remote monitoring in many of their vaults. Given that they have real time information about vault equipment from this system, they are reviewing their inspection frequencies. The remote monitoring system may present opportunities for them to spread out their maintenance cycles. One CenterPoint employee noted a situation where the remote monitoring system helped them identify a failed CT in a network protector, rather than have to wait until this was identified through an inspection.

CenterPoint is also performing periodic battery checks at locations that have battery powered or backed up microprocessor based equipment. The period depends on the anticipated battery life. As CenterPoint revisits their inspection frequencies, they plan to integrate the battery inspections with the underground inspections.

Technology

SAP is the repository for inspection records for equipment at CenterPoint.

Each facility type, such as a manhole, has a maintenance plan assigned in the SAP system that defines the cycle or other trigger for maintenance. This system automatically generates the maintenance by issuing orders to the Crew Leaders.

5.17.5 - Con Edison - Consolidated Edison

Maintenance

Preventative Maintenance and Inspection

People

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including:

Inspections/manhole inspections
Post-construction inspections to determine to adherence to specifications
Safety inspections
Critical manhole inspections, performed in any manhole on the immediate block of a substation, and inspected on a three-year cycle
Regular manhole/vault inspections, scheduled every five years
- Infrared inspections of transformers/network protectors/substations
- Infrared is a four-year cycle for 277/480-V installations.
- Infrared is not programmatic, but is performed randomly, or by exception at 120/208 V. Infrared inspections are performed more frequently at sensitive customer locations such as hospitals and museums.
- Substation infrared is annual.
- Use strategically placed site glasses to obtain infrared views of some locations.
- Use outside contractor to perform infrared training.
Cable and Joint failure analysis specimen retrieval and tracking
Fill-in work, special requests
Check out erroneous readings monitored through the RMS system
Map verification; that is, comparing what is on the mapping system to what is in the field
Random spot checks, focused on workmanship
Random equipment checks
- For example, the Field Engineering group performs random monthly spot checks of primary splice packs to be sure that the kit is complete.
Respond to voltage complaints

Note: This group does not routinely inspect design versus build, or as-built versus mapped.

The department is made up primarily of Splicers. People are chosen for jobs in the department by seniority.

Process

Inspection and Maintenance

Con Edison performs periodic maintenance and inspection of network distribution equipment, including network feeders, transformers, network protectors, grounding transformers, shut and series reactors, step-down transformers, sump pumps and oil minder systems, remote monitoring system (RMS) equipment, and vaults, gratings, and related structures.

Con Edison’s approach to performing an inspection is to inspect all the equipment and structures associated with a particular vault ID at a location regardless of category or classification, and even if the particular equipment associated with a particular vault ID resides within different compartments (for example, a transformer and network protector may be located in separate physical compartments even though they both share the same vault ID). This type of inspection is referred to as a CINDE Inspection, based on the name of their maintenance management system (Computerized Inspection of Network Distribution Equipment).

Con Edison performs inspections energized; crews do not take a feeder outage to perform inspections, perform pressure drop testing, or take transformer oil samples. Con Edison does not routinely exercise feeder breakers.

In an effort to more efficiently use their resources, and when nonpriority conditions allow, Con Edison takes advantage of situations where they have to enter a vault or manhole for a reason other than a scheduled inspection, and perform a nonscheduled inspection while they are in the vault. When the record of this nonscheduled inspection is recorded in CINDE, the system “resets the clock” for the next inspection date.

Network equipment at 208 V is generally inspected on a 5-year cycle. 460-V facilities, sensitive customers, facilities in flood areas, and other more critical locations are inspected more frequently, often annually. Con Edison establishes network equipment inspection cycles depending on two factors: the inspection category and the inspection classification.

The inspection category refers to the type of inspection, and includes a Visual Inspection, a 120/208-V Test Box Inspection, and a 460-V Test Box Inspection. The Visual Inspection includes activities beyond visually assessing condition and recording information, such as pressure drop testing and taking transformer oil samples. The test Box inspections involve specialized testing of network protectors with the network relay installed. Note that all of the elements of a Visual Inspection are performed along with the Test Box Inspections.

The inspection classification refers to characteristics of the inspection site that dictate the inspection cycle. For example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a “tidal” area would be visually inspected annually.

Con Edison considers the following classifications in determining inspection cycles:

Routine
Back-feed: banks installed on a feeder involved in a back-feed incident
Candidate for Replacement: commonly due to corrosion damage
Essential Services: critical customers
Flooded Bank: nonsubmersible equipment that has experienced high water levels
208-V Isolated Bank: units that require more frequent inspection than distributed secondary grid units
Remote Monitoring System(RMS), Non RMS, Unit Not Reporting (UNR): Con Edison varies inspection cycles based on the level of remote monitoring installed
Tidal, Water, and Storm Locations

Note that Con Edison requires employees to perform at least a quick visual inspection (QVI) anytime an individual enters a network enclosure, even if the reason for entering an enclosure does not warrant a CINDE Inspection. This type of inspection (QVI) differs from the CINDE inspection category of Visual Inspection described above, in that it is not a full, accredited inspection.

Network Protector Inspection

Network Protectors are inspected on various cycles depending on the inspection classification, as part of the CINDE Visual Inspection and Test Box Inspections.

Transformer Inspection

Transformers are inspected on varying schedules, depending on the inspection classification, but typically no longer an interval than six years. Transformer inspections are performed as part of the CINDE Visual Inspection.

Transformer inspections include:

Visually inspecting for leaks
Measuring pressure
Reading oil temperatures and levels
Taking oil samples for dielectrics and dissolved gas analysis
Performing pressure drop testing
Assessing condition of anodes and replacing if necessary
Performing a corrosion assessment
Checking bus condition
Checking condition of gaps/limiters, and connections
For 460-V units, inspect low-voltage bushing boots for debris and seal integrity

Con Edison performs approximately 8,000 inspections annually.

Cable Failure Analysis

Con Edison’s goal is to perform a failure analysis on every cable and splice failure that occurs. The utility is able to perform an actual analysis on 80 – 90% of the problems that occur; the remainder represent problems that are destroyed or inaccessible.

In addition to testing cable that failed, the utility tries to expand testing to look at the condition of adjacent cable sections that did not fail. In the case of a splice failure, crews replace all three splices and perform diagnoses on the unfailed splices to aid in drawing conclusions about the cause of the failure.

A big challenge for Con Edison is failures that occur in transition joints (between PILC and non-PILC conductors). These transition joints are commonly referred to as “stop joints.” The failures they encounter typically occur on the paper side of the joint. The utility has implemented a replacement program to install cold shrink joints to replace them. They have had good success with the cold shrink joints.

Transformer Failure Analysis

Con Edison performs a root cause analysis of all network transformer removals including units that failed in service, units that were removed because of failed dissolved-gas-in-oil-analysis (DGOA), units that were removed because of failed oil temperature, pressure, or level indications from the RMS system, and units that failed during testing.

Removed units are sent to Con Edison’s Distribution Engineering Equipment Analysis Center (DEEAC), where they are taken apart for a thorough root cause analysis. Analysis includes detailed physical inspections and review of oil test results. Common findings include excess corrosion due to tank holes or porosity, primary bushing failures due to installation defects or mechanical strain, secondary bushing leaks due to manufacturer defects or loose flex straps, evidence of partial discharge from DGOA results or from physical evidence such as carbon deposits, and evidence of arcing, again from test results or physical evidence.

Con Edison keeps detailed statistics on transformer failure performance, including the number of removed units by failure category (failed in service, failed during testing, etc.), and statistics about the causes of those failures (corrosion, insulation failure, manufacturer defect, etc.). Con Edison’s largest single cause of transformer failure is corrosion.

By understanding the root cause of transformer failures, Con Edison has increased the number of units removed based on inspection findings, monitored information, and testing results. This has resulted in a significant decrease in the number of transformers that fail in service. For example, transformer-in-service failures went from being the cause of 9% of network feeder lockouts (Open Autos or OA’s in Con Edison’s lexicon) in 2005, to being the cause of only 4% of network feeder lockouts in 2007.

Generator Maintenance

Con Edison maintains several emergency generators to be used at certain key customer sites in case of an outage. The Field Engineering group is responsible for maintaining these emergency generators. This maintenance includes monthly inspections, quarterly load tests, and annual drills where the generators are physically moved to the site and connected to the customer’s system. In order to expedite the connection of these generators in an emergency, the customers have specially designed features at their service connection points that enable a quick connection of the generators to their systems.

Technology

Inspection and Maintenance Software

Con Edison uses legacy maintenance management software called CINDE, which is an acronym for Computerized Inspection of Network Distribution Equipment. CINDE is a system that records inspection data and initiates inspections based on predetermined cycles. These cycles depend on the category of inspection (for example, a visual inspection versus a “Test Box” inspection) and various predetermined classifications of inspections (for example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a tidal area is visually inspected annually).

Con Edison inspectors record inspection data on hand-held devices (Tough Books). The utility requires that the inspection data be downloaded into the CINDE – Mainsaver system (Mainsaver is the part of the CINDE system used to record data) within three days following the inspection.

Inspection data that is entered into the CINDE system includes:

Equipment serial numbers
As-found and abnormal conditions, such as transformer oil level, state of corrosion, and water in the vault
Defective equipment or structures
Repairs or change-outs undertaken
As-left condition, such as transformer pressure and liquid level, and pressure of housing

The CINDE – Mainsaver system is also used by Con Edison to prioritize follow-up work, or outstanding defects to be corrected that are identified through inspection or other visits to network enclosures. The Electric Operations Region is responsible for prioritizing follow-up work by considering the location of the work with respect to risk to public safety, reliability impact, the type of installation, age of the outstanding defect, and the efficient use of resources.

Dissolved-Gas-in-Oil-Analysis (DGOA)

Con Edison performs Dissolved-Gas-in-Oil-Analysis (DGOA) as part of its routine transformer inspection. DGOA sampling was added to the inspection scope in 2006. The utility samples approximately 5,000 transformers per year, with the first complete round of sampling to be completed in 2011.

Con Edison implemented DGOA in an effort to identify trends in gassing profiles, so that they can preemptively remove transformers at risk of failure, minimizing the potential hazard. The utility recently purchased software called Automated Transformer Lab Analysis Alert System (ATLAAS) that will enable them to specify limits, issue alerts, and aid them in monitoring the rate of change in dissolved gas levels.

Each sample is categorized by severity with a corresponding action associated with it. A transformer categorized as “Normal” will continue to be sampled routinely; a transformer with a category of “Watch” will be re-sampled more frequently; a transformer with a category of “Recycle / Retrofilled” will be scheduled for oil replacement; and a transformer with a category of “Remove” will be scheduled for removal.

In 2006, Con Edison removed 54 transformers based on DGOA testing. In 2007, they removed 37. Con Edison engineers suspect they may have been initially too aggressive in replacing units based on DGOA, and continue to analyze trending to better understand and utilize test results.

5.17.6 - Duke Energy Florida

Maintenance

Preventive Maintenance and Inspection

People

Organizationally, the Duke Energy Florida resources that inspect, maintain, and operate the urban underground and network infrastructure fall within the Network Group which is part of the Construction and Maintenance Organization. More broadly, Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager. The region consists of various Operation Centers, organized either geographically or functionally throughout the Region.

The Network Group is organized functionally, and has responsibility for construction, maintain and operating all urban underground infrastructure (ducted manhole systems), both network and non - network, in both Clearwater and St. Petersburg. The Network Group is led by a supervisor who reports to the Region General Manager. The group consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position), all part of the Network Specialist job family.

The Network Specialist is a jack-of-all-trades, position, responsible for all facets of UG work, including informing maintenance and inspection of underground network facilities. Network Specialists also work with the installation and maintenance of automation associated with the equipment they manage.

The Network Group at Duke Energy Florida has close ties with peers within Duke Energy sister companies throughout the country, and regularly shares information, lessons learned, and network standards with them.

Historically, the scheduling and resourcing of inspection and maintenance work has been performed by the Network Group. At the time of the practices immersion, Duke Energy Florida was modifying its process to engage the Resource Management group in providing scheduling services for inspection and maintenance activities.

Process

Network work crews at Duke Energy Florida perform regularly scheduled inspections and maintenance of all vaults, manholes, and equipment. The following table depicts program frequency, which can vary between Clearwater and St. Petersburg.


Preventive Inspection & Maintenance Programs	Duke Energy Florida – Clearwater	Duke Energy Florida – St. Petersburg
Network Protector Inspection	Done in conjunction with Vault Inspections; 3 x per year to 6 x per year depending on vault criticality	Done in conjunction with Vault Inspections 1 x per year
Network Protector Maintenance and Testing	Every 2 years	As needed based on inspection findings
Vault Inspections	3 x per year to 6 x per year depending on vault criticality	1 x per year
Network Transformer Inspection and Maintenance	Done in conjunction with Vault Inspections 3 x per year to 6 x per year depending on vault criticality	Done in conjunction with Vault Inspections 1 x per year
Network Transformer Oil Testing	N/A Piloting dissolved gas monitoring sensor technology	N/A
Vault Environmental Cleanup	3 x per year to 6 x per year depending on vault criticality	1 x per year
Manhole Inspections	Every 5 years	Every 5 years
Network Feeder Sectionalizing Switches (RAs) – inspection and exercise	3 x per year	N/A

Crews perform regularly scheduled vaults and manholes visitations that include visual inspection and load checks. Note that historically, visual inspections and network load checks were performed on a separate schedule. They have been combined into one program referred to as “Load Checks.” Inspections include a visual check and cleaning of the vault. Also, crews perform an IR inspection. Then, network crews check network voltages and amperage, network protectors, transformer condition and cables. Amperage checks are performed on the secondary.

Crews check the overall integrity of the network protector cabinet, including gaskets, hands and mounting. They assure that the make that they are properly vented, and that there are no leaks. The network protector pressure is checked using a commercial liquid “soap bubble” product. Network protector amperage is checked with a CT clamp reading. Voltage readings between the network protector and transformer are compared.

The company had stopped transformer oil testing, but anticipates, with new equipment, that it will start oil sampling again soon. Duke Energy Florida typically replaces network transformers in the 25 to 30-year age range, or as conditions warrant.

As a part of an ongoing cable replacement project, cables are also checked during the Load Check against the cable replacement list.

Crews use checklist sheets during these scheduled Load Check inspection visits. Any faulty condition that cannot be immediately repaired is entered on the sheet and a repair work order is scheduled.

Technology

Completed inspection checklists are entered into the WMIS system including any defects found that need repair.

5.17.7 - Duke Energy Ohio

Maintenance

Preventative Maintenance and Inspection

People

Performance of maintenance and inspection of the network infrastructure in Cincinnati is the responsibility of the Duke Energy Ohio Dana Avenue underground group. This group is comprised of Cable Splicers and of Network Service Persons who perform inspection and maintenance activities in the network. Company representatives acknowledged that for a period of time, they did not attend to maintenance of their network infrastructure to the degree they are doing so today. In recent years, there has been a renewed focus on inspection and maintenance of network infrastructure.

Duke Energy Ohio also has network infrastructure in their Terra Haute office. This particular network system is comprised of 18 vaults and about 90 manholes. Field forces that maintain the network system in Terra Haute office are aligned closely with the substation side of the business. For example, splicing and maintenance of network equipment are performed by Substation Maintenance mechanics, who also perform substation maintenance work

Process

Maintenance and inspection frequencies vary depending on the type of equipment and the location. In the network, Duke Energy Ohio is performing much rehabilitation work as part of a ten year program that includes cable and equipment replacements and upgrades, and vault and manhole structural upgrades (See Network Rehabilitation). According to Duke, this rehabilitation has had a positive side effect of “capital eating O&M”, meaning that their capital investment in refurbishment has offset some maintenance expenses.

Maintenance Programs


Program	Period or Cycle
Network protector drop tests	Weekly
Manhole inspections	Six years
Vault inspections	Four times per year (quarterly)
Network transformer oil sampling	Four years

Technology

Duke Energy Ohio recognizes the role of technology in moving to a more predictive approach to maintenance. For example, they are installing communication enabled relaying in their network protectors which can notify an operator of a problem. They are planning to set up alarming in their PI system used to record monitored information to notify operators and network planning engineer of anomalies.

In addition to being able to monitor dynamic load, and remotely operate equipment, Duke desires for their remote monitoring system to have some sort of a life cycle count down; that is, to tell the operator or an engineer when a piece of equipment may need to be replaced.

As necessary to perform maintenance of a manhole (or vault), Duke Energy Ohio will use a specialized vacuum truck for removing debris from the enclosure.

Figure 1 and 2: Debris Removal from Manhole

Figure 3 and 4: Debris Removal from Manhole

5.17.8 - Energex

Maintenance

Preventative Maintenance and Inspection

People

Inspection and maintenance programs are developed by the Network Performance and Maintenance group within the Asset Management department. Within this group are two resources accountable for developing maintenance standards or policies for various asset types. The policies define what inspection and maintenance work is to be performed, how often, and is articulated in an associated “Activity Frequency Document.” The policies also include a refurbishment and replacement protocol for each asset type; that is, a description of what conditions should lead to either refurbishment or replacement. The approach used conforms to PAS 55. Note that the development of the maintenance policies is done jointly between asset managers at Energex and asset managers at Ergon, its sister company, serving the rural areas of Queensland. The decision to develop the maintenance and inspection plan jointly was driven by a desire for consistency, and so that both utilities could leverage a common information technology, Ellipse by Ventyx. Both Energex and Ergon are state-owned (Queensland) utilities. The Network Performance and Maintenance group has approximately 30 persons working to develop maintenance and inspection plans, and repairs.

One resource within Asset Management is responsible for taking the maintenance policies or standards and turning that into a program of work. This individual works closely with both internal and external providers to deliver the program of work.

All maintenance work is linked closely to the assets as defined in the Energex network asset register. In total, Energex has about $11B in assets. Energex’s approximate budget for inspection programs is $22 M, and for planned maintenance, $76M.

The development of the work plan and budget includes an allocation for inspection and planned maintenance. At the time of the immersion, the company was preparing for its five-year submission of a spend plan for approval to the regulatory agency in Australia (In Australia, utilities undergo a regulatory review and approval of an overall spending plan every five years). The company will likely submit a plan to hold the spending on operating expenses flat over the next five years, making it critical that they focus their investment in the right areas [1]. The company recognizes that with certain programs, like vegetation management, it is very difficult to adjust the spending levels from year to year. Therefore, it is working on strategies to reduce the unit cost of each activity.

Urban networks outside the city are mostly fed overhead. Thus, vegetation management is a large maintenance item for Energex. The current trim cycles are one year for urban areas, and a four-year cycle in the rural areas, with $40M in total spending.

Substation Inspection

Substation technicians and maintenance engineers are members of the Asset Management group at Energex and perform visual, security, and diagnostic testing of substations. The inspection and maintenance programs are developed by the Network Maintenance and Performance group within the Asset Management department. This group is accountable for developing maintenance standards or policies for various asset types such as substations. The policies define what inspection and maintenance work is to be performed, how often, and is articulated in an associated “Activity frequency document.”

In performing substation inspections, Energex differentiates relay – operated substations from non-relay operated substations (such as switchgear). Because of the difference in technology, Energex expects a different skill level in these separate substation types and have different inspection criteria and crews for each. Relay operated substations are maintained by Substation Fitter Mechanics, a more specialized position than the Electrical Fitter Mechanic who works with non-relay operated stations.

Process

Ellipse issues orders to perform either inspections or programmatic maintenance system to the field locations that will perform the work. For maintenance programs that are developed for each asset type, Energex has established a four-stage Maintenance Acceptance Criteria (called the “Big MAC”), which defines acceptance criteria to be used by inspectors and defines timelines for action depending on the criticality of the maintenance finding. The guideline includes a defect manual that guides the inspector in appropriately categorizing a finding, based on measurement readings, or visual indicators (such as rust, for example).

Findings are categorized as:

P1 – Critical finding – corrective maintenance must be completed within 30 days
P2 – Corrective maintenance must be completed within 6 months
C3 - Corrective maintenance must be completed within 18 months
C4 – Corrective maintenance can be held and scheduled when it can be worked in with other work (feeder outage for example).

If the finding is outside the acceptance criteria, Energex determines the action based on the guideline.

Note: The 11 kV: low-voltage substation maintenance protocol is covered by the substation policy.

Energex has trained operators (substation mechanics) who are focused on performing routine substation inspections (RSIs) in relay operated substations, both the 110-kV:11 kV substations, and the C/I substations (11 kV: low voltage) that are supplied by the three-feeder meshed system in the CBD. There is a periodic visual inspection, and then there is also cyclical maintenance performed by these resources. Energex has approximately 30 substation mechanics in a group who perform this work. Energex is moving to performing a visual “security” inspection on a six-month cycle (assuring that the station is secure), and a full inspection, including a visual inspection and taking readings, once every 18 months (see Table 1). The inspector records the information on a manual form. The information is then given to a clerk and entered into the system. At the time of the immersion, Energex was developing a tool for substation inspectors to enter information on-site into a tablet, but have not yet implemented this system-wide.

For non-relay operated substations, such as a transformer with a ring main unit, the inspections are performed by joint fitters who work in the hub locations. As the inspector identifies findings, he categorizes it, and records the information on a form. The information is entered into the Ellipse system on return to the office.

Energex knows how many defects of each type are in the system. Accomplishment of the corrective maintenance within the prescribed timeframe is a key performance indicator, and is reported on routinely. Energex stays current on the accomplishments of the corrective maintenance items identified by inspections.

Energex has a routine program that includes infrared thermography of substations. The company has had some problems with heating on low-voltage switchboards, which prompted this program.

The company has implemented a targeted application of partial discharge monitoring using a transient earth voltage device to address a particular problem.

Energex does not conduct any routine cable diagnostic testing. The company performs cable diagnostic testing as part of a new installation commissioning process and, of course, to find faults.

Energex is not performing routine pit (manhole) inspections.

Substation Inspection

Personnel perform routine substation inspections (RSI), including both Energex owned and customer owned substations, every six months. These inspections include a review of overall station condition including cable condition, and a review of substation security.

Energex performs full diagnostic testing of substations, including infrared testing, power transformer testing, and cable diagnostic testing (33 kV) every 18 months. Energex performs infrared inspections of substations to determine hot spots, especially switchgear and other components that have been known to have specific problems.

Technology

All asset maintenance policies and protocols are managed within an enterprise asset management technology called Ellipse by Ventyx. The maintenance cycles for all assets are kept here as well. If an inspector identifies something anomalous, they may record the finding with a photograph. Each asset has an inspection cycle assigned (see Table 1). Each asset also has a clearly defined inspection procedure as outlined in the online standards guide. Maintenance standards guides are also available in hard copy on maintenance trucks.

Table 1. Network maintenance programs and cycles.


Program	Period or Cycle
Network circuit breaker	5-year cycle
Network transformer	5-year cycle
Pit (manhole) inspection	None
Work depot inspections	5-year cycle, per regulation
Substation inspections	Visual security inspection every 6 months; full visual and testing inspection every 18 months
Customer substation inspections	6 months
Vegetation management	1-year cycle in CBD; 4-year in outlying areas with less rainfall

[1]Queensland has established minimum service requirements, which are performance standards of reliability and service. These standards have become more stringent over the years, leading utilities to spend more to achieve the more aggressive targets. In the current environment, the regulator has relaxed the standards to 2009 - 2010 levels, and there is significant pressure on Energex to lower electricity prices. Consequently in planning their upcoming submission, the company is considering holding maintenance and inspection spending flat, recognizing that performance may drop back to 2009 – 2010 levels. One challenge that Energex faces is a difference in performance requirements between the state regulator in Queensland, which determines the spending plan and ultimately influence electricity pricing to pay for that plan, and the federal regulator. The federal regulator in Australia has a service target incentive scheme that rewards utilities on current performance that is improved over historic performance. Energex managers were addressing this challenge at the time of the immersion.

Substation Inspection

All asset maintenance policies and protocols for substation inspections are managed within an enterprise asset management technology called Ellipse by Ventyx. Each asset has an inspection cycle assigned; each asset also has a clearly defined inspection procedure as outlined in the online standards guide. Maintenance standards guides are also available in hard copy on some maintenance trucks .

If an inspector identifies something anomalous, they may record the finding with a photograph, which can be uploaded into the system.

5.17.9 - ESB Networks

Maintenance

Preventative Maintenance and Inspection

People

Maintenance and inspection programs are managed by the Asset Management group.

The development of maintenance and inspection programs is performed by engineers in close conjunction with a Strategy Manager who works as part of the Finance & Regulation group within Asset Management. This individual also works closely with the regulator, developing and submitting for approval a 5 year program of maintenance. The strategy works closely with the other groups in Asset Management to identify risks and prioritize programs.

The management of the execution of approved maintenance and inspection program is performed by the Program Management group, also part of Asset Management.

The execution of maintenance and inspection programs is performed by resources within Operations. ESB Networks has two operations centers, one north and one south.

Process

ESB Networks performs maintenance on a variety of equipment types. ESB Networks has established inspection frequencies within its SAP system based on equipment type and location, The system issues maintenance orders to the maintenance delivery teams for the predetermined maintenance and inspection cycles. Crews receive approximately 50,000 maintenance orders per year (total company – not just urban UG maintenance).

Orders are issued with “measurement points” associated with the expected completion time of the orders. If an order does not clear in the expected time frame, the system will re- issue the order as a high priority. Although most ESB Networks maintenance programs are cyclical, employees do have the opportunity and ability to escalate an inspection frequency or submit an individual maintenance request.

For its High Voltage underground system, ESB Networks performs seven different maintenance testing types. Not all components are subject to the full suite of tests, however. For example, transformer connections to a bus bar would not normally call for a sheath test.

Programs include bi-annual patrols of all its HV cable routes, as well as inspection and replacement programs for selected equipment including:

Five year program to replace oil filled cables and terminations
Replacement of 38kV PILC with XLPE for feeders supplying the business district
Replacing 9kM of leaking gas compression circuits (110kV)
Quarterly gauge inspections
Annual sheath inspections

For the Medium voltage system, ESB Networks Network Technicians perform periodic inspections of MV substations (each station visited once every four years). Orders are issued per group of substations within a particular block In addition to a visual inspection, Network Technicians perform ultraTEV™ inspections (a partial discharge inspection) at high risk locations, and check SF6 gas levels of primary switch gear. (Note that the Eaton Magnefix® style switchgear is inspected every two years). There is no proactive infrared testing.

ESB Networks does not have specific policies or procedures for preventative maintenance of its 10-20 kV conductor systems. Maintenance is performed only if there is a problem found, either by field crews or through monitoring.

All inspection information is recorded on a form at the site during the time of inspection, and then recorded into the SAP system at the office. If the crew finds an issue, it can address on the spot, it performs the necessary maintenance and records it.

Technology

ESB Networks uses an SAP business warehouse that addresses every aspect of network maintenance. The system is used to automatically issue scheduled maintenance orders to field teams, record maintenance findings, and to escalate maintenance when required. ESB Networks also uses this information in a program report to regulators who oversee the utility’s performance.

5.17.10 - Georgia Power

Maintenance

Preventative Maintenance and Inspection

People

Preventive maintenance and inspections of network equipment are performed by resources within the Network Operations and Reliability group. The Network Operations and Reliability group is led by a manager and consists of Test Engineers, Test Technicians, Cable Splicers and WTO’s and field supervision, which perform routine inspections of cable and cable systems, transformers, protectors, and other network infrastructure.

Vaults and manhole inspections are performed by Duct Line Mechanic and/or Cable Splicer crews depending on availability, and report to a Maintenance supervisor, part of Network Operations and Reliability. Although the Georgia Power Network Underground group does not have specific crews assigned to inspections, the Maintenance group will pull assign crew members to perform required inspections. The inspection and maintenance of network protectors is the responsibility of Test Technicians within the Network Operation and Reliability group.

Process

Inspections of vaults and manholes are on a five-year and six-year basis, respectively, on a statewide basis. Inspection crews are usually comprised of three crew members, drawn from senior Duct Line and Cable Splicers with a supervisor and possibly a WTO. Prior to inspections, the supervisor uses an Access database program to generate a blank form already populated with some specifics about the configuration of the particular manhole or vault to be inspected if a crew has filled out the information during construction or during a previous inspection. The printed inspection form does not have previous findings pre populated, assuring that the field crews must perform and record an updated inspection. Once completed, the form is populated into the Access system.

See Attachment A.

Similarly, Test Technicians generate forms from the Access database prior to network protector inspections. Completed forms are fed back into Access. All forms are kept in hard copy for seven years. If the crew identified a smaller problem at the site, and has the qualifications to implement a repair, they will perform the needed maintenance during their routine inspection; otherwise, a maintenance work order is generated by the supervisor and sent to the Maintenance group for action.

Table 1 Network Maintenance Programs


Inspection	Period or Cycle
Manhole Inspection	6-year
Vault Inspection	5-year inspection, except high-priority locations, such as the Atlanta airport
Network Protector Inspection and Maintenance	5-year, separate program from the vault inspection
Transformer Inspection	5-year, done as part of vault inspection
4kV network inspection	4-year inspect and test on the network protectors

Technology

Maintenance and inspection frequencies vary depending on the type of equipment and the location. For example, vault inspections at the Atlanta airport are performed yearly, while other vaults are inspected on a five-year inspection cycle. (See Manhole Inspection; Network Vault Inspection ; Network Protector Maintenance; Network Transformer Maintenance) Note that Georgia Power does not have any regulatory required maintenance frequencies that it must adhere to.

Where possible, information from inspection is also entered into the DistView software system for the Network Underground group. With DistView, inspectors can log onto the company intranet with a wireless laptop, bring up information about the location, enter data about inspections into pre-determined fields, and also add notes as findings are top-of-mind at the site and at the time of inspection. The inspector receives a monthly report of the pending corrective maintenance jobs from the Access system.

5.17.11 - HECO - The Hawaiian Electric Company

Maintenance

Preventative Maintenance and Inspection

People

HECO Substation resources perform maintenance and inspection of network equipment.

HECO currently is not performing any programmatic inspection and maintenance of their non-network underground facilities.

Process

Network system preventive maintenance and inspection programs include:


Program	Cycle or other Trigger
Manhole Inspection, including amp readings of molimiters.	Annual^[1]
Network Vault Inspection	2-3 years – inspected during transformer and NP maintenance
Network Transformer Maintenance (Includes Oil Sampling and Pressure Testing)	2 -3 years
Network Protector Maintenance	2-3 years

Non urgent corrective maintenance actions that are identified during inspection are put into a folder to be performed the next time a particular feeder is out of service. This is consistent with the approach used by many utilities.

Technology

See Strategic Inspection and Maintenance System.

^[1] HECO’s desired schedule is to perform these inspections and take amp readings annually. In practice, they have not adhered to this schedule.

5.17.12 - National Grid

Maintenance

Preventative Maintenance and Inspection

People

National Grid has a strong focus on asset management. Organizationally, they have an Asset Management group led by a senior vice president. This group is comprised of Asset Strategy, Distribution Planning, Investment Management, Transformation (business transformation), and Engineering. The Asset Strategy group is responsible for establishing high level policies and strategic direction, including the development of maintenance and inspection strategies.

Execution of National Grid’s maintenance and inspection strategies is the responsibility of Underground Lines East. This group is led by a manager, and includes field resources focused on civil aspects of the underground system and a field resources focused on the electrical aspects. The Underground Lines group is responsible for both the network and non – network infrastructure in eastern NY, including the Albany network. The total UG Electric East group has 29 field resources.

The Civil Group is comprised of Mechanics, Laborers, and Equipment Operators, and is led by a supervisor. This group includes a machine shop located in Albany. The group has 23 field resources.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics, is led by three supervisors. Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. Cable Splicers are also responsible for performing manhole inspections. Maintenance Mechanics perform network switching, fault location, minor vault maintenance, and inspection and maintenance of network vaults and equipment such as transformers and network protectors.

In addition, National Grid has a company-wide Inspections Department, led by a manager, responsible for completing regulatory required inspection programs. This group consists of supervisors assigned to the National Grid regions, and a union workforce to perform routine inspections. Note, however, that network inspections within Albany are performed by crews from Underground Lines East.

National Grid does not use dedicated full time maintenance crews; rather, they schedule maintenance as a work assignment along with other work types.

Process

Historically at National Grid, there had not been much maintenance visibility for distribution network assets. Network systems are inherently reliable based on their design. As with most utilities, the implementation of asset management processes at National Grid is more mature for substation assets than for distribution assets. National Grid plans to roll critical distribution assets, such as network transformers and protectors, into the tool set they have established for managing substation assets. An example of this is the use of technologies such as the Cascade system to record information about and manage distribution assets.

National Grid has established an asset register for distribution assets. For most distribution assets, National Grid’s GIS system (Smallworld) serves as the asset register. Network protector and transformer maintenance and repair data was previously maintained locally or in AIMSS. There is ongoing corporate-wide discussion as to where the data will reside. It may migrate to CASCADE with substation data, or may be maintained locally. NYE is, and has been retaining, data locally on Microsoft Access.

National Grid has recently standardized its maintenance approach to network equipment, increasing the frequency of inspection from historical practice. One driver of increasing the maintenance frequency is to be able to gather data such as loading information. Because National Grid has no remote monitoring on their network system (beyond the substation feeder breaker), the only opportunity they have to gather information about the equipment, whether condition information or loading information, is during field inspections. In general, network facilities in the Albany network are well-maintained.

Maintenance and inspection frequencies vary depending on the type of equipment and the location.

Network Maintenance Programs


Program	Period or Cycle
Network protector inspection	Annual
Network protector maintenance and testing	Five Years Two Years for CMD Style Protectors
Network transformer inspection and maintenance (does not include routine Oil sampling)	Annual
Vault inspections	Annual, performed in conjunction with the network transformer inspection
Manhole inspections	Five Years
Elevated Voltage Testing	Annual

Technology

Crews use handheld devices (Symbol Units, part of Motorola) to record inspection information. This unit has the required inspection information built into it, and a mapping feature. It also contains the most up-to-date system data and previous inspection results. Appropriate codes for the inspection are entered directly into the unit and returned to the supervisor for entry into the computer database. These codes alert GIS of changes in the field.

Computapole is a mobile utilities software platform that runs on handheld devices and is customized to meet National Grid’s specific needs. Computapole is used for inspections and mapping functions on handheld devices. Once information is entered in the Computapole system, work is managed by an interface with STORMS (below) to create work requests.

Severn Trent Operational Resource Management System (STORMS) is National Grid’s work management system. The work management system includes tools to initiate, design, estimate, assign, schedule, report time/vehicle use, and close distribution work. Computapole sends inspection information to STORMS to create work requests as needed.

Inspectors do not take photographs of condition issues identified during inspection.

National Grid does not use duct line cameras.

Note that at the time of the EPRI immersion, National Grid was engaged in a corporate-wide discussion as to where network transformer and protector maintenance and repair data will reside. It may migrate to CASCADE with substation data, or may be maintained locally. NYE is, and has been, retaining data locally on Microsoft Access.

5.17.13 - PG&E

Maintenance

Preventative Maintenance and Inspection

People

PG&E has assigned a specific person as the “Manager of Networks”, part of the Distribution Engineering and Mapping organization. This asset manager is responsible for determining the maintenance and inspection strategies for network assets including network transformers, network switches, and network protectors. Note that the asset management of cables and cable accessories is the responsibility of a different asset manager at PG&E, located within Distribution Standards.

The Manager of Networks has a well documented asset strategy for managing network assets.

The Manager of Networks works closely with a program manager within the Electric Distribution Maintenance Program group, also part of the Distribution Engineering and Mapping organization. This program manager is responsible for defining the work processes and supporting the divisions in obtaining funding for distribution maintenance programs. The group looks closely at what assets are to be maintained, what the resource requirements are to perform the maintenance, and what the funding requirements are. They also actively work with the manager of networks to identify process improvement opportunities. See Attachment F for a sample process map developed by the Electric Distribution Maintenance Program group for performing network protector maintenance.

Performance of maintenance and inspection of the network infrastructure at PG&E is the responsibility of the Maintenance and Construction- Electric Network organization. The group is led by a Superintendent, VP, who is responsible for the secondary network infrastructure in the Bay Area Region, including San Francisco and Oakland. Note that this individual’s responsibility includes radial distribution in San Francisco and Oakland as well.

Reporting to the superintendent, VP are three Distribution Supervisor positions who supervise the network field resources, two in San Francisco and one in Oakland. In addition, there is a distribution supervisor who leads the Network Protector Maintenance / Repair shop, and a Supervisor of the Compliance group, responsible for quality compliance.

The field groups are comprised of cable splicers, a bargaining unit position (IBEW). Cable splicers perform both cable work, such as cable installation and splicing, and network equipment work, such as network protector and transformer maintenance.

In San Francisco, PG&E network crews who perform preventive maintenance work the night shift^[1] . The decision to work at night is driven by two main factors. One is that regulations issued by the San Francisco Municipal Transportation Agency prevent utilities from blocking traffic during the day. The other is that loading is lower at night, enabling PG&E to clear feeders and maintain adequate capacity to meet loading. Note that in Oakland, PG&E performs network preventive maintenance with day shift crews.

In San Francisco, they typically run four 3- man crews in the evening to perform maintenance. A crew is normally made up of a journeyman cable splicer, who does most of the network protector maintenance work, and two helpers (usually apprentice cable splicers).

PG&E also has three cable crew foremen on the night shift. The cable crew foreman is a working position, with one foreman typically taking clearances and installing grounds, and the others overseeing the crews.

Inspection of manholes, including cables and cable accessories in the network, is performed by the Compliance Department, part of the M&C Electric network organization. This group performs and reports on regulatory required inspections and patrols (CPUC GO 165) of distribution infrastructure.

Process

Maintenance and inspection frequencies vary depending on the type of equipment and the location. PG&E is actively shifting its maintenance strategy from time-based maintenance to condition based maintenance approaches. An example of this is their annual sampling program of oil filled chambers within the network unit to develop performance trends for each chamber and triggers for action (see Network Transformer Maintenance / Oil Testing).

Network Maintenance Programs


Program	Period or Cycle
Network protector inspection	Annual
Network protector maintenance and testing	Three years
Network transformer inspection, maintenance and oil testing Including primary chamber, ground switch, and main tank	Annual, transformer maintenance action driven by inspection and testing findings.
Vault inspections	Annual, performed in conjunction with the network transformer inspection
Vault Environmental Cleanup	Number of cleanups based on findings from annual vault inspection
Manhole inspections	Three years

Technology

PG&E recognizes the role of technology in moving from time based to predictive, condition based maintenance. For example, they are installing a new, fiber based network monitoring system that will be able to monitor pressure, temperature, loading and voltage sensing of all chambers, and will enable remote control of switches and network protectors (See Remote Monitoring). The system will also enable automated generation of maintenance tags based on monitored trends.

^[1] Note that Cable Splicers are assigned during the day to work on San Francisco’s radial underground system. These crews can be redirected to address network issues that may arise during the day. However, all planned work on the network is performed at night.

5.17.14 - Portland General Electric

People

Crews working in the CORE group primarily perform preventative maintenance and inspection on the network. In general, the CORE group uses a philosophy of repairing issues when they arise, including findings from period inspections. If crews find any significant electrical problems, they may engage Distribution Engineers for support. Civil issues are usually outsourced to external contractors for repair. The Service & Design Project Managers (SDPMs), who coordinate with the customer to make the required repairs, address structural problems in customer-owned facilities.

CORE Group

The CORE group oversees the underground facilities and has a supervisor overseeing operations and fieldwork. The CORE General Foreman reports to the Response & Restoration (R&R) Supervisor.

Crews

The craft workers assigned to the CORE group, which is a part of the Portland Service Center (PSC), focus specifically on the underground CORE, including both radial underground and network underground infrastructure in downtown Portland. Their responsibility includes operations and maintenance of the network infrastructure. An Underground Core Field Operations Supervisor leads the CORE group.

Currently, the following 16 people work in CORE:

Four non-journeymen
Eleven journeymen (e.g., assistant cable splicers, cable splicers, foremen)
One Special Tester

Resources in the CORE include the following:

Crew foreman: Crew foreman (a working, bargaining unit position), required to be a cable splicer
Cable splicer: This is the journey worker position in the CORE.To become a cable splicer in CORE, an employee must spend one year in the CORE area as a cable splicer assistant.
Cable splicer assistant: A person entering the CORE as a cable splicer assistant must be a journeyman lineman. All cable splicers start as assistant cable splicers for one year to learn the system and network.

The cable splicer position is a “jack-of-all-trades” position with work including the following:

Cable pulling
Splicing
Cable and network equipment maintenance
Cleaning
Pulling oil samples from transformers

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault, while the helper, typically a non-journeyman classification, stays above ground carrying material and watching the barricades and street for potential hazards.

Special Tester

PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. Outside the network, Special Testers work with reclosers and their settings, and perform cable testing and cable fault location. Within the network, the Special Tester works closely with the network protectors, becoming the department expert with this equipment. PGE has embedded one Special Tester within the CORE group who receives specialized training in network protectors from the manufacturer, Eaton.

The Special Tester usually partners with cable splicers and works as part of a crew. The “special testing” crew includes the Special Tester, a crew foreman (a cable splicer), a lineman/cable splicer, and a topman, who is a non-journeyman helper. The topman stays outside the hole and watches the manhole/vault entrance for potential hazards.

In addition to NP testing and settings, the Special Tester focuses on power quality issues, including customer complaints about voltage.

Reliability Technicians: Reliability Technicians perform infrared (IR) thermography inspections on primary systems and network protectors as part of the Quality and Reliability Program (QRP), a reliability improvement program targeted at key infrastructure. PGE has three of these IR specialists, who mainly focus on the transmission system but also work on high-priority distribution systems. Organizationally, the Reliability Technicians belong to the same group as the Special Testers and report to the Testing Supervisor.

Network Protector Crew: The CORE group has created a dedicated crew that deals with network protectors and performs other construction work. This crew is comprised of cable splicers who receive formal training and attend conferences to gain experience with network protectors. This crew includes a foreman, journeyman (who will rotate every three months), and Special Tester.

PGE has approximately 230 network protectors on the system, with half included in the 480 V spot networks, and half in the 120/208 V area grid systems. Presently, PGE has three construction/maintenance crews and will add the dedicated crew protector crew.

Maintenance Crew: Historically, work crews have been assigned a variety of work types depending on needs, ranging from new construction to maintenance and operation of the system. Due to the large number of new construction projects underway in Portland, and to assure that the demand for resources to support that construction does not erode the focus on maintenance, the CORE group is considering creating a dedicated maintenance crew that will maintain a focus on network infrastructure inspection and maintenance.

Process

PGE performs periodic inspection and maintenance of network equipment. An overview of its programs is provided in the following table.


Preventive Maintenance Programs
Network Protector Inspection, Maintenance and Testing	Testing is annual for 480 V units and every two years for 216 V units. Maintenance is performed with the primary feeder energized. Accompanied by complete vault inspection
Network Transformer Inspection and Maintenance	Informal cycle, usually performed in conjunction with NP maintenance
Transformer Oil Testing	Four-year cycle, accompanied by complete vault inspection
Vault Inspections	Informal cycle, usually performed in conjunction with equipment maintenance and testing
Vault Environmental Cleanup	Clean vaults as part of inspection
Manhole Inspections	Informal cycle, generally inspected every year

Manhole and Vault Inspections

PGE’s network has 1300 manholes/vaults. Of these, 529 are vault structures, with 280 vaults containing equipment.

For vaults that contain equipment, such as network transformers or network protectors, the frequency of inspection dovetails the performance of equipment maintenance, as the maintenance of equipment is accompanied by a vault inspection. For example, 480 V network protectors are maintained annually, so the inspection of the vaults that house 480 V protectors is also performed annually.

For general purpose structures, including vaults, manholes, and handholes that do not contain equipment, PGE attempts to inspect all underground enclosures annually. However, manpower availability determines the exact cycle. At the start of each year, general work orders for inspection of manholes are created in Maximo for a particular geographical area, with each work order covering the manholes in a one- or two-block area. A crew receives these work orders and is expected to perform inspections of the general purpose enclosures when it does not have any customer work. If there is little customer work on the network, inspections can be completed for all non-equipment manholes and vaults within a calendar year.

PGE employees, not contractors, perform all inspections of general purpose structures, including both an electrical and civil (structural) review. Inspections also include a visual inspection to identify leaks, assess vault cleanliness, etc., and may include the use of IR thermography at the discretion of the inspection crew. All crew have been issued IR guns. If the crew identifies something amiss, it may bring in the Special Tester, who has a more sophisticated IR camera and has received special training in interpreting IR readings. (Note that PGE also has a cyclical IR program as part of its QRP program, which targets high-priority areas for routine IR thermography on a four-year cycle, including all network primary cables and equipment.)

Crews may take load readings on the secondary system to try identifying open limiters when inspecting vaults. Because some of the secondary feeders are difficult to access, this continuity testing is restricted to accessible secondary feeders.

Manhole/vault cleaning is bundled together with the inspection function. As part of the inspection, crews clean the manhole/vault. Crews clean vaults ahead of time if they know that they will be visiting a specific vault for maintenance work.

PGE does not use a formal inspection sheet for inspections of the general purpose vaults, although a crew completes a Field Action Report if it finds issues with a manhole/vault. The Field Action Report records follow-up corrective action identified during inspection. See Appendix B for a sample Field Action Report. If no action is needed, crews do not fill out any paperwork but the completion of the inspection is noted in Maximo. If testing of equipment is performed in the vault, then crews do not keep records of the testing.

If a crew can repair a problem without the need for engineering or design services, such as replacing a damaged ladder, it will do so while it is there. The CORE keeps limited documentation of these informal fixes as part of its “fix-it-when-you-find-it” approach. For repairs that are not done right away, the Field Action Report prioritizes them based on urgency. Electrical issues receive a “1,” the highest priority. A lid that is shattered or needs replacement receives a “2” priority. Priority “3” work is rarely undertaken because the crew tends to repair such small issues while at the site. The priorities guide the urgency of the repair but are not accompanied by specific deadlines for accomplishment. Crews do try to be as expedient and efficient as possible, scheduling work as soon as circuits are available.

Engineering generally responds to electrical problems while SDPMs handle the other tasks, such as coordination with external contractors. If vaults/manholes are in need of civil or structural repairs, PGE uses an external Level III contractor. The company has a two-year contract with the outside contractors to undertake this type of work. For large, complex repairs, a structural engineer will be used.

Engineering works closely with the CORE management to assure that these repairs are addressed. PGE notes that it has little backlog of electrical repairs but some backlog of structural repairs.

For vaults that contain equipment, inspections are performed in conjunction with the performance of equipment maintenance. For example, when a Special Tester performs protector maintenance, the crew also performs a visual inspection and IR inspection of the entire vault.

Network Protectors

Network protectors are maintained annually for 480 V protectors at spot network locations, and every two years for the 216 V protectors supplying the area networks. As part of the testing, the Special Tester connects a NP test kit. When crews inspect and maintain network protectors, the primary feeder remains energized. They re-pressurize the network protectors once they close them, using nitrogen at 2-3 lb of pressure and ensuring that there are no leaks around the enclosure. Protector maintenance is documented on index cards. PGE is presently undertaking a project to convert this process to an electronic format.

As part of the network protector testing, crews also undertake a general vault inspection, including an inspection of other equipment in the vault and civil condition. This includes inspection of the network transformer, checking and recording the transformer oil temperature (oil sampling and testing is performed as part of a separate program), and performing a general infrared inspection of the vault.

PGE does remotely monitor network protector information, including the voltage and all three-phase currents on the transformer side and bus side of the unit. This measures the power factor, temperature, position of the contact breaker, and whether it is open or closed. Part of the feeder clearance process involves checking the monitored values. If after opening a feeder breaker, the remote monitoring system indicates that one of the protectors is still closed, a crew goes out to the vault to troubleshoot.

PGE does not perform periodic drop testing, in which it opens the feeder to verify that all the network protectors will open, but it does identify closed protectors when it periodically takes a circuit out to perform maintenance.

Transformers

PGE has not had any catastrophic failures of network transformers and attributes this, in part, to the relatively low loading on the system and the area not having salted roads. It does not monitor the network transformers in any way, although a system for remotely monitoring transformer temperatures is planned.

Termination Chambers: PGE is actively replacing lead cable terminations at the network transformer with Energy Services Network Association (ESNA) style connections. Crews modify the transformer termination chambers using a new conversion kit on site. First, they establish clearance. Afterwards, the crew cuts the plate off the termination chamber, places a new termination, welds it, rewires the transformer, and re-energizes it. PGE has performed 6-12 of these conversions.

Transformer Oil Inspections: PGE does routinely sample and test oil in the network transformers. The CORE crews take the samples from all fluid-filled chambers, and an external laboratory performs the analysis. Crews de-energize the primary circuit at the feeder breaker before performing oil sampling. They are not taking a clearance, as this is not considered performing physical work on the system. They do try to schedule the pulling of oil in conjunction with feeder outages that may be scheduled for other reasons.

Historically, crews performed oil sampling and testing on a four-year cycle, but they believe that the frequency should be more often so that they can spot trends rather than react to individual high readings. They are in the process of accelerating the sampling period and have not yet decided on a timeframe.

The type of oil analysis performed on transformer samples includes oil analysis, dissolved gas analysis (DGA), power factor testing, and polychlorinated biphenyls (PCB) analysis. PGE has started using FR3 type oil (ester) on all equipment other than the network transformers, although the change is not yet complete. PGE will consider changing its network transformer specification to the use of flame retardant oil alternatives in the future.

When entering the vault to perform transformer oil sampling, crews also perform a vault inspection, including a visual inspection and the use of IR.

Infrared (IR)

As part of their vault inspections associated with equipment maintenance, crews perform infrared inspections of the major components in the vault with regular FLIR cameras. The Special Tester has more sophisticated equipment, and if crews identify an issue, they call the Special Tester to undertake a more in-depth assessment. Crews have started to undertake IR checks as part of manhole and vault entry, but this is informal and not part of the formal manhole entry requirements.

Crews use a form to document any anomalies, known as the Feeder Inspection Form. If they find an IR anomaly, they record the load to make sure that overloading is not the cause.

The Special Tester or Reliability Technician also performs IR inspections of network feeders on a four-year cycle, as part of a maintenance and inspection program separate from the vault inspections and performed in conjunction with transformer and network protector maintenance. This program is part of the QRP, a heightened inspection program for key infrastructure, including the network. In order to do this, the inspector, either the Special Tester or Reliability Technician, partners with a crew and at least a topman and a journeyman, because inspectors usually must enter the vaults.

The IR is undertaken on every component and primary joint, and the inspector looks for components that show a high temperature. Where resources permit, the inspector may also IR-test some secondary systems. If the inspector finds any abnormal conditions, the inspector takes a picture and creates a report. The issue is fixed within a week, and all reporting is by exception, with reports passed to the Network Engineering Group.

Special Testers IR test some cable joints/bends on the system. If they find a difference in temperature between joints in a cable of over 10oF (-12oC), the general practice is to deal with it within two weeks. Where the difference is between 20 and 28oF (-7 and -2oC), the problem must be dealt with immediately.

Cables and Connectors

Overall, the utility has had few issues with cable performance in the network. PGE does not perform any routine diagnostic cable testing on the network feeders, although it previously made some attempts to diagnose the primary cables crossing the river. PGE does not routinely test new cables. However, before commissioning new cable or returning a de-energized primary circuit to service, crews perform a DC hipot test. In general, PGE policies advise against leaving cables de-energized for long periods of time. If the cable has been de-energized for several weeks, the cable failed and was repaired, or the cable was modified (e.g., a section replacement), then crews perform a circuit verification test, which includes a DC hipot test. When replacing a T-body or a major component, a DC hipot test is also performed.

PGE performs very low frequency (VLF) testing on the getaway cables at substations and does not take, include, or record any tan delta measures.

Distribution Automation Inspection

PGE has a remote monitoring system that provides information from the network protector relay. All the line workers have access to this system and can determine if any network protectors are currently open. PGE would like to more effectively leverage the remote monitoring system to better ascertain the health of and troubleshoot the system.

Technology

Network Truck: The network van has the network test kit. All critical spares are either on the network truck or in easily accessible locations. The truck has a generator and pump.

Maximo: PGE uses the Maximo for Utilities 7.5 system to manage inspection reports and store details about any maintenance needed.

5.17.15 - SCL - Seattle City Light

Maintenance

Preventative Maintenance and Inspection

People

SCL has an Energy Delivery Field Operations department that includes a network Electrical Services group (Area Field Operations – Network) group, and a network Civil Services group.

The Electrical Services group is made of 84 total people including the supervision and a five-person cable-locate crew. (Note: this cable-locate crew does underground locating for the whole company). This group performs all construction, maintenance, and operation of the network system.

The Civil Services group consists of approximately 36 employees. In addition, SCL contracts approximately 25% of their civil construction work associated with their network system as well.

Cable Splicer Position

The Cable Splicer position at SCL is a generalist position. Cable Splicers perform all electrical aspects of network construction, operations, and maintenance. All electrical employees who work in the network are either Crew Chiefs, journeyman Cable Splicers, or apprentices in the mode of progression, working their way towards the journeyman level.

Crew Makeup

A network crew is normally made up of one Crew Chief, one or two Cable Splicers, and one apprentice. The type of work to be done and SCL work rules will dictate the appropriate crew makeup. For example, performing switching in a vault requires at least two journeyman-level employees to be in the vault. These and other work rules and safety practices are spelled out in the Washington State Safety Standards for Electrical Workers, Chapter 296-45 WAC.

Process

Preventive Maintenance and Inspection

SCL performs two main programmatic inspection and maintenance programs on network equipment:

Four-year maintenance cycle for network feeders. (Note: Network feeder maintenance includes transformer inspection and maintenance and manhole and vault inspection and maintenance.)
Four-year maintenance cycle for network protectors. (This program is completely independent of the feeder maintenance program.)

Modified Maintenance Approach

While SCL’s goal is to maintain feeders on a four-year cycle, they have fallen behind on their maintenance because of the construction workload. To address this, they have implemented two types of feeder maintenance. The first type is the “full maintenance,” which means they do a full and complete inspection and maintenance during the scheduled feeder outage. The second type is an abbreviated version of maintenance called a “modified maintenance.” This type of inspection includes a thorough inspection of any transformer exposed to the elements, such as a subsurface vault, but a shorter maintenance on a transformer housed in a surface or other dry vault. Note: any feeder that has not been maintained within six years must have full maintenance performed.

Technology

Transformer Oil Testing

Transformer oil samples are taken and tested at an SCL Testing Laboratory, rather than at an external lab.

5.17.16 - Survey Results

Survey Results

Maintenance

Preventive Maintenance and Inspection

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 7 : Please indicate if your company performs the following Inspection activities on a routine basis and at what frequency.

Question 11 : Are you using Infrared (iR) technology as part of your manhole and vault inspection / assessment process?

Question 12 : With which activities do you perform iR testing?

Question 14 : Are you using cameras (non iR) as part of your manhole / vault inspections (check all that apply)?

Question 25 : Please indicate if your company performs the following Maintenance activities on a routine basis and at what frequency.

Survey Questions taken from 2015 survey results - Maintenance

Question 91 : Do you perform cable limiter continuity checks (amp checks) as part of your preventive maintenance program?

Question 100 : Do you use a non-iR diagnostic camera to assess the condition of ducts and conduits?

Survey Questions taken from 2012 survey results - Maintenance

Question 6.12 : Do you perform heat gun checks as part of your preventive maintenance programs?

Question 6.19 : Do you perform cable limiter continuity checks as part of your preventive maintenance program?

Question 6.31 : Do you use a diagnostic camera to ascertain the condition of ducts and conduits?

Question 6.34 : Do your crews utilize tablets or laptop computers for maintenance

Question 6.35 : Is your record keeping done electronically or manually?

Survey Questions taken from 2009 survey results - Maintenance

Question 6.24 : Do you perform heat gun checks as part of your preventive maintenance programs? (This question is 6.12 in the 2012 survey)

Question 6.25 : Do you perform cable limiter continuity checks as part of your preventive maintenance program? (This question is 6.19 in the 2012 survey)

Question 6.36 : Do you use a diagnostic camera to ascertain the condition of ducts and conduits? (This question is 6.31 in the 2012 survey)

5.18 - Strategic Inspection and Maintenance System

5.18.1 - Con Edison - Consolidated Edison

Maintenance

Strategic Inspection and Maintenance System

(Computerized Inspection of Network Distribution Equipment (CINDE))

People

Field Engineering Group

Con Edison has a field engineering group consisting of 40 individuals who perform a variety of quality-assurance-related tasks including:

Inspections/manhole inspections
Post-construction inspections to determine to adherence to Specifications
Safety inspections
Critical manhole inspections, performed in any manhole on the immediate block of a substation, and inspected on a three-year cycle
Regular manhole/vault inspections, scheduled every five years
- Infrared inspections of transformers/network protectors/substations
- Infrared is a four-year cycle for 277/480-V installations.
- Infrared is not programmatic, but is performed randomly, or by exception at 120/208 V. Infrared inspections are performed more frequently at sensitive customer locations such as hospitals and museums.
- Substation infrared is annual.
- Use strategically placed site glasses to obtain infrared views of some locations.
- Use outside contractor to perform infrared training.
Cable and Joint failure analysis specimen retrieval and tracking
Fill-in work, special requests
Check out erroneous readings monitored through the RMS system
Map verification; that is, comparing what is on the mapping system to what is in the field
Random spot checks, focused on workmanship
Random equipment checks
- For example, the Field Engineering group performs random monthly spot checks of primary splice packs to be sure that the kit is complete.
Respond to voltage complaints

Note: This group does not routinely inspect design versus build, or as-built versus mapped. The department is made up primarily of Splicers. People are chosen for jobs in the department by seniority.

Process

Inspection and Maintenance

Con Edison performs periodic maintenance and inspection of network distribution equipment, including network feeders, transformers, network protectors, grounding transformers, shut and series reactors, step-down transformers, sump pumps and oil minder systems, remote monitoring system (RMS) equipment, and vaults, gratings, and related structures.

Con Edison’s approach to performing an inspection is to inspect all the equipment and structures associated with a particular vault ID at a location regardless of category or classification, and even if the particular equipment associated with a particular vault ID resides within different compartments (for example, a transformer and network protector may be located in separate physical compartments even though they both share the same vault ID). This type of inspection is referred to as a CINDE Inspection, based on the name of their maintenance management system (Computerized Inspection of Network Distribution Equipment).

Con Edison performs inspections energized; crews do not take a feeder outage to perform inspections, perform pressure drop testing, or take transformer oil samples. Con Edison does not routinely exercise feeder breakers.

In an effort to more efficiently use their resources, and when non-priority conditions allow, Con Edison takes advantage of situations where they have to enter a vault or manhole for a reason other than a scheduled inspection, and perform a nonscheduled inspection while they are in the vault. When the record of this nonscheduled inspection is recorded in CINDE, the system “resets the clock” for the next inspection date.

Network equipment at 208 V is generally inspected on a 5-year cycle. 460-V facilities, sensitive customers, facilities in flood areas, and other more critical locations are inspected more frequently, often annually. Con Edison establishes network equipment inspection cycles depending on two factors: the inspection category and the inspection classification .

The inspection category refers to the type of inspection, and includes a Visual Inspection, a 120/208-V Test Box Inspection, and a 460-V Test Box Inspection. The Visual Inspection includes activities beyond visually assessing condition and recording information, such as pressure drop testing and taking transformer oil samples. The test Box inspections involve specialized testing of network protectors with the network relay installed. Note that all of the elements of a Visual Inspection are performed along with the Test Box Inspections.

The inspection classification refers to characteristics of the inspection site that dictate the inspection cycle. For example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a “tidal” area would be visually inspected annually. Con Edison considers the following classifications in determining inspection cycles:

Routine
Back-feed: banks installed on a feeder involved in a back-feed incident
Candidate for Replacement: commonly due to corrosion damage
Essential Services: critical customers
Flooded Bank: nonsubmersible equipment that has experienced high water levels
208-V Isolated Bank: units that require more frequent inspection than distributed secondary grid units
Remote Monitoring System(RMS), Non RMS, Unit Not Reporting (UNR): Con Edison varies inspection cycles based on the level of remote monitoring installed
Tidal, Water, and Storm Locations

Note that Con Edison requires employees to perform at least a quick visual inspection (QVI) anytime an individual enters a network enclosure, even if the reason for entering an enclosure does not warrant a CINDE Inspection. This type of inspection (QVI) differs from the CINDE inspection category of Visual Inspection described above, in that it is not a full, accredited inspection.

Technology

Inspection and Maintenance Software

Con Edison uses legacy maintenance management software called CINDE, which is an acronym for Computerized Inspection of Network Distribution Equipment. CINDE is a system that records inspection data and initiates inspections based on predetermined cycles. These cycles depend on the category of inspection (for example, a visual inspection versus a “Test Box” inspection) and various predetermined classifications of inspections (for example, a “Routine” 208-V vault is visually inspected on a 5-year cycle, while a 208-V vault located in a tidal area is visually inspected annually).

Con Edison inspectors record inspection data on hand-held devices (Tough Books). The utility requires that the inspection data be downloaded into the CINDE – Mainsaver system (Mainsaver is the part of the CINDE system used to record data) within three days following the inspection. Inspection data that is entered into the CINDE system includes:

Equipment serial numbers
As-found and abnormal conditions, such as transformer oil level, state of corrosion, and water in the vault
Defective equipment or structures
Repairs or change-outs undertaken
As-left condition, such as transformer pressure and liquid level, and pressure of housing

The CINDE – Mainsaver system is also used by Con Edison to prioritize follow-up work, or outstanding defects to be corrected that are identified through inspection or other visits to network enclosures. The Electric Operations Region is responsible for prioritizing follow-up work by considering the location of the work with respect to risk to public safety, reliability impact, the type of installation, age of the outstanding defect, and the efficient use of resources.

5.18.2 - Energex

Maintenance

Planned Maintenance Outages

People

Energex has comprehensive maintenance standards. Standards are made available to employees on the internet. Energex performs a complete review of all standards on a three-year cycle. As changes occur mid cycle, Energex distributes bulletins that provide the updated information to the maintenance employee base. The Standards group employs maintenance engineers and uses contractors who follow the published Energex standards guides available on the company intranet. Contractors are used primarily for non-technical work such as vegetation management.

Process

Energex has embarked on a four year project to perform systematic upgrades and preventative maintenance of its extensive urban underground system in the CBD. As a result, Energex must engage with customers on its three-feeder mesh systems to provide a schedule for planned outages as the company works on specific sections of the CBD network.

For example, some customers are supplied by Energex via multiple transformers separated by a switch on the primary. If Energex plans to take the normal feed out of service, the customer may have to manually switch its load to received supply from the alternate feed to the building. Therefore, maintenance is usually done on weekends. Customers are good about switching their service during these outages. During planned maintenance, the customer is operating in n-1. If a customer loses service, they will have no power until Energex closes the switchboard

5.18.3 - HECO - The Hawaiian Electric Company

Maintenance

Strategic Inspection and Maintenance System

People

HECO has an Inspection group focused on performing asset inspections and prioritizing follow-up maintenance activities identified by inspection. This group is part of the Planning Division of the C&M Underground Division.

The group is comprised of five resources (Inspectors) plus a Senior T&D Maintenance Engineer. The Inspectors are people who have experience as Lineman in the Overhead C&M group. Inspectors are in the bargaining unit. The pay grade of an Inspector is higher than the pay grade of a Lineman.

Process

All of the programmatic inspections being performed by this group are focused on overhead facilities (wood pole inspections, for example). HECO currently is not performing any programmatic inspection and maintenance of their non-network underground facilities.

However the group may get involved with underground facility inspection and maintenance prioritization when a problem is identified by a third party such as a C&M supervisor.

For example, if a C&M Supervisor identifies a problem whose repair is not required immediately^[1] (such as a padmount transformer “sweating” oil), the Supervisor will involve the Inspections group to evaluate and prioritize the repair.

The inspector will go into the field and inspect the unit and determine next steps. If the inspector does feel that the repair should be made immediately, they will create a Repair Order (RO) to fix / replace the unit.

If an inspector notes that a unit is actively leaking, they may place some oil absorbent material at the site.

If the inspectors concur with the initial assessment of the C&M supervisor who identified the problem, that the maintenance item is not an emergency and can be prioritized and scheduled for repair, they will perform a physical inspection, noting the findings, photograph the asset, and entered it into a company developed software system called the Strategic Inspection and maintenance System (SIMS).

SIMS houses the inspected data, photographs, and enables the inspection record to be viewed by others on HECO’s intranet. Note that cable diagnostic test data is not being recorded in SIMS.

Inspectors will review the findings in SIMS and assign a “severity” score based on weightings of certain characteristics. The finding is weighted depending on the environment, the type of construction, the type of structure or equipment, safety implications, and other considerations. See (Attachment J) Note that the weightings for underground equipment inspection findings are still under development at HECO, as HECO initially implemented this approach for overhead facility inspection findings.

After assigning the severity score, Inspectors will prepare work packages and send them to the C&M Planning group whose job it is to schedule the work and monitor its execution. One of HECO’s biggest challenges is that some of the identified work continues to be subordinated to other, higher priority projects, and doesn’t get addressed for some time. This has resulted in a backlog of corrective maintenance work packages.

HECO does not have written guidelines or checklists that that indicate that work of a certain type of or a certain assigned level of severity, must get done in a certain period of time. Sometimes the Inspectors will provide the Planning group with an email indicating the level of priority - but there is no list of criteria that guides the planners in prioritizing these items.

HECO noted that this lack of a written guideline is by design, in that they don’t want a document that says they must do something in a certain period of time, which could limit their scheduling flexibility. They also indicated that the relative priority of projects are changing all the time, so that if they did document the response to certain kinds of activity they would have to keep updating the document to keep it current.

Technology

HECO is using a work management system called Ellipse, by Mincom.

HECO is using a home developed system for creating Repair Orders (RO’s).

HECO is using a home developed software package, SIMS, to record and prioritize inspection information. Data, including photographs, associated with inspections are recorded in this system. Inspectors use field laptops to record inspection information into SIMS.

SIMS inspection data is available on HECO’s intranet.

HECO has 2 websites for posting inspection and corrective maintenance information - one where all the inspection information goes (from SIMS), and the other with information about the work packets that are created to perform follow up work indentified by the inspection. After the inspectors review the information they gathered by inspection, they create “work packets” for the findings that must be corrected. These work packets are the ones that are sent to the planning group to be scheduled for completion. Work packets can be reviewed at the second website.

Inspectors can utilize SIMS to review both the inspection data, and the progress of any follow up work.

^[1] If a problem must be addressed immediately, the C&M supervisor will create a repair order, bypassing the Inspections group, with the work being treated as an emergency repair.

5.18.4 - Survey Results

Survey Results

Maintenance

Strategic Inspection and Maintenance System

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 24 : In determining your maintenance frequency, do you perform a risk or condition assessment of your individual equipment, (manholes, vaults, etc.), and vary your maintenance approach based on that assessment? (For example, a higher risk vault inspected more frequently than a lower risk vault)

Question 25 : Please indicate if your company performs the following Maintenance activities on a routine basis and at what frequency.

Survey Questions taken from 2015 survey results - Maintenance

Question 80 : In determining your maintenance frequency, do you perform a risk or condition assessment of your individual equipment, (manholes, vaults, etc.), and vary your maintenance approach based on that assessment? (for example, a higher risk vault inspected more frequently than a lower risk vault)

Question 85 : Please indicate if your company performs the following activities on a routine basis and at what frequency.

Survey Questions taken from 2012 survey results - Maintenance

Question 6.1 : Do you have a documented, up to date maintenance guidelines for performing maintenance on network equipment? (Example: network transformer maintenance guideline)

Question 6.2 : In determining your maintenance frequency, do you perform a risk assessment of your individual equipment, manholes, vaults, etc and vary your maintenance approach based on that risk? (For example, a higher risk vault inspected more frequently than a lower risk vault)

Survey Questions taken from 2009 survey results - Maintenance

Question 6.2 : In determining your maintenance frequency, do you perform a risk assessment of your individual equipment, manholes, vaults, etc and vary your maintenance approach based on that risk? (For example, a higher risk vault inspected more frequently than a lower risk vault)

Question 6.3 : Do you have a documented, up to date maintenance guidelines for performing maintenance on network equipment? (Example: network transformer maintenance guideline) (This question is 6.3 in the 2012 survey)

5.19 - Switchgear Inspection and Maintenance

5.19.1 - Duke Energy Florida

Maintenance

Switchgear Inspection and Maintenance

People

Regularly scheduled inspections and maintenance of all switchgear in Clearwater and St. Petersburg are performed by craft workers, Network Specialists and Electrician Apprentices, within the Network Group, part of the Construction and Maintenance Organization. The Network Group is led by a supervisor, and consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position).

Duke Energy Florida’s construction and maintenance organization is divided into regions, with both Clearwater and St. Petersburg falling within their South Coastal Region. The Construction and Maintenance organization for the South Coastal Region is led by a General Manager.

A Project Manager (part of the Project Management group) will aid in the scheduling and oversight of inspections and maintenance for crews.

Process

Duke Energy Florida network crews inspect switchgear - both network sectionalizing switches, referred to as “RA” (rocker arm) switches, and Automated Transfer Switches, referred to as ATS switches - on a regular basis during vault inspections (see Figures 1 and 2). The frequency of inspection depends on the conditions at the site and the criticality of the device location, and can range from once per year to up to six times per year. For example, switchgear associated with hospitals are inspected and maintained six times per year (every 2 months). In general, Automatic Transfer Switches (ATS) not associated with critical customers are inspected twice per year.

Figure 1: Network feeder primary sectionalizing switch (RA) switch

Figure 2: Network feeder primary sectionalizing switch (RA) switch

Costs for performing switch inspection and maintenance are budgeted separately from other maintenance expenses.

Switch inspection and maintenance is comprehensive including items such as:

Visual inspection vault
Visual inspection of the switch, barriers, insulators, arresters
Record the switches controller’s setting(s)
Manually operate (exercise) the switch
Check the switch for automatic operation by source-loss simulation
Inspect fault indicators (RA switches have remote reporting FCIs)
Perform Infrared scan

Information from the inspection is recorded on an inspection form, including an assessment of the priority or severity of the finding. See Attachment J . Information from the inspection is entered into a computer system, and the hard copy form is maintained in a file. Duke Energy Florida has a “Further Work Ticket Process” which is initiated to pursue remediation for corrective maintenance items identified by inspection. The repair schedule is dictated by the priority of the finding.

Duke Energy Florida does have SCADA control and monitoring of most switchgear locations. SCADA may also alerts crews to switchgear conditions that need immediate attention. For example, Duke Energy has recently experienced a number of alarms from proximity sensors which were installed to ATS’s as part of the installation of distribution SCADA. Proximity sensors were added to these devices to confirm operation of the device by detecting the position of the switch blades using the sensor. The sensors can trigger alarms which result in the performance of on-demand inspections by network crews. Note that the recent experience in these alarms was determined to be the result of a performance issue with the sensor itself, and the Duke Energy Florida Network Group is in the process of replacing these sensors.

Technology

Switchgear checklist Inspection and Maintenance forms are filled out on site and entered into the online WMIS workflow management system.

SCADA utilizes a 900 MHz radio system.

5.20 - Terminator Maintenance (37kV)

5.20.1 - CEI - The Illuminating Company

Maintenance

Terminator Maintenance (37kV)

People

CEI has one Underground Network Services Center responsible for performing preventive maintenance and inspections of the underground, including the networked secondary and non network ducted conduit systems. The service center is comprised of Underground Electricians who inspect and maintain the underground system.

Process

CEI inspects 37kV oil filled terminations (spreaders) on 6 month cycle. These devices contain oil under pressure and are inspected for leaks and to assure they have adequate oil and oil pressure.

Technology

37kV Terminator maintenance is recorded manually on a 37kV Spreader Maintenance form. See Attachment Q

5.21 - Testing Laboratory

5.21.1 - AEP - Ohio

Maintenance

Testing Laboratory

Technology

AEP has a test laboratory (Dolan Labs). Network component testing and analysis may be performed at Dolan, or sent to external laboratories.

5.21.2 - Ameren Missouri

Maintenance

Testing Laboratory

Technology

Ameren Missouri has a laboratory testing facility. Transformer oil testing is being performed at the chemistry lab.

Ameren Missouri presently performs component failure analysis at their Underground Construction department location. Ameren Missouri also uses and will continue to use external laboratories to perform failed component analyses.

5.21.3 - CEI - The Illuminating Company

Maintenance

Testing Laboratory

Refer to:

( Cable Design)

( Unsatisfactory Performance Report)

( Network Transformer Maintenance )

( Failure Analysis (Cable, Transformers) )

BETA Lab

People

First Energy has a 60,000 sq ft, state of the art laboratory and testing facility, called the Beta Laboratory, for performing measurement, testing, calibration, electrical failure analysis, and safety and health training services. The Beta Lab provides services to both FirstEnergy operating companies, such as CEI, and offers for profit services to outside entities.

See Attachment X for a brochure that summarizes the Beta Lab’s capabilities.

Organizationally, the Beta Lab is part of the FirstEnergy Nuclear Operating Company (FENOC), but provides services to all FirstEnergy companies, including energy delivery companies, such as CEI. About 15% of it the Lab’s internal (FirstEnergy) work is focused on the energy delivery part of the business.

The lab is made up of 65 permanent employees, with some employees located at remote sites, but most working at the lab site itself.

The Beta Lab is ISO 9001 registered.

Process

The Beta Lab consists of five primary work units:

Chemistry Unit, which performs testing such as transformer oil analysis for substation and network transformers,
Metrology, which provides equipment testing and calibration services, such as recalibrating a crimping tool. (Note that this service work does not include meter testing, relay testing, or rubber goods testing – these services are provided to CEI by other test facilities, such as the Central Electric Lab, located in Akron.)
Fire and Safety Services, which includes the provision and testing of fire extinguishers, as well as training services.
Metallurgy, which performs metal failure investigations, such as analyzing a crane failure or defective truck parts.
Component Material Testing, which performs dedication testing inspections for new materials (such as a new cable), electronic circuit card analysis, and electrical failure forensic analysis, such as cable splice failure analysis. The result of the failure analysis is a detailed report, which summarizes the evidence revealed during the investigation. The report may also include a discussion of the root cause and a recommendation. See Attachment Y

Technology

The Beta Lab uses technology extensively in the performance of its work. Some of this technology is “State of the Art”, such as their Scanning Electron Microscope (SEM), the camera based device they are using to scan electronic circuit cards to identify and catalogue failures, and an employee developed simulator to test Nuclear control rod operations control systems.

Information technology is also widely used, including databases for recording equipment calibration information, and test results. As an example, the Beta Lab is recording oil testing results in a Laboratory Information Management System (LIMS). This system provides indication and trending information from oil testing such as Dissolved Gas Analysis (DGA). The Beta Lab is pursuing tying this information with Energy Delivery Work Management systems, so that historical trends from LIMS can be used to drive the creation of work requests to inspect, maintain or replace equipment.

5.21.4 - CenterPoint Energy

Maintenance

Testing Laboratory

People

CenterPoint Training and Major Underground management resources perform analysis of failed splices.

Process

CenterPoint performs an analysis on each splice failure to understand what caused the failure.

This analysis is performed in-house , by CenterPoint Training and Major Underground management resources.

5.21.5 - Con Edison - Consolidated Edison

Maintenance

Testing Laboratory

Refer to:

( Cable Testing / Diagnostics)

People

Cable Testing Laboratory

Con Edison has its own cable testing laboratory, which has been in operation since the 1970s. This laboratory has over 100,000 cable and accessory specimens. Sometimes the lab sends specimens to outside labs to obtain independent analysis and opinions.

Con Edison invests in keeping its laboratory staff current on the latest thinking in cable testing. They are active in industry groups. They invest in rotating new people into the cable department, including engineers from Con Ed’s Gold program (a mentoring program for high potential engineers and business professionals).

Figure 1: Photograph of portable partial discharge detector being developed / tested by Con Edison at the Cable Testing Laboratory

Distribution Engineering Equipment Analysis Center

Con Edison has recently launched a new team dedicated to the analysis of electric distribution equipment. The mission of the Distribution Engineering Equipment Analysis Center (DEEAC) is to optimize the performance of distribution equipment through a system safety approach that utilizes data trending and incident analysis. To support this mission, the team is focused on enhancing the safe operation of distribution equipment and also improving overall system reliability by proactively mitigating operational risk. These goals will be achieved through targeted forensic analysis, data characterization of all field-returned equipment, and quality assurance of distribution equipment. Con Edison is dedicated to supporting the mission of DEEAC with a shared focus on continuously improving system safety.

5.21.6 - Duke Energy Florida

Maintenance

Testing Laboratory

People

Failed equipment identified by field crews is sent to the Standards group for analysis via an informal process. Within Standards, there is a component engineer who may perform forensic analysis on failed equipment to understand failure causes.

Process

Performance of the forensic analysis within Duke Energy Florida is dependent on the complexity of the failure and the backlog of work for the component engineer. If Duke Energy is not able to perform the failure analysis internally, Standards will engage external laboratories to assist with failed component analyses.

5.21.7 - Duke Energy Ohio

Maintenance

Testing Laboratory

Technology

Duke Energy Ohio has a laboratory testing facility at Queensgate, in Cincinnati.

They are presently considering performing network transformer oil diagnostic testing at this facility.

This laboratory does not perform forensic analysis on failed cables or failed cable splices. Duke Energy Ohio utilizes external laboratories to perform forensic analysis on failed cable and cable splices.

5.21.8 - Energex

Maintenance

Testing Laboratory

People

Energex has a Network Performance and Maintenance group, responsible for implementing the maintenance and policy standards, and for monitoring the performance of the system. Any failed equipment identified which has been in service greater than two years is sent to this group for evaluation.

The group is comprised of engineers who perform forensic analysis in failed equipment to determine root causes, such as cutting open and analyzing a failed joint. Note that failed equipment which has been in service less than two years is sent directly to the Standards group, as early failures could be indicative of a product issue, rather than a workmanship / aging / or other issue.

Some issues are referred to the Procurement group, especially if workers in the field feel there may be a quality problem with a part or piece of equipment. Procurement then liaises with the vendor to determine if there is a part/equipment quality control problem.

Process

The Network Performance and Maintenance group liaises with the Standards group as necessary. Any workmanship issues are normally shared with the OAC for investigation.

5.21.9 - ESB Networks

Maintenance

Testing Laboratory

People

ESB Networks has a forensic lab for analyzing failed cables and joints located within the ESB Networks training center in Portloaise. The failure analysis is performed by both the training coordinator within the training facility responsible for UG cables and the Asset Manager for cables and his team.

Process

ESB Networks performs analyses on all failed joints, other than situations already identified, such as cable dig-ins. About 70 percent of all failed joints for any cause end up being analyzed. It is notable that ESB Networks analyzes all failed transition joints. Results of the analysis are summarized in a report, and significant findings are communicated to the field force through bulletins know as Technical Notifications, or TNs.

A noteworthy practice at ESB Networks is interaction among the training coordinator for cables, the asset manager for cables, and the field force (Jointers). This interaction has resulted in close working relationships and good two way communication between the Jointers, engineering and training. As a result of this close relationship, the Jointers do not hesitate to bring information about problems with joints back to “the office.” Trainers noted that they try to help the Jointer understand the science of joint preparation so that the jointers have a better appreciation for the importance of the steps associated with the preparation (see Figures 1 and 2).

Figure 1: Cable Forensic Analysis

Figure 2: Joint preparation using ESB Networks specific cut back template

The Training and Asset Management groups have a close working relationship and share the process of performing forensic analysis and preparing summaries. As an example of the effectiveness of these working relationships, the Training and Asset Management groups worked with a manufacturer to include ESB Networks-specific instructions in its cable splice kits. Much of the feedback to customize these instructions came directly from feedback from a field Jointer.

5.21.10 - Georgia Power

Maintenance

Testing Laboratory

People

The Network Underground group has a testing laboratory located at its centralized facility in Atlanta. The lab is managed by a senior engineer in the Network Underground group and staffed by Test Engineers and Test Technicians on an as needed basis. Network Underground Test Engineers, Test Technicians, and Network Engineers all have access to the network underground test Lab.

Process

The Georgia Power Network Underground testing facility is used to testing network system equipment, cable, and failed components. The test lab also performs routine commissioning tests on certain incoming items, such as transformers and network protectors before they are rotated into stock or deployed in the field.

For example, when a new transformer arrives, Test Technicians perform TTR and Meggers tests, check the oil level and its dielectric properties, and then record the nameplate information including serial number into the Georgia Power GIS system before it is put into stock.

The lab is also used for testing of failed components as most forensic analysis is performed in-house. In the event a cause of a failed component cannot be determined, the Network Underground senior engineers may turn the failed equipment over to the manufacturer or send it to an outside, third-party analysis group, such as NEETRAC.

Technology

EPRI researchers were impressed by the tools, equipment, and orderly management of the testing facility.

5.21.11 - PG&E

Maintenance

Testing Laboratory

Technology

PG&E has a high voltage testing facility at their research and development center in San Ramon.

Beginning in 2010 PG&E began transitioning the testing of network transformer oil samples from external laboratories to their San Ramon facility. During the transition phase, PG&E is testing both internally and in an outside laboratory. This parallel testing ensures the consistency of results and provides verification of the quality of the work undertaken by PG&E’s laboratory.

PG&E is presently implementing a failure analysis laboratory at their Livermore facility to be able to perform forensic analysis on failed equipment such as cables and splices. PG&E also uses and will continue to use external laboratories to perform failed component analyses.

5.21.12 - SCL - Seattle City Light

Maintenance

Testing Laboratory

Refer to:

( Preventive Maintenance and Inspection)

Technology

Transformer Oil Testing

Transformer oil samples are taken and tested at an SCL testing laboratory, rather than at an external lab.

5.21.13 - National Grid

Maintenance

Testing Laboratory

Technology

National Grid has two testing laboratories for performing failed equipment analysis. One is located in Syracuse, NY and the other in Worcester, MA. The laboratories analyze failed equipment and materials, including items such as splices, fire damaged cables or equipment, and insulation (e.g. for water presence).

The findings from the analysis are summarized in a Failure Report, which includes the following major sections:

i) Event Description ii)Description of Failed Equipment (and any reference material, if needed) iii) Failure Examination / Material Dissection iv) Analysis and Conclusions. See Attachment C for a sample Failure Report.

External services are used by National Grid as required for certain analyses.

5.22 - Vault - Manhole - Cleanup

5.22.1 - AEP - Ohio

Maintenance

Vault - Manhole - Cleanup

People

Routine vault and manhole cleaning are the responsibility of the Network Mechanics. Severe cases may be assigned to AEP’s civil contractor.

Process

As a part of its routine vault and manhole inspection program, network crews are responsible for cleaning and draining the enclosure and for power washing the equipment if necessary. The bread trucks used by AEP Ohio network crews do contain a vacuum pump for removing water (see Figures 1 and 2).

Figure 1: Vacuum pumping of manhole water

Figure 2: Manhole water being ejected

Technology

As a part of its enhancements to the remote monitoring system, AEP Ohio is adding the capability of remotely monitoring fluid levels in network protectors and in the vaults. The monitoring system will issue an alarm when high fluid levels are detected.

The bread trucks used by AEP Ohio network crews do contain a vacuum pump for removing water (see Figure 3).

Figure 3: Bread Truck vacuum pump cabinet

5.22.2 - Ameren Missouri

Maintenance

Vault - Manhole - Cleanup

People

Vault and manhole cleaning is performed by System Utility Workers, part of the Underground Construction department.

This department is comprised of Cable Splicers, Construction Mechanics, and System Utility Workers. Cable Splicers and Construction Mechanics are journeymen positions, with Cable Splicers performing work with the electrical infrastructure such as making up joints and terminations, and Construction Mechanics performing the civil aspects of the work. Note that at the time of the practices immersion, Ameren Missouri was implementing a new position, called the System Journeyman, which combines the duties of Cable Splicers and Construction Mechanics.

System Utility Workers serve as helpers to the other two positions, and perform duties such as cable pulling and manhole cleaning.

Process

Vaults that require clean-up are identified through the manhole and vault inspection programs.

Technology

See figure 1

Figure 1: Ameren Missouri Vactor truck, used for vault cleaning and vacuum

5.22.3 - Duke Energy Florida

Maintenance

Vault - Manhole - Cleanup

People

Network crews are used to clean manholes and vaults in Clearwater and St. Petersburg.

Cleaning of vaults on customer property are the customer’s responsibility, although inspections of customer property are made by Duke Energy Florida crews.

Process

All vaults are inspected three times a year in Clearwater, and once a year in St. Petersburg. As part of the inspection Process, manholes and vaults are cleaned if necessary. During the rainy season, additional inspections and cleanups may be required. Also, when pumps show as failed as reported by the Sensus system, crews will visit the manholes and vaults to clean the holes and address any environmental issues, and repair or replace the failed pump.

Technology

Pumps are monitored by the Sensus system. Dispatchers and the Network Group receive alarms of failed pumps.

5.22.4 - Georgia Power

Maintenance

Vault - Manhole - Cleanup

People

Vault and manhole cleaning are the responsibility of the Maintenance crews who report to a Distribution Supervisor of maintenance within the Network Operations and Reliability group. The maintenance supervisor has access to all work orders received from routine inspections of vaults and manholes, as well as responsibility for any immediate calls for maintenance from the Operations and Reliability group and the Network Underground engineering group.

Process

As a part of its routine vault and manhole inspection program, inspectors note the condition of vaults and manholes and whether they need to be cleaned. Entry of the inspection finding that a cleaning is required into the Georgia Power Access system generates an automatic work order to the maintenance group.

Vaults and manholes are cleaned by using vacuum trucks (See Figure 1). Debris is taken to a holding yard, put in a holding bin, and inspected for contamination. If the debris inspection determines contamination, the debris is first stored in hazardous materials bins before being sent to appropriate third-party disposal processors. All other debris is disposed of in a conventional manner.

Figure 1: Vacuum Truck

If water is found during inspection, inspectors generate a work order to maintenance to have the vault or manhole pumped using water vacuum trucks. After testing, if the water is free of contamination, a special filter sock is fitted to the truck’s release valve and contaminant-free water is filtered through the sock and pumped into the street. Where contamination is found, the water is held in the vacuum truck holding tank and sent to the maintenance yard where is stored in hazardous waste containers for shipment to the appropriate waste disposal company for processing.

Technology

As a part of its remote monitoring system, the Network Control Center can monitor fluid levels in the protectors and in the vaults. The monitoring system issues an alarm to the control room when high levels are detected. Every morning Maintenance and Operations receive a monitoring report of fluid levels in vaults and manholes and any moisture alarms that might have tripped.

5.22.5 - PG&E

Maintenance

Vault - Manhole - Cleanup

People

PG&E has hired an external general contractor to perform vault cleaning and environmental cleanups. The contractor performs a turnkey service, and provides all the equipment for the work, including trucks. All work is supervised by a PG&E inspector who is on site during the vault cleaning.

The contractor will coordinate with other PG&E groups as necessary to complete the vault cleaning. For example, they will work with PG&E paint crews for asbestos abatement.

Process

Vaults that require clean-up or are identified as having environmental issues are recorded on a notification tag during the course of the annual inspection and maintenance procedures. In 2009, there were 26 vaults identified by maintenance crews for clean-up. The vault cleaning is performed with the vault energized.

The contractor removes any biohazards, and them vacuums and power washes the vault. The cables and any components that are energized are not power-washed.

In the majority of cases the need for environmental clean up of the vault is a direct consequence of their illicit use by vagrants as temporary sleeping quarters and/or drug use. In order to limit this, following the clean-up, the manhole covers are replaced with SWIVELOC covers, a vented manhole system using a solid rather than a vented cover (See Manhole Replacement Program.)

Throughout 2010 there has been a continued focus on environmental clean up of underground vaults. PG&E projects that 86 vault locations will undergo environmental cleanup during 2010.

5.22.6 - Portland General Electric

Maintenance

Vault - Manhole - Cleanup

People

The crews in the CORE group are responsible for both radial and network underground facilities in the downtown CORE. Vault and manhole cleaning is performed in conjunction with the performance of inspection and maintenance work, either prior to or during the inspection and/or maintenance.

Process

At the start of every year, general work orders for inspection of manholes are created in Maximo for a geographical area, with each work order covering the manholes in a one- or two-block area. A crew receives these work orders and is expected to perform inspections of the general-purpose enclosures when it does not have any customer work. As part of this normal vault and manhole inspection program, crews clean the structure if needed. They clean the structure in advance if they know that they will enter a specific vault to perform maintenance work.

At some point, the city decided to tie the sewage system to the storm drain system so high water levels and flooding may see sewage flow into vaults. If crews notice evidence of sewer gases in manholes/vaults, they do not enter the space and instead call for it to be cleaned. Crews call the repair organization and arrange for a contractor to clean the manhole/vault.

5.22.7 - References

EPRI Unde rground Distribution Systems Reference Book (Bronze Book)

Chapter Section 9.2.9 - Environmental Concerns

6 - Operations

6.1 - Determining a Feeder to be De-energized

6.1.1 - AEP - Ohio

Operations

Determining a Feeder to be De-Energized

People

It is the responsibility of the Network Mechanics to determine a feeder is de-energized before performing work. Crews will often work with the Distribution Dispatchers as well to verify that feeders are de-energized.

Process

If any network maintenance, repair, or emergency work must be performed on the network, field crews have multiple fail-safes to determine that the feeder is de-energized before performing work.

Distribution Dispatchers control the system and will open feed breakers. Substation personnel perform the grounding of the feeder at the substation.

Workers establish perimeter grounds at the nearest three transformers to the work site. AEP Ohio works with two primary switch configurations: wall-mounted solid dielectric vacuum switches (Elastimold MVI), which is the new design, and transformer-based switches, which is the historical design.

If crews need to cut into a cable and there are no visible grounds, crews must spike the cable while wearing insulated rubber gloves, and using a hydraulic powered remote spiking device. If the crew needs to test/repair all three legs on a Y-splice or all four legs on an H-splice, they spike the bus to prove it is de-energized.

Technology

All new Y- and H-splice busses, prepared with 600-amp separable connectors, now have built-in spike probes (Elastimold Spiking Aids, see Figures 1 and 2). These enable a worker to remove the cap and assure that the cables are grounded by placing the spiking tool through the probe at the joint without having to spike the cable itself. As AEP Ohio crews service lines and splices, they are replacing older splices with the new splice that include the spike probes.

Figure 1: Separable connector joint with Spiking Aid (1 of 2)

Figure 2: Separable connector joint with Spiking Aid (2 of 2)

6.1.2 - Ameren Missouri

Operations

Determining a Feeder to be De-energized

People

Cable Splicers within the Underground (UG) Construction group are responsible for repairing failed cable and are thus involved in determining if a feeder is de-energized. The (UG) Construction group is organizationally part of the Underground Division, responsible for underground infrastructure within a defined geographic territory that includes downtown St. Louis, and thus, the St. Louis network infrastructure. The Underground Construction group is responsible for all of the conventional (manhole and conduit system) underground in the Division.

Process

Ameren Missouri does not spike cable. They will confirm that the cable is de-energized by testing for back pressure at the station, installing grounds to establish a safe work area in conformance with their clearance (WPA) procedures, and identifying the cable to be cut based on mapping, cable position, visual indication, and cable tags. Ameren Missouri will cut the cable with a remotely operated (from outside of the hole), hydraulic guillotine cutter.

Technology

Ameren Missouri uses a remotely operated, hydraulic guillotine cutter to cut cable.

6.1.3 - CEI - The Illuminating Company

Operations

Determining a Feeder to be De-energized

People

UG Electricians within the UG Network Services department are responsible to assure that feeders a de-energized using appropriate testing and grounding procedures.

Process

UG Crews who will need to work on a de - energized feeder will follow CEI’s process for obtaining a clearance on that feeder. For network feeders, the switching steps have been pre-written are used by the DSO to develop orders to provide clearance.

The feeder breaker itself may be opened by a switchman, but most often is opened by an UG Electrician.

The UG Electrician will utilize the manhole print and a device called a “Sound Coil”^[1] to aid in determining which feeder in a given hole is de - energized, before attempting to cut and ground that feeder.

More specifically, CEI will send an UG Electrician into the hole with a feeder print and the sound coil device to determine which cable is deenergized. When the cable has been determined, the electrician will place the cutter head of the cable cutting device on the cable. CEI will then send a second Electrician into the hole, who will verify the selected cable by using the manhole print and applying the sound coil. Only when this dual check is complete, will CEI commence with the cable cut.

Note: This verification step was added to CEI’s procedure for de-energizing a feeder as a result of a post incident investigation of an incident where an employee marked and cut the wrong cable.

The UG Electrician will use an electrically operated hydraulic cutter to cut and ground the cable. This device is operated remotely, with the hose and pump located out of the hole, away from the manhole opening, and placed on a protective blanket^[2] . The Electrician himself wears protective clothing, including dielectric shoes when operating the device.

Technology

The UG Electrician will utilize a device called a “ Sound Coil ” to aid in determining which feeder in a given hole is de- energized.

The UG electrician will utilize a remote hydraulic cable cutter to cut and ground the cable across the cutter head.

^[1] The Sound Coil is a device that emits a tone when sensing current on a feeder (See “Sound Coil” for more information.)

^[2] The only situation in which a CEI crew member would cut a cable while positioned in the hole is if they can see and confirm that both ends are cut free.

6.1.4 - CenterPoint Energy

Operations

Determining a Feeder to be De-energized

People

Cable Splicers within Major Underground are responsible to assure that feeders are de-energized using appropriate testing and grounding procedures.

Process

Substation Operators will open the feeder breaker under the direction of the Real Time Operations Dispatchers. Major Underground will check as dead and ground the feeder.

Major Underground crews who need to work on a de-energized feeder will follow CenterPoint’s process for obtaining a clearance on that feeder. For network feeders, the pre-written switching steps are used by the Distribution Dispatcher to develop orders to provide clearance. The Cable Splicer will utilize the maps, field labeling, and an ammeter to determine which feeder in a given hole is de-energized before attempting to cut and ground that feeder. Using maps and field labeling, Cable Splicers will carefully compare the physical position of the feeder in the hole with the documented position on the maps. In addition, the ammeter test is used to confirm that there is no load on the feeder.

After determining which cable is to be cut, the Cable Splicer will begin to carefully strip the cable. During this process, the Cable Splicer will look for evidence to confirm the cable is de-energized. For example, when removing the semi-conductor he will be looking for “spitting”. This will be followed by a “hair” test. After physically stripping the cable jacket and cutting past the semiconductor, the insulation will be notched while wearing rubber gloves and sleeves. Seeing no evidence that the cable is energized, the gloves will be removed to see if the hair on the arm stands up. Finally the cable will be touched and the cable cut completed.

CenterPoint is not using a remotely operated cable cutter. The Cable Splicer cuts through the de-energized cable in the hole.

Note: CenterPoint is presently reviewing their existing processes.

6.1.5 - Con Edison - Consolidated Edison

Operations

Determining a Feeder to be De-energized

Process

When Con Edison de – energizes a feeder, they do not open the network protectors, or pull the fuses. They also do not disconnect the transformers from the primary. Their approach, briefly, is to open the feeder, ensure no back feed through neon indicators at the substation, ground the feeder, and ground the work zone (including, if appropriate, the operation of an internally mounted ground switch in the transformer). Con Edison believes that this process addresses all potential energy sources, and provides a safe work environment for its employees.

De-energizing a Feeder

Con Edison performs its normal feeder maintenance with the feeder energized. For cables, this maintenance consists of an inspection of primary joints and terminations, Esna elbows, bayonets, cable racks, cable bonding or grounding, service take-offs, street ties, interval ties, gaps, quick connects, cable limiters, and duct entries to identify any abnormal conditions.

When Con Edison takes a feeder out of service to perform maintenance or construction, the utility does not “block and lock” the network protectors on the feeder. That is, they do not manually open the protector breaker or remove the protector fuses. Note that the utility also does not open a primary switch at the transformer, because Con Edison’s transformer specification does not call for a disconnect switch at the transformer primary.

This approach differs from the approach employed at many utilities, where crews visit every network protector, open up the secondary, and remove fusing before working on the de-energized circuit.

Con Edison’s process is to:

Open the feeder.
Ensure no back-feed from the back-feed indication that they have at the source. (Back-feed indication is a neon indicator at the breaker panel.) If the indicator at the station does reveal back-feed, crews visit the specific network protector or other source to resolve the issue.
Ground the feeder at the station.
Ground on either end of the work zone (all potential sources).
Do the work.

Con Edison believes that this process addresses all potential energy sources. They have never had a problem with this approach.

Why the difference in practice? One reason as that the very size of their system requires lengthy circuits with many transformer and network protector locations on each circuit. This high number of locations, combined with the potential to have to pump water out of the holes, makes it impractical to visit each location, pump it free of water, and block and lock the protectors. And, their current approach provides a completely safe, grounded work environment.

Technology

Cable Spear

Con Edison uses a device called a “Spear” to ensure that a cable is de-energized and grounded. A “spear” at Con Edison is a hydraulic cutter with a ground lead attached that can withstand 40,000 Amps. This device is operated remotely from outside of the hole. The device cuts into the conductor and grounds it. The term “spearing” the cable refers to the use of this device.

Normally, Con Edison does not spear a cable unless the cable has been positively identified. In an emergency, Con Edison may “spear” a cable without positive identification, based on information from the records.

The spearing tool Con Edison uses for network feeders is a specialty tool supplied by Reliable Equipment, 92 Steamwhistle Drive, Ivyland PA 18974 https://www.reliable-equip.com/.

6.1.6 - Duke Energy Florida

Operations

Determining a Feeder to be De-energized

People

Network crews at Duke Electric Florida are in charge of the tasks associated with establishing a clearance, including verifying that a feeder is de-energized. Clearing a network feeder involves close communication between the dispatchers in the DCC and the Network crews. Duke Energy Florida has a defined clearance process documented in their Switching and Tagging manual. All who perform switching must be on the company’s switching and tagging list. The DCC maintains the approved list.

Network Specialists are qualified to perform the tasks associated with taking a clearance, and Electrician Apprentices are trained as a part of their on-going OJT. Electrician Apprentices who received the required training and are on the switching and tagging list, can perform switching and hold clearances.

Process

Whenever a de-energization of a feeder or feeder section is needed, the work crews collaborate closely with the dispatcher to identify the location to be de-energized, and to establish the clearance through switching, tagging and grounding. Documented switching and tagging procedures are followed for de-energizing and re-energizing feeder.

To assure the cable section in question is de energized, Network Specialists first enter the manholes at each end, checking the feeder cable’s duct position visually and against their maps, making certain the feeder in question matches on each end. Crew will then apply a pulse tone on a single phase of the cable at two points around the work zone using an external, battery-operated tone generator. The tone it is put onto the conductor using a feed through. The pulse tone can be detected in the manhole to be worked by using a wand, confirming the cable to be cut.

Once the de-energized feeder is confirmed, a remotely operated hydraulic spike is used to pierce the cable to ground. After applying the jaws of the hydraulic piercing tool to the cable, the workman exits the hole before piercing the cable to ground. Duke Energy Florida has a documented standard procedure for grounding and piercing underground primary cable. See Attachment G.

Technology

For cable identification, Duke Energy Florida is using the Bierer [1] ST500 Digital Service Tester & Phase Identifier (see Figure 1).

Figure 1: Bierer ST500PGN Digital All Purpose Service Tester & Phase Identifier

[1] http://www.bierermeters.com

6.1.7 - Duke Energy Ohio

Operations

Determining a Feeder to be De-energized

People

At Duke Energy Ohio the responsibility for determining a feeder to be de-energized belongs to the Dana Avenue field crews, Cable Splicers and Network Service persons.

Process

Dana Avenue underground crews who will need to work on a de - energized feeder will follow their process for obtaining a clearance on that feeder.

After obtaining clearance on a feeder, including placing all of the transformer primary switches in the ground position, the Dana Avenue field personnel use the following process to determine a feeder to be de-energized before cutting the cable.

First, using their Conduit and Cable maps, field crews will identify the cable from the duct position indicated on the map.

Next, field crews will verify the feeder by checking the field applied tags in the hole. Duke Energy Ohio labels all of their conductors and equipment with tags.

Next, field crews will check amperage if possible.

Now, field employees will spike the one of the three cables using a hydraulic spear controlled from outside the hole. Before cutting the cable, they will have a second set of eyes look down on the spike for “copper on the chisel".

Finally, the crews will cut the cable.

6.1.8 - ESB Networks

Operations

Determining a Feeder to be De-energized

People

ESB Networks performs cable spiking to determine whether a feeder is the de-energized. Cable spiking is performed by Network Technicians. The Network Technician is the journeyman line worker at ESB Networks networks. Note that the Network Technician position is a jack of all trades position with specialization based on a work assignment rather than classification.

ESB Networks has very rigid procedures around determining if a feeder is de-energized. The company believes that their approach is a very safe one.

Process

Before any cable is worked on, it must be identified at the point of work. The Network Technician first identifies the cable through their records. Network Technicians maintain copies of their MV DFIS maps on their trucks. For their Dublin infrastructure, these maps are carefully maintained, detailed, and accurate.

The feeder in question is switched out of service through the ESB Networks switching and clearance process. The clearance process requires that switching actions are executed and confirmed.

The person who holds the clearance for the cable calls for a test signal to be placed on the cleared feeder at the station to assure that that test signal is present on the cable at the section he intends to cut, normally in a hole that has been excavated at the identified faulty section.

When ready to spike the cable, the person who holds the clearance contacts the ESB Networks control center and lets them know that he is about to spike the cable.

The Network Technician uses a spiking gun (see Figure 1), which is a chiseled device that is driven through the cable to ground using a charge (see Figure 2). The charge is released by striking the spiking device with a hammer. This device simultaneously spikes and grounds the cable. Note that the spiking gun is operated from outside the vault.

Figure 1: ESB Networks cable spiking tool

Figure 2: Cable spiking cartridges

ESB Networks networks has developed a detailed check list for MV cable identification and spiking. See Attachment A: Cable Identification and Spiking Checklist.

Technology

ESB Networks networks uses a cable spiking tool that drives a chisel through the cable using a charged cartridge that is struck with a hammer. This device uses customized aluminum bases developed by ESB Networks networks that are sized to fit the various cable sizes used by ESB Networks, and include a slot that is used to keep the cable captive during the spike (see Figure 3).

Figure 3: Aluminum U Channel for retaining cable

6.1.9 - Georgia Power

Operations

Determining a Feeder to be De-energized

People

It is the responsibility of the Network Control Center personnel within the Georgia Power Network Underground group to obtain a clearance of a network feeder through the Distribution Control Center at Georgia Power. (See Operation Practices - Clearances )

Engineers in the Operations and Reliability Group at the Georgia Power Network Underground group are responsible for operating and monitoring the network system. This group is led by a manager, and is part of the Network Underground group, a centralized organization for managing all network infrastructures at Georgia Power.

The Operations and Reliability group has seven engineers on staff, responsible for the following:

Monitoring the network through the SCADA system.
Requesting and confirming de-energized feeders for maintenance or during failures.
Re-routing power to alternate feeders and/or networks in case of failures.
Serving as first-responders to customer service interruptions.
Part of the design phase for new networks or new major customer service.
Part of network protector selection (standards).
Responsible for the network system SCADA (remote monitoring and control) design and operation.

The Engineers, called Test Engineers, are four-year or two-year associate-degreed engineers. Test Engineers are responsible for network system operation, and work closely with maintenance crews, Test Technicians, Major Account representatives, and the Distribution divisions (Non – network operations) of Georgia Power.

The Georgia Power Network Control Center (part of Network Operations and Reliability) works closely with the Distribution Control Center (non – network) to clear a network feeder. The Network Control Center is responsible for obtaining a clearance for opening any network feeders (during emergencies, maintenance, routine inspection, etc). The Distribution Control Center, responsible for monitoring and controlling the breakers of the dedicated primary feeders that supply the network, issues clearances to the Network Operations and Reliability group. Field crews are ultimately responsible for assuring that a feeder is de-energized before commencing work.

Process

If any network maintenance, repair, or emergency work must be performed on the network, field crews must work through the Network Control Center to obtain clearance. The following steps are taken:

To obtain clearance, the crew on site must confer with the Network Control Center, indicating the feeder that must de-energized.
Operations personnel will check the status (through the remote monitoring system) of all network protectors at the locations to be affected to assure that de-energizing the feeder will not drop customers, or to identify those who will be affected.
Operations must then call the Georgia Power Distribution Control Center to open the designated feeder.
Work can begin when it is determined that the feeder is de-energized.

Once DCC and Operations have opened, grounded, cleared and tagged the feeder as open, the crew must verify that the feeder they are working on is de-energized.

First, the crew goes to adjacent vaults and moves the transformer handle to the “ground” position. Because of the interlock, if the feeder is not de-energized, the crewman would be unable to place the switch handle in the ground position. The crew then enters the manhole or vault to be worked, wearing appropriate PPE and verifies the feeder to be worked by its tag or by its position in the duct line. (Georgia has high confidence in the accuracy of its duct maps, and in its standard approach to cable racking (Peachtree racking).

From outside the manhole, personnel don protective boots, gloves, glasses, and full PPE clothing to spike (or “pike”) the cable with a either a cable spear (long pole) or a remotely operated hydraulic tool to confirm that that the feeder to be worked is de-energized and grounded. The blade of the cable spike or tool must pierce the metallic sleeve, sheath or covering and make contact with the conductor. According to maintenance personnel interviewed during the immersion, only twice in 32 years have crews spiked an energized cable.

When re – energizing a feeder after work which has separated cables, Georgia Power determines if feeders are phased correctly by leveraging a transformer modification (part of their standard) that uses phasing tubes on the top of every transformer. The phasing tubes provide a simple and foolproof way for tracing voltage to ascertain phase. On the transformer end, field personnel can insert a probe into the de-energized unit, and can put a signal on the cable and use this to determine phasing (See Figure 1).

Figure 1: Network Transformer primary compartment – note phasing tubes

Technology

The Network Underground group of Georgia Power makes extensive use of its Network Control Center to coordinate the activities associated with a work clearance between the field crews and the Distribution Control Center. Its extensive mapping, tagging, and online vault and manhole diagrams available through GIS, give both the crew and the Operations Control Center a very high level of confidence in feeder identification, and their approach to on site testing assures worker safety.

6.1.10 - HECO - The Hawaiian Electric Company

Operations

Determining a Feeder to be De-energized

People

Cable Splicers within the Underground Group at HECO are responsible to assure that feeders a de-energized using appropriate testing and grounding procedures.

The Underground Group at HECO is part of the Construction and Maintenance organization. The group is comprised of two UG supervisors, fifteen Cable Splicers, 2 Utility Mechanics, and 2 Utility Assistants. The Cable Splicer is the journeyman position in the department.

Process

In most cases, the section of cable to be worked has already been isolated and tagged (“holdoff” tags) by the Primary Trouble Man (PTM) prior to the UG crew beginning to work. The UG crew is responsible for testing to determine that the feeder is de-energized and grounding the feeder.

The Cable Splicer will utilize the maps and plastic tags that label the circuits in the vault / enclosure to identify the feeder. HECO does use field labeling using these plastic tags throughout their system.

Figure 1: Example Label indication the cable route (single phase URD)

HECO will use Test devices, such as the AB Chance tester or the HECO developed Fuse Stick (See Fuse Stick) ) at capacitive test points to confirm that the circuit is de-energized. They will then physically ground the circuit.

Figure 2: HECO Fuse Stick

After the circuit is grounded, the Cable splicer will use either a hot line cutter for smaller cables, or a hydraulic cutter for larger cables to cut and ground the cable. This device is operated remotely, outside of the manhole. The Cable Splicer wears regular safety shoes – not dielectric shoes when operating the device.

Technology

The UG Electrician will utilize an AB Chance Tester, or home developed device called a Fuse Stick to test and ground.

Figure 3: AB Chance Tester

6.1.11 - National Grid

Operations

Determining a Feeder to be De-energized

People

Maintaining and operating the Albany network system, including proving cables to be de-energized, is the responsibility of Underground Lines East. This group is led by a manager, and includes field resources focused on civil aspects of the underground system and a field resources focused on the electrical aspects.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics, is led by three supervisors. Maintenance Mechanics perform network switching, fault location, minor vault maintenance, and inspection and maintenance of network vaults and equipment such as transformers and network protectors. It is typically the Maintenance Mechanics who are involved in switching a network feeder. They can be backed up on this by Cable Splicers. When the network feeder is de-energized, tagged and a Clearance issued, grounds are applied. Cable Splicers will then use the procedure in EOP UG013 to perform an electronic trace of the feeder and prove it dead by cutting the cable with an approved grounded cutter from outside the manhole or vault.

National Grid has a documented procedure for Positive Identification of De-Energized Underground Cables that is part of their Electric Operation Procedures (EOP). This procedure, undergoing a revision at the time of the EPRI immersion, includes a decision tree flow diagram to guide field workers through the steps of the procedure.

Note that National Grid EOP’s are available in hard copy or electronically on the company’s intranet.

Process

National Grid has a documented procedure for Positive Identification of De-Energized Underground Cables that is part of their Electric Operation Procedures (EOP). This procedure details the steps associated with determining a feeder to be de-energized and includes a detailed flow diagram outlining the steps.

National Grid will isolate, tag, test as de-energized and ground the feeder in question.

After clearing a feeder field crews will identify the cable in the hole through various means including prints, cable tags, duct location, cable size, location markings, etc.

National Grid does label all of their conductors with tags.

National Grid uses a tone signal generator or electronic signal tracer, such as units from Timco Instruments, Biddle, and Hipotronics, to identify the de-energized cable.

National Grid’s preferred method of cutting the cable is to use a remotely operated guillotine cutter from outside the hole. This tool will cut and ground the cable. As an alternative, where the remotely operated guillotine cutter cannot be used, crews can use a grounded 8 foot insulated ratcheted cable cutter from a safe position outside of the hole. National Grid does not spike cables.

National Grid’s procedure includes steps for identifying de-energized lead covered cables where an electric signal trace (tone) is not possible. In these cases, field crews will perform a series of cuts, performing a voltage test after each step using a Clantech PV1100 or Statiscope. For example, they will start by removing an appropriate length of lead cover, and then perform a voltage test.

Technology

National Grid uses a remotely operated hydraulic guillotine cutter that simultaneously cuts and grounds the cable. As an alternative, where the remotely operated hydraulic guillotine cutter cannot be used, crews can use a grounded 8 foot insulated ratcheted cable cutter from a safe position outside of the hole.

Figure 1: Hydraulically operated guillotine cutter

National Grid uses a tone signal generator and electronic signal tracer such as units from Timco Instruments, Biddle, and Hipotronics.

6.1.12 - PG&E

Operations

Determining a Feeder to be De-energized

People

At PG&E, the responsibility for determining a feeder to be de-energized belongs to the M&C Electric Network field crews.

PG&E has good, up to date maps that show duct positions.

Process

After clearing a feeder (opening and grounding), field personnel use the following process to determine that a feeder is de-energized before cutting the cable.

First, using their duct maps, field crews identify the cable from the duct position indicated on the map.

Next, field crews verify the feeder by checking the field applied tags in the hole. PG&E labels all of their conductors with tags.

Next, field crews will check amperage, if possible.

The crews will put phase identification on the cables.

Finally, field employees will spike one of the three cables using a hydraulic spear controlled from outside the hole. Before cutting the cable, they will confirm the presence of copper on the cable. This is the normal practice. If they can’t reach the cable with the spike from outside the hole, they will use a set of remotely operated hydraulic cutters that both cut and ground the cable.

Technology

PG&E’s spiking tool is a fiberglass rod with a spike on it.

The also utilize a remotely operated hydraulic guillotine cutter that simultaneously cuts and grounds the cable.

PG&E also uses a Hipotronics phase identifier to confirm phasing before making repairs. The device, connected at the substation, sends out one pulse on A phase, 2 pulses on B and returns on C phase. They use a sound coil to pick up the pulse and identify the phases down stream.

6.1.13 - Portland General Electric

Operations

Determining a Feeder to be De-energized

People

The System Control Center (SCC) is responsible for operation of the network and grants clearances for crews working on a feeder.

The load dispatcher works closely with the network crew foreman to accomplish switching on the network. Substation operations perform switching at the substation, while the CORE underground crews perform switching out on the network. The Special Tester is also often involved in this process.

Process

After clearing a feeder, the load dispatcher monitors the network protectors remotely. If the load dispatcher sees that a protector still shows as closed on the monitoring system when it should be open, the load dispatcher contacts the individual listed on the shut-down order to notify the individual that a particular unit still shows as closed.

When the dispatcher sees that the feeder is de-energized, the dispatcher gives the crew clearance to install grounds.

To ascertain that a feeder is de-energized, crews first use duct maps and field-installed cable tags to identify the circuit to be worked on in the hole. Crews may use an acoustic tool called the hummer, listening for radio frequency (RF) on the feeder to help confirm that the cable is dead. If they hear no RF, they know that the feeder is de-energized. PGE noted that this listening tool is not foolproof, however, and that crews always cut cable remotely from outside the hole just in case they inadvertently cut into an energized cable.

They identify the cable to be cut using a battery-powered guillotine cutter operated from outside of the hole. This cutting tool simultaneously cuts and grounds the cable through the cutting blade. PGE does not spike network cables.

6.1.14 - Survey Results

Survey Results

Operations

Determining a Feeder to be De-energized

Survey Questions taken from 2018 survey results - safety survey

Question 25 : Please indicate which of these activities are part of your procedure for determining a feeder to be de-energized and cutting a medium voltage network cable.

Question 26 : Please indicate which of the following activities are part of your network feeder clearance procedures.

Question 27 : When the feeder has been cleared, in what position have you left the network transformer primary switch?

Question 28 : Are there any differences in your network feeder clearance procedures for a routine clearance (such as for adding a new transformer) and an emergency clearance (such as for a cable failure)?

Survey Questions taken from 2012 survey results - Operations and Safety (Question 8.9)

Question 7.12 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders)

Question 8.9 : What procedures / tools do you use to determine that a cable is de-energized?

Survey Questions taken from 2009 survey results - Operations and Safety (Question )

Question 7.16 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders) (This question is 7.12 in the 2012 survey)

Question 8.9 : What procedures / tools do you use to determine that a cable is de-energized?

6.2 - Dispatching

6.2.1 - AEP - Ohio

Operations

Dispatching

See Organization - Operations Center

6.2.2 - CEI - The Illuminating Company

Operations

Dispatching

People

The CEI underground system is operated out of the Northern Ohio Regional Dispatch Office (RDO). This office is responsible for the operating the entire Illuminating Company system, including the network.

The RDO is staffed with 36 employees, including a manager, 27 Distribution System Operators (DSO’s), 2 Outage Coordinators, 1 Engineer, a computer system expert, and other support staff.

The DSO position is a non bargaining position. Most DSO’s have an electrical background in distribution and were hired “from the outside”. A formal degree is not required. CEI will give preference to candidates with military experience when hiring DSO’s, as military training provides structure and discipline – two characteristics sought after by CEI in DSO’s. DSO’s can advance to a senior level by gaining experience and demonstrating proficiency in certain tasks required for advancement. DSO’s will periodically be assigned to accompany Underground crews in the field to gain experience.

Process

The RDO runs seven operations “desks”, 24-7, with the system broken up by geography. That is, each desk controls a different geographic area. In assigning DSO’s to the desks, CEI will mix senior people with newer people to provide training. They assure that at least two senior DSO’s are working on the floor at any one time. Their goal is for all the DSO’s to eventually progress to the senior level.

Technology

The RDO is documenting operating processes and procedures in a system called E Net. They have one individual who is assigned the responsibility of maintaining and updating this system.

6.2.3 - CenterPoint Energy

Operations

Dispatching

People

Distribution dispatching is housed within the CenterPoint Energy Control Dispatch Center (ECDC). This facility also houses the Regional Transmission Operator (RTO) desk.

Distribution Dispatchers focus primarily on switching and troubleshooting of the distribution system beyond the substation breaker. Distribution Dispatchers are assigned responsibility for certain territory by service center. CenterPoint has twelve Service Centers, and assigns one or two dispatchers per service center. A normal day shift will employ a minimum of 14 dispatchers.

The RTO focuses primarily on the transmission network, but is also responsible for operation of distribution breakers at the substation. For example, the RTO would dispatch a Substation Operator to open a major underground dedicated distribution feeder breaker at the substation.

Process

At CenterPoint, Distribution Dispatchers are represented by a collective bargaining agreement (Union). A Distribution Dispatchers can become a journeyman after three years of training (both formal and OJT) and testing. Distribution Dispatcher candidates must pass a highly selective test to enter the program. Only 10-15% of candidates who take the test qualify for entry into the program. Apprentice dispatchers are assigned a mentor to guide them through the program.

6.2.4 - Duke Energy Florida

Operations

Dispatching

See Organization - Operations Center

6.2.5 - Energex

Operations

Dispatching

People

Outages and trouble calls are the responsibility of the Operations Center , part of the Service Delivery organization at Energex.

Outages in the CBD that come in through customer calls are managed by Evaluators within the control center.

Management

Energex has a centralized crew dispatch team comprised of ten resources who work the day shift (6:30 – 4:00). The team is organized by geographic area, with dispatcher responsible for dispatching to field crews within their assigned area.

Note that crew dispatching is a distinct group from the switching coordinators in the central control center who operate the distribution system. The dispatchers work closely with the control center, as area service issues, such as feeder outages, are handled by the Control Center.

Resources that fill the crew dispatcher positions typically come from the Contact Center Group (CCG). The crew dispatch position is a bargaining unit (union) position.

Energex noted that the centralized dispatchers have good rapport with field crews. They encourage field crews to visit the center, and dispatchers to visit with field crews.

After hours, crews are typically dispatched by Evaluators, who are part of the control center, and work directly with customer in-bound calls of outages or reports of area outages.

Process

Every power bill to customers lists three phone numbers: one for general enquiries, one for reporting loss of supply and one for reporting network related emergencies. Energex’s IVR system routes calls accordingly: general enquiries go to the Energex contact center whilst loss of supply and network emergencies are routed to the operations control room where the calls are answered by dedicated trouble call staff. The IVR system proactively sends out messages to customers in the event of an outage in the area. Incoming calls recognize caller ID, and Trouble Call staff are presented with the customer account information when they field calls.

Trouble Call staff receive customer calls or field reports and put in trouble tickets to the online trouble ticket system, which creates a service request. Service requests are then evaluated to determine the extent of the problem and a job service order is created. The Service order is then routed to central dispatch to provide the appropriate crew(s) to respond to the outage or service interruption. On any given day there is at least one evaluator assigned for every two of the 12 zones in the Energex service grid.

When a call or calls come in, an evaluator can help to determine whether the report is merely an individual outage or an area problem, and route the trouble ticket to the appropriate division — log it as a network incident if it is an area problem and forward it to either an LV or HV switching coordinator, or send to dispatch if it is an individual outage.

During prolonged outages, estimated time to recovery (ETR) recorded messages can be proactively sent to customers within designated affected areas. The same message can be played to customers calling into the customer center. ETRs are determined by near real-time information from dispatch crews in the field reporting into the operations center.

Management

Switching coordinators and evaluators (from the Central control center) determine which type of job to dispatch through the central dispatch center. Area service issues, such as primary feeder outages are handled by the switching coordinators to repair/maintain. Customer-related outages, transformer outages, and wires down are handled and trouble tickets issued to central dispatch by evaluators.

Energex has central hubs throughout its system, each of which has at least two maintenance crews. The CBD hub also has mechanics specifically trained for CBD network underground work.

Technology

Energex uses an automated service request generation and trouble ticket tracking system. When calls come in from customers, they are routed as service tickets to dispatch, but network service calls, such as lines down, are routed to operations, all through the same online system.

Dispatch crews utilize a mobile data system, Field Force Automation (FFA), a Ventyx system, which uses a commercial 3G wireless network. Dispatch crews can receive and report back information into operations via wireless “tough book” laptops and through Energex’s 3G network.

Energex uses a distributed management system that tracks which crews are available, where they are located, and what the crew’s area of expertise is — Electrical Connections Officer (ECO) or Rapid Response crew. Service requests are handled by an automated system at central dispatch that issues trouble tickets to the appropriate crews closest to the service issue. A percentage of the business as usual work can be automated at start of day to assist in the allocation of customer service work to the appropriate work crews.

6.2.6 - ESB Networks

Operations

Dispatching

Unspecified, See Organization - Operation Center

6.2.7 - Georgia Power

Operations

Dispatching

Unspecified, See Organization - Operation Center

6.2.8 - HECO - The Hawaiian Electric Company

Operations

Dispatching

People

HECO System Operations has implemented a comprehensive cross training program for Trouble Dispatchers. The program involves the dispatchers spending a period of weeks working with other departments to gain real world experience to supplement classroom training. The program is administered by the System Operations Training Department.

Process

The cross training consists of several “ride along” opportunities where a Trouble Dispatcher trainee will work along side certain field types, such as a Primary Trouble Man (PTM).

The first “ride along” takes seven weeks and is part of a general orientation of different functions within the Company. This program consists of two weeks with the PTM’s, three weeks with a C&M day crew, and two weeks with a C&M night crews. At this point the dispatch trainees are trying to associate the classroom portion of the training (trouble shooting, repair work, terminology, equipment) with what they see in the field.

The Trouble Dispatcher trainee then goes through seven training modules and receives on-the-job training in the dispatch center. They work on a shift and learn while working alongside the experienced dispatchers. This takes at least 6 months, after which the dispatcher is tested and qualified. The seven training modules include:

Orientation
Basic Distribution Concepts
Trouble Dispatch Orientation
Trouble Dispatch Operations
Switching & Tagging for Trouble Dispatchers
Communications Skills for Trouble Dispatchers
Emergency Operations for Trouble Dispatchers

Optionally, a second “ride along” occurs after the dispatcher has more experience and can ask detailed questions. This second “ride along” is for 1 week with the PTMs, and can occur anytime during the last 5-6 months of training.

Technology

HECO has documented the objectives of each training module and uses “sign off sheets” for each module to record when the Trouble Dispatcher trainee has accomplished each step of the module.

See Attachment(s) Attachment L and Attachment M .

6.2.9 - SCL - Seattle City Light

Operations

Dispatching

People

Operations Center

SCL uses a centralized operations center for their company. This center operates both the transmission and distribution systems. There are two distribution desks in the operations center, one of which has accountability for the network. (Note that there is not a dedicated desk to operate the network. The operators at this desk have both network and radial distribution operations responsibility.)

Distribution Operators (dispatchers) typically enter the position with either utility experience and electrical background, or specific experience as a journeyman. Often, they have four years of education plus two years of electrical experience. They must take a test to get into the position.

6.3 - Fault Indicators

6.3.1 - AEP - Ohio

Operations

Fault Indicators

People

Monitoring of the underground network system, including fault detection, is the responsibility of the Dispatchers at the Operations Center. AEP does not utilize faulted circuit indicators (FCIs) on its network feeders.

Process

Most faults are detected by Operations Center personnel through its SCADA system.

Technology

Overcurrent relays and network protectors feed data into the AEP Ohio redundant, dual-loop fiber-optic SCADA communications network. Dispatchers can identify fault conditions occurring in the field from the Operations Center monitoring facility.

AEP engineers are leveraging the waveform data collection ability of the Schweitzer 351S relays to perform fault impedance location. Engineers have provided information to the dispatchers than provides a table of distances and impedances to particular manholes.

6.3.2 - Ameren Missouri

Operations

Fault Indicators

Process

Ameren Missouri has not historically used faulted circuit indicators (FCIs) on its network system. At the time of the practices immersion, Ameren Missouri was piloting the use of faulted circuit indicators on its radial primary system.

Technology

Ameren Missouri is piloting a faulted circuit indicator on their primary radial distribution system. Specifically, they are currently piloting the AutoRanger, from Schweitzer, and have plans to test the communications enabled feature of that product in the future.

6.3.3 - CEI - The Illuminating Company

Operations

Fault Indicators

People

Troubleshooting of locked out feeders is performed by Operators (or Switchmen) under the control of the Regional Dispatcher. The present practice for troubleshooting a feeder that has tripped off line includes an Operator going to the location of the fault indicators to ascertain their status.

The fault indicator specification was developed by the CEI Engineering Services group.

Process

CEI has a standard practice of installing fault indicators on their substation exit cables. Their substation exit cables exit the substation underground, and then go up a riser to the overhead portion of the line. The fault indicators are placed on the overhead line just beyond the riser pole disconnects.

Prior to the implementation of the practice to install these fault indicators, CEI’s dispatching practice for troubleshooting a feeder that tripped off line was to open the disconnects at the Substation exit riser and try to reclose the feeder (in effect, testing the condition of the exit cable portion of the circuit). If the circuit tripped upon reclose, the dispatcher would know that the problem was in the exit cable portion of the feeder. If not, the dispatcher would know that the problem was located beyond that point. This approach was effective, but would typically consume 20-30 minutes to have a switchman perform the work involved. Because these problems involved feeder lockouts, large numbers of customers were involved, contributing significantly to CAIDI.

In an effort to improve reliability by reducing the number of customer minutes of interruption by shortening the troubleshooting time, CEI implemented the practice of installing fault indicators on all the substation exit cables, just beyond the disconnects where the feeder moves from underground to overhead.

The present practice for troubleshooting a feeder that has tripped off line includes an Operator going to the location of the fault indicators to ascertain their status.

If the fault indicators are flashing, the troubleshooter would know that the fault occurred beyond the disconnect switches. The operator could them begin troubleshooting the rest of the feeder and restoring customers, without spending the time to ascertain the condition of the exit feeder cables.

If the fault indicators are not flashing, this would suggest that the faulted section of the feeder is in the exit cable portion. However, because the fault indicators do not always register on a downstream fault, the dispatcher will still disconnect and attempt to close the exit cable section to prove its condition before continuing with additional troubleshooting / restoration activities.

Technology

The fault indicators they use for this application are relatively inexpensive and reset automatically upon circuit re-energization. (Note: this is different than the type of fault indicators used to troubleshoot momentary interruptions where the fault indicators would retain their status until manually reset).

6.3.4 - CenterPoint Energy

Operations

Fault Indicators

Process

CenterPoint does not use fault current indicators (FCI’s) in their major underground infrastructure, as they have found them to be unreliable.

6.3.5 - Con Edison - Consolidated Edison

Operations

Fault Indicators

Process

Conduit Size Restriction

One challenge that Con Edison faces is trying to expand capacity given the space limitations of and damage to existing duct bank systems. In some locations, spare ducts may be crushed or blocked. In others, the size of the spares may not be adequate to pull through the necessary cable to meet loading.

For example, in a design where 750 MCM cable is called for, Con Edison may have to consider running double 500’s because the 750 cannot fit in the 4-inch spare conduit.

The Brooklyn Operation Center noted that about 10% of their ducts are crushed. In Manhattan, the number of crushed ducts is significantly higher, at 45 – 50%.

In some cases, Con Edison bifurcates the feeders; that is, breaks the feeder into two sections outside the station in order to adjust to the limited space considerations and add reliability. In this design, Con Edison installs SF₆ switches with fault indication outside the station, protecting each leg of the bifurcated feeder. In a feeder lockout, this enables them to isolate the faulted section and pick up the rest of the load.

6.3.6 - Duke Energy Florida

Operations

Fault Indicators

Process

Most faults are detected by the Network Control Center personnel through its SCADA system connected to remote network protectors and to self-reporting fault circuit indicators located at locations near the feeder midpoint. The fault indicators provide Operations with the general area of a fault via SCADA, so that they can direct field to the location for further analysis and fault isolation. The Operations and Reliability group, as well as maintenance crews, have a written procedure for fault location and isolation.

Technology

Duke Energy Florida utilizes sectionalizing devices in its network feeders. Historically, these devices have been oil filled three way switches and are equipped with remote reporting fault circuit indicators (FCIs). All remote reporting FCIs communicate to the company’s SCADA system. (See Network Monitoring).

Duke Energy Florida is in the process of replacing the oil-filled sectionalizing devices used on the Clearwater network feeders with solid dielectric vacuum switches. The oil-filled devices are near end of life, and it is becoming more difficult to obtain parts. In addition, the move away from an oil insulated device is motivated by safety considerations. The new solid dielectric vacuum devices are slightly larger than the oil filled devices and will be placed in sidewalk vaults.

These devices, which do not have fault interruption capability, will also be equipped with remote reporting faulted circuit indicators (FCIs) that communicate via SCADA to the DCC. The new devices will be placed on an angled stand so that the switch faces the vault exit and can be easily operated with a hot stick from outside the hole. The switches will also have a pendant operation arm.

The decision to proactively replace the older oil gear with the new solid dielectric switches was collaborative involving the component engineer within the PQR&I group, the Standards engineer, and the Network Group.

6.3.7 - Duke Energy Ohio

Operations

Fault Indicators

Process

Duke Energy Ohio does not use fault current indicators (FCI’s) in its network system. They do use them in some 19.9 kV applications at selected locations on their radial distribution system.

6.3.8 - Energex

Operations

Fault Indicators

Process

Energex has a photovoltaic monitoring research project underway focused on gathering data to be able to better forecast power supplied by intermittent solar panel supplies, to determine battery storage requirements.

The project is focused on approximately 150 solar panel-equipped customers. The monitoring system is bringing back “one minute” data from the grid. So far Energex has amassed six terabytes of information for its study. The project includes the allocation of batteries for storage at the pilot sites, and will include battery monitoring.

Working with researchers, the Energex team is attempting to come up with network forecasting of intermittent supply, which is quite useful for battery storage.

Technology

The team is investigating a system that integrates solar panels with an intelligent inverter and a battery. By remote control, Energex could send parameters to the device for demand management and voltage management for the utility, and the customer could receive information and capability to change parameters to minimize his bill.

6.3.9 - ESB Networks

Operations

Fault Indicators

Process

ESB Networks has broadly applied Faulted Circuit Indicators (FCIs) on their MV 10kV system in Dublin. The company typically places the FCI on the MV cable where it terminates within the switchgear.

FCIs are an integral part of ESB Networks’ troubleshooting process. The company utilizes the FCIs to narrow down the cable sections where the outage occurred. Then ESB Networks disconnects that section, and attempts to reclose the remaining sections.

Technology

A commonly used FCI is maintenance free, self-resetting FCI manufactured by Horstmann GmbH^[1] (see Figure 1 and Figure 2). This indicator uses a vial filled with a clear liquid, with a red particulate in the base of the vial. During a fault, a “mixer” is pulled up by the magnetic field, which stirs up the red particles, turning the liquid in the vial from clear to red. After 6-8 hours, the red die particles resettle, resetting the indicator. ESB Networks reports high trust in this type of indicator.

Figure 1: Faulted circuit indicators

Figure 2: Faulted circuit indicators: Note spring shaped “mixer”

ESB Networks has not invested in remote indication of FCI status. The company notes that without the implementation of automated (remote) switching, the investment in remote indication of FCI status is uneconomic.

^[1] http://www.horstmanngmbh.com

6.3.10 - Georgia Power

Operations

Fault Indicators

People

Monitoring of the underground network system, including fault detection and self-reporting faulted circuit indicators, is the job of the Operations and Reliability personnel in the Network Control Center. The Operations and Reliability Group, part of Network Underground, is responsible for operating and monitoring the network system, and for directing field crews in locating faults. Operators will use information from fault indicators to narrow the investigation to the faulted sections of the feeder as reported by the FCIs. It is the responsibility of the field crews to assist operations in locating faults.

The Network Control Center Test Engineers are four-year or two-year associate-degreed engineers. The group works closely with maintenance crews, Key Account representatives, Test Technicians, and the Distribution Control Center.

Maintenance and trouble-shooting crews are comprised of Cable Splicers, Duct Line Mechanics, WTOs, and their supervisors .

Process

Most faults are detected by the Network Control Center personnel through its SCADA system connected to remote network protectors and to self-reporting faulted circuit indicators located at locations near the feeder midpoint. The fault indicators provide Operations with the general area of a fault via SCADA, so that they can direct field to the location for further analysis and fault isolation. The Operations and Reliability group, as well as maintenance crews, have a written procedure for fault location and isolation.

Technology

Fault indicators feed into the Network Control Center through the Network Underground SCADA network. Operators can monitor the entire network from the center, including data from self-reporting fault indicators.

Georgia Power is also studying the use of electronic relaying and a distance-to-fault calculation to further narrow the location of the fault. They have installed some substation relays capable of monitoring and recording the fault signature, and have are building models within CYME to calculate the maximum fault duty at various locations along the feeder.

6.3.11 - HECO - The Hawaiian Electric Company

Operations

Fault Indicators

People

Troubleshooting is performed by Primary Trouble Men (PTM’s) under the control of the Dispatcher. The HECO practice for troubleshooting a feeder or feeder section that has tripped off line includes a PTM going to the location of the fault indicators to ascertain their status.

Process

HECO installs fault current indicators in all padmounted transformer installations, three phase and single phase. In addition, HECO has a standard practice of installing fault indicators on their substation exit cables. Their substation exit cables exit the substation underground, and then go up a riser to the overhead portion of the line. The fault indicators are placed on the overhead line just beyond the riser pole disconnects.

The HECO practice for troubleshooting a feeder that has tripped off line includes a PTM going to the location of the fault indicators to ascertain their status.

If the fault indicators at a station exit riser are flashing, the troubleshooter would know that the fault occurred beyond the disconnect switches. The operator could them begin troubleshooting the rest of the feeder and restoring customers, without spending the time to ascertain the condition of the exit feeder cables.

If the fault indicators at a station exit are not flashing, this would suggest that the faulted section of the feeder is in the exit cable portion.

In troubleshooting looped underground infrastructure, the PTM will open each padmounted transformer along the route to isolate the section in which the fault occurred. The PTM will then sectionalize in order to isolate the faulted section and restore service to customers.

Technology

The fault indicators HECO uses for substation exit cable risers and for transformer installations are relatively inexpensive and reset automatically upon circuit re-energization. (Note: this is different than the type of fault indicators used to troubleshoot momentary interruptions where the fault indicators would retain their status until manually reset).

Figure 1: FCI – Manual Resetting

In underground applications, HECO’s is presently using the following FCIs:

Fisher Pierce 1514SH
SEL TPR – used on elbow capacitive test point
Chance MR450 or Linam MR450 – manual reset
HECO is testing a Power Delivery Products Overhead Load Tracker w/ Navigator Memory in one of their switch vaults on conjunction with a telemetric RTU.

In Overhead applications, HECO’s is using the following FCIs:

Power Delivery Products - Overhead Load Tracker w/ Navigator memory.
Cooper CPS SCVT (Star, current reset, variable trip) with FlexNet communications (TEST ONLY on selected 46kv overhead lines)

Figure 2: FCI – Self Resetting

6.3.12 - National Grid

Operations

Fault Indicators

Process

National Grid does not use fault current indicators (FCI’s) in its network system. Network feeders are designed without sectionalizing points, with feeders going right to the network transformers, leaving no place to install FCI’s. National Grid has applied fault indicators in selected locations where they have more than one circuit feeding off a common breaker, with no specific circuit monitoring capability. In these cases they use FCI’s to ascertain which feeder caused a breaker operation.

National Grid uses FCI’s extensively in their radial system.

6.3.13 - PG&E

Operations

Fault Indicators

Process

Within San Francisco, PG&E uses primary sectionalizing devices on network feeders (historically, the G&W T Ram). Fault indicators are placed at these switch locations to aid troubleshooters (cablemen) in fault location.

Technology

PG&E is buying Schweitzer three conductor lead cable fault indicators. These fault indicators are SCADA ready, but are not presently tied in to SCADA. PG&E, with the implementation of their new network remote monitoring system, intends to tie these fault indicators into SCADA so that the distribution operator can view indicator status.

6.3.14 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 11.7: Faulted Circuit Indicators

6.3.15 - Survey Results

Survey Results

Operations

Fault Indicators

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 15: Do you use faulted circuit indicators (FCI’s) in your Urban UG infrastructure? (Check all that apply)

6.4 - Fault Location

6.4.1 - AEP - Ohio

Operations

Fault Location

People

Fault location is the responsibility of the Network Mechanics, who work closely with both the Distribution System Operators and Network Crew Supervisors. In the event of a fault off hours, the dispatcher will notify the Duty Supervisor, who will then call in needed crews.

All Network Mechanics are trained in fault locating and perform all aspects including switching, location, and making repairs. The exception is switching and placing grounds at the substation, which is performed by Station Servicers. Network Mechanics will lift cable terminations at the station to connect the thumper. The AEP network engineers may also be involved in fault location.

Process

When a fault occurs, the Operations Center Dispatcher will call out the Duty Supervisor, who will mobilize Network Mechanics to locate the fault. AEP Ohio has a test truck specifically outfitted for fault location. It is pre-rigged with a DC Hi pot impulse generator (thumper) and all other necessary equipment for fault location.

After repairs, AEP will perform an AC VLF withstand and tan delta test, at 15-kV for 45 minutes. The company captures and records information. Note that for new cable, AEP will perform a “commissioning” AC VLF tan delta test – 20 kV for 45 minutes. This initial test provides a benchmark. From then on, the company will perform the 16-kV test after repairs. Note that subsequent withstand tests are only performed if they have broken into the cable insulation on the feeder.

Once the fault is found, Network Mechanics will make repairs. The makeup of the repair crew depends on the type of problem that created the fault and can include network maintenance and civil construction personnel.

Technology

The Dispatch Center and crews have extensive, accurate network maps, which are available online. The AEP Ohio system contains microprocessor relays (Schweitzer SEL 351S), which are being used by Network Engineering to analyze waveforms to aid in pinpointing the location of faults. In some cases, the information recorded by the relays is highly useful in isolating the location of faults. However, in its network circuit design, some feeders branch off the main trunk circuit, making fault location more difficult. In these cases, Network Engineers can analyze the fault impedance on the main trunk and give the work crews a place to start for location using maps from the Dispatcher. Network engineers are also investigating using waveform information for precursor fault detection.

NPServe, a new Eaton device, is under test and consideration at AEP Ohio to aid in secondary fault locations. A firmware upgrade to current VaultGard devices, along with NPServe, can obtain data from downstream devices and may enable AEP Ohio to more accurately pinpoint faults.

6.4.2 - Ameren Missouri

Operations

Fault Location

People

At Ameren Missouri, fault location for network primary cables is the responsibility of the Service Test organization. Distribution Service Testers perform the locating and work with the Traveling Operators who perform the switching to the clear the feeders for locating.

Organizationally, both the Traveling Operators within the Distribution Operating group and Distribution Service Testers within the Service Test group are part of Reliability Support Services.

The Service Test department has training guideline for cable fault locating used for training of the Distribution Service Testers. At the time of the practices immersion, Ameren Missouri was developing a formal fault location procedure.

Secondary troubleshooting is the responsibility of the Underground Construction department. In a network outage, the dispatcher in the SDC would first call a supervisor within the either the Service Test group or the Underground Construction department depending on the nature of the outage.

The steps for clearing a network feeder involve the dispatchers within the System Dispatch

Center and Traveling Operators. Dispatchers issue the switching orders for clearances, and the Traveling Operators are responsible for performing switching within the network vaults (including operating both the primary disconnect switch on the network unit and the network protector), at the substation for network feeders, and at customer switchgear. The dispatcher may issue a “restraint”, which enables one operator to apply a test voltage.

Repairs, such as cable replacement or splices, are the responsibility of the Underground Construction group.

Process

In a cable outage, the traveling operator’s first step is to switch open the feeder. In most cases, the feeder would have locked out. When they first open the feeder, they apply the test breaker at the station and check for potential using phase sticks to assure that there is no back feed from hung up protectors. If they do find one hung up, they will identify the protector that failed to open form their remote monitoring system, and then go to that location and manually open and lock open the protector before fault locating.

Traveling operators visit every hole and open the transformer primary switches in each vault. Ameren Missouri does not require a visible break at the transformer disconnect switch. Note that the Traveling Operator knows which vault entrance leads to the primary switch because that entrance (the primary side entrance) is marked with a tag just below the grate, visible from above. After opening all the transformer switchers, the operator would go back to the station and perform a “shorts” test - a way of confirming that they haven’t missed a transformer or that there isn’t a short on the system.

As the Traveling Operators perform switching, they place appropriate clearance tags, such as Holdoff tags and Grounding tags. At the station they use a Racking Holdoff tag, which enables the breaker to be racked into the test position, but not back onto the bus. They also use information tags (Blue tags) to notify others of pertinent information.

Once the Traveling Operators have the feeder switched open, they would call in the Dist Service Testers to locate the fault. After the fault is located, the repair work is the responsibility of the Underground Construction group.

Distribution Service Testers use DC hi pot testers (capacitor impulse discharge units) to thump the cable. They use ballistic detectors to narrow the location and galvanometers to pinpoint the location of the fault.

In order to reduce the time to repair, the Traveling Operators will call for fault location crews (comprised of Distribution Service Testers) BEFORE they are completed with the switching to account for the time necessary to call out and assemble the Dist Service Test crews. Similarly, the Dist Svc Testers will call out UG crews (Cable Splicers) prior to completing their location to allow time for the UG folks to respond to the call and assemble. In this way there is no “down time” associated with the handoffs from task to task.

After a network feeder has been separated (to prepare splices, for example) the Traveling Operators will check phasing before restoring the feeder. (See Clearances for more discussion on phasing).

Technology

Dist Service Testers and Traveling Operators have mobile data terminals in the trucks. These are used to access the Byers maps (See Mapping).

Ameren Missouri is using DC hi pot impulse generators from Biddle, Hipotronics, High Voltage, and Von. They are using ballistic testers and galvanometers to narrow the location of faults.

6.4.3 - CEI - The Illuminating Company

Operations

Fault Location

People

Fault location is the responsibility of the UG Electricians within the Underground Network Services department. Typically, certain electricians become proficient with fault location techniques and are normally assigned this responsibility.

Process

A network distribution system fault usually results in a primary feeder breaker locking out.

At CEI, a Substation department employee normally obtains relay targets, and racks out the breaker at the substation.

Underground Electricians will verify the feeder as dead and obtain clearance on the feeder by confirming that all of the network protectors are open and tagging them. UG Electricians will also open the primary disconnect switch on each transformer. (Note: the transformer disconnect switch remains within the zone of protection and can be operated as needed by electricians to perform phasing and grounding)

CEI uses both a high voltage capacitance discharge test set (Thumper), and a DC Hi Pot tester to locate faults.

CEI is using above ground fault detection equipment, in the form of a pickup coil designed by a CEI employee. When using a high energy (high voltage pulses) device to locate faults, an Electrician can hear a hum from the pickup coil from above grade. When the worker loses tone, then he knows he has gone past the fault. CEI strives to narrow the problem to no more than three holes using this above ground technique.

Figure 1: CEI Pickup Coil

Once they’ve narrowed down the locations, UG Electricians enter the manholes and take readings with a galvanometer to detect pulses. If the pulse is present, the operator proceeds to the next manhole. The absence of a pulse indicates that the fault is located somewhere between the current manhole and the one previously checked.

After locating and cutting a faulted section of cable clear, CEI crews will Megger the cable in both directions to assure that these sections are fault free. They will also Meggar the faulted section to confirm the failure in the faulted section.

After the fault is located, Underground Electricians will go to the transformers in each side of the faulted section and put the transformer primary switches in the ground position, so that they will be working between grounds when spicing.

After repairing the fault, CEI will perform a cable test (a VLF test at elevated voltages based on the IEEE maintenance rating) before attempting to reenergize a circuit or circuit section to verify that the cable is good and that no other faults exist. An exception is in testing circuit sections that contain old 5kV oil switches. Here they will use a 5kV Meggar test so as to not damage the switches.

Technology

CEI has several fault location trucks, equipped with test equipment to facilitate fault locating.

Figure 2: CEI Fault Location Truck

Figure 3: Primary connection transformer

6.4.4 - CenterPoint Energy

Operations

Fault Location

People

Fault Location is performed by Network Testers of the Relay group within the Major Underground group at CenterPoint.

The Relay group is comprised of Network Testers, a bargaining unit position at CenterPoint. Network Testers report to a Crew Leader, a non bargaining unit position at CenterPoint. The Relay group is lead by an Operations Manager.

Cable Splicers, from the Cable group, may assist Network Testers on fault locations, acting as “listeners” to help pre locate faults.

CenterPoint does not have dedicated fault location crews. All Network Testers are trained in performing fault location.

Process

CenterPoint uses DC Hi Pot testing and high voltage capacitance discharge testing (the Thumper) in conjunction with above ground impulse detection to locate faults.

After checking feeders for dead and grounding, Network Testers will apply the fault location test set to the faulted cable. They will first Meggar the cable, then apply the Hi Pot test set to determine the break down voltage. They use this to set the Thumper.

CenterPoint is using an above ground impulse detection device to aid in locating faults. The device is TEC-X35, developed by a vendor in partnership with Con Edison. The X35 device is used above ground to display polarized thumper signals to help direct field operators to the fault location. A field operator stands directly over the feeder and takes measurements above the ground. A reference measurement is taken at the feeder source. The operator then moves along the path of the feeder taking measurements and comparing them to the reference measurement. A positive reading with an amplitude similar to the one taken in the substation vicinity indicates that the operator has not yet reached or passed the fault location. A small or negative reading indicates that the operator has passed the fault or has chosen the wrong feeder leg.

If for some reason, the crews are having difficulty locating the fault, they will disconnect all the transformers and try again. In difficult to find faults, they will resort to breaking the feeder in half and testing cable sections.

After locating and cutting a faulted section of cable clear, CenterPoint crews will VLF test the remaining cable in both directions to assure that these cable sections are fault free (see Cable Testing / Diagnostics).

Technology

CenterPoint has specialized trailers that are equipped with fault location / cable diagnostic equipment, including DC hi pot testers, and VLF testers. Network Testers will hook the trailer on their trucks and take to the job site.

Figure 1: Cable Testing Van - External

Figure 2: Cable Testing Van - Internal

CenterPoint is using test units by Cable Dynamics and by Centrix

6.4.5 - Con Edison - Consolidated Edison

Operations

Fault Location

People

Field Operating Department (FOD) (Also called the Field Operating Bureau)

The Field Operating Department is part of Electric Distribution, and has responsibility for the emergency crews (the crews using the red emergency trucks), as well as the following accountabilities:

Fault locating (distribution and transmission)
High-tension switching (entering customer high-tension vaults and operating devices)
Feeder identification
Hi-pot testing

Fault Location Knowledge Retention

The biggest issue faced by the Fault Locating group is the loss of knowledge as experienced resources leave the department. Their biggest challenge is to find ways to retain people and knowledge.

Con Edison is currently rewriting the Field Operating Department (FOD) manual; however, this manual will provide a general overview, not specifics. Con Edison believes that much of performing fault location is based on experience and “feel.” Because each situation is different, fault-locating techniques are not skills that can be learned from books alone. Fault-locating skills must be developed through work experience.

Con Edison is bringing young employees into the department to learn. General Utility workers (GU’s) who enter the department must go through formal training, testing, OJT, and Field Operating Department (FOD) school. It takes 3-4 years to become a journeyman. Even after an employee becomes a journeyman Field Operator, Con Edison typically waits until that employee is more experienced before assigning certain duties, such as high-tension switching.

The performance of fault locating is a 24-hour-a-day, 7-day-a-week operation. Con Edison, on average, locates three faults a day. Their average time to locate a fault is two hours.

One of the challenges faced by many companies is that fault locating is shared with other duties. Consequently, it is difficult to develop experts and retain expertise. At Con Edison, the fault-locating group is a dedicated group, enabling them to become very proficient in fault-locating techniques. Con Edison has been called on by other utilities numerous times to aid in fault location.

Process

Feeder Identification

When the suspected location of the fault is identified, the Con Edison field operator places a “Suspected” tag on the cable where the fault is suspected to have occurred. After identifying the suspected location of a fault, Con Edison sends out low-voltage pulses on all three phases of the feeder to positively identify the cables and cable phases. Only after the cable and cable phases are positively identified, does the field operator apply a tag confirming the feeder with the fault.

Once the location of the fault is identified, the field operator calls the station operator to take off the signal used to locate the fault, and ground and test the feeder. The District Operator orders the placement of the ground in the first vault with a transformer past the fault. Placing that ground at the transformer involves receiving an order including the switch lock combination and operating the ground switch at the transformer primary. This grounds and shorts all three phases. The reason for going to the transformer is to confirm that the circuit is being grounded, and because good tracing current can be identified at this location.

The Substation operator then puts a tracing current on the circuit. The following protocol is utilized for distinguishing the phases: A phase, one beat; B phase, 2 beats; C phase, negative (return). An operator in the manhole listens for the A, B, and C signals. He or she also checks every other cable in the hole to be sure the proper cables have been identified.

Once the field operator identifies the cable, he or she physically marks the cable and fills out a tag that positively identifies the cable, moving it from “suspected” to being positively identified. The tag has a serial number, and is included in switching orders with dispatcher.

Fault Locating

A distribution system fault usually results in a primary feeder breaker locking out (Open Auto). When a feeder opens, the District Operator (DO) has the substation operator retrieve the relay targets. Then the DO gives the feeder to the substation operator to establish the condition of the feeder. The Substation Operator performs a Hi-pot test to confirm that there is a fault.

When it is determined that there is a cable fault, the Control Center calls the Field Operating Department (FOD) to locate the fault.

The basic steps to fault locating include:

Isolate the feeder (Open high-tension switches and any other potential back-feed source.).
Verify the feeder as dead (Confirm that there is no back-feed from network protectors that may be hung up.).
Ground the feeder.
Locate fault.

Con Edison uses several methods to locate faults. High-voltage methods (use of high-voltage pulses applied to the feeder at the substation) include:

High-voltage pulses can be applied with a capacitance discharge test set (thumper) (20,000 V)
High-voltage DC pulses can be applied with a Thyratron
High-voltage Kenotron surges

After the pulses are applied, fault-locating operators travel the route of the feeder, entering manholes to take readings with a galvanometer that detects the pulse. If the pulse is present, the operator proceeds to the next manhole. The absence of a pulse indicates that the fault is located somewhere between the current manhole and the one previously checked.

Although inherently time-consuming and labor-intensive, applying high-voltage pulses (thumping) has proven best suited to the characteristics of Con Edison’s system when compared with other fault-location methods. Low-voltage methods are used much less often, because they only work under certain circumstances. Note that Con Edison uses an above-ground fault detection technology that minimizes the number of manholes that must be entered to detect a fault.

Other methods, such as Time Domain Reflectometry (TDR) are used to locate faults on transmission lines, but are less effective on Con Edison’s distribution system because of the significant number splices, Y and T connections, transformer connections, and the bonding of dissimilar cable types with varying propagation velocities, which can create indistinguishable reflections to an operator, masking the identity of the fault.

Secondary Fault Location

Con Edison does not have a good method of ascertaining whether or not cable limiters have blown. Utility crews take a current reading and use a device that puts a signal on the secondary, but these methods are not trusted by all the work groups at Con Edison.

Con Edison has asked three different manufacturers to develop a new limiter design that provides fault indication and can be quickly replaced. For example, one manufacturer has developed a cable limiter with a clear covering so that the user can see that the device is open. Con Edison is currently evaluating this product.

Technology

Reactance to Fault Application – RTF

Con Edison is using a system that predicts the location of faults on the system based on an analysis of the electrical waveform at the time of the fault. The base platform for the system is the EPRI PQ View product, with an add-on called the “Fault Location Module.” The Con Edison system collects and houses the data and manages the waveform of the fault. Con Edison has integrated this model with their mapping system, such that the system can display the prediction of the fault location on their feeder map board. From this system, Con Edison can also view relay targets from a locked out feeder.

Prior to the implementation of this system, Con Edison’s approach to troubleshooting a feeder was to go halfway out on the circuit, and begin tracing and testing. The implementation of the Reactance to Fault (RTF) application enables the utility to pinpoint the location of the fault, significantly reducing the average restoration time. (Con Edison reduced the average restoration time by about one hour!)

The system also lets an operator know if the fault type is of a hazard level where company safety rules require special precautions for manhole entry, or prevent entry, depending on the specific hazards encountered (called C & D faults in Con Edison lexicon).

Above-Ground Fault Detection

Con Edison utilizes an above-ground device to pre-locate faults, opening manholes only to pinpoint the location of the faults. The device is a TEC-X35, and was developed collaboratively over a period of years by Con Edison and several technology partners, such as the former Bell Labs, and the Technology Enhancement Corporation (TEC). This device has helped Con Edison to substantially reduce the time and cost of finding faults, and thus, reduced the length of feeder outages. The savings results from a reduction in the number of manholes to be opened, possibly pumped out, and entered using traditional fault-location techniques. By minimizing the number of manholes entered, Con Edison avoids dealing with potential environmental issues associated with pumping out oil-contaminated water.

The X35 device is used above ground to display either polarized thumper signals or DC high-voltage test set (Thyratron) signals to help direct field operators to the fault location. A field operator stands directly over the feeder and takes measurements above the ground. A reference measurement is taken at the feeder source. The operator then moves along the path of the feeder taking measurements and comparing them to the reference measurement. A positive reading with an amplitude similar to the one taken in the substation vicinity indicates that the operator has not yet reached or passed the fault location. A small or negative reading indicates that the operator has passed the fault or has chosen the wrong feeder leg. When the location of the fault has been narrowed down, Con Edison uses traditional techniques (Galvanometer) to pinpoint the fault location.

Trucks

Con Edison provides its employees with the specialized tools and equipment that they need to do their jobs, including trucks outfitted for the different types of work that they perform. Employees stated that they believed Con Edison provides them with good quality trucks, appointed with the equipment they need to perform their work. People demonstrated a sense of pride in their trucks and associated equipment.

Con Edison’s network resources use specially equipped box trucks. Each department truck is outfitted to meet the needs of that group, including multiple storage bins for housing the onboard equipment.

For example, Fault Location Operators use a box truck equipped with a capacitive dc test set and a Galvanometer.

6.4.6 - Duke Energy Florida

Operations

Fault Location

People

For network issues, the Network Specialists and Electrician apprentices who are part of the Network Group serve as first responders in a system outage, and are responsible for fault location.

For non-network issues, such as troubleshooting an automated transfer switch (ATS), Troublemen, serve as first responders and are responsible for fault location. Troublemen report to a field supervisor, and are organizationally part of Duke Energy Florida’s Construction & Maintenance (C&M) group. Troublemen work closely with the dispatchers at the DCC.

All supervisors at Duke Energy Florida have an “on call” responsibility. Supervisors rotate their on-duty responsibility.

Duke Energy Florida uses the ARCOS automated callout system for obtaining craft worker resources.

Process

In Clearwater, the dispatchers at the DCC monitor feeder cables and can identify faults, usually when a breaker trips. In addition, dispatchers may receive indication from remote reporting faulted circuit indicators installed at network feeder sectionalizing switches. In general, the dispatcher relies on field crews to identify which fault indicators (FCIs) are tripped, and locate faults.

Any switching performed on the network during fault events at a site is performed by network work crews in the field. In non-network areas, field switching during fault events will be performed by Troublemen. At remotely operated substations, DCC will open breakers. If manual switching is required at a substation, Substation Electricians are sent to the substation to perform switching.

Permanent repairs to faults are not always performed immediately when a feeder opens because the network system has enough contingency to pick up the load. Once a feeder is open and isolated, crews can perform hi-pot (thumper) tests to determine the where the fault is along the isolated line segment. After the fault is located, the dispatcher is notified and generates a work order for a crew to make repairs the next day, unless customers are without power. If customers are without power, repairs are made immediately after the fault has been located.

In St. Petersburg, when an ATS successfully transfers, crews may also wait until the next day to address the issue. If necessary, crews will identify and isolate the faulted segment to ensure safe delivery of power to customers.

Radial feeders with no contingency will be repaired immediately after fault location by Troublemen and Dispatch.

Technology

Duke Energy Florida has SCADA control and monitoring at its substation breakers. In addition, for network feeders, they have installed remote reporting faulted circuit indicators at network feeder sectionalizing switch locations. These devices are hardwired to pole mounted devices which communicate back to the DCC via a 900 MHz radio system.

Duke Energy Florida has expanded its application of SCADA to monitor and control its automated transfer switches (ATS), which are prevalent in the primary / reserve feeder scheme used to serve customers outside of the network in Clearwater and in St. Petersburg.

Duke Energy Florida’s historic cable design has used separable connectors, such as the use of T-body connections for straight splices. This type of design enables field crews to separate cable sections, facilitating the fault location process.

6.4.7 - Duke Energy Ohio

Operations

Fault Location

People

At Duke Energy Ohio, fault location is the responsibility of the Dana Avenue underground. This includes not only fault location on the network system, but fault locating on the URD system as well^[1] .

The Relay and Test department and Substation Maintenance departments typically get involved in network feeder fault location, as they are responsible for diagnostic testing performed inside the substation fence.

Process

One of the first actions taken by the Dana underground group in responding to a fault is to notify the Relay and Test department and Substation Maintenance department so that they can report to the substation and begin doing the necessary work to prepare to locate the fault (un-tape cable terminations, for example).

Dana Ave. crews will visit each transformer location long the feeder and open up the transformers; that is, put the transformer primary switch in the open position. Crews will place a ground on the first transformer outside the substation.

For certain feeders, Dana crews will look to see if there’s water in manholes. They know of certain holes that typically take on water, near the river. If there is water present, they will notify a pumping contractor to visit these holes and pump out the water.

After the Relay and Test department resources at the substation are ready to perform the fault location test, the Dana underground crews will remove the grounds so that they can perform the test. For network feeders, the Relay and Test department “thumps” the cable using a Hi pot tester (Thumper) permanently installed at the network substation.

Dana Avenue field resources use a receiver and locate the fault. Duke Energy Ohio is not using above ground signal detection, as they are not using a grounded system. Field resources enter each hole with the receiver to determine the location of the fault.

After the fault is found, the Dana Avenue crew’s will put a ground on the system outside the station. Then, the resources at the substation will ground the station. Finally, Dana Avenue crews will revisit every transformer location on the feeder, and put the transformers in the ground position. Note that every transformer is grounded, rather than creating an island around the fault.

Duke is unable to obtain a visible break in their network system. Their network transformer primary switch compartments do not contain a site window. Crews will lock open and tag network protectors, but they do not remove network protector fuses or rack out the breakers.

After repairs, Dana Avenue underground crews revisit every transformer location, and move the transformer switch back to closed position returning the system to normal.

Before they reenergize the primary feeder, they will perform a fuse test. (See Network Protector Fuse Test)

Technology

Duke is using a Hi pot capacitive discharge tester (Thumper) to locate faults.

They do not use radar for fault location, as radar is ineffective for them, having a hybrid system, with long feeders and multiple branches.

Figure 1 and 2: Thumper located at Network Sub

^[1] Note that, on average, Duke Energy Ohio experiences between 600 and 700 URD burnouts per year.

6.4.8 - Energex

Operations

Fault Location

People

Fault location is the responsibility of the Operations Center , part of the Service Delivery organization at Energex. Outages that are reported by customer calls typically flow through the Evaluator position in the center, while outages that are reported through remote monitoring or field service reports typically flow through the switching coordinators.

Energex has rapid response crews located in their various service centers, referred to as hubs. The rapid responders are comprised of electrical fitter mechanics, which is the highest capability journeyman position at Energex. Within the Central Business District (CBD), substation fitter mechanics, who are qualified to work with the relay operated switchgear (breakers) that are part of three-feeder mesh, serve as rapid responders. Substation fitter mechanics are a bit more specialized than the electrical fitter mechanic position.

Rapid response crews work two shifts, a 6:00 am to 2:00 pm shift, and a 2:00 pm - 10:00 pm shift, 7 days per week. Energex utilizes a “stand by” roster, which it uses to call out to standby rapid response crews on the night shift. Within the Central Business District (CBD), Energex also holds a substation crew (substation fitter mechanics) on standby. Note that workers on standby may take vehicles home with them so that they can respond more rapidly (each crew member takes a vehicle home).

Process

Switching coordinators monitoring the CBD can monitor alarms associated with the primary feeder that has a protection indicator that flags a fault. Multiple indicator flags isolate the leg of the feeder that has a fault. Almost every substation is relay operated, and all 11 kV units have fault indicators.

A rapid response crew and a substation crew respond the outage. When it is determined that cable fault location will be required, a cable diagnostic crew would be called in to locate the fault.

Technology

Figure 1: Cable test set applied to medium voltage circuit

6.4.9 - ESB Networks

Operations

Fault Location

People

ESB Networks has a well-documented process for performing fault location, documented in their Cable Fault Location manual (See Attachment B: Cable Fault Location Manual Table of Contents ). The document outlines the ESB Networks preferred processes for performing cable location, and includes information on various cable fault location tools and techniques as well as issues related to safety and training. ESB Networks revisits the content of this manual on a three-year cycle to assure it is up to date.

Process

ESB Networks had defined a preferred process for performing fault location. It consists of:

Evidence gathering: Includes performing a thorough assessment, including obtaining maps, and reviewing information provided from protective relays or fuses.
Fault assessment and diagnosis: Includes test to confirm the existence of and to categorize the fault, so that the proper fault location techniques can be employed. Includes continuity and resistance testing.
Pre-location and fault conditioning, if required: Includes application of strategies to reduce the test time voltages are applied to minimize cable stresses, and to minimize the down time on the cable. The pre-location strategies vary depending on the findings from the fault assessment and diagnosis. The table below (Figure 1) outlines the pre-location strategies:

Figure 1: Pre-location Strategies

Route tracing and measurement: Includes impressing a signal on the cable to mark the route of the cable.
Pin-pointing: Includes strategies to pinpoint the location of faults such as thumping the cable and using a ground microphone, and using audio frequency signal generators and receiver coils.
Excavation: Includes strategies for positively identifying the cable, including spiking the cable.
Secondary effects: Includes checking to make sure that secondary and service were not damaged by the fault.

Figure 2: ESB Networks fault location process

ESB Networks primary switches used within their MV substations cannot be used to break load, but can be closed into a fault – a “fault make.” When ESB Networks troubleshoots a faulted primary cable section, it first uses faulted circuit indicators (FCIs) to try to narrow down the location of the affected section. Then personnel disconnect the portion of the feeder thought to be outaged, and try closing back in the remaining section. If it closes into the fault, the feeder trips again. In this way, personnel can narrow down the location of the fault.

Technology

Because ESB Networks uses sector-shaped cables within its secondary, there is some difficulty getting good crimp connections with traditional secondary connector systems such as HOMAC connectors. Consequently, the system experiences occasional connector failures in the secondary system.

In Dublin, many services are “T” services, where the service is tapped off of the secondary using a self-piercing connector. One challenge that ESB Networks networks faces is that the locating of faults in the secondary system is difficult with these T connections. ESB Networks often must resort to “stabbing” the cable at various locations to see if it is still live.

Fortunately, ESB Networks has excellent records of where the cables are located. It has hand-drawn records that include detailed maps of the secondary. Highly congested areas are enlarged so that details are available, including the location of joints and cable bends.

For cable changes, an Engineering Officer goes out into the field and confirms the change and assures that the records are up to date. The ESB Networks UG has a separate person for this operation because the group understands the importance of complete records. For example, ESB Networks needs accurate records to be able to dig up the ground in the right spots.

Neutrals are connected through a Peterson coil to the 38-kV side of transformers that creates an arc-suppressed system. ESB Networks does not trip for earth faults, and it has three hours to clear the fault. When there is a ground fault, ESB Networks monitors the open delta voltage and receives an alarm indicating it has a ground fault on the system. The fault could be transient. If it is sustained, ESB Networks receives a sustained alarm. Because the meshed system in Dublin is protected by impedance and differential relays, it can isolate interruptions in milliseconds.

6.4.10 - Georgia Power

Operations

Fault Location

People

It is the responsibility of the Network Control Center personnel (Test Engineers) within the Georgia Power Network Underground group to assist ground crews in locating faults on the network system. Test Engineers in the Operations and Reliability Group are responsible for operating and monitoring the network system, including directing fault location activities. This Network Control Center is organizationally part of the Network Operations and Reliability group, led by a manager.

The Network Control Center Test Engineers are four-year or two-year associate-degreed engineers. The group works closely with maintenance crews, Key Account representatives, Test Technicians, and the Distribution Control Center.

Operations department Test Engineers along with Maintenance crews comprised of Cable Splicers, Duct Line Mechanics, and WTOs, perform the field work associated with fault location.

Process

When a primary fault occurs, it causes the feeder breaker to trip. That causes alarms at the Distribution Control Center and at the Network Control Center. The DCC operator immediately notifies the Test Engineer on call and sends a text message to selected management and others. Most faults are also detected by the Network Control Center personnel through its remote monitoring system connected to all the network protectors and reporting faulted circuit indicators. The fault indicators provide the general area of a fault through SCADA and enable the operator to narrow down the location to send crews for further analysis and fault isolation. Georgia Power has a written procedure for fault location and isolation.

Georgia Power crews will use a DC hi-pot (impulse tester) applied to the circuit at the substation, and thump the cable to identify the fault location. Operations department field personal and maintenance crews, under the direction of the Network Control Center operator, will walk the line above using an above-ground EMF detector, and listening for the thump. Maintenance crews open manholes that might be near the fault. A second crew of operations and maintenance workers will start on the other end of the feeder, opening manholes to inspect, and working their way back to narrow the location of the fault.

The impulse generator (thumper) charges and discharges at automatic eight-second intervals, and the crew may leave a person behind at the station to monitor the generator. While crews normally use an above-ground EMF detector while walking the line, they occasionally lose the pulse, and must enter the manhole to use a cable-clamp based EMF detector. The clamp-based detectors are 90 to 95 percent accurate. Once crews pass where the fault is occurring, deflections almost disappear.

Once the fault is found, operation personnel ground the feeder at the substation, and notify the maintenance supervisor to proceed with work. The maintenance supervisor will then put his field grounds in place to make sure the crew is working between grounds. The makeup of the repair crew involved depends on the time of day, and type of problem that created the fault, and can include maintenance or construction resources

In general, the Georgia Power secondary grids in Atlanta experience few faults, as they are not heavily loaded. However, in Savannah the company has a heavily loaded secondary mesh system and is designed with cable limiters. At selected locations in Savannah, the secondary is configured with current transformers (CTs) clamped around half the secondary cables and CTs on the other half of the mesh, with remote communications. If a cable limiter blows, Operations can then see through SCADA the load shift from one CT to the other, and thus determine remotely that the limiter has blown. To reduce cost, the company uses two CTs per phase on a four-cable secondary run.

Technology

The Network Control Center and maintenance crews have extensive, accurate network maps available online through the Georgia Power Underground group’s GIS system.

Georgia Power uses the ARCOS system to perform callouts of field crews to respond to an outage / emergency. This automated phone system calls the roster of “on-standby” personnel and directs them to call their supervisors for instructions. Maintenance crews and other designated personnel are expected to be on stand-by and have a response requirement: they must respond to at least 50 percent of all emergency, off-hours calls each year. Georgia Power also has a volunteer list for those who want overtime, and volunteers are first in the ARCOS calling queue. Note that all employees of a classification are grouped together for call out, even if they work in different groups.

Georgia Power has installed self-reporting faulted circuit indicators on some feeders, which helps to narrow the search for the fault location (at least eliminates half the feeder). They noted that these devices have limited battery life.

Georgia Power has also done pilot projects using fault current magnitude with computer models of the system to predict the likely fault locations. This is promising, and is expected to be even more useful as data improves in the system models, and as more network feeder breakers are equipped with electronic relays.

6.4.11 - HECO - The Hawaiian Electric Company

Operations

Fault Location

People

Primary Fault location at HECO is the responsibility of the Cable Splicers within the Underground Group. Secondary fault location is the responsibility of the Overhead Group.

The Primary Trouble Man (PTM) position is also involved in the front end of the fault location process, responding to the initial outage caused by the fault, isolating the suspected faulted section, and restoring service.

Process

Most of HECO’s distribution system is installed in concrete encased conduit. The exception is some older direct buried, looped URD sections. According to HECO, the majority of cable faults occur in these direct buried installations.

A distribution system fault usually results in the operation of a protective device such as a riser fuse or breaker lockout. HECO will dispatch a Primary Trouble Man (PTM) to isolate the problem to a cable section, and sectionalize to restore service. Because HECO’s URD system is designed in a loop configuration, and because of their practice of using fault current indicators in all pad mounted equipment, the PTM is able to go to each transformer location, and using fault indicators, identify the suspected cable section in which the fault occurred. The PTM can then sectionalize; that is, lift elbows to isolate the faulted cable section, and close normally open points along the loop to restore service to customers. The PTM will also apply the appropriate safety tags to the isolated cable section.

Cable Splicers from the Underground group will perform the actual fault finding and repair. Having the PTM’s respond to outage, isolate, and sectionalize to restore service to customers enables HECO to schedule fault location. When the Cable Splicers arrive, the faulted cable section will have been already isolated and tagged by the PTM. The Cable Splicers will verify the feeder as dead, before commencing with fault location. They will do this using both an AB Chance tester using the elbow test point, and a HECO fuse stick, a HECO developed tester for testing and grounding (see “Fuse Stick”).

Figure 1: Padmount transformer with parked, tagged elbow

Figure 2: AB Chance tester

HECO uses a high voltage capacitance discharge test set (Thumper) to locate faults. Note the test set leads attached to the cable section through a feed through bushing in the pictures below.

Figure 3 and 4: Test Set leads applied

Using the thumper, the Cable Splicers will isolate the location of the fault so that they can make repairs. After locating and cutting a faulted section of cable clear, HECO crews make the splice, and then do a proof test (voltage test) to assure that the splice holds.

Figure 5 and 6: URD Splice

Technology

HECO uses Fault Current indicators in every padmounted transformer. This facilitates trouble shooting in that a PTM can quickly isolate the section in which the fault is located.

Figure 7: Fault Current Indicator in Padmounted Transformer

HECO has fault location trucks, equipped with test equipment to facilitate fault locating.

Figure 8 and 9: HECO Fault Location Truck

6.4.12 - National Grid

Operations

Fault Location

People

Maintaining and operating the Albany network system, including fault locating, is the responsibility of Underground Lines East. This group is led by a manager, and includes field resources focused on civil aspects of the underground system and a field resources focused on the electrical aspects.

The Electrical Group, comprised of Cable Splicers and Maintenance Mechanics is led by three supervisors. Maintenance Mechanics perform fault locations, as well as network switching, minor vault maintenance, and inspection and maintenance of network vaults and equipment such as transformers and network protectors.

National Grid has a documented procedure for fault location that is part of their Electric Operation Procedures (EOP). This procedure contains flow charts that guide the field resources through the process. Note that National Grid EOP’s are available in hard copy or electronically on the company’s intranet.

Process

To perform testing, National Grid will isolate, tag, test as de-energized and ground the circuit to be tested per their written Clearance and Control procedures. For network feeders this procedure includes visiting every transformer vault, opening the transformer primary switch, and opening the network protectors. All network protector switch handles are opened, tagged and locked open, and the transformer primary disconnect switches are locked open.

As stated in the National Grid EOP, the objective of the fault locating procedures is to safely and expeditiously pinpoint the exact location of a cable system failure while minimizing the potential for damage to good cable. The procedure consists of five steps: Investigation, Verification, Pre-locating, Pinpointing and Confirmation.

Investigation provides a preliminary assessment of the fault situation from field conditions, relay targets, and a review of maps and records to determine feeder type and configuration.

Verification usually consists of two parts; performing a Meggar test to measuere insulation resistance of each phase, and an AC VLF Hipot test (Pick Up test) to identify the faulted phase.

Pre-Locating involves performing activities to narrow down the location of the fault, including such things as examining the cable route for visible signs of the fault, (for example, dislodged manhole covers or smoke emanating from a manhole) and applying tests to determine the distance to the fault, such as Time Domain Reflectrometry (TDR) . These tests and others, including the Murray Loop Bridge Method and Voltage Ratio Method, are detailed in the National Grid EOP.

Pinpointing consists of applying a tracer signal to the faulted cable and then finding the signal in the field. This can either be a capacitor discharge test (“thumper”) where an employee goes to the site and listens for the audible thump or detects the discharge using a magnetic / audio detector (pickup coil), or the use of a current trace (Thyratron) signal where a field employee can detect the signal using an impulse detector.

Confirmation involves a field employee observing the faulted cable if possible.

Technology

National Grid is using fault location equipment from HV Diagnostics. Resources appear to have confidence in this equipment.

Figure 1: HV Diagnostics VLF Test equipment

Figure 2: HV Diagnostics VLF Test equipment

National Grid is using two different magnetic detectors, the TEC-X35, Megger Electromagnetic Impulse Detector and the Megger MPP1000. The TEC-X35 is a handheld detector that is capable of picking up the signal from above, eliminating the need to enter manholes.

6.4.13 - PG&E

Operations

Fault Location

People

PG&E’s Maintenance & Construction Electric Network Department is responsible for the maintenance of the underground network system, including fault location. In San Francisco, all routine maintenance is undertaken at night. However, the department does maintain a daytime crew that performs fault location and repair.

The more complicated faults to locate are often supervised by a Supervisor- Distribution, part of the M&C Electric Network group.

PG&E has well documented procedures explaining the use of its fault location equipment. (See Attachment L .)

Process

Faults may result in a feeder locking out, or emerging faults may be identified through diagnostic testing, such as Very Low Frequency (VLF) alternating current (AC) which is sometimes referred to as high potential (Hi-pot) testing. .

EPRI observers witnessed the PG&E fault location process associated with a feeder identified as having a problem, through VLF testing. PG&E field crews and supervision demonstrated high degrees of proficiency in the use and understanding of the function of fault location equipment, executing the fault location process, and interpreting the readings from the tests. EPRI observers noted good working relationships among crew members, supervision, engineering, and Applied Technology Services (ATS) resources that were on site.

PG&E had performed a VLF test on the network feeder as part of a proactive testing program. The VLF test revealed some breakdown of the installation on one of the phases of a particular feeder. PG&E used a combination use of VLF testing and a capacitive discharge unit (thumper) to locate the fault.

After clearing the feeder, the VLF test was initially applied at the substation which showed a breakdown somewhere on the feeder.

Because PG&E’s network feeders are designed with normally closed sectionalizing points (typically either older oil-filled switches or new solid dielectric switches), fault location crews have the ability to isolate a section of a feeder to be tested. In this case, PG&E opened one of the sectionalizing points and then re- performed the VLF test at the substation. This second test revealed no breakdown of the insulation, indicating that the problem with the cable was further down the line, beyond the sectionalizing point.

To perform testing, PG&E will open the circuit and ground it. They will visit the sectionalizing locations, and open and ground them. Once they have isolated a section to be tested, they will visit every transformer vault between the switches, and open both the transformer primary switch, and the network protectors. All switch handles are tagged and locked in the open position.

They will then apply the VLF test set to the section of cable. Note that proactive VLF testing is performed by the Applied Technology Services (ATS) group. This group will sometimes participate in and supervise VLF testing associated with fault location. In this case, the ATS group was on site because the initial problem was discovered by proactive testing of the network feeders.

After confirming that the feeder section isolated between the two sectionalizing devices was indeed the faulted section, the fault location crew applied a thumper with arc reflection (radar), which provided a signal to indicate the location of the fault. However, this particular circuit had so many taps that the reflection did not reveal the location of the fault.

The fault location crews then “thumped” the cable, and assigned resources to visit each vaults using pickup coils to pinpoint the location of the fault. The cause of the breakdown, in this case, was a failed lead splice.

Technology

PG&E is using fault location equipment Von. Their tester is a combination arc reflection and capacitive discharge unit. PG&E resources appear to have confidence in this equipment.

The VLF test set is transported to the location by a specialized van equipped with a ramp used to wheel the VLF test set on and off the truck. This particular van also contains other cable diagnostic equipment, such as tan delta device and a TDR kit.

Figure 1: Von Arc Reflection and Capacitive Discharge Tester

Figure 2: VLF Test Truck

Figure 3: VLF Test Kit

PG&E is buying Schweitzer three conductor lead cable fault indicators. These fault indicators are SCADA ready, but are not presently tied in to SCADA. PG&E, with the implementation of their new network remote monitoring system, intends to tie these fault indicators into SCADA so that the distribution operator can view indicator status.

6.4.14 - Portland General Electric

Operations

Fault Location

People

Crews within the underground CORE group, along with the Special Tester, perform fault location. The load dispatchers within the System Control Center (SCC) are usually participants in the fault location process as well.

If a breaker locks out on a network feeder, the dispatcher receives an alarm and contacts the duty engineer and duty general foreman (DGF), the people on call to respond to situations in the network. The DGF will assemble a crew and try to isolate the fault. This crew normally involves the Special Tester, who performs fault locating. The Special Tester is a journeyman lineman with additional training and technical skills, including fault locating. PGE has embedded one Special Tester within the CORE group.

The typical underground crew performing fault location consists of the Special Tester, a crew foreman (a working foreman who is a journeyman cable splicer), a lineman/cable splicer (journeyman), and a topman, a non-journeyman helper.

Process

To locate faults, crews use a direct current (DC) high potential (hipot) tester (thumper) and time-domain reflectometry (TDR). All Special Testers carry fault location equipment on their trucks.

If a feeder breaker opens for a network feeder due to a fault, the SCC calls the duty general foreman in the network group. Because of the system redundancy of the network design, a faulted feeder would not result in customer outages, so there will be no outage management system (OMS) events. The DGF decides whether the issue can wait until the following day or needs to be dealt with immediately. In light load periods, the repair of single feeder outages is often left to the following workday.

When a feeder locks out, the dispatcher provides a clearance to the crew, which performs fault locating. Obtaining this feeder clearance involves going to each vault and opening both the network protector (handle in the open position), and the primary switch on the network unit. The crew then goes back to the substation and tests and grounds the feeder for safety.

To perform fault location, the crew ungrounds the feeder at the substation and connects the DC hipot equipment to each phase at the cable termination, one at a time, to determine which phase may have faulted. Once it has isolated the phase, it performs a TDR test to try to determine the location of the fault. TDR injects a voltage pulse into the cable system and looks at reflections back to the source end of the circuit caused by discontinuities in system impedance. The Special Testers noted that TDR is useful in narrowing the location of the fault if the fault is not far from the substation.

The main method used for fault location is cable thumping. The Special Tester applies the thumper to the circuit at the cable terminations at the station. Crews use a hand-held impulse detector, which must be placed on the cable to detect the pulse. Crews go from manhole to manhole until they locate the fault. If this device detects the pulse from the thumper, then the crews know that the location of the fault is further out on the circuit. If the TDR test does not help them narrow the location of the fault, crews typically begin this process midway out on the feeder.

Technology

To locate faults, crews use a DC hipot tester (thumper) and time-domain reflectometry (TDR). All Special Testers carry fault location equipment on their trucks.

While PGE uses faulted circuit indicators (FCIs) on its radial systems, they are not extensively used on the network system.

6.4.15 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter 11: Fault Location

6.4.16 - Survey Results

Survey Results

Operations

Fault Location

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 16 : In what applications will you perform network primary cable diagnostic testing? (Check all that apply)

Question 17 : In what applications will you perform Non-network primary cable diagnostic testing in urban UG systems? (Check all that apply)

Survey Questions taken from 2018 survey results - Asset Management survey

Question 10 : If you perform periodic network primary cable diagnostic testing, please indicate / describe what testing techniques you use.

Survey Questions taken from 2015 survey results - Maintenance

Question 81 : In what applications will you perform network primary cable diagnostic testing? (check all that apply)

Question 84 : Please indicate / describe what testing techniques you use.

Question 87 : Are performing periodic secondary network cable withstand testing?

Survey Questions taken from 2012 survey results - Maintenance

Question 6.5 : In what applications will you perform cable diagnostic testing?

Question 6.7 : If yes, please indicate / describe what testing techniques you use.

Survey Questions taken from 2009 survey results - Maintenance

Question 6.9 : In what applications will you perform cable diagnostic testing?

Question 6.10 : If yes, please indicate / describe what testing techniques you use.

6.5 - Flood Plan

6.5.1 - Energex

Operations

Flood Plan

People

The central business district of Brisbane is a flood-prone area, and Energex has historically had multiple experiences with CBD flooding. Energex has produced a comprehensive flood risk management plan that includes strategies for improving flood resilience in the CBD.

The plan was produced by a committee that was formed to specifically identify strategies for making the Energex infrastructure more resilient to flooding. The plan was guided by recommendations from a study performed by an external contractor to assist Energex in identifying flood mitigation options for the CBD.

Process

The plan includes guidelines such as:

Plans for identifying electricity assets that may be affected by a major flood, such as overlaying Energex network assets (from GIS) over a map of major flood risk areas.
A review of business continuity plans for key areas, such as the control center and stores and logistics.
Operational plans for critical infrastructure, such as installing sandbags/protective barriers to protect certain equipment in substations, and performing switching to shift load away from stations that are susceptible to flooding.
Plans for identifying dry disconnection switching points for flood-prone distribution assets.
Priority listing for performing preemptive disconnection and reconnection of certain critical assets.

Energex has implemented a number of flood resiliency initiatives including the following:

Raising facilities and implementing barriers at substations prone to flooding.
Documenting and prioritizing assets that should be disconnected and when in advance of a predicted flood event.
Identifying spots for generator connections around the network, and installing ground level connections for mobile generators at building vaults.
Sealing conduits to prevent flood waters from flowing through conduits and flooding normally dry vaults.
Installing remotely operated switches at wet/dry interface points around the system.

6.6 - Fuse Stick

6.6.1 - HECO - The Hawaiian Electric Company

Operations

Fuse Stick

People

The Fuse Stick is a home made device developed by the HECO Underground group as a tool for testing, grounding, and confirming that facilities are de-energized. See Determining a Feeder to be De-energized . The tool is used as supplemental tester to conventional testers. HECO developed the device because of a lack of confidence in conventional test devices, and because the fuse stick tester provides a quicker way to ground than applying a ground elbow.

Note that HECO is using conventional testers also, and that the fuse stick is used as a supplemental tester only.

Process

HECO crews will first apply a conventional tester, such as an AB Chance tester, to capacitive test points to determine whether or not a cable is de-energized. Note that their testers are outfitted with batteries, and are checked to assure they are working prior to each use.

Assuming that the Chance tester provides no reading, indicating that the circuit is dead, HECO will next apply the fuse stick. The “Ground End” of the fuse stick is grounded via a ground lead. The “Fuse End” is then touched to test point. ( If the circuit is energized, the fuse would pop.) Then the Fuse stick head is flipped over and the ground end is touched to the test point, grounding the feeder. This process is repeated at each test point (multiple phases for example).

Technology

Soldered end cap that would blow out and provide visible indication (Fuse End)

The Fuse Stick tester consists of an insulated stick with a 1 amp fuse mounted in the end. The one end of the fuse is fitted with a copper probe that is grounded by a ground lead (Ground End). The other end of the fuse is fitted with a conductive cap with a soldered end designed to blow out should the fuse blow (Fuse End). (See photographs below)

Figure 1: HECO Fuse Stick

Figure 2: HECO Fuse Stick (Grounded End)

6.7 - Incoming Materials Inspection

6.7.1 - Duke Energy Florida

Operations

Incoming Materials Inspection

People

Equipment standards are determined by the Network Standards group, in cooperation with the local (Duke Florida) and Duke Corporate Network Standards groups.

At the Clearwater supply and maintenance facility, Network Specialists test, maintain and rehabilitate network protectors and NP relays.

Process

Network Specialists acceptance test new network protectors as they arrive from the manufacturer. Duke Energy Florida underground experts feel this acceptance testing of new equipment is critical and noted that they had two new network protectors fail their acceptance testing in recent years.

Incoming cable and accessories are also spot inspected to identify failures.

6.7.2 - Energex

Operations

Incoming Materials Inspection

Process

In years past, Energex performed routine incoming equipment inspections for new materials coming onto their property. With the advent of ISO 9000, and Energex’s requirement that vendors comply with this standard, Energex has ceased these inspections, and instead relies on the supplier quality procedures for testing new materials. Incoming materials are accompanied by the results of this vendor testing. Some quality issues with a product identified by the field force would be addressed through procurement (e.g., receipt of a batch of cable with cracked insulation).

Energex has defined testing and commissioning procedures for installing equipment. For example, new cables are subjected to diagnostic (DC hi-pot for PILC, AC VLF for XLPE) testing, prior to energization.

Other examples of quality initiatives include the approval of all civil designs by a civil professional engineer, procurement of hardened materials, such as the purchase of an outer cable jacket that is resistant to termites, a common problem in Queensland, and the use of dry type transformers in the building vaults within the CBD.

6.7.3 - Georgia Power

Operations

Incoming Materials Inspection

People

The Network Underground group has a testing laboratory located at its centralized facility in Atlanta. The lab is managed by a senior engineer in the Network Underground group and staffed by Test Engineers and Test Technicians on an as needed basis. Network Underground Test Engineers, Test Technicians, and Network Engineers all have access to the network underground test Lab.

Process

The Georgia Power Network Underground testing facility is used to test network system equipment, cable, and failed components. The test lab also performs routine commissioning tests on certain incoming items, such as transformers and network protectors before they are rotated into stock or deployed in the field.

For example, when a new transformer arrives, Test Technicians perform TTR and Meggers tests, check the oil level and its dielectric properties, and then record the nameplate information including serial number into the Georgia Power GIS system before it is put into stock.

The lab is also used for testing of failed components as most forensic analysis is performed in-house. In the event a cause of a failed component cannot be determined, the Network Underground senior engineers may turn the failed equipment over to the manufacturer or send it to an outside, third-party analysis group, such as NEETRAC.

Technology

EPRI researchers were impressed by the tools, equipment, and orderly management of the testing facility.

6.8 - Load Shedding

6.8.1 - CEI - The Illuminating Company

Operations

Load Shedding

People

If circumstances require manual load shedding, the execution of the load shed is led by the RDO.

Process

CEI has pre-prioritized circuits and can initiate a rolling load shed of predetermined amounts of load, as required by the situation. The blocks of load included in this scheme are primarily served by the 13kV distribution system.

Network feeders are not included in this listing; consequently, network load is not included in manual load shed.

Similarly, the 11kV subtransmission system that serves the major load centers in downtown Cleveland is excluded from the manual load shed predetermined load groupings. Major customers may be sought out to voluntarily curtail loads in an emergency.

Technology

Using their EMS system, CEI can call for blocks of load to be shed on a rolling basis automatically, based on predetermined load groupings based on circuit priority.

6.8.2 - CenterPoint Energy

Operations

Load Shedding

People

If circumstances require manual load shedding, the execution of the load shed is led by the Energy Control Dispatch Center (ECDC).

Process

CenterPoint has prioritized circuits based on criticality. As required by the state of Texas, they have implemented a flagging system to prevent any inappropriate disconnect of critical customers.

Network feeders are not included in manual load shed listings.

Technology

CenterPoint can call for blocks of load to be shed on a rolling basis automatically, based on predetermined load groupings based on circuit priority.

6.8.3 - Con Edison - Consolidated Edison

Operations

Load Shedding

People

Con Edison has one main System Operations Control Center, and Regional Control Centers, such as the Manhattan Control Center.

The System Operations Control Center is the main operating authority, responsible for operating the system and for the protection of the workers for the entire Con Edison system. The System Operations Control Center controls and operates Generation, Transmission, and Distribution.

Technology

Con Edison has a scheme to shed load as the frequency drops or if the rate of change in the frequency exceeds a given threshold. The system prioritizes the feeders that it drops. For example, the scheme sheds overhead load first.

Con Edison has installed a network start-up and shutdown panel for picking up multiple feeders at one time in the event of the loss of an entire network. The panel brings the controls for all breakers to two points in the station, because stations are designed to service two networks. The panel is connected to the operator at the System Operations Control Center.

6.8.4 - Duke Energy Ohio

Operations

Load Shedding

People

At Duke Energy Ohio, load shedding is the responsibility of the Power Supervisor, within the Operations Center (made up of PS and the Trouble department).

Process

Duke Energy Ohio has established multiple priority levels for feeders to guide power supervisor’s in shedding load in an emergency.

Load shedding is done manually – Duke Energy Ohio is not using the software to automatically roll blocks of load at different time intervals.

Note that network feeders are excluded from manual load shed.

6.8.5 - HECO - The Hawaiian Electric Company

Operations

Load Shedding

People

If circumstances require manual load shedding, the execution of the load shed is led by the Dispatch Center.

Process

HECO has pre-prioritized circuits and predetermined load blocks for use in the event of a manual load shed. Circuit priority is based on key customers along a feeder such as hospitals, airports, military installations, etc.

The decision as to which load to shed will be made by the Load Dispatcher based on these priorities, and other factors such as the time of day.

Network feeders are not included in this listing; consequently, network load is not included in manual load shed.

HECO will also call on large customers to assist with load curtailments. Some of these customers receive discounted rates in exchange for the ability to shed their load in an emergency.

Technology

HECO sheds load manually, using predetermined blocks of load that consider circuit priority. They are not using software that automatically sheds load on a rolling basis.

6.8.6 - National Grid

Operations

Load Shedding

People

At National Grid, load shedding is the responsibility of the Regional Control Center.

National Grid has a written procedure that describes plans for shedding and restoring the network load. This document provides operating guidelines for a network load shed and restoration. The guideline includes network primary cable ratings, network secondary cable ratings, detailed descriptions of required operator action in contingency situations, detailed descriptions of the potential results of an various primary feeder contingencies on the network during peak conditions, and procedures the operator must follow in the event that the shedding of network load is ordered.

Process

Network feeders are excluded from National Grid’s normal manual load shed plans. National Grid has developed a separate plan to be able to shed the network load and pick it up. This involves opening the bank breakers at the two substations that supply the networks within Albany.

National Grid performs an annual tabletop drill focused specifically on the network. In addition, every five years it does a larger, more complex drill.

Technology

National Grid does not have a network group feeder switch that simultaneously opens or closes network feeder breakers. Rather, their procedure requires the opening of substation bank breakers in order to drop network feeder load simultaneously, followed by the opening of the individual breakers, then followed by the closing of the bank breakers to restore any radial (non-network) circuits. The procedure also describes switching to restore network load.

6.8.7 - PG&E

Operations

Load Shedding

People

At PG&E, load shedding is the responsibility of Distribution Operations.

Process

Network load is included in manual load shedding plans.

6.8.8 - SCL - Seattle City Light

Operations

Load Shedding

People

If circumstances require manual load shedding, the execution of the load shed is led by the System Operator.

Process

During high load conditions, the System Operator polls the network using the DigitalGrid (Hazeltine) system four or five times a day to understand field loading and voltage conditions.

SCL System Operators maintain a list of customers that are fed by each network feeder so that they can contact customers to curtail load during critical periods.

SCL’s procedures for responding to network emergencies are not formally documented. SCL does not perform regular drills to practice restoration procedures to the network. Note: SCL does document and drill restoration procedures for outages to the non-network parts of their system. These drills normally exclude outages to network facilities.

Technology

SCL has installed a system developed by DigitalGrid, Inc. (formerly Hazeltine, and referred to by SCL employees as “the Hazeltine System”) to monitor their network equipment. This system uses power line carrier (PLC) technology for communication. (Communication signals are sent through existing utility power cables) SCL has been using this system for years, and has some degree of remote monitoring in all network vaults.

Operations Practices — Vault / Network Fires

SCL’s current design standard calls for fire protection heat sensors and temperature sensors in their vaults. The heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225°F. The temperature sensors send an alarm to the dispatcher at 40°C. (SCL utilizes temperature sensors in about 20% of their network transformer locations. They are actively adding locations, with a goal of 100% coverage.)

SCL does not have a written procedure for responding to a vault fire. Although their operators do have the authority to drop load in an emergency, they do not have a protocol to guide them as to whether or when they should drop load in response to a fire.

Note that because of the “sub-network” design, with each secondary network completely separated from the other, a complete network outage due to a fire would be limited to the customers served by that one sub-network, with the other networks unaffected.

6.9 - Network Protector Fuse Test

6.9.1 - Duke Energy Florida

Operations

Network Protector Fuse Test

People

Maintenance of network protectors are performed by craft workers, Network Specialists and Electrician Apprentices, within the Network Group, part of the Construction and Maintenance Organization. The Network Group is led by a supervisor, and consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position).

Process

Before network protectors are returned to service they are checked for back feed current on all connections in and out of the network protector using a one-amp fuse.

6.9.2 - Duke Energy Ohio

Operations

Network Protector Fuse Test

People

When a network feeder is out of service, Duke Energy Ohio will perform a network protector fuse test to identify any potential faults or grounds on a primary feeder before re-energizing the feeder at the station breaker. The test will confirm that all transformers on a feeder have been switched from the ground position to closed position.

The network protector fuse test is performed by Network Service persons.

Process

Duke Energy Ohio is using a network protector fuse test to identify a fault or ground on the primary system before closing the feeder breaker.

They will identify a vault location housing a network protector where it is safe to work. They will remove the network protector fuse and replace it with a smaller fuse, normally a 500 amp fuse. They will then manually close the protector, thus energizing the primary through the network protector and transformer. If there is a fault or ground on the primary, this test will pop the smaller fuse.

Figure 1: Network Protector – With small fuse links

Duke Energy Ohio performs this test to save the wear and tear on the substation breaker that would be caused by closing into a fault. The fuse test was developed at a time when test instrumentation was difficult to use and not portable.

6.9.3 - Georgia Power

Operations

Network Protector Fuse Test

See Network Protector Maintenance

People

The Georgia Power Network Underground group has two full-time Test Technicians responsible for Network Protector Testing and Maintenance who report to the Network UG Reliability Manager of the Network Operations and Reliability Group.

Process

When they are putting a network protector back in service, Georgia Power does not perform any sort of a “fuse test” in the protector, such as placing a low amperage fuse in the protector so that if there is a problem, the fuse will open. They don’t like the idea of exposing a worker to that condition. Their process is to close the network protector remotely - if there is a problem on the system, the worker would be out of the hole. Note that they are examining other options for safely closing protectors such as a device (by EDM) that uses timing to check for proper phasing.

6.10 - Operations Practices - Clearances

6.10.1 - AEP - Ohio

Operations

Operational Practices - Clearances

People

The Distribution Dispatching Center is responsible for operating the distribution systems, including granting clearances for Network Mechanics to perform work activities on a feeder. The Dispatch Center coordinates closely with the Network Mechanics who report out of the Network Service Center to operate the network system. The Dispatcher is responsible for operating feeder breakers at the substation, but has given Network Mechanics authority to operate feeder devices beyond the station, such as opening the HV switches on the network units to clear a feeder.

Process

Work crews, in cooperation with the Dispatcher, are authorized to clear feeders and open network protector switches and primary transformer switches. Worker clearances are established by establishing perimeter (bracket) grounds at the nearest three transformers to the work site.

Because AEP Ohio’s new standard for the network unit includes the use of a separate (from the transformer tank) wall-mounted primary switch, such as an Elastimold MVI, workers can often obtain a clearance to work in a particular location without having to de-energize and clear the entire feeder.

In these cases, the worker notifies the dispatcher and can remotely operate the switch, which is a load break device, from outside the hole. If the protector does not open automatically, the worker can remotely open the protector from outside the hole as well. The worker can then test and ground the primary feeder feeding into the transformer and proceed with the work. Grounding is done with a grounding feedthrough tied to ground. Note that for 480-V NPs, workers have the ability to create a visible break between the protector and the secondary bus by operating disconnects mounted on top of the protector. Separating the secondary avoids the potential for arc flash from inadvertent contact with the secondary system.

AEP employees cite the ability to de-energize the primary supplying any one network vault as a key benefit of the use of the separately-mounted switch. Specifically, it avoids the process of obtaining and clearing an entire feeder, which requires advance notice to the dispatcher and entails a visit to every network unit location to verify as open and ground, and it enables them to maintain N-2.

In many cases, existing infrastructure is designed with the network unit primary switch integrated into the transformer. In these cases, after assuring that the protectors are open, the Network Mechanic will place the transformer switch in the ground position.

AEP Ohio works with two primary switch configurations: wall-mounted Elastimold (see Figures 1 through 4) and transformer-based switches. Wall-mounted switches can be remotely closed. In some cases, Network Mechanics install 200-A elbow grounds on the back of the 600-A termination, with elbows bolted to the ground ring at the bottom of the vault. Transformer-mounted switches are put into the ground position after making certain the protector is in the open position (either manually or automatically). If the crew is working with an MVI or SF₆ switch, they check the protector, pull the caps off the back of the transformer, perform a test to determine that it is de-energized, and then put the grounding in place.

Figure 1: Wall-mounted Elastimold MVI switch – network vault

Figure 2: Wall-mounted Elastimold MVI switch – note grounding bar

Figure 3: Wall-mounted Elastimold MVI switch – network vault

Figure 4: Disconnects on top of protector

6.10.2 - Ameren Missouri

Operations

Operation Practices - Clearances

People

At Ameren Missouri, the steps for clearing a network feeder involve the dispatchers within the System Dispatch Center and Traveling Operators, part of Reliability Support Services.

The Traveling Operator position is responsible for performing switching within the network vaults (including operating both the primary disconnect switch on the network unit and the network protector), at the substation for network feeders, and for operating customer switchgear. In addition, Traveling Operators may perform overhead work using an Extendo stick. (Traveling Operators do not use bucket trucks).

Organizationally, Traveling Operators work in the Distribution Operating group, part of the Reliability Support Services group and work closely with the Service Test group, also part of Reliability Support Services. They provide 24 x 7 coverage. The Distribution Operating group has a support engineer assigned to provide support to the Traveling Operators.

Ameren Missouri has a 20 week intensive training program for Traveling Operators to become qualified.

Process

Ameren Missouri’s clearance process involves the preparation of a switching order, called Workman’s Protection Assurance (WPA), by the dispatchers within the SDC. Dispatchers have prepared pre-defined orders for both normal and emergency switching in the network. These predefined orders serve as templates and provide a starting point for the dispatcher to prepare specific switching orders per request.

The SDC uses a triple check process when preparing a switching order (WPA).

Step one is writing the order, performed by the SDC dispatcher.
Step two is that someone else within the dispatch center checks the switching order.
Step three is a check by the dispatcher who issues the order to the Traveling Operator to perform the switching. Note that this may be a different dispatcher than the one who wrote the order.

The traveling operator who receives the order is, of course, a fourth check of the accuracy of the order.

The individual steps associated with the orders for network clearances are not delivered one at a time from dispatcher to traveling operator. Rather, all of the switching orders to clear a network feeder or feeder section are turned over to the traveling operators for execution. As traveling operators move from hole to hole, they don’t communicate routinely with the dispatcher in every hole. Rather, they will contact the dispatcher at various points during the switching to notify the dispatcher of their progress.

Traveling operators will perform the various tasks associated with clearing a feeder, including racking out the feeder breaker, racking in a test breaker if required (for fault location, for example), testing for potential using phase sticks, operating transformer primary switch handles within each network, operating network protectors if required for the clearance, and placing required clearance tags.

Figure 1: Transformer Primary Switch Handle

Figure 2: Transformer Primary Switch Handle – note phase positions

Figure 3: Test Breaker

As the traveling operators perform switching, they place appropriate clearance tags, such as Holdoff tags and Grounding tags. At the station they use a Racking Holdoff tag, which enables the breaker to be racked into the test position, but not back onto the bus. They also use information tags (Blue tags) to notify others of pertinent information.

Note that entering a network vault to perform switching is a two person job at Ameren Missouri, with one person in the hole, while the other is up top (above the hole).

When a traveling operator finds a problem within a vault, they will document the problem on a Network / Radial Vault Entrance and Condition form. Substation problems are reported on a Substation Maintenance Request form.

If a cleared feeder has been separated for some reason (for example, because cable splices have been installed to repair a failed cable section), the traveling operators will check the feeder phasing before restoring the feeder to service.

They do this by going to a transformer location and moving the switch handle into the ground position. Back at the substation, an operator will hook up a home developed annunciator device called a rabbit cage. This device uses a DC supply and has indicator lights which illuminate when the cable legs are grounded. So, when the transformer switch is in the ground position - all of the lights on the rabbit cage will be illuminated.

Ameren Missouri transformers have phase positions on their transformer switch handles (part of their transformer specification). To check phasing, the traveling operator will begin with the transformer switch in the ground position and assure that all of the lights on the rabbit cage are illuminated by checking in with the operator at the substation. The traveling operator will then move the switch handle to each phase position and check with the attendant at the substation to assure the appropriate light for that phase on the rabbit cage goes out. In the first position, the C light should go out, then the B light, and finally the A light, indicating that the phasing at the transformer matches the phasing at the station.

Ameren Missouri performs this test twice before confirming phases. They will perform this phasing test before restoring a feeder even if only one cable was spliced, just to be sure there weren’t inadvertent other changes made to the system.

Note that sometimes, traveling operators will “give phases”. For example, a cable splicer may want to determine the appropriate phases to mark the cable phases before completing a splice. In this case, traveling operators at the station will ground a phase at the station, and the cable splicer will apply a set of test lights similar to the rabbit cage in the vault to assure that they illuminate on grounds.

Note that if a transformer and protector are replaced, the Dist Service Testers will assure phasing on the secondary side.

Technology

Traveling operators utilize mobile data terminals in their trucks to access the mapping system.

Traveling operators will don a 40 Cal arc suit, which is a lab coat style with shin covers to perform certain activities such as testing for potential using phase sticks.

Figure 4: 40 Cal Arc Flash Suit

Figure 5: Testing for potential with phase sticks

When using the test breaker, traveling operators will test for potential using phase sticks to assure that there is no back feed from hung up protectors.

Traveling operators utilize a home developed annunciator device called a “rabbit cage” to check the feeder phasing before restoring a feeder to service.

Figure 6: Connecting the Rabbit cage to the Test breaker

Figure 7: The Rabbit Cage – used to test for phasing

Figure 8: The Rabbit cage connected to the test breaker

6.10.3 - CEI - The Illuminating Company

Operations

Operation Practices - Clearances

People

The DSO’s within the RDO are responsible for issuing clearances, subject to FirstEnergy’s Clearance Procedure Manual of Operations. The Manual defines procedures and responsibilities associated with requesting and obtaining clearance.

FirstEnergy has produced an “Excerpts from the Manual of Operations” booklet that serves as a useful reference and training guide.

The RDO has produced a “Network Switching Guidelines” document which describes procedures for clearing the primary feeders that provide the secondary network. This document includes pre-written switching steps to “clear” the network system in the event of a fault, to establish an issue clearances for the network primary feeders, and to establish and operating condition for the network feeders once a fault location has been identified, allowing the Person in Charge to perform agreed to work on the system. See Attachment T

Further, the RDO has created pre-written switching instructions for every vault in the 11 kV non-network system serving the main load centers in downtown Cleveland.

When UG crew leaders request an outage of a network feeder, they submit a clearance request to the RDO. This process, as well as the required timeframes for initiating the request, is defined in the FirstEnergy Corp Manual of Operations.

CEI uses Outage Coordinators, who are responsible for reviewing this request and preparing and coordinating the necessary clearances on an advance basis. Ultimately, the DSO orders the required switching and tagging for the clearance. Network clearance steps are pre-written in the Network Switching Guidelines.

Process

CEI requires a “visible break” as part of their clearance procedure. For example, when clearing a network feeder, the feeder will be opened and the breaker racked out and tagged, and all network protectors will be placed in manual open, and tagged. CEI will also operate the disconnect switch on the network transformer primary, moving it to the open position. The transformer switch is not tagged because it is in the clearance zone created by the clearance tag at the protector.

An exception to the visible break requirement is the 5 kV oil switch (not used in the network feeders) which does not provide the visible break.

Technology

Procedures are documented in E Net system. Manual copies of procedures are made available to those that require them.

6.10.4 - CenterPoint Energy

Operations

Operation Practices - Clearances

People

Distribution dispatching is housed within the CenterPoint Energy Control Dispatch Center (ECDC). This facility also houses the Regional Transmission Operator (RTO) desk.

The RTO will issue orders to open and tag feeder breakers at the substation. This switching is executed by Substation Operators.

Distribution Dispatchers focus on the switching of the distribution system beyond the substation breaker. Distribution Dispatchers are assigned responsibility for certain territory by service center. CenterPoint has twelve Service Centers, and assigns one or two dispatchers per service center. A normal day shift will employ a minimum of 14 dispatchers.

The Distribution Dispatch Center provides switching orders for all devices beyond the substation breaker. Note that while the Dispatcher will prepare switching orders and issue clearances for major underground feeders, the execution of the switching on the feeders is led by Major Underground resources.

In Major Underground, all crew members are eligible to perform switching. In performing switching, Major Underground will assign one person on the crew (usually the head journeyman) to interface with the Dispatcher to complete switching. This person will assign the various switching tasks to other members of the crew – but he will service as the point person to interface with the dispatcher. CenterPoint decided to conduct switching in the Major Underground this way because of difficulties communicating from dispatching to resources in each of the manholes, the fact that in obtaining an UG clearance, the devices do not have to be opened in a particular sequence, and most of the feeders supplying the networks don’t have any tie points.

Process

When UG Crew Leaders request an outage of a network feeder, they submit a clearance request to the ECDC. Note that for the “dedicated” circuits in Major Underground, the Distribution Dispatcher prepares switching orders to clear the circuits from pre-written templates maintained by the GIS group with Major Underground. This pre- written order indicates what locations and devices the switchman must visit to execute the switching. In preparing the job specific switching order, the dispatcher updates the pre-written template with what specific work must be accomplished at each location. For example “open”, “close”, “verify”, etc. The Dispatcher will review the switching order against the mapping system to verify its accuracy.

The Distribution dispatcher coordinates with the RTO to open and tag the feeder breaker. After obtaining a hold order from the RTO, indicating that the circuit has been opened with a visible break and tagged, the Distribution Dispatcher will coordinate with the head journeyman on the Major Underground crew who will act as a liaison between the Dispatcher and the field crews who will perform the switching. The crew will verify the feeder breaker as open and ground the circuit.

Then the switching will be performed to isolate other potential sources (ex: open and tag the network protectors). Note that all of this switching is performed and controlled by the head journeyman of the crew

not by the Dispatcher. The Dispatcher will record the Start time on a running switching order; however, the dispatcher does NOT read each line of the order to the switchman as they do in overhead. The crew members will report back to the head of the crew when the switching is complete.

After he has received confirmation from his crew members that the work is complete, the head journeyman of the crew completes the order to the dispatcher who verifies the circuit as dead by checking the circuit loading.

CenterPoint requires a “visible break” as part of their clearance procedure. All vaults must have a place to create a visible disconnect, either a blade that is open that a crew member can see, or an elbow that is parked. Before a CenterPoint crew will “check for dead” and ground, there must be a visible disconnect to every point feeding that cable.

Technology

Procedures are documented on line. Manual copies of procedures are made available to those that require them.

6.10.5 - Con Edison - Consolidated Edison

Operations

Operation Practices - Clearances

People

Operations Control Centers

Con Edison has one main System Operations Control Center, and Regional Control Centers, such as the Manhattan Control Center.

The System Operations Control Center is the main operating authority, responsible for operating the system and for the protection of the workers for the entire Con Edison system. The System Operations Control Center controls and operates Generation, Transmission, and Distribution.

Employees called District Operators (DO’s) report to the System Operations Control Center. District Operators work in shifts (several DO’s per shift), and provide 24-hour a day, 7 days a week, 52 weeks a year coverage. District Operators have exclusive operating authority and control of all distribution feeders, including circuit breakers within the substation, and all equipment and cable runs up to and including the points of termination in the field. District Operator operating authority includes issuance of approval for status change, application of protection, and issuance of work permits and test permits on distribution feeders. (Distribution feeders include all network feeders and all non-network “cable” feeders including aerial cable, and some open wire on 33 kV in Staten Island.)

Con Edison network workers (in the Work Out Centers or in the Field Operating Department [FOD]) don’t place and check their own protection; they rely on the District Operator. Con Edison has a methodical, tightly controlled clearance process, where the District Operator (DO) directs the activities to provide clearance on a feeder. If field personnel encounter a situation that doesn’t match what they expect to find, or if there is any lack of clarity in the clearance steps, the job stops immediately.

The Regional Control Centers interface between the System Operations Control Center and the Work Out Centers to get the work done. Following a strict protocol, after fault location, positive feeder identification and application of protection, the District Operator at the System Operations Control Center delegates the responsibility for work on cable or equipment to the “Feeder Control Representative” in a Regional Control Center. Again, following strict protocols, the Feeder Control Representative “signs on” each work crew at each work location and “signs them off” after they complete or partially complete their assigned work. When all work is completed and all workers are signed off, again following a strict protocol, the Feeder Control Representative reports the work completed and all sign-off’s to the District Operator, who then takes back full control of the distribution feeder, orders it tested, prepared for service, and finally orders it restored (cut in).

Overhead feeders (open wire, bare wire, tree or covered wire, and self-supporting wire) plus underground radial spurs fed from the overhead wire are under the control of the appropriate Regional Control Center. Strict but different protocols are followed for those feeders as well.

Process

When Con Edison takes a feeder out of service to perform maintenance or construction, the utility does not “block and lock” the network protectors on the feeder. That is, they do not manually open the protector breaker or remove the protector fuses. Note that the utility also does not open a primary switch at the transformer, because Con Edison’s transformer specification does not call for a disconnect switch at the transformer primary.

This approach differs from the approach employed at many utilities, where crews visit every network protector, open up the secondary, and remove fusing before working on the de-energized circuit.

Con Edison’s process is to:

Open the feeder.
Ensure no back-feed from the back-feed indication that they have at the source. (Back-feed indication is a neon indicator at the breaker panel.) If the indicator at the station does reveal back-feed, crews visit the specific network protector or other source to resolve the issue.
Ground the feeder at the station.
Ground on either end of the work zone (all potential sources).
Do the work.

Con Edison believes that this process addresses all potential energy sources. They have never had a problem with this approach.

Why the difference in practice? One reason as that the very size of their system requires lengthy circuits with many transformer and network protector locations on each circuit. This high number of locations, combined with the potential to have to pump water out of the holes, makes it impractical to visit each location, pump it free of water, and block and lock the protectors. And, their current approach provides a completely safe, grounded work environment.

6.10.6 - Duke Energy Florida

Operations

Operations Practices – Clearances

People

Clearing a network feeder involves close communication between the dispatchers in the DCC and the Network crews. Network crews take clearances on feeder cables in the field through a process defined by Duke Energy Florida’s Switching and Tagging manual. All who perform switching must be on the company’s switching and tagging list. The DCC maintains the approved list.

Network Specialists are qualified to perform the tasks associated with taking a clearance, and Electrician Apprentices are trained as a part of their on-going OJT. Electrician Apprentices who received the required training and are on the switching and tagging list, can perform switching and hold clearances.

Process

To initiate a clearance of a feeder, a clearance authorization is required. A Network Specialist or Supervisor within the Network Group will prepare a switching request where he will detail the steps to clear the feeder. Alternatively, a Dispatcher may prepare the initial listing of steps based on the clearance required. The switching request is then forwarded to an experienced dispatcher (a second dispatcher in the case where a Dispatcher prepared the initial listing of steps) who will review the steps and assure that they are correct. The reviewed version of the switching request is then sent back to person who created the initial listing. Finally, the switching steps are send back to a Network Specialist in the Network Group – the requester of the clearance - for final approval.

To clear a feeder, after opening the feeder breaker, Network Specialists will visit each vault on the feeder, open all network protectors, and also open the high side switches suppling the transformers in each vault. They will do this at every vault on the feeder or de-energized section of the feeder. Note that Duke Energy Florida does have primary sectionalizing switches installed on their network feeders. Where possible they will operate these switches to isolate the section to be de-energized. In these cases, they will visit every vault on the de-energized portion of the feeder to open the protectors and high side switches. The use of the sectionalizing switches reduces the number of vaults they must visit to clear a feeder section.

The steps associated with taking a clearance on a feeder section including switching to open the feeder on both sides of the work area, certifying the cable section as dead, tagging and grounding.

Switching is performed by crew members with field direction from the Network Specialists. Crew members carry a switch book where all switching orders are written down. The switching orders will identify all of the switching steps including:

Who performs the switching
What device is operated
Where the location of the device to operate is located
When will the device will be operated (in operational order)

Each step associated with the switching and tagging is communicated between the dispatcher and person doing the switching using three-way communication. The crew member will record what the dispatcher tells him verbatim in his switch book and then he will read the information back to the dispatcher. After the crew member has read the switching step to the dispatcher, the dispatcher will confirm that it matches what is on his switching order. Only after confirmation, the dispatcher will issue the clearance number and allow the crew member to operate the device. For prearranged switching, the dispatcher and switchman may review a series of switching steps using this process. When the switchman receives authorization, he will then complete the steps. He will not contact the dispatcher at every step unless there is a discrepancy.

To assure the cable section in question is de energized, Network Specialists enter the manholes at each end, check the feeder cable’s duct position, make certain they match on each end, and apply a pulse tone on the cable with an external, battery-operated tone generator on a single phase of the feeder. Once the de-energized feeder is confirmed, a remotely operated hydraulic spike is used to pierce the cable to ground.

All switchers must be on the approved switching and tagging list. Every two years, all Network Specialists and Electrician Apprentices take a switching and tagging procedure training course.

Another standard safety procedure prior to entry into a manhole/vault is to establish a protection “hotline.” The “hotline” is a safety setting in the network protector to cut down the instantaneous trip from the normal setting of 30 cycles down to 6 cycles. The “hotline” clearance is tagged to the crew leader, who designates the person working in the hole as an alternate clearance holder.

Technology

Duke Energy Florida uses an Access Data Base to facilitate the clearance authorization process. Switching requests are entered into this system, and approved.

Before network protectors are returned to service they are checked for back feed current on all connections in and out of the network protector using a one-amp fuse.

6.10.7 - Duke Energy Ohio

Operations

Operation Practices - Clearances

People

The steps for obtaining clearance of a network feeder are performed by a combination of the Dana Avenue underground group, and Mobile Operators who are part of the Substation department.

Dana Avenue underground resources are trained to do switching, and are on the Duke Energy Ohio Switching and Tagging list. Switching is performed by either Senior Cable Splicers or Network Service Persons.

For most of the distribution system, the Trouble Department takes care of required switching at night, operating devices and placing tags, so that when the crews arrive in the morning, they can place grounds and begin working immediately. Mobile operators do this switching within the substation.

For the network distribution system, field switching and tagging is performed by the Network Services persons within the Dana Avenue underground.

Process

For a scheduled outage, Dana Avenue Underground personnel will complete an outage request form. The outage request form includes the date and time of the outage, the name of the “tag person”; that is, the person who would be doing the bulk of the work and in whose name clearance tags would be placed. The request also includes a “counter tag person”, generally a supervisor, who is the person to contact in case of a schedule change. Sometimes the request will also include the person who will do the switching (either mobile operators or Dana Avenue switchers). The outage request will also ask for the specific clearance requirements, including requesting grounding to create isolation. (The request may ask for a “Hold”, which is a one sided isolation, where a major customer performing the work would have to provide their own isolation on their end.)

Normally a five day lead time is required for a distribution outage to a network feeder. The outage request is sent to two T&D Operations Coordinators, who are the individuals who write the actual switching orders. Next, the request goes from the Operations Coordinators to the Power Supervisor (PS).

Dana Avenue supervision will monitor requests for scheduled feeder outages that may originate with the Substation group, so that they can take advantage of the outage to perform any pending corrective maintenance or refurbishment.

Emergency clearance requests are normally coordinated through the Trouble Desk and PS.

For work on a network primary feeder, Dana Avenue underground crews will open up the network transformer primary disconnect switches as part of their clearance process. For secondary work, they may not open the transformer primary.

When racking out a network protector breaker, they will take a primary feeder outage. Before racking out the breaker to do the work, they will open up the primary disconnect and put it in the open position.

6.10.8 - Energex

Operations

Operation Practices - Clearances

People

Energex has 22 staff members called switching coordinators who operate its central control center on rotating shifts. Switching coordinators are responsible for issuing clearances for distribution system work. The people in the control center rotate their positions on a regular basis, and any operator can monitor and/or control any segment of the Energex power grid, including the CBD underground network.

Switching coordinators are typically drawn from field staff ranks, usually either substation technician or mechanic and rapid response, with training specifically for the control room operation.

Process

Switching coordinators are responsible for issuing clearances on lines. If clearance is needed for a low-voltage line, the LV coordinator on duty in the control center issues the clearance. However, if a clearance of a medium or high voltage portion of the system is required, the clearance is issued by a switching coordinator.

Technology

Energex uses its Distribution Management System (DMS), Power On, to reflect switch position changes in real time. The system is either updated automatically for all telecontrolled or telemetered equipment, and manually by the control room operators for non telemetered or non telecontrolled equipment, so that the DMS reflects the actual real time, switched state.

6.10.9 - ESB Networks

Operations

Operation Practices - Clearances

People

Network operations at ESB Networks, including issuance of working clearances on medium voltage distribution lines, are performed by Operations Managers and Customer Service Supervisors, part of the Operations Group. ESB Networks has a Customer Services Supervisor for each of its 35 MV geographic areas. Organizationally, the Operations group, part of Asset Management, is comprised of two Operations Management centers, one North and one South, a System Protection group, an Operations Policy group, and a Systems Support group.

ESB Networks has two central operations centers, North and South, but it is soon moving to a single central control center.

Process

Clearance for any emergent line work must go through the Operation Centre. The clearance process is called “Telemess”, and involves a rigorous formal process for executing the switching and proving the readiness of the system. The process includes the request, proof of disconnect (such as through a technique such as cable spiking) and proof of readiness. The proof of readiness is a separate written document communicated at the conclusion of the switching that articulates the end results of the switching that are relevant to the clearance holder.

Planned outages are formally requested using an online request system. For some requests, particularly at HV, an outage planner will perform a study to assure that the system can manage the outage, that other outages will not affect the planned outage, and to develop the outage load transfer plan which defines the switching stems necessary to provide the outage. For this reason, planned outages and requests for clearances are avoided during peak demand periods.

Operators can remotely open the specified circuit through the SCADA system, or issue orders to field operators to perform the required switching. Note that within the Underground section, ESB Networks has operators who utilize small map boards that replicate the downtown underground network , and reflect the condition of the system manually using push pins (similar to the electronic version used in the control room for the rest of the system) (see Figure 1).

Figure 1: Map board used by ESB Networks operators to reflect conditions in the underground network

The term Telemess is derived from the use of telephone messaging to issue the clearance to the field worker or operator who will perform the work. (see Figure 2).

Figure 2: Telemess form used for switching for clearances

Figure 3: Electronic view of the system

6.10.10 - Georgia Power

Operations

Operation Practices - Clearances

People

Engineers in the Network Operations and Reliability Group are responsible for operating and monitoring the network system. This group is led by a manager, and is part of the Network Underground group, a centralized organization for managing all network infrastructure at Georgia Power.

The Operations and Reliability group has seven engineers on staff, responsible for the following:

Monitoring the network through the SCADA system.
Requesting and confirming de-energized feeders for maintenance or during failures.
Re-routing power to alternate feeders and/or networks in case of failures.
Serving as first-responders to customer service interruptions.
Part of the design phase for new networks or new major customer service.
Part of network protector selection (standards).
Responsible for the network system SCADA (remote monitoring and control) design and operation.

The Engineers, called Test Engineers, are four-year or two-year associate-degreed engineers. Test Engineers are responsible for network system operation, and work closely with maintenance crews, Test Technicians, Key Account) representatives, and the Distribution regions (Non – network operations) of Georgia Power.

The Georgia Power Network Control Center (part of Network Operations and Reliability) works closely with the Distribution Control Center (non – network) to clear a network feeder. The Network Control Center is responsible for obtaining a clearance for opening any network feeders (during emergencies, maintenance, routine inspection, etc). The Distribution Control Center, responsible for monitoring and controlling the breakers of the dedicated primary feeders that supply the network, issues clearances to the Network Operations and Reliability group.

Process

All requests for clearances for work to be performed on the network must come through the Network Control Center. Note: If the work to be performed is civil in nature, and will not require handling of cable and cable accessories, no clearance is necessary.

The following steps are taken to obtain a feeder clearance (For example to perform transformer maintenance):

The crew to perform the work confers with the Network Control Center, indicating the feeder that must be de-energized.
Operations personnel will check the status (through the remote monitoring system) of all network protectors at the locations to be affected to assure that de-energizing the feeder will not drop customers, or to identify those who will be affected.
Network Operations will then call the Georgia Power Distribution Control Center to open the designated feeder. The DCC will check to confirm that the feeder is clear. Network Operations can also verify that the protectors have opened. The DCC will tag the feeder, and issue a clearance to Network Operations to test for voltage, ground and work on the feeder. Note that a feeder clearance involves opening and grounding the feeder at the station, but not going into every vault and isolating the feeder from the network. Field crews may ground transformers adjacent to a work location to establish temporary working grounding.
Work can begin when field crews verify that the feeder is de-energized. (See Determining a Feeder is De-Energized ).

Technology

The Network Control Center has online access to remotely control network protectors, and gather information from the protectors, such as voltage, current and status (open or closed). The control center works closely with field crews to identify and confirm feeder information using maps and feeder tags.

6.10.11 - HECO - The Hawaiian Electric Company

Operations

Operation Practices - Clearances

People

HECO has a C&M Planning group that is focused on setting up the job packages and scheduling the work to be performed. This group is also responsible for submitting “Holdoffs”, HECO’s term for requesting a feeder clearance.

The C&M Planning group is comprised of 7 people, with one resource focused on the underground.

Switching orders are prepared by Load Dispatchers within the System Operations Dispatch Center.

Switching orders and the placement of tags are executed by the Primary Trouble Men (PTMs).

Process

When UG crews require sectionalizing of a feeder (for a feeder outage, for example) they work through the C&M Planning group to request the switching orders. The C&M planning group prepares and submits a “Holdoff” request to the System Operations Dispatch Center. System Operations requires at least 7 days in advance to write the switching orders.

Switching orders are prepared by Load Dispatchers within the System Operations Dispatch Center. Switching orders and the placement of tags are executed by the Primary Trouble Men (PTMs). Note that the Holdoff Tag can be used to either show that a line is isolated or grounded.

Figure 1: Holdoff Tag placed on Transformer Primary Switch

HECO’s Underground system is designed to N-1. Most work on the underground system can be performed safely by switching customers to alternate feeders / feeder sections, enabling the normal feeder to be de-energized without disrupting service to customers. However, this approach often requires significant switching steps to isolate the section to be de-energized. See “Three Phase Transformer Change outs – Hot Cap Procedure” as an example. The number of PTM’s available to perform the switching is often the limiting factor in the amount of
holdoffs that can be requested for any one week.

6.10.12 - National Grid

Operations

Operation Practices - Clearances

People

National Grid has a Regional Control Center (RCC) responsible for their Eastern Region in eastern New York. This region is broken into four control areas, by geography with a separate control desk for each area. One control area (Capitol) includes the city of Albany, and thus control of the network. National Grid does not have a dedicated operator focused solely on the network – the operator responsible for the Capitol control area has responsibility for both network and non network infrastructure.

Each control desk within the RCC is manned by a Regional Operator, responsible for both load dispatch and trouble dispatch for that area. Regional Operators provide switching orders to direct switching and tagging, issue clearances, and direct restoration activity. Regional Operators work 12 hour shifts each, and provide 24/7 coverage. The Regional Operator position is a bargaining unit position at National Grid.

If switching is required for a project, the supervisor within the underground organization is responsible for submitting an application, called a transmission outage application (TOA) to the Outage Coordinator within the regional control center. The Outage Coordinator assigns the writing of the switching order to a regional operator.

Substation operators are responsible for performing switching and tagging at the substation, including network feeders.

Network switching is only performed by the underground organization. Switching to clear a network feeder is normally performed at night so that the feeder is cleared before the start of the next workday. The underground supervisor would schedule switching crews to report to work at two or three in the morning to accomplish the switching.

National Grid has a well-defined clearance procedure in their electric operating procedures (EOP).

Process

National Grid’s normal required lead time to submit a TOA is three days prior to needing the feeder cleared. However, for network projects, the underground group often provides extra lead time – up to several weeks in some cases. The supervisor who prepares the TOA request will identify the clearance points to facilitate the writing of the formal switching order by the regional operator.

The RCC operators prepare the switching orders to clear a network feeder. The RCC does not use templates for network switching orders, as they want to assure that the operator is thinking through the process. The switching order includes orders to go into each vault to clear the network protector and transformer primary switch. The Regional Control Center Operator issues switching orders using National Grid’s s formal documented switching process.

In general, substation operators perform all switching in the substation including the placing of tags. Switching on the network system is only performed by the underground crews who are part of New York Underground East.

Note that the regional operator will provide the switch men multiple orders associated with a given vault. For example, if the switching order requires the man to enter a vault and open up two network units, both of these orders will be given at one time to prevent the switchman from having to come out of the hole after switching the first unit to receive orders to switch the second.

National Grid does require a visible open for a clearance point. Network protectors and network transformer disconnect switches are an exception to this rule. When National Grid clears the feeder, underground crews (Maintenance Mechanics) go to each vault to open and lock open all network protectors, and open and lock all transformer primary disconnects.

Technology

National Grid has remote monitoring and control of network feeder breakers at the substation. National Grid does not have remote monitoring and control of the network.

Note: National Grid is planning to pilot a network remote monitoring system as part of their network secondary distribution system strategy.

6.10.13 - PG&E

Operations

Operation Practices - Clearances

People

The steps for obtaining clearance of a network feeder may be performed by a combination of the distribution operators, cable crew foremen, cable splicers, cablemen, and substation resources.

Distribution operators will issue clearances of network feeders.

In Oakland, the distribution operators use substation resources to open breakers or confirm them as open and place grounds. A cable crew foreman will observe this and accept the clearance by reporting the placement of the grounds to the distribution operator. (Note that in Oakland, a journeyman cable splicer is normally upgraded to a cable crew foreman in order to obtain the clearance.)

In San Francisco, the cable crew foreman, part of the M&C electric network group, will both place the grounds and accept the clearance.

Additional steps for clearance depend on the work to be performed. Cable splicers or cablemen may be utilized to perform additional sectionalizing as required.

Process

In Oakland, network feeder clearances are scheduled for the daytime, and may last for a week, as the Oakland networks are lightly loaded. In San Francisco, network feeder clearances are scheduled for the night time, and are normally returned to service by the next morning. This avoids traffic issues, and takes advantage of the lower loading at night.

For a scheduled outage, a project coordinator who works within the M & C Electric Network group will request a feeder clearance from the distribution operator using an electronic clearance request form. This form describes which feeder is to be cleared, and the time. Normally a seven day lead time is required for distribution outage to a network feeder. The distribution operator will write the actual switching order. The dispatcher does have pre-planned switching orders prepared for common clearances. Switching orders are sent back to the requestor for conformation.

PG&E attempts to complete all switching before the crews arrive for work. Network circuits are normally opened by the distribution operator via SCADA. The distribution operator will confirm that all network protectors have opened through the remote monitoring system before giving orders to place grounds.

In Oakland, the distribution operators use substation resources to open breakers or confirm them as open and place grounds. A cable crew foreman will observe this, and accept the clearance by reporting the placement of the grounds to the distribution operator. In San Francisco, the cable crew foreman, part of the M&C electric network group, will both place the grounds and accept the clearance.

Additional steps for clearance depend on the work to be performed. Cablemen or cable splicers may be utilized to perform additional sectionalizing as required.

For cable work, the only ground placed is at the substation, other than personal grounds placed around the work location.

For network protector testing, a cable splicer wearing a 100 cal suit, will confirm that the protector is open, rack it out, pull the fuses, and open the associated transformer primary switch. Note that the distribution operator is notified when the transformer primary switch handle is operated.

For transformer oil sampling, the cable splicer checks the network protector to confirm it is open. Note, they do not set the network protector to the open position. They will move the transformer primary switch lever to open. Where the transformer primary switch is a wall mounted vacuum switch, they will open the switch, and park the elbows on standoff brackets.

PG&E has experienced network protectors “hanging up” when a circuit is de-energized. In some cases this may be a result of light loading conditions. In others, this may be due to voltage imbalance between feeders supplying a given spot network. In yet other cases this may be due to improper relay settings. At the time of the EPRI immersion, PG&E was researching this issue to identify and address the causes and to develop consistent procedures for addressing hung up protectors.

Technology

PG&E has embarked upon a five year project to replace the existing network remote monitoring system with a modern system that provides increased monitoring and control (See Remote Monitoring). This system will include remote operating capabilities for the network protectors will include remote open/close of switches and station transfer trip.

6.10.14 - Portland General Electric

Operations

Operation Practices - Clearances

People

The System Control Center (SCC) is responsible for operation of the network and grants clearances for crews working on a feeder.

The load dispatcher works closely with the network crew foreman to accomplish switching on the network. Substation operators perform switching at the substation, while the CORE underground crews perform switching out on the network.

Process

Planned outages on the network follow a structured process.

The Network Engineering Department creates a shut-down order document, which lists the steps necessary to take the network feeder out of service and grants clearance to field crews to work on the feeder. The shutdown order is forwarded to the load dispatcher for verification and completion. PGE utilizes templates that guide the creation of the switching steps associated with a shut-down order. Load Dispatch receives a three-day lead time for planned shutdowns.

Dispatchers communicate with crews to carry out the switching in the field.

To clear a feeder, dispatchers use the following steps:

Call the general foreman to ensure that no one is working on the feeder to be opened or in any of the feeder vaults or manholes.
Open the feeder breaker via SCADA.
Wait for the network protectors to open and verify that they have opened by checking the remote monitoring system. Note that the CORE group is responsible for checking the remote monitoring system to confirm that all the network protectors have opened. Load Dispatch performs a secondary verification when crews and substation wiremen call to request rack-out and tagging of the substation breaker.
A dedicated wireman at the substation racks out the breaker and tags it with a danger tag. Once this action is complete, the wireman reports to the dispatcher that the wireman has opened, racked out, and tagged the breaker for the crew.
The dispatcher calls the crew and gives it permission to open and danger tag all the associated vaults on the shutdown order. The shutdown order lists all the vaults, and the dispatcher gives one order specifying to open and tag all the associated vaults.
Field crews visit each network work protector (already opened on backfeed), move the NP handle to the open position, and tag it so that it cannot close in any way.
The crew opens the primary switch on the transformer and tags it.
Everything is now open and tagged as specified in the order.
The crew notifies the dispatcher that all switches have been opened and tagged.
The load dispatcher gives the crew clearance to install grounds and proceed with its work.

Feeders are typically grounded only at the substation, and PGE’s common practice is not to set up a tighter zone of grounding.

The SCC relies on the CORE group to isolate faults and provide them with recommendations about what switches need to be opened. SCC still authorizes the switching but works closely with the crew to ensure that it understands exactly what process and order to follow.

Power Restoration: To restore power, there is a simultaneous close capability that closes all four network feeder breakers at the same time. The SCADA operates this remotely. The SCC calls the general foreman before closing any breaker to ensure that crews are not currently working in any of the vaults on that feeder. The foreman confirms with the crews whether it is safe to close.

Technology

PGE migrated to an Oracle NMS outage management system, which is based on WebSphere technology [1]. Oracle NMS is a scalable distribution management system that manages data and supports switch planning and management.

D. Handova, “PGE: Driving Customer Value With Network Management Systems.” EnergyCentral.com. http://www.energycentral.com/c/iu/pge-driving-customer-value-network-management-systems (accessed November 28, 2017).

6.10.15 - SCL - Seattle City Light

Operations

Operation Practices - Clearances

People

Operations Documentation

Clearance procedures are well documented in the Seattle City Light System Operations Clearance, Keep Open, and Hold Open Procedures. Employees who are qualified to perform switching and tagging and give and receive clearances must be familiar with these procedures, and pass a test to demonstrate their proficiency.

Process

Operations Practices – Clearances

When network crew leaders request an outage of a network feeder, they submit a clearance request to the dispatchers. This process is defined in the System Operations Clearance, Keep Open, and Hold Open Procedures Document.

SCL has a position called Outage Coordinator, who is responsible for reviewing this request and preparing and coordinating the necessary clearances, keep opens, and equipment outages on an advance basis. Ultimately, the System Operator (dispatcher) orders the required switching and tagging for the clearance, keep open, or hold open.

SCL requires a “visible break” as part of their clearance procedure. They contend that this requirement – being able to observe the visible break on the transformer primary switch through the site window, and also pulling the fuses when opening the network protector – has contributed to their strong safety record.

Network clearances are site specific. The clearance must describe both the location and the specific piece of equipment that a crew is working on.

6.10.16 - Survey Results

Survey Results

Operations

Clearances

Survey Questions taken from 2018 survey results - safety survey

Question 26 : Please indicate which of the following activities are part of your network feeder clearance procedures.

Question 27 : When the feeder has been cleared, in what position have you left the network transformer primary switch?

Question 28 : Are there any differences in your network feeder clearance procedures for a routine clearance (such as for adding a new transformer) and an emergency clearance (such as for a cable failure)?

6.11 - Organization - Operation Center

6.11.1 - AEP - Ohio

Operations

Organization - Operation Center

People

AEP Ohio performs all operations activities associated with its network infrastructure from its Grandview Network Service Center in Columbus. The center is comprised of Network Mechanics and Network Crew Supervisors, who perform all field activities associated with the network. Note that some network crews do report to a center in Canton to be physically closer to the Canton infrastructure, but organizationally report to the Network Service Center.

The Center is also responsible for field activities associated with ducted manhole systems (network and non-network), substation exit cables, and looped UG distribution systems. In addition, the center houses trouble-men, who work 24 x 7 and respond to OH and UG issues, and a transformer repair shop.

The Service Center works closely with the Distribution Dispatch Center, which is responsible for all distribution operations, including operations of network systems. Distribution Operators (dispatchers) are responsible for operating the entire distribution system, both network and non-network. There is not a dedicated network operations group.

Process

AEP Ohio has a remote monitoring system installed in its network infrastructure. The data monitored can vary depending on the level of monitoring in each vault, but includes protector status information, transformer data, and vault sensor information such as thermal event monitoring. Note that at the time of the practices immersion, the Dispatch Center did not yet have the ability to monitor network protectors.

The Dispatch Center coordinates closely with the Network Mechanics who report out of the Network Service Center to operate the network system. The Dispatcher is responsible for operating feeder breakers at the substation, but will typically grant Network Mechanics authority to operate feeder devices beyond the station, such as opening the HV switches on the network units to clear a feeder, for example.

Technology

AEP Ohio has a SCADA system installed in is network that enables partial remote monitoring and control of network devices through NP relays and using the Eaton VaultGard system. AEP is in the process of implementing a new communications and control system in the network that will expand its remote control capability in the network. This fiber-based system will expand the monitoring and control capability of vault devices such as protectors and switches. AEP is also installing a network master trip and close system, which will enable a group feeder pick up, and the ability to selectively enable or disable any of the feeders that are part of the group.

6.11.2 - Ameren Missouri

Operations

Organization - Operation Center

People

Ameren Missouri’s operations center is referred to as the System Dispatch Center (SDC).

At any one time, the SDC has six dispatchers on duty, with two dispatchers having responsibility for the downtown area including the network. Dispatchers are rotated through each desk within the SDC so that each is experienced with each control area.

Dispatchers are a management position at Ameren Missouri.

Ameren Missouri has two positions that work closely with the SDC - Troublemen, and Traveling Operators. Troublemen serve as first responders and work primarily with the overhead and URD systems. Traveling Operators work with the network system and substations, including troubleshooting the network, and performing switching within network vaults and substations when required. The Traveling Operator is classification called by the dispatcher when a network feeder locks out. The Traveling Operators work as part of Reliability Support Services group and work closely with the Service Test group, also part of Reliability Support Services.

Process

Ameren Missouri’s clearance process, called Workman’s Protection Assurance (WPA), involves the preparation of a switching order by the dispatchers within the SDC. Dispatchers have prepared pre-defined orders for both normal and emergency switching in the network. These predefined orders serve as templates and provide a starting point for the dispatcher to prepare specific switching orders per request.

The SDC uses a triple check process when preparing a switching order (WPA).

Step one is writing the order, performed by the SDC dispatcher.
Step two is that someone else within the dispatch center checks the switching order.
Step three is a check by the dispatcher who issues the order to the Traveling Operator to perform the switching. Note that this may be a different dispatcher than the one who wrote the order.

The Traveling Operator who receives the order is, of course, a fourth check of the accuracy of the order.

The individual steps associated with the orders for network clearances are not delivered one at a time. Rather, all of the switching orders to clear a network feeder or feeder section are turned over to the Traveling Operators for execution.

Technology

Ameren Missouri’s network feeders are portrayed on the large display board within the SDC. Ameren Missouri uses a ring bus design at the substation, with only two network feeders fed from any given bus section.

The Ameren Missouri dispatch center does have a group pickup switch for network feeders, enabling Ameren Missouri dispatchers to either open or close an entire network from that switch.

Ameren Missouri’s SCADA system is an Open Automations Systems (OAD) product, and was developed with Price Waterhouse.

Ameren Missouri has remote monitoring of its network vaults. Using the ETI electronic relay in network protectors as part of its remote monitoring system, they monitor various points including voltage by phase, amps by phase, protector status, transformer oil top temp and water level in the vault. The monitoring points are aggregated at a box mounted on the vault wall that communicates via wireless. Information from this system is available to the dispatcher.

From the remote monitoring system, the Service Test supervisor, as well as a predetermined group of other recipients, receives a computer system generated Email that indicates when a network protector has opened. So, when a feeder locks out for example, the supervisor would immediately be notified by the system through emails indicating that the protectors on the feeder have opened. In addition, the department supervisor receives a report each morning that indicates which feeders were out the night before, and those that exceed preset load levels.

At the time of the practices immersion Ameren Missouri was considering the implementation of a Distribution Management System, and was looking to include reactance to fault technology to aid in fault location.

6.11.3 - CEI - The Illuminating Company

Operations

Organization - Operation Center

People

The CEI underground system is operated out of the Northern Ohio Regional Dispatch Office (RDO). This office is responsible for the operating the entire Illuminating Company system, including the network.

The RDO is staffed with 36 employees, including a manager, 27 Distribution System Operators (DSO’s), 2 Outage Coordinators, 1 Engineer, a computer system expert, and other support staff.

The DSO position is a non bargaining position. Most DSO’s have an electrical background in distribution and were hired “from the outside”. A formal degree is not required. CEI will give preference to candidates with military experience when hiring DSO’s, as military training provides structure and discipline – two characteristics sought after by CEI in DSO’s. DSO’s can advance to a senior level by gaining experience and demonstrating proficiency in certain tasks required for advancement. DSO’s will periodically be assigned to accompany Underground crews in the field to gain experience.

Process

The RDO runs seven operations “desks”, 24-7, with the system broken up by geography. That is, each desk controls a different geographic area. In assigning DSO’s to the desks, CEI will mix senior people with newer people to provide training. They assure that at least two senior DSO’s are working on the floor at any one time. Their goal is for all the DSO’s to eventually progress to the senior level.

CEI does not run a distinct network desk; rather, the DSO (s) assigned to the desk whose geographic responsibility includes the area of Cleveland served by the network operates the network. CEI has had minimal problems with the network.

The RDO has a full backup center, with redundant systems. CEI does periodically practice the transfer of control from the primary center to the backup center.

Technology

CEI is utilizing a SCADA system, with limited monitoring and control of facilities beyond the substation breaker for distribution feeders.

CEI utilizes an outage management system (Power ON) to facilitate outage determination and restoration.

The RDO is documenting operating processes and procedures in a system called E Net. They have one individual who is assigned the responsibility of maintaining and updating this system.

6.11.4 - CenterPoint Energy

Operations

Organization - Operation Center

People

Distribution dispatching is housed within the CenterPoint Energy Control Dispatch Center (ECDC). This facility also houses the Regional Transmission Operator (RTO) desk.

Distribution Dispatchers focus primarily on switching and troubleshooting of the distribution system beyond the substation breaker. Distribution Dispatchers are assigned responsibility for certain territory by service center. CenterPoint has twelve Service Centers, and assigns one or two dispatchers per service center. A normal day shift will employ a minimum of 14 dispatchers.

The RTO focuses primarily on the transmission network, but is also responsible for operation of distribution breakers at the substation. For example, the RTO would dispatch a Substation Operator to open a major underground dedicated distribution feeder breaker at the substation.

At CenterPoint, Distribution Dispatchers are represented by a collective bargaining agreement (Union). A Distribution Dispatcher can become a journeyman after three years of training (formal and OJT) and testing. Distribution Dispatcher candidates must pass a highly selective test to enter the program. Only 10-15% of candidates who take the test qualify for entry into the program. Apprentice dispatchers are assigned a mentor to guide them through the program.

Process

To obtain clearance to work on a feeder, Major Underground will submit a Switching Order request to the Distribution Dispatch Center at least 24 hours in advance of the needed switching.

The Distribution Dispatch Center provides switching orders for all devices beyond the substation breaker. Note that for the dedicated^[1] circuits in Major Underground, the Distribution Dispatcher prepares switching orders to clear the circuits from pre-written templates maintained by the GIS group with Major Underground.

The Distribution dispatcher coordinates with the RTO to open and tag the feeder breaker. The RTO is responsible for providing switching orders to operate distribution feeder breakers at the substations.

For circuit lock-out switching:

The RTO will issue a hold order, indicating that the circuit has been opened with a visible break and tagged. RTO will communicate with Distribution Dispatcher. Distribution Dispatcher will issue a switching order to the head journeyman on the UG crew to field switch all locations on the locked out circuit. Switching will be performed to isolate all potential back feed sources (For example: Network Protector Maintenance). After switching is complete, the UG crew will verify the circuit is de-energized and ground the circuit. The UG crew will now take a clearance to work on the circuit.

Note that the field switching sequence is performed and controlled by the head journeyman on the crew–not by the dispatcher. The dispatcher does NOT read each line of the order to the switchman as they do in the overhead.

For planned switching:

Distribution Dispatching will issue a switching order to the UG crew to clear-up all locations on the circuit. Switching will be performed to isolate all potential back feed sources (for example: Network Protector Maintenance).

After the UG crew completes their switching, they will communicate with Distribution Dispatching to drop out and clear up the circuit. The Distribution Dispatcher coordinates with RTO to open and tag the feeder breaker. Once the feeder breaker is cleared up and tagged, UG will receive an order to check for de-energized and ground the circuit. The UG crew will now take a clearance to work on the circuit.

Note that the field switching sequence is performed and controlled by the head journeyman on the crew–not by the dispatcher. The dispatcher does NOT read each line of the order to the switchman as they do in the overhead.

Technology

CenterPoint utilizes a “home grown” outage management system. This system has a prediction engine that creates cases for each suspected trouble location. It is tied to SCADA, in that Breaker trips and lockouts are displayed in the OMS. It is further linked to CenterPoint ’s “graphical switching” system, described more fully below. Note that the OMS is not linked to the GIS system, because the development of the outage management system predates the GIS system.

CenterPoint’s graphical switching system, developed by CES (now Oracle), is tied in with both their outage management system and GIS system to display up-to-date maps on the wall. This system updates the digital maps as switching is performed. For example, during an outage restoration, as circuits are sectionalized, these changes are recorded in the Outage Management system, and the Graphical switching system displays an up to date map of the distribution system.

However, the “dedicated” underground system, including network secondary systems, is not displayed in the graphical switching system. This is in part because the foundation for this system is the GIS system (ESRI) and at the time the graphical switching system was installed, the GIS system had not yet been up dated with the dedicated underground facilities.

CenterPoint’s GIS system is ESRI. The GIS has been updated to include dedicated underground facilities, and CenterPoint intends to implement graphical switching for this distribution. CenterPoint has not fully implemented GIS for underground because the congestion inherent in underground systems and the looped nature of network systems makes both the display and the electrical connectivity of the GIS model complex.

CenterPoint is using mobile data units in its troubleshooter vehicles. These units enable no lights cases to be “dumped” to a mobile data unit located in the truck, rather than dispatching the troubleshooter by radio. CenterPoint has equipped its relay section trucks with mobile data units. However, trouble is normally dispatched to the major underground group by radio (voice).

In storms, major underground resources and trucks may support the service centers. In storm situations, the mobile data terminals are used, with “no lights” cases sent to the mobile units.

CenterPoint does have a backup dispatch center, and periodically checks to see that backup functionality is working.

^[1] The term “dedicated” underground at CenterPoint refers to three phase infrastructure is located entirely underground in their ducted manhole system. A dedicated network feeder does not mean that the feeder serves only a network. Rather, it refers to a feeder that is entirely underground. In fact, at CenterPoint, feeders that supply the underground network also supply radial load along the way.

6.11.5 - Con Edison - Consolidated Edison

Operations

Organization - Operation Center

People

Operations Control Centers

Con Edison has one main System Operations Control Center, and Regional Control Centers, such as the Manhattan Control Center.

The System Operations Control Center is the main operating authority, responsible for operating the system and for the protection of the workers for the entire Con Edison system. The System Operations Control Center controls and operates Generation, Transmission, and Distribution.

Employees called District Operators (DO’s) report to the System Operations Control Center. District Operators work in shifts (several DO’s per shift), and provide 24-hour a day, 7 days a week, 52 weeks a year coverage. District Operators have exclusive operating authority and control of all distribution feeders, including circuit breakers within the substation, and all equipment and cable runs up to and including the points of termination in the field. District Operator operating authority includes issuance of approval for status change, application of protection, and issuance of work permits and test permits on distribution feeders. (Distribution feeders include all network feeders and all non-network “cable” feeders including aerial cable, and some open wire on 33 kV in Staten Island.)

Con Edison network workers (in the Work Out Centers or in the Field Operating Department [FOD]) don’t place and check their own protection; they rely on the District Operator. Con Edison has a methodical, tightly controlled clearance process, where the District Operator (DO) directs the activities to provide clearance on a feeder. If field personnel encounter a situation that doesn’t match what they expect to find, or if there is any lack of clarity in the clearance steps, the job stops immediately.

The Regional Control Centers interface between the System Operations Control Center and the Work Out Centers to get the work done. Following a strict protocol, after fault location, positive feeder identification and application of protection, the District Operator at the System Operations Control Center delegates the responsibility for work on cable or equipment to the “Feeder Control Representative” in a Regional Control Center. Again, following strict protocols, the Feeder Control Representative “signs on” each work crew at each work location and “signs them off” after they complete or partially complete their assigned work. When all work is completed and all workers are signed off, again following a strict protocol, the Feeder Control Representative reports the work completed and all sign-off’s to the District Operator, who then takes back full control of the distribution feeder, orders it tested, prepared for service, and finally orders it restored (cut in).

Overhead feeders (open wire, bare wire, tree or covered wire, and self-supporting wire) plus underground radial spurs fed from the overhead wire are under the control of the appropriate Regional Control Center. Strict but different protocols are followed for those feeders as well.

Process

Morning Call

Con Edison conducts a “morning call” in each region, and in their System Operations group. The morning call is a telephone conference call where important operating issues are discussed. The morning call typically takes about ten minutes to complete. The call includes a discussion of:

first contingencies; that is, situations where a piece of equipment is out of service and the system is operating in an N-1 condition,
activities and outages scheduled on primary feeders
secondary activity anticipated for the day
outages/incidents experienced on the systems
work reporting; that is, a review of the work scheduled for the day
shunts and bridges; that is, places where temporary cables are installed, usually above ground, bypassing a section of the distribution system
street light work scheduled for the day
environmental issues
feeder issues

The handout used during the call consists of:

Display of the Feeder Board, listing the primary feeders that are out of service
Display of the Critical Transmission and Substations Equipment Outage Status
Table of the current feeder outages, indication of the reason for the outages, anticipated duration, work to be performed, other pertinent comments, etc.
HIPOT Summary (high potential feeder test summary), listing feeders that were tested the previous day
Banks dropped
Customer Service – Distribution Equipment report, indicating the defective banks off the system, both customer and company owned
Lists of other systems statuses, such as Banks Made Auto, Banks on Outage, Open Mains Received, Open Mains Tied Permanent
Customer Outages
Shunts and Bridges Summary Report
Customer Outages
Outstanding Job Summary by Responsibility
Age Distribution Summary by Responsibility, showing the number of projects of different types, sorted by how long the job has taken (the age of the job)
Daily Open Mains summary Report
Summary of Primary C and D Faults
Daily Incident Report, highlighting safety incidents

Outages

Con Edison’s System Operations Control Center has control of primary feeders. If a feeder trips, it is the responsibility of this control center to clear the feeder. More specifically, the System Operations Control Center is responsible for tasks such as troubleshooting the feeder, applying grounds, performing testing, and using Con Edison’s Reactance to Fault (RTF) system to predict the location of the fault. See Reactance to Fault Application - RTF.

Because of Con Edison’s network design and N-2 contingency planning, most faults that result in feeder lockouts (“Open Autos,” in Con Edison lexicon) do not result in customer outages. For reports that do come in from customers, a ticket is created by the Con Edison Call Center in their outage management system with a customer address. The linkage between the customer’s account and the electrical location is not automatic. The Distribution Operator adds a structure number to the outage ticket, indicating the location on the electrical system. When this assignment is complete, information about these outage tickets can be displayed on the map. Con Edison is working on automating the process for assigning a structure number to a customer address.

When the fault is located and the feeder is scheduled for work, the System Operations Control Center hands the feeder over to the Manhattan (or other regional) Control Center to accomplish the work.

When work is done, the Manhattan Control Center gives control of the feeder back to the System Operations Control Center. System Operations verifies that the feeder is ready to be re-energized by test, and then puts the feeder back in service.

Con Edison Operators can view the status of feeders on their “Feeder Board,” available through their Heads Up Display (HUD). One feature of this display is that if two feeders are out of service, the feeder board highlights common holes — that is, vaults or manholes that contain both out-of-service feeders.

Con Edison carefully manages the time of the outage of a feeder. Feeder restoration time during hot periods at Con Edison has been significantly reduced, from about 36 hours to around 13 hours on average. The utility’s target is to have feeders out of service for no more than 14.7 hours during high temperatures. (14.7 hours was arrived at by targeting reductions in the various components that comprise outage duration.). Note that this target applies to both unplanned feeder outages (Open autos) and planned outages.

Distribution System Operation Under Contingency Conditions

Con Edison has a specification that provides guidance for actions to be taken and activities to be pursued by the Electric Operations, System Operation, and Substation Operations when unusual operating conditions such as multiple contingencies above the design criteria and/or elevated system loading arise on the distribution system.

The document includes guidelines for emergency cooling of network transformers, outlining different methods for cooling, and describing in what circumstances to use each method.

The document includes sections that describe actions that should be taken in the event of first and second contingencies for networks of different voltages and substations, including things such as information that should be gathered, people to be notified, and factors to consider.

For example, in a first contingency condition on a 13 kV network, where a network feeder opens automatically, some of the actions that should be taken include:

Examine the Reactance-to-Fault (RTF) Application (where available), and determine the type of fault (i.e., single-phase, double-phase, or three-phase) and a calculated fault location.
Examine relay targets, and determine the type of fault (i.e., single-phase, three-phase, or instantaneous with ground or time delay with ground).
Process the feeder, and identify the component that failed (i.e., cable, splice, transformer, or transformer termination. Also, if it is a single-phase or three-phase cable or splice).
Correlate the identified failure with the RTF application and the feeder relay targets. If they do not correlate, consider performing a modified Hi-pot after repairs are completed.
Complete repairs, remove feeder grounds, and apply Ammeter Clear Test and modified Hi-pot test.
Monitor system conditions for possible overloaded equipment (from Con Edison’s Remote Monitoring system).
Identify and investigate open network protectors.
Replace network protector blown fuses reported by RMS.
Review RMS data (Visual WOLF) and exception data to identify potentially overloaded feeder sections and transformers.
Review “next worse” contingency scenario in anticipation of an additional feeder out of service.
Etc. (This is only a partial listing of actions)

The document also provides guidance for operators in making the decision to initiate and execute a network shutdown if necessary.

Technology

Heads Up Display (HUD)

Con Edison has much information available to operators through their Heads Up Display tool (HUD). HUD is a map-based graphics tool that displays the real-time status of primary and secondary network components. This tool provides users with an integrated, layered approach to viewing real-time information about most components of the distribution system. The system provides visual alerts to notify users of existing or potential problems or events. The system integrates data from multiple sources (SCADA, RMS, etc.) to reflect the real-time status of each network across the Con Edison distribution system.

Remote Monitoring System (RMS) / Distribution SCADA

Con Edison uses a Remote Monitoring System (RMS) in every one of its network transformer vaults to remotely monitor and communicate information back to the office. The system uses power line carrier (PLC) technology to communicate monitored information from transmitters located in each vault, over the 60-cycle electric signal, to receivers located at the substation.

The RMS in use at Con Edison was originally designed at Con Edison’s request in the 1970s, by Hazeltine, with installation of devices beginning in 1982. The RMS system is made up of transmitters located in each of the transformer vaults, pick-up coils on every feeder at the substation that detect the PLC signal, and receivers at the substation that gather the information detected for a given network. From the substation, information is communicated back to the central office using telephone frame relay lines (TCPIC lines), that provide near-virtual connectivity, enabling Con Edison to download information from every receiver about every one minute.

At the substations, Con Edison is using receivers developed by Digital Grid. The utility has experienced good performance from these receivers. Con Edison is currently testing a receiver developed by ETI and is in the process of replacing older Hazeltine receivers with these newer units.

At network transformer vault locations, Con Edison uses transmitters from ETI and Digital Grid. Many existing installations are equipped with older transmitters from Hazeltine and BAE. The transmitter is connected to one phase of the network protector. The power connection is to network side of the network protector (always powered), and the signal wire connection is to the transformer side, so that if a network protector opens on light load, there is still a signal. In area substations that supply two networks, the transmitters on each network are connected to and transmit information over different phases.

As Con Edison has been using RMS for years, it has different “generations” of systems in place. In the first-generation installations, the RMS system monitors the three-phase % percent loading, and five status points such as network protector status or transformer temperature alarm status. In the second-generation installations, the RMS monitors three-phase % loading, three-phase voltage, eight status points, and two analog readings. In the latest generation installations, the transmitters have additional processing capability and can monitor things such as transformer tank pressure, oil temperature, and oil level status. The utility is also monitoring the Oil Minder System in those vaults that contain them.

Con Edison is effectively using its intranet to give employees access to this remotely monitored data. The utility has developed an on-line system, Net RMS, which enables all employees to view the information from their computers, including field laptops. The system is tied in with SCADA, so it displays which feeders are open and closed. The system also displays the % offload that will be picked up by the nearby vaults if a given feeder locks out, a useful tool in contingency planning.

Con Edison is planning to expand functionality of its RMS to be able to communicate with the network protector relay, and to gather additional information such as network protector temperature.

The Distribution SCADA department is made up of 10 engineers, who are responsible for all the Distribution SCADA beyond the area substation.

Picking up Multiple Feeders in the Event of a Network Outage

Con Edison has installed a network start-up and shutdown panel for picking up multiple feeders at one time in the event of the loss of an entire network. The panel brings the controls for all breakers to two points in the station, because stations are designed to service two networks. The panel is connected to the operator at the System Operations Control Center.

Con Edison has a scheme to shed load as the frequency drops or if the rate of change in the frequency exceeds a given threshold. The system prioritizes the feeders that it drops. For example, the scheme sheds overhead load first.

6.11.6 - Duke Energy Florida

Operations

Organization - Operation Center

People

Duke Energy has a centralized Distribution Control Center (DCC) which provides operational control for the distribution system throughout Duke Energy Florida, including network infrastructure in Clearwater and St. Petersburg. The group is led by a General Manager. Previous to the formation of a centralized DCC, Duke Energy Florida had operated with smaller operations centers scattered throughout the state, and would operate decentralized during the day, and centralized at night. With the formation of the new center, they operate centrally at all times.

Within the DCC, approximately 30 dispatchers work rotating shifts to provide 24x7 staffing. The dispatchers are assigned to operations desks, called pods, and are assigned specific areas geographic regions of responsibility such as the North Coastal region, or the South Coastal region. Duke Energy Florida has 18 operating regions, and each pod serves two of these areas.

On each shift there is usually one dispatcher who has network experience. Duke Energy Florida feels that this staffing level adequate to support the network, as network design is self-healing, experiences few outages, and because of the expertise of the Network engineers and underground resources. The DCC collaborates closely with the Network Group on network issues. If major network system problems arise, network experts from the Network Group or engineering are called in to supplement the Operations Center staffing.

The dispatcher is a bargaining unit position at Duke Energy Florida. Candidates for a dispatcher position must have journeyman line worker experience or operator experience, with the senior qualified applicant receiving the position. Dispatchers, having knowledge of line work, have good rapport with the field force.

Within the DCC, Duke Energy Florida does not distinguish between “load” dispatching and “service” dispatch – dispatchers are responsible for all aspects of dispatch within their geographic area of responsibility. Part of their rationale for this approach was to aid in scheduling.

The DCC has a full back up center (in the process of being rebuilt at the time of the immersion).

Duke Energy Florida also has a Grid Management function, co-located with the DCC, which provides engineering and other technical support to the DCC. Both the DCC and the grid management group fall organizationally under the same director.

Process

In dealing with network operations issues, the DCC works closely with the Network Group. For example, for network switching, the dispatcher will prepare switching orders and send to the network group to perform a peer review of the switching steps, an important failsafe according to Duke Energy Florida.

Online geographical GIS maps, SCADA screens, and system schematic views to enable dispatchers to perform a number of tasks including load management, switching, outage management, and workforce management. Dispatchers can operate network switches and monitor open/closed feeders from the Operations Center. One important Dispatch job is performing system modelling during outages: when an outage occurs, Dispatchers can use the online modelling program to perform load analysis when rerouting feeders. Whenever a feeder is out, the system automatically tags it as open and reports the information to the field crews via mobile data terminals or on a laptop.

While Duke Energy Florida has remote monitoring of its network vaults, this information is being monitored by the Network Group, not the dispatcher. (See Network Monitoring)

Technology

The DCC is an impressive, state-of-the-art operations center that has consolidated monitoring, dispatch, and operations for all of Duke Energy Florida in one command center. The center is equipped with modern technology, such as excellent and varied monitors, wall mounted displays, and desks that raise and lower so that people can stand.

Within the DCC, a master list of the available trucks and their locations are online. Dispatchers can track truck locations in real-time via an online GPS-enabled mapping program. Outage information is also displayed.

SCADA, GIS, and schematic views of the network are online for Dispatchers.

6.11.7 - Duke Energy Ohio

Operations

Organization - Operation Center

People

Duke Energy Ohio has an Operations Center that is comprised of a Power Supervisor (PS), and a Trouble Desk Supervisor.

The Power Supervisor deals with all operations issues within the substation and on network feeders. System alarms are forwarded directly to the Power Supervisor. The power supervisor issue switching orders and grants working clearances.

The Trouble Desk Supervisor, as the name implies, deals with trouble on the system such as outages and is involved in mobilizing crews to respond. This person deals with Dana Avenue crews on a daily basis.

Duke Energy Ohio does not have a dedicated Power Supervisor or Trouble Desk representative focused solely on the network.

Process

For a scheduled outage, Dana Avenue Underground personnel will complete an outage request form. Normally a five day lead time is required for a distribution outage to a network feeder. The outage request is sent to two T&D Operations Coordinators, part of the Operations Center, who write the actual switching orders. Next, the request goes to the Power Supervisor (PS), who will issue the switching orders.

Emergency clearance requests are normally coordinated through both the Trouble Desk and PS.

Technology

Duke Energy Ohio is using a system called DEETS for scheduling and managing planned outages.

Duke is using an Outage Management system (DOMS, by Oracle) to manage unplanned outages. This is a GIS based system , although the network system beyond the network substations is not modeled in the system.

At the time of this immersion, Duke Energy Ohio was in the process of installing a communication backbone for remote monitoring in their network system (see Remote Monitoring / SCADA).

6.11.8 - Energex

Operations

Organization - Operation Center

People

Energex has 22 staff members called switching coordinators who operate its central control center on rotating shifts. The people in the control center rotate their positions on a regular basis, and any operator can monitor and/or control any segment of the Energex power grid, including the CBD underground network. Switching coordinators are typically drawn from field staff ranks, usually either substation technician or mechanic and rapid response, with training specifically for the control room operation.

Process

Energex has a control room that monitors its entire electric power infrastructure, which is primarily radial in nature. The entire network is broken up into 10 to 12 control zones, with switching coordinators manning and monitoring each zone. Two to three staff generally share a number of control zones which includes the CBD underground network. (see Figure 1). These staff monitor all alarms and SCADA systems on the CBD. All CBD substations have alarms that are connected to the control room either through hard-wired connections or through a wide area network (WAN). The switching operators in the control room assigned to CBD issue switching instructions, issue clearances, assign tags, and also work with Central Dispatch to dispatch crews to unplanned events affecting the CBD network (tripped circuits, faults, flooding, etc.). [See the Remote Monitoring section in this report.]

Figure 1: Portion of Energex control room

The switching coordinators in conjunction with shift managers in the control room decide what needs to be done in any given situation they have monitored. This includes what human resources to dispatch to a scene after hours.

(See the Rapid Response)

Technology

Energex has a remote monitoring system in place throughout its grid using both hard-wired RTUs and SCADA systems over a WAN.

(See the Remote Monitoring section in this report.)

6.11.9 - ESB Networks

Operations

Organization - Operation Center

People

The transmission system, 400kV, 220kV and 110kV outside of Dublin is operated by the TSO – Eirgrid. Within Dublin, the 110 kV system is controlled by the Distribution System Operator (DSO) at ESB Networks.

ESB Networks also controls also controls the 38kV transmission system, as well as the medium voltage (10, 20 kV) and Low voltage (230, 200V) distribution systems.

Network operations at ESB Networks, including supervision and training of operations personnel, is performed by Operations Managers within the Operations group, part of Asset Management.

Organizationally, the Operations group is comprised of two Operations Management centers, one North and one South, a System Protection group, an Operations Policy group, and a Systems Support group.

The operations group includes a demand manager for forecasting network load demands in both regions, and ESB Networks has a MV manager, called a Customer Services Supervisor, for each of its 35 MV geographic areas. The central control of these areas is the responsibility of the centralized operations centers. ESB Networks has two central operations centers, North and South, but it is soon moving to a single central control center.

Network operator training includes the following:

A seven-day classroom training course that concludes with a written test. The test includes many critical questions, especially concerning safety procedures. If candidates do not get these questions right, they must retake the test.
There are also practical assessments for operations personnel that cover a variety of on-the-job tasks in the areas of:
- Overhead line work
- Cable work
- HV stations
- Metering
- Commissioning of new equipment.

MV system management is the responsibility of a customer services supervisor (CSS) trained in MV operations. These personnel assume the responsibility of their assigned MV systems, and give permission for work to take place on the MV system. Once permission is granted, work is coordinated between the field operator and the CSS. The CSS personnel are also the managers and controllers of the LV network.

Process

The “Bible” for ESB Networks networks operators is its internally-developed “Safety Rules” book. This document was prepared and is continually updated by the Operations Policy group.

Every Network Technician (NT) has a signed copy of the “Safety Rules” book, certifying that they have received it and read it. The book aids operations managers in the following way:

Sets out how work should be organized
Sets out how to communicate with the control room operator
Sets out the different roles personnel have when operating on the system

In a typical operations scenario, a customer may call in that an outage has occurred. The CSS MV operator can trace the outage through its online outage management system (OMS), which has a real-time representation of the system through its SCADA field controls. The MV stations have SCADA reporting in to the operations center, mainly over fiber optic cable.

OMS provides extremely detailed views of the network and can point to a particular LV outlet coming out of any monitored MV station. There are typically four LV outlets out of each MV station. These MV circuits are available to the operator in a schematic view.

Once the outage is traced, the CSS can arrange for maintenance through its Dispatch Centre, which is also housed in the operations center. The Dispatch Centre calls out to the appropriate Network Technicians. After hours (holidays and nights), operators use the OMS to dispatch stand-by NTs to investigate outages.

Technology

ESB Networks has deployed SCADA at most (98%) of their 38:10kV substations. At the time of the immersion, they were piloting the use of remotely monitored and controlled devices at a medium voltage station (10KV : LV), in Dublin. ESB Networks utilizes the ABB Network Manager 3 (NM3) SCADA system.

Within SCADA controlled substations, ESB Networks is utilizing a backup communications device, called CELLO. CELLO, installed as a business continuity measure, enables communications in the event of a communications failure of SCADA. If an RTU is lost, the CELLO system will send a text message via the cellular network to the operations Center, who will them dispatch someone to the station.

ESB Networks is using an OMS system, (Oracle Utilities OMS V1.7.10), which is linked to their SCADA system. In addition, the SCADA is linked to their Asset Register System (ARS), which records breaker operations.

Each control area has its own OMS computer and system. These systems are maintained by IT staff who are solely dedicated to the ESB Networks network system, not part of a traditional corporate IT organization. Any employee can log in and see the network state through OMS. Mobile phone applications are also available for personnel in the field to access OMS information.

Outside the city of Dublin, ESB Networks has remotely monitored and controlled devices, and is actively involved in a system wide deployment of smart grid technology on their distribution. The deployment involves the implementation of recloser auto loop schemes, with automated reclosers placed at MV feeder cubicles, with remote monitoring and control of these devices from the Operations Centre. The driver if the deployment is to improve reliability performance as measured by customer minutes lost (CML) and customer interruptions (CI). (Note that ESB Networks is subject to potential penalties associated with reliability, such as an 8 Euro penalty for each hour that customers are out of service, and a 10 Euro penalty for every interrupted customer).

6.11.10 - Georgia Power

Operations

Organization - Operation Center

People

Georgia Power maintains a Network Control Center (also referred to as the SCADA Room) for operating its urban network infrastructure across the state. This center, located at the Network Underground headquarters in Atlanta, is distinct from the distribution control center(s) used to manage the remainder (non–network) of the Georgia Power distribution infrastructure. Test Engineers in the Network Operations and Reliability Group are responsible for operating and monitoring the network system, including new installation commissioning, establishment of SCADA connectivity, and the ongoing operations, monitoring and control of each network vault.

The Network Operations and Reliability group is part of the Network Underground group at Georgia Power, a centralized organization responsible for all design, construction, maintenance and operation of the network infrastructure for the company.

The Network Operations and Reliability group has seven Test Engineers on staff, responsible for the following:

Leadership of the Network Control Center
Monitoring and controlling the network through the SCADA system.
Requesting and confirming de-energized feeders for maintenance or during failures (feeder clearances).
Re-routing power to alternate feeders and/or networks in case of failures.
First-responders to customer service interruptions.
Can be part of the design phase for new networks or new major customer service.
Part of network protector selection (standards).
Responsible for SCADA network design and operation.

The Test Engineers are four-year or two-year associate-degreed engineers. The Test Engineer position is a non-bargaining, non-exempt position.

The group works closely with field Maintenance crews and Test Technicians, also part of Network Operations and Reliability.

Process

The Network Control Center monitors every Georgia Power network underground network protector location, including voltage, current, temperature, protector position (open / closed) and fluid levels from both the vault and the protector. In some locations, the center can monitor custom data points that are installed for fans or doors open/closed, for example. In addition, Georgia Power has installed AMI metering at customer sites. Monitoring of the Georgia Power underground network system has been in place since 1990.

The Network Control Center uses a combination of dedicated radio (Southern Link, a company owned radio network) and cell frequencies, with fiber (often at collector points aggregating information from multiple vaults) to connect to SCADA systems in every vault. The Control Center monitors voltage and current from protector equipment in each vault, at the bus level at substations, and can monitor bigger customers in every spot network location from CTs in network protectors there. The SCADA system cycles data every five to 10 seconds.

The Georgia Power Network Control Center only monitors and responds to alarms within the underground network system and its dedicated SCADA equipment. Non – network distribution infrastructure is operated by a separate Distribution Control center. However, the Distribution Control Center is responsible for monitoring and controlling network feeders. So the opening or closing of a network feeder breaker is performed by the Distribution Control Center, in coordination with the network Control Center. The Network Control Center is not staffed at all times, but only when needed by the Test Engineers. The Distribution Control Center is always staffed, with a specific operator responsible for the network feeders.

The Network Control Center personnel open and close protectors remotely on a regular basis, mainly as a part of the routine five-year Network Protector Maintenance program. Operators can lock protectors open remotely.

If the Network Control Center seeks to clear a network feeder, a Test Engineer must obtain a clearance from the Distribution Control Center (See Operations – Clearance) The Network Center Control personnel can monitor whether a feeder is still hot once the breaker is open (a network protector hang up, for example). In addition to having remote monitoring of protector voltage, current, and position, each network feeder has potential lights at the station which illuminate on back feed. Georgia Power Control Center personnel find that monitoring cable potential is critical for operating a network infrastructure. ) The Network Center Control personnel can monitor whether a feeder is still hot once the breaker is open (a network protector hang up, for example). In addition to having remote monitoring of protector voltage, current, and position, each network feeder has potential lights at the station which illuminate on back feed. Georgia Power Control Center personnel find that monitoring cable potential is critical for operating a network infrastructure.

In most situations, the Network Control Center can determine whether a network protector is hung up in about five minutes, although the group is moving to a faster communication system. Crews can also go to that location and ping it for a faster response.

The Operations and Reliability group also has piloted an automatic fault finding system at a few locations. This system uses reporting faulted circuit indicators in conjunction with Schweitzer electronic relay information to pinpoint where a fault may have occurred.

The Operations and Reliability group runs routine disaster drills. It uses a Network Contingency Plan book that details procedures for when a network goes out, etc. The Contingency Plan breaks down every step to assigned roles within the department. The plan is also useful in determining steps for finding out how much load there is on a network segment, if a segment needs more capacity, if the group should tie to another network, etc.

Technology

Access to the Network Control Center is by a locked door for use by authorized personnel only, and operators must securely log into the Control Center console(s) once inside. The Control Center is currently tied to its SCADA devices through licensed radio, cellular, DSL-type connections, and fiber optic cable.

From the Control Center map Operations Personnel can guide field crews to particular locations, which the crews can access online as well. The Operations Control Center can also call up a detailed circuit map online (See Figure 1 through Figure 4).

At the time of the immersion, Georgia Power was investigation options to remotely monitor network transformer information.

Figure 1: Network Operations Center wall map

Figure 2: Network Operations Center wall map

Figure 3: Network Operations console

Figure 4: Network Operations console

6.11.11 - HECO - The Hawaiian Electric Company

Operations

Organization - Operation Center

People

The HECO Dispatch Center is comprised of two dispatch desks, and one supervisory desk.

The dispatch desks in include the “Load dispatch” desk and the “Trouble dispatch” desk.

Both desks are manned by one person, in a 24-7, three shift operation. Both Load dispatchers and trouble dispatcher are union jobs at HECO.

HECO does not have a distinct desk or dispatcher position for monitoring and operating its network infrastructure.

The supervisory desk is manned by a Supervisor Load Dispatcher (SLD), in a 24-7, two shift operation (12 hour shifts). The SLD is a non bargaining position.

Process

The Load Dispatcher is responsible for operating the system, writing and issuing switching orders, and making sectionalizing decisions.

The Load Dispatcher does not have real time access to cable loading information out on the feeders/ feeder sections, as HECO’s application of SCADA is limited to the substation. For each circuit, the dispatcher has access to spot readings that are taken for each feeder annually - one reading is obtained during the day, one at night, one in the summer, and one in the winter. Before switching, the dispatchers will review these published spot readings to understand the typical loading of a feeder or feeder section, and compare that with knowledge of actual loadings obtained from either SCADA (at the station) or spot readings. HECO dispatchers acknowledged that one of their challenges is that the load steadily “creeps” up over time so that the published loadings may not match actual loadings.

The Trouble Dispatcher responds to outages and dispatches Primary Trouble Men. HECO has an Outage Management system that includes a representation of their distribution system, and knows which customers are served by what transformers. During the day, customer no lights calls are received by a HECO call center. At night, these calls are taken and processed by a contracted call center. Calls do not come directly to the dispatcher, other than situations that cannot be addressed by the call centers.

The Dispatch Center participates in annual Outage Drills / tests of the HECO Incident Command Structure. HECO is in the process of updating their written Blackstart procedure. HECO drills typically do not model the loss of the network, and they do not have a written procedure that outlines what to do if the network is lost.

Technology

HECO is utilizing a SCADA system with limited monitoring and control of facilities beyond the substation breaker for distribution feeders. Most 12kV feeders do have SCADA monitoring and control at the breaker.

HECO’s wallboard depicts 46kV circuits down to the 12kV breaker. From that point on, HECO is using their OMS system to display distribution circuits, with the exception of network circuits, which are not mapped within OMS. They are presently working with a vendor to combine the OMS circuit displays with the wallboard application. This will enable them to tag the wall board through OMS and on EMS through SCADA. HECO is planning to model network circuits in OMS in the future.

HECO is not using remote monitoring in the network, with the exception of some water alarms in certain network vaults.

HECO utilizes an outage management system (Siemens) to facilitate outage determination and restoration. Their system resides on a circuit model that is built from their GIS system. HECO is in the process of implementing a new customer information system that will tie into OMS.

6.11.12 - National Grid

Operations

Organization - Operation Center

People

National Grid has a Regional Control Center (RCC) responsible for their Eastern Region in eastern New York. This region is broken into four control areas, by geography with a separate control desk for each area. One control area (Capitol) includes the city of Albany, and thus control of the network. National Grid does not have a dedicated operator focused solely on the network – the operator responsible for the Capitol control area has responsibility for both network and non network infrastructure within the area.

Each control desk within the RCC is manned by a Regional Operator, responsible for both load dispatch and trouble dispatch for that area. Regional Operators provide switching orders to direct switching and tagging, issue clearances, and direct restoration activity. Regional Operators work 12 hour shifts each, and provide 24/7 coverage. The Regional Operator position is a bargaining unit position at National Grid.

Regional operator positions are normally filled from within. It is sometimes a challenge to fill open positions, as the job involves shift work. New Regional Operators receive intensive formal and on-the-job training for the first nine months they are in the position. Formal training is delivered three days a week, with much of it delivered by on-site trainers. Training on network systems and operations is included in the formal program.

Process

The RCC operators prepare the switching orders to clear a network feeder. The RCC does not use templates for network switching orders, as they want to assure that the operator is thinking through the process. The switching order includes orders to go into each vault to clear the network protector and transformer primary switch. The Regional Control Center Operator issues switching orders using National Grid’s formal documented switching process. Network switching procedures are detailed in an appendix to Electric Operating Procedure G014, Clearance and Control.

In general, substation operators perform all switching in the substation including the placing of tags. Switching on the network system is typically performed by the underground crews who are part of New York Underground East. Switching to clear feeder is typically performed at night. Underground crews will be scheduled to come in at night to complete a switching to clear a feeder before the start of the next workday.

Note that the regional operator will provide the switchmen multiple orders associated with a given vault. For example, if the switching order requires the man to enter a vault and open up two network units, both of these orders will be given at one time to prevent the switchman from having to come out of the hole after switching the first unit to receive orders to switch the second.

Technology

National Grid uses GE Small World as their GIS tool, and Power On as their outage management tool.

The Regional Control Center has remote monitoring and control of all network feeder breakers. National Grid does not have remote monitoring and control of any network equipment beyond the feeder breaker. The only exception to this is Henry St. Station in Glens Falls, one of two stations feeding a small network in the city of Glens Falls.

6.11.13 - PG&E

Operations

Organization - Operation Center

People

PG&E has multiple operations centers. At the time of the EPRI practices immersion, PG&E was in the process of consolidating their operations centers into one center.

These operations centers include distribution operators who provide switching orders to direct switching, tagging, and issue clearances, and switchmen who perform field switching.

PG&E also uses Cablemen, part of the Restoration Group, who trouble shoot the underground distribution system and perform restoration activities. The cablemen work rotating shifts and provide 24/7 coverage. Restoration activities are directed by the distribution operators.

PG&E does not have a dedicated distribution operator focused solely on the network.

Process

PG&E conducts a daily outage conference call, involving people from multiple departments to review outage incidents that occurred the previous day.

For a scheduled outage, a project coordinator who works within the M & C Electric Network group will request a feeder clearance from the distribution operator using an electronic clearance request form. This form describes which feeder and the time. Normally a seven-day lead time is required for a scheduled distribution outage to a network feeder. The distribution operator will write the actual switching order.

Technology

PG&E has an existing remote monitoring system installed in their underground network system. They have embarked upon a five-year project to replace the existing network remote monitoring system with a modern system that provides increased monitoring and control. (See Remote Monitoring).

6.11.14 - Portland General Electric

Operations

Organization - Operation Center

People

System Control Center (SCC): The SCC is usually referred to as Load Dispatch, and operators are known as load dispatchers, who are managed by the Transmission and Distribution (T&D) Dispatch Manager. The SCC has two distribution control regions, and Dispatchers are assigned geographically. From Monday to Friday, two dispatchers cover each of the two PGE regions.

One of the regions and therefore one of the dispatch desks includes downtown Portland and the CORE network. Dispatchers rotate between the two desks so that all dispatchers gain experience working with the network. The SCC employs eight dispatchers total who rotate between the desks on 12-hour shifts. Dispatchers are salaried employees (non-bargaining).

PGE employs load dispatchers from a range of backgrounds. Some are electrical engineers, some are ex-lineman, and others are SCADA technicians or truck drivers. This approach provides a diverse range of experience. PGE lacks a formal training program for load dispatchers. Training is primarily on the job. The load dispatcher position is not considered entry level, so PGE prefers to hire people with prior experience and qualifications.

Load dispatchers perform switching according to checked and verified plans drawn up by engineers. Dispatchers then communicate with crews to carry out the switching in the field.

Distribution/Network Engineers: Three Distribution Engineers cover the underground network and are responsible for supporting the maintenance and operation of the network, including working with dispatchers on operational issues and determining maintenance approaches for network equipment. The Distribution Engineers are not based in the Portland Service Center (PSC) or CORE group. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to perform certain civil maintenance tasks.

Crews

The craft workers assigned to the CORE group, part of the PSC, focus specifically on the underground CORE which includes both radial underground and network underground infrastructure in downtown Portland. Their responsibility includes operations and maintenance of the network infrastructure. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

Currently, the following 16 people working in CORE:

Four non-journeymen
Eleven journeymen (e.g., assistant cable splicers, cable splicers, foremen)
One Special Tester
Crew foreman: Crew foreman (a working, bargaining unit position), required to be a cable splicer
Cable splicer: This is the journey worker position in the CORE.To become a cable splicer in CORE, an employee must spend one year in the CORE area as a cable splicer assistant.
Cable splicer assistant: A person entering the CORE as a cable splicer assistant must be a journeyman lineman. All cable splicers start as assistant cable splicers for one year to learn the system and network.
Cable pulling
Splicing
Cable and network equipment maintenance
Cleaning
Pulling oil samples from transformers

Resources in the CORE include the following:

The Cable Splicer position is a “jack-of-all-trades” position with work including the following:

The typical underground crew consists of three people: two journeymen and a non-journeyman helper. The foreman, who is a qualified cable splicer, is one of the working journeymen on the crew. The two journeymen typically perform the work inside the manhole or vault, while the helper usually stays above ground, carrying material and watching the barricades and street for potential hazards.

In addition, a crew may include an equipment operator to operate the cable puller, vacuum truck, or other equipment. Note that some work, such as backhoe work, is usually performed by external contractors.

Other Crews and Positions

Special Tester: PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. Outside the network, Special Testers work with reclosers and their settings, and perform cable testing and cable fault location. Within the network, the Special Tester works closely with the network protectors, becoming the department expert with this equipment. PGE has embedded one Special Tester within the CORE group. This individual receives specialized training in network protectors from the manufacturer, Eaton.

The Special Tester usually partners with cable splicers, working as part of a crew. The “special testing” crew includes the Special Tester, a crew foreman (a cable splicer), a lineman/cable splicer, and a topman. The topman stays outside the hole and watches the manhole/vault entrance to ensure no accidents.

In addition to NP testing and settings, the Special Tester focuses on power quality issues, including customer complaints about voltage.

Network Protector Crew: The CORE group has created a dedicated crew that deals with network protectors and performs other construction work. This crew is comprised of cable splicers who receive formal training and attend conferences to gain experience with network protectors. This crew includes a foreman, journeyman (who rotates every three months), and Special Tester.

PGE has approximately 230 network protectors on the system, with half included in the 480 V spot networks, and half in the 120/208 V area grid systems. Presently, it has three construction/maintenance crews and will add the dedicated crew protector crew.

Journeyman Locator: The CORE has a cable splicer/journeyman in charge of “locate” requests, and this role is never outsourced. The network had 1600 locates last year, and ideally the locator works with the Mapper to ensure accurate maps.

Infrared (IR) Tech: IR techs inspect primary systems and network protectors as part of the Quality and Reliability Program (QRP). PGE has three IR techs, who mainly focus on the transmission system. They also work on high-priority secondary systems.

None of the IR techs are dedicated solely to the CORE.

6.11.15 - SCL - Seattle City Light

Operations

Organization - Operation Center

People

SCL uses a centralized operations center for their company. This center operates both the transmission and distribution systems. There are two distribution desks in the operations center, one of which has accountability for the network. (Note that there is not a dedicated desk to operate the network. The operators at this desk have both network and radial distribution operations responsibility.)

Distribution Operators (dispatchers) typically enter the position with either utility experience and electrical background, or specific experience as a journeyman. Often they have four years of education plus two years of electrical experience. They must take a test to get into the position.

Operations Documentation

Clearance procedures are well documented in the Seattle City Light System Operations Clearance, Keep Open, and Hold Open Procedures. Employees who are qualified to perform switching and tagging and give and receive clearances must be familiar with these procedures, and pass a test to demonstrate their proficiency.

Operations Performance Management

Individual performance evaluation for dispatchers includes a peer evaluation. Trainees receive mentoring from seasoned employees. For example, trainees spend two rotations with each team of dispatchers. Only about 30% are successful getting through the program.

Outage Drills

SCL does not regularly conduct drills to practice restoration of outages to the network. Note that SCL Operators do conduct routine outage drills / blackstart drills; however, these drills normally are not focused on responding to network problems.

Process

Operations Practices – Clearances

When network crew leaders request an outage of a network feeder, they submit a clearance request to the dispatchers. This process is defined in the System Operations Clearance, Keep Open, and Hold Open Procedures Document.

SCL has a position called Outage Coordinator, who is responsible for reviewing this request and preparing and coordinating the necessary clearances, keep opens, and equipment outages on an advance basis. Ultimately, the System Operator (dispatcher) orders the required switching and tagging for the clearance, keep open, or hold open.

SCL requires a “visible break” as part of their clearance procedure. They contend that this requirement – being able to observe the visible break on the transformer primary switch through the site window, and also pulling the fuses when opening the network protector – has contributed to their strong safety record.

Network clearances are site specific. The clearance must describe both the location and the specific piece of equipment that a crew is working on.

Operations Practices - Primary Switch Operation

In order to open the primary switch (on the network transformer primary), SCL either de-energizes the primary feeder or opens the network protector, separating the load from the transformer before operating the switch.

SCL work practices require that at least two journeymen be present in the vault to perform switching.

Operations Practices — Network Protector Maintenance

SCL maintains a network protector by simply opening the protector and removing the fuses. They leave the primary switch closed (energized), such that the source side of the protector remains energized. Note that they do not necessarily tag it, nor is a clearance required from the dispatcher in order to maintain a network protector.

Operations Practices – Operations Center

SCL has a separate network display board in their control center (separate from the large display that depicts their transmission system, substations, and distribution breakers). This display board depicts the transformer vault locations and the secondary network. The board is manually updated by dispatchers to show open devices, clearances, abnormal conditions, etc.

SCL also uses an issues board where they indicate any abnormal conditions, such as one of the network feeders for a sub-network being out of service for maintenance. If one feeder is out of service, they indicate which feeder is out, as well as indicate that the other feeders supplying that network are operating at an N-0 condition. Should the operators encounter issues with the network, they check the issues board to understand the system conditions.

Operations Practices – Emergency Response / Restoration

During high load conditions, the System Operator polls the network using the DigitalGrid (Hazeltine) system four or five times a day to understand field loading and voltage conditions.

SCL System Operators maintain a list of customers that are fed by each network feeder so that they can contact customers to curtail load during critical periods.

The Operations Center does not have a means for a group load pickup for network feeders, nor a written procedure that describes the processes for responding to a network blackout. The last time they encountered the need to pick up multiple feeders, they sent multiple crews to various locations and performed a countdown – three, two, one, close – to close multiple switches at the same time.

SCL’s procedures for responding to network emergencies are not formally documented. SCL does not perform regular drills to practice restoration procedures to the network. Note: SCL does document and drill restoration procedures for outages to the non-network parts of their system. These drills normally exclude outages to network facilities.

Operations Practices — Vault / Network Fires

SCL’s current design standard calls for fire protection heat sensors and temperature sensors in their vaults. The heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225°F. The temperature sensors send an alarm to the dispatcher at 40°C. (SCL utilizes temperature sensors in about 20% of their network transformer locations. They are actively adding locations, with a goal of 100% coverage.)

SCL does not have a written procedure for responding to a vault fire. Although their operators do have the authority to drop load in an emergency, they do not have a protocol to guide them as to whether or when they should drop load in response to a fire. Note that because of the “sub-network” design, with each secondary network completely separated from the other, a complete network outage due to a fire would be limited to the customers served by that one sub-network, with the other networks unaffected.

Technology

Monitoring

SCL does not use distribution-level SCADA on their network, but they do have access to the remote monitoring system (DigitalGrid). They have a separate console for accessing this remote information, and alarms from this system are available at each dispatcher console.

The SCL Dispatchers have access to the NetGIS system through a network viewer. This viewer enables them to view the contents and configuration of each network vault.

6.11.16 - Survey Results

Survey Results

Operations

Operation Center

Survey Questions taken from 2015 survey results - Operations

Question 107 : Do you have a dedicated operator within your dispatch center/control room for operating the network?

Question 108 : Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 109 : If you remotely monitor information about network devices, please indicate what information you are monitoring. (check all that apply)

Question 110 : If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA system?

Question 111 : Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker?

Question 112 : If so, what devices are remotely controlled? (check all that apply)

Question 126 : Do you require your network crews to wear flame retardant (fr rated) clothing?

Question 127 : If so, what clothing system level is required to work in the network (routine work)?

Survey Questions taken from 2012 survey results - Operations

Question 7.1 : Do you have a dedicated operator within your control room for operating the network?

Question 7.2 : Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 7.3 : If you remotely monitor information about network devices, please indicate what information you are monitoring. (Check all that apply)

Question 7.4 : If you are using remote sensing, how is the information communicated? (check all that apply)

Question 7.5 : If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA System?

Question 7.6 : Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker?

Question 7.7 : If so, what devices are remotely controlled?

Question 7.8 : If you do remotely control devices, indicate from which location(s) you have the ability to do so.

Question 7.9 : If you are remotely monitoring and/or controlling network equipment, what vendor/system are you using?

Question 7.10 : Do you have documented, up to date procedures for responding to network emergencies?

Question 7.12 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders)

Survey Questions taken from 2009 survey results - Operations

Question 7.1 : Do you have a dedicated operator within your control room for operating the network?

Question 7.2 : Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 7.3 : If you remotely monitor information about network devices, please indicate what information you are monitoring. (Check all that apply)

Question 7.5 : If you are using remote sensing, how is the information communicated? (check all that apply) (This question is 7.4 in the 2012 survey)

Question 7.6 : If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA System? (This question is 7.5 in the 2012 survey)

Question 7.7 : Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker? (This question is 7.6 in the 2012 survey)

Question 7.8 : If so, what devices are remotely controlled? (This question is 7.7 in the 2012 survey)

Question 7.9 : If you do remotely control devices, indicate from which location(s) you have the ability to do so. (This question is 7.8 in the 2012 survey)

Question 7.10 : If you are remotely monitoring and/or controlling network equipment, what vendor/system are you using? (This question is 7.9 in the 2012 survey)

Question 7.13 : Do you have documented, up to date procedures for responding to network emergencies? (This question is 7.10 in the 2012 survey)

Question 7.14 : Do you have a procedure that provides guidance in responding to vault fires?

Question 7.15 : If so, does it provide guidance to an Operator indicating when it is necessary to de-energize a network due to the emergency?

Question 7.16 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders) (This question is 7.12 in the 2012 survey)

6.12 - Outage Drills

6.12.1 - AEP - Ohio

Operations

Outage Drills

People

At present, there is no AEP-wide formal procedure for conducting outage drills to simulate network emergencies – the decision to and performance of drills has been and remains the responsibility of each operating company. However, at the time of the practices immersion, AEP was considering adopting a system-wide approach to the performance of drills involving network infrastructure.

Process

For example, SWEPCO, one of AEP Ohio’s sister companies, recently held outage drills simulating outage conditions on their network. In the first drill, the Dispatcher on duty knew of the drill, but the field personnel did not. Only when field personnel were dispatched to the “trouble” area, did the Dispatcher lay out the particular drill scenario of a smoking manhole. The drill was successful in that it revealed some opportunities to improve the restoration process. (For example, the drill revealed an issue with manhole labeling that hindered the ability of the field force to locate a particular manhole.) SWEPCO made some adjustments to its restoration process based on learnings from the first drill and conducted a second drill.

Findings from the two drills were taken to the Distribution Leadership Team, and lessons learned were shared across all operating companies, with specific recommendations on how to conduct drills and what items needed to be refined in such drills. There is discussion at AEP Ohio that training personnel may play a role in formulating and running outage drills in the future in coordination with Dispatchers.

6.12.2 - Ameren Missouri

Operations

Outage Drills

People

Ameren Missouri does not have documented procedures for responding to outages of different types related to the network.

Process

While Ameren Missouri does perform periodic outage drills, these drills have not historically involved the network.

6.12.3 - CEI - The Illuminating Company

Operations

Outage Drills

People

Outage Drills are conducted and led by the Regional Dispatch Office (RDO), and involve the UG Network Services department, as well as other departments at CEI.

Process

CEI conducts outage drills annually, and is required to do so by the Ohio utility commission (PUCO), if they don’t experience a major storm^[1] . These drills typically do NOT simulate the loss of the network, but do include simulating the loss of underground radial feeders.

CEI has black start plans and conducts black start drills. However, the RDO and UG Network Services department are not included in black start drills.

Technology

CEI is using an outage management system (OMS) called Power On. CEI utilizes its outage management technology in conducting outage drills.

^[1] Major storm defined as having 6 % or more of their customers (43000 customers) out of service

6.12.4 - CenterPoint Energy

Operations

Outage Drills

People

CenterPoint conducts periodic Emergency Operation drills, led by the Energy Control Dispatch Center (ECDC). These drills include practicing hurricane preparedness activities.

CenterPoint also conducts periodic “Blackstart” training.

Major Underground maintains an Emergency Operations Plan document.

Process

CenterPoint Emergency Operation drills typically do NOT simulate the loss of the network.

Technology

CenterPoint maintains a fully function backup control center in the event of the loss of the primary control center.

CenterPoint uses a simulator to aid them in Blackstart training.

6.12.5 - Con Edison - Consolidated Edison

Operations

Outage Drills

Process

Distribution System Operation under Contingency Conditions

Con Edison has a specification that provides guidance for actions to be taken and activities to be pursued by the Electric Operations, System Operation, and Substation Operations when unusual operating conditions, such as multiple contingencies above the design criteria and/or elevated system loading, arise on the distribution system. The document includes guidelines for emergency cooling of network transformers, outlining different methods for cooling, and describing in what circumstances to use each method.

The document includes sections that describe actions that should be taken in the event of first and second contingencies for networks of different voltages and substations, including information that should be gathered, people to be notified, and factors to consider.

For example, in a first contingency condition on a 13-kV network, where a network feeder opens automatically, some of the actions that should be taken include:

Examine the RTF application (where available), and determine the type of fault (for example, single-phase, double-phase, or three-phase) and a calculated fault location.
Examine relay targets and determine the type of fault (for example, single-phase, threephase, instantaneous with ground, or time delay with ground).
Process the feeder, and identify the component that failed (for example, cable, splice, transformer, or transformer termination. Also, if it is a single-phase or three-phase cable or splice).
Correlate the identified failure with the RTF application and the feeder relay targets. If they do not correlate, consider performing a modified HIPOT after repairs are completed.
Complete repairs, remove feeder grounds, and apply Ammeter Clear Test and modified HIPOT test.
Monitor system conditions for possible overloaded equipment (from Con Edison ’ s RMS).
Identify and investigate open network protectors.
Replace network protector blown fuses reported by RMS.
Review RMS data (Visual WOLF) and exception data to identify potentially overloaded feeder sections and transformers.
Review the next-worse contingency scenario in anticipation of an additional feeder out of service.

The document also provides guidance for operators in making the decision to initiate and execute a network shutdown if necessary.

Generator Maintenance

Con Edison maintains several emergency generators to be used at certain key customer sites in case of an outage. The Field Engineering group is responsible for maintaining these emergency generators. This maintenance includes monthly inspections, quarterly load tests, and annual drills where the generators are physically moved to the site and connected to the customer’s system. In order to expedite the connection of these generators in an emergency, the customers have specially designed features at their service connection points that enable a quick connection of the generators to their systems.

6.12.6 - Duke Energy Florida

Operations

Outage Drills

People

Working closely with the DCC, the network group is responsible for emergency preparedness and response for issues in the network.

At the time of the practices immersion, Duke Energy Florida had no written guidelines or procedures for responding to emergencies in the network, such as for a smoking manhole or loss of the network. They do have written guidelines for substation level outages. In the rare historic cases where they have experienced trouble, they have relied on experience.

Duke Energy Florida has recognized the need to document emergency response procedures for the network, including a black start, and responding to a smoking manhole condition. The development of these procedures is an item that will be addressed as part of their network revitalization plan. (See Network Revitalization – Florida Primary and Secondary Network Improvement Plan)

The Duke Energy Florida training matrix for network workers does include training courses that prepare workers for emergencies, such as manhole rescue training.

Annually, a Senior Network Specialist, with the assistance of a Network Engineer, will provide training for DCC dispatchers, both training for new hires and refresher training for dispatchers. This is done on an as need basis, and occurs annually. This training includes bringing dispatchers into the field, as well conducting training within the DCC.

Process

Duke Energy Florida does perform extensive storm preparedness and hurricane preparedness drills. These drills involve simulated major events, including populating OMS with changing weather conditions, areas affected, predicted storm surges, etc. Every employee has a role, with documented lists of responsibilities. For example, the Network Specialists and Electrician Apprentices within the Network Group would typically have responsibility for network feeders in these drills. At the end of the Simulation, employees are asked for lessons learned and improvement suggestions. After the last simulation, for example, questions were raised about how to handle oil spills from switchgear in the event of storm surge flooding of manholes/vaults. The company responded by developing a comprehensive Storm Surge Process document for use in the field that documents and prioritizes roles and responsibilities.

Historically, these drills have not included the case where the network feeders are out of service. The thinking has been that if you lose a network feeder, it will probably be as a result of a problem “above” the feeder level, such as the loss of the substation. However, the developers of these drills do plan to include network scenarios in future drills.

In a network emergency, an expert within the Network Group would provide guidance to the crews, especially if new members join the organization, including how to bring feeders back online. This is often done in the field at specific locations. These on-site scenarios are coordinated with Dispatch.

All network supervisors have dedicated On-Call and On Duty time slots to insure emergency response coverage at all times. “On-Call” means that personnel are expected to respond in case of emergency. “On-Duty” personnel report on-site and actively monitor systems for trouble.

Duke Energy Florida also has an automated robo-call system (ARCOS), capable of delivering 100 phone calls at once, to bring network crews in during emergencies. Network crew members have a contractual obligation to respond to a predetermined percentage of calls. The Network Group has very good callout response.

Technology

Duke Energy Florida uses ARCOS to handle worker call outs in response to outages after hours. ARCOS is a Software as a Service (SaaS) solution for utilities to respond, restore and report in real-time for day-to-day events and emergencies. The software is cloud-based and include callout, scheduling, and crew management functions. ARCOS lists of crew members with skills and contact information are populated by Duke Energy Florida and updated as crew member information and job skills change.

Duke Energy Florida is investigating the application of self -ventilating manhole systems, though hadn’t installed any at the time of the practices immersion. They noted that their manhole tops are not designed with “lips,” making the installation of a manhole restraint system that requires modifications and connection to the manhole cover frame much more problematic. To add the lip to the existing opening would result in an opening which is too small (29 ½ inches). Consequently, to install self-venting manhole systems that require the lip for retention requires a change out of the manhole roofs, a costly effort.

6.12.7 - Duke Energy Ohio

Operations

Outage Drills

People

Duke has documented procedures for responding to emergencies of certain types. For example, they have a procedure for responding to a secondary cable fire , a procedure for responding to a manhole fire (See Attachment I ), and a procedure for operating the network under emergency conditions (See Attachment J). Documentation of emergency response procedures is the responsibility of the Network Planning Engineer

Process

Duke Energy Ohio does perform periodic black start drills. Network feeders are not included in black start drills.

6.12.8 - Energex

Operations

Outage Drills

People

Disaster and emergency drills for the CBD underground network are the responsibility of the Network Operations group, part of the Service Delivery organization at Energex.

Process

Evaluators and switching coordinators within the control center run yearly preparedness audits prior to the peak summer demand season (see Figure 1). They work on the company-wide Energex Emergency Preparedness Committee and the Summer Prep Steering Committee, which includes the CEO. The group runs two simulation exercises, which simulate a test of the full end-to-end process for a major storm. The simulation runs from operations down to the street-level with dispatches of crews to “affected” areas in the scenario.

Figure 1: Energex Summer Preparedness Plan

The group also performs system re-start drills. Contingency plans are also reviewed on an annual basis that takes into consideration various scenarios, such as loss of supply to substations. All contingency plans are N-1 in nature. Generally speaking, Energex does not have any N-2 contingency plans formalized. However, if network planning and project maintenance call for an N-2 situation, there are engineers in the network operations center who formulate load flows and contingency plans to address the N-2 situation.

6.12.9 - Georgia Power

Operations

Outage Drills

People

Troubleshooting and restoration of outages falls primary with the Georgia Power Underground Network Operations and Reliability group, part of Network Underground. The group is supported by field maintenance and trouble-shooting crews comprised of Cable Splicers, Duct Line Mechanics, WTOs, and their supervisors. The Operations and Reliability group is responsible for issuing clearances and directing maintenance crews to affected areas of the network.

Georgia Power has developed a Contingency Plan, available internally in print and on line, which describes actions to be taken in the event of an emergency. The plan guides decision makers in various situations, such as the loss of multiple feeders, loss of a vault due to excessive flooding, loss of a network substation, and other scenarios extensive flooding of a network.

Georgia Power is active with the Southeastern Electric Exchange (SEE), a consortium of companies (trade association) who collaborate on mutual issues. SEE has a Network Underground Committee, and Georgia Power has developed relationships with other utilities who could possibly help if outside assistance is needed for major trouble on the network. SEE also has a Mutual Assistance Committee which could help coordinate that assistance.

Process

The Operations and Reliability Group has performed outage drills in the past, but does so infrequently.

6.12.10 - HECO - The Hawaiian Electric Company

Operations

Outage Drills

People

HECO does conduct annual Outage Drills that test their use of the Incident Command System. These drills involve most everyone in the company, including the Dispatch Center and the C&M Underground group.

Process

HECO conducts outage drills annually. These drills typically do NOT simulate the loss of the network, but do include simulating the loss of underground radial feeders.

Technology

HECO utilizes its outage management technology in conducting outage drills.

6.12.11 - National Grid

Operations

Outage Drills

People

National Grid has documented procedures for responding to network emergencies of certain types.

Procedures for shedding and restoring network load are maintained on the Regional Control Center. Other procedures such as responding to a fire in a manhole are held by the underground group common and often part of the electric operating procedures (EOP).

Process

National Grid performs annual table top drills to practice response to network emergencies. These annual network drills mock specific scenarios such as peak loading conditions, feeders out of service, equipment fires, load shedding, etc. National Grid operations resources practice the various steps associated with restoration. The annual drill conforms to a regulatory requirement in the State of New York.

In addition, once every five years, National Grid conducts a more detailed drill that includes network outage situations. These drills go well beyond the tabletop exercises, including things such as dispatching crews to specific locations. These drills are not mandated.

6.12.12 - PG&E

Operations

Outage Drills

People

PG&E has documented procedures for responding to emergencies of certain types. For example, they have a procedure for responding to a manhole fire, and perform periodic table top drills to practice and train.

Process

PG&E performs table top drills to practice response to certain emergencies such as manhole fires.

6.12.13 - Portland General

Operations

Outage Drills

People

Emergency preparedness and response in the network is a shared responsibility among multiple groups, including the System Control Center (SCC), Distribution Engineers, and the CORE underground group.

In the case of a smoking manhole or other manhole event, the load dispatcher in the SCC informs the duty general foreman (DGF), who assembles the appropriate field crews to respond to the event.

Process

The response depends on the situation. As an example, PGE described a situation where they had a smoking manhole, and lost two of four primary feeders supplying a network. After conferring, the distribution engineer and load dispatcher decided to drop the network to avoid overloading of the equipment. PGE relies on the experience of its people to make these decisions and has not developed written guidelines related to unforeseen events occurring on the network, such as when to drop the network or how to respond to a smoking manhole.

During an emergency,PGE follows the principles of the incident command system (ICS). Employees are well-versed in ICS at the management level.

Fire Department Training: PGE coordinates with the Portland Fire Department (PFD) for training and covers what actions to take if there is a fire in a vault or manhole. PGE used to run exercises on a yearly basis with the PFD and intends to reestablish these. If a vault rescue is needed, the Portland Fire Department (PFD) utilizes their own rescue equipment. The PFD’s response time is good because they operate from locations across the downtown area.

Technology

PGE uses solid 32 in. (81 cm) diameter manhole lids with venting holes. PGE is testing various manhole lid retention systems to prevent covers from being launched into the air during events.

6.12.14 - SCL - Seattle City Light

Operations

Outage Drills

People

SCL’s procedures for responding to network emergencies are not formally documented. SCL does not perform regular drills to practice restoration procedures to the network. Note that SCL Operators do conduct routine outage drills / blackstart drills; however, these drills normally are not focused on responding to network problems.

Technology

Operations Practices — Vault / Network Fires

SCL’s current design standard calls for fire protection heat sensors and temperature sensors in their vaults. The heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225°F. The temperature sensors send an alarm to the dispatcher at 40°C. (SCL utilizes temperature sensors in about 20% of their network transformer locations. They are actively adding locations, with a goal of 100% coverage.)

SCL does not have a written procedure for responding to a vault fire. Although their operators do have the authority to drop load in an emergency, they do not have a protocol to guide them as to whether or when they should drop load in response to a fire. Note that because of the “sub-network” design, with each secondary network completely separated from the other, a complete network outage due to a fire would be limited to the customers served by that one sub-network, with the other networks unaffected.

6.12.15 - Survey Results

Survey Results

Operations

Outage Drills

Survey Questions taken from 2018 survey results - safety survey

Question 12 : Do you periodically conduct a network exercise (drill) for responding to a safety emergency in a manhole, vault, or multi-level vault?

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 28 : Do you perform periodic drills that include network situations, such as a network outage or network manhole fire?

Question 29 : If you perform emergency drills that involve the network, do you sometimes involve other stakeholders, such as first responders (such as the fire department)?

Survey Questions taken from 2015 survey results - Operations

Question 117 : Do you perform periodic drills that include network situations, such as a network outage or network manhole fire?

Question 118 : Do you perform a network emergency drill at least once a year where your company will simulate a network emergency with key individuals in a room and everyone discusses how they would respond?

Survey Questions taken from 2012 survey results - Operations

Question 7.11 : Do your company’s periodic outages drills normally include network situations?

Survey Questions taken from 2009 survey results - Operations

Question 7.11 : Do your company’s periodic outages drills normally include network situations?

6.13 - Outages - Restoration

6.13.1 - AEP - Ohio

Operations

Outages - Restoration

People

Troubleshooting and restoration of outages is primarily the responsibility of the Network Mechanics and Network Crew Supervisors. Network Engineers and the Network Engineering Supervisor may also be involved troubleshooting and restoration.

Process

A key responsibility for each AEP network grid operating company is “Preparedness for Network Event,” including troubleshooting, outages, and restoration. Each local operating company has procedures in place for responding to such events.

For example, AEP Ohio has developed a procedure for responding to a fire in a spot network at a customer site. The procedure includes “first responder authority,” which empowers AEP field personnel to make the decision of whether to drop network feeders, if necessary, to protect the system, customers, and employees, or for quicker problem resolution. This procedure was developed in response to learnings from post-analyses of events that have occurred on the AEP system.

AEP Ohio has also developed a guideline for responding to “smoking manholes,” which is also based on post-event analyses and critique. This guideline includes steps for dealing with smoking manholes in both single and double contingency operations. The guideline was presented to the Network Standards Committee at AEP, which includes representatives from all AEP operating companies with network grids. These members hold regular teleconference meetings to tackle issues such as troubleshooting, outages, and restoration. The smoking manhole guideline from the Standards Committee and its members was sent to the Distribution Leadership Team (DLT), which includes all the vice presidents of the operating companies, for discussion and input. The DLT members are also invited to the regular Network Standards Committee teleconferences. After consideration, the smoking manhole guidelines were adopted and approved. (See Attachment I and Attachment J : Single Contingency and Double Contingency Guidelines.)

6.13.2 - Ameren Missouri

Operations

Outages - Restoration

People

Troubleshooting and restoration of outages may involve multiple groups at Ameren Missouri.

Traveling Operators and Distribution Service Testers are typically involved in troubleshooting, clearing and fault locating on the primary distribution system supplying the network.

Secondary troubleshooting is the responsibility of the Underground Construction department.

In a network outage, the dispatcher in the SDC would first call a supervisor within the either the Service Test group or the Underground Construction department depending on the nature of the outage.

The Ameren Missouri SDC includes dispatchers who prepare switching orders to direct switching and tagging, and issue clearances. Traveling operators perform the switching, Distribution Service Testers locate faults and repair network equipment (non cable), and Cable Splicers within the Underground Construction group repair cable and prepare splices.

Restoration activities may involve the network engineers in the Underground Division, who may be consulted for guidance in reconfiguring the system to restore service.

For outages involving major customers, Major account representatives are involved in coordination with customers throughout the restoration.

Process

While Ameren Missouri does perform periodic outage drills, these drills have not historically involved the network.

Technology

Traveling Operators and Distribution Service Testers have mobile data terminals installed on their trucks.

Ameren Missouri does have a group pickup switch for their networks.

6.13.3 - CEI - The Illuminating Company

Operations

Outages - Restoration

People

Outage restoration of the underground system is performed by the UG Electricians within the Underground Network Services Department, working closely with the Distribution System Operators (DSO’s) in the Regional Dispatch Office (RDO).

Unplanned network outages in Cleveland are rare and almost never result in customer interruptions. The same is true for major customers served by CEI’s 11kV sub-transmission system.

The RDO employs two Outage Coordinators who coordinate planned interruptions, including the drafting of the appropriate switching orders.

Process

The UG Network Services department assigns a crew to a “trouble shift” each day. In the event of an outage or other problem, the DSO will contact the trouble shift on duty to respond. The trouble crew works directly for the DSO in responding to trouble. In a larger event, additional crews will be called in, as required.

In a large outage restoration, the RDO assigns an individual to keeping the outage management system up to date with estimated restoration times (ETR). These times are entered on the trouble tickets themselves, and can be automatically provided to customers who call in through CEI’s Interactive Voice Response (IVR) system. Note that CEI has deemed the provision of ETRs to customers an important enough task to assign a full time resource to this responsibility.

Technology

CEI is using an outage management system (OMS) called Power On. In addition, they utilize an Interactive Voice Response System (IVR) that can record “no light” calls, automatically feed their outage management system to support automated prediction, and provide ETRs to customers.

6.13.4 - CenterPoint Energy

Operations

Outages - Restoration

(Troubleshooting / Outages)

People

Troubleshooting of the underground system is performed by both Troubleshooters who are part of the Dispatching organization and the Major Underground construction groups (Cable and Relay groups) working closely with the Energy Control Dispatch Center (ECDC).

In general, the responsibility for troubleshooting three phase underground infrastructure lies with the Major Underground group.

The responsibility for troubleshooting outages on overhead and single phase underground facilities lies with the Troubleshooter position, a union position reporting to the ECDC. These ECDC Troubleshooters will coordinate with Major Underground on certain outages.

Major Underground schedules crews to work on second shift (4pm to midnight) as part of its normal work schedule. This work force consists of ten Cable Splicers and from two to four Relay personnel. The second shift positions are posted positions. These crews are assigned schedule work and serve as Major Underground trouble shooters for outages that occur on second shift.

For night time outages (after midnight), the dispatcher would contact the crew leader or operations manager on duty (crew leaders and operations management rotate call out duty on an eight week rotation). This individual would call out the appropriate resources to respond to the trouble.

During major events, CenterPoint Major Underground crews will work 16 hour shifts.

Process

The Major Underground group is responsible for troubleshooting outages within the three phase major underground system.

Troubleshooters, a union position reporting to the ECDC, will troubleshoot outages with overhead and single phase underground infrastructure. These Troubleshooters work as one man crews, usually out of a pick up truck. In some cases they will work out of a telescopic bucket truck.

ECDC Troubleshooters deal mostly with overhead and single phase underground, infrastructure that is not the responsibility of the Major Underground Group. However, if there is a blown riser fuse on a three phase riser pole (normally the responsibility of the Major Underground group), the troubleshooter will be sent, and may attempt to refuse. In this case the Dispatcher will contact Major Underground for permission to operate the fuse. If the Troubleshooter finds all three phases of the riser pole have blown, he will not work it - the Major Underground group will be called to trouble shoot the problem.

With respect to network infrastructure, the troubleshooters do not respond to problems in spot networks, or the secondary network grid system. For outages in the network, Major Underground has responsibility for trouble shooting all three-phase underground infrastructure.

Technology

CenterPoint utilizes a “home grown” outage management system. This system has a prediction engine that creates cases for each suspected trouble location. It is tied to SCADA, in that Breaker trips and lockouts are displayed in the OMS. It is further linked to CenterPoint ’s “graphical switching” system.

CenterPoint’s graphical switching system, developed by CES (now Oracle), is tied in with both their outage management system and GIS system to display up-to-date maps on the wall. This system updates the digital maps as switching is performed. For example, during an outage restoration, as circuits are sectionalized, these changes are recorded in the Outage Management system, and the Graphical switching system displays an up to date map of the distribution system.

However, the “dedicated^[1]” underground system, including network secondary systems, is not displayed in the graphical switching system. This is in part because the foundation for this system is the GIS system (ESRI) and at the time the graphical switching system was installed, the GIS system had not yet been up dated with the “dedicated” underground facilities.

CenterPoint’s GIS system is ESRI. The GIS has been updated to include dedicated underground facilities, and CenterPoint intends to implement graphical switching for this distribution. CenterPoint has not fully implemented GIS for underground because the congestion inherent in underground systems and the looped nature of network systems makes both the display and the electrical connectivity of the GIS model complex.

CenterPoint is using mobile data units in its troubleshooter vehicles and in the trucks in the Major Underground Relay group. These units enable no lights cases to be “dumped” to a mobile data unit located in the truck, rather than dispatching the troubleshooter by radio. However, trouble is normally dispatched to the Relay group (Major Underground) by radio (voice), except in major events where underground resources may support the service centers.

^[1] The term “dedicated” underground at CenterPoint refers to three phase infrastructure is located entirely underground in their ducted manhole system. A “dedicated” network feeder does not mean that the feeder serves only a network; rather, it refers to a feeder that is entirely underground. In fact, at CenterPoint, feeders that supply the underground network also supply radial load along the way.

6.13.5 - Con Edison - Consolidated Edison

Operations

Outages - Restoration

People

Con Edison’s System Operations Control Center has control of primary feeders. If a feeder trips, it is the responsibility of this control center to clear the feeder. More specifically, the System Operations Control Center is responsible for tasks such as troubleshooting the feeder, applying grounds, performing testing, and using Con Edison’s Reactance to Fault (RTF) system to predict the location of the fault.

Process

Outages

Because of Con Edison’s network design and N-2 contingency planning, most faults that result in feeder lockouts (“Open Autos,” in Con Edison lexicon) do not result in customer outages. For reports that do come in from customers, a ticket is created by the Con Edison Call Center in their outage management system with a customer address. The linkage between the customer’s account and the electrical location is not automatic. The Distribution Operator adds a structure number to the outage ticket, indicating the location on the electrical system. When this assignment is complete, information about these outage tickets can be displayed on the map. Con Edison is working on automating the process for assigning a structure number to a customer address.

When the fault is located and the feeder is scheduled for work, the System Operations Control Center hands the feeder over to the Manhattan (or other regional) Control Center to accomplish the work.

When work is done, the Manhattan Control Center gives control of the feeder back to the System Operations Control Center. System Operations verifies that the feeder is ready to be re-energized by test, and then puts the feeder back in service.

Con Edison Operators can view the status of feeders on their “Feeder Board,” available through their Heads Up Display (HUD). One feature of this display is that if two feeders are out of service, the feeder board highlights common holes — that is, vaults or manholes that contain both out-of-service feeders.

Con Edison carefully manages the time of the outage of a feeder. Feeder restoration time during hot periods at Con Edison has been significantly reduced, from about 36 hours to around 13 hours on average. The utility’s target is to have feeders out of service for no more than 14.7 hours during high temperatures. (14.7 hours was arrived at by targeting reductions in the various components that comprise outage duration.). Note that this target applies to both unplanned feeder outages (Open autos) and planned outages.

Distribution System Operation Under Contingency Conditions

Con Edison has a specification that provides guidance for actions to be taken and activities to be pursued by the Electric Operations, System Operation, and Substation Operations when unusual operating conditions such as multiple contingencies above the design criteria and/or elevated system loading arise on the distribution system.

The document includes guidelines for emergency cooling of network transformers, outlining different methods for cooling, and describing in what circumstances to use each method.

The document includes sections that describe actions that should be taken in the event of first and second contingencies for networks of different voltages and substations, including things such as information that should be gathered, people to be notified, and factors to consider.

For example, in a first contingency condition on a 13 kV network, where a network feeder opens automatically, some of the actions that should be taken include:

Examine the Reactance-to-Fault (RTF) Application (where available), and determine the type of fault (i.e., single-phase, double-phase, or three-phase) and a calculated fault location.
Examine relay targets, and determine the type of fault (i.e., single-phase, three-phase, or instantaneous with ground or time delay with ground).
Process the feeder, and identify the component that failed (i.e., cable, splice, transformer, or transformer termination. Also, if it is a single-phase or three-phase cable or splice).
Correlate the identified failure with the RTF application and the feeder relay targets. If they do not correlate, consider performing a modified Hi-pot after repairs are completed.
Complete repairs, remove feeder grounds, and apply Ammeter Clear Test and modified Hi-pot test.
Monitor system conditions for possible overloaded equipment (from Con Edison’s Remote Monitoring system).
Identify and investigate open network protectors.
Replace network protector blown fuses reported by RMS.
Review RMS data (Visual WOLF) and exception data to identify potentially overloaded feeder sections and transformers.
Review “next worse” contingency scenario in anticipation of an additional feeder out of service.
Etc. (This is only a partial listing of actions)

The document also provides guidance for operators in making the decision to initiate and execute a network shutdown if necessary.

Technology

Reactance to Fault Application – RTF

Con Edison is using a system that predicts the location of faults on the system based on an analysis of the electrical waveform at the time of the fault. The base platform for the system is the EPRI PQ View product, with an add-on called the “Fault Location Module.” The Con Edison system collects and houses the data and manages the waveform of the fault. Con Edison has integrated this model with their mapping system, such that the system can display the prediction of the fault location on their feeder map board. From this system, Con Edison can also view relay targets from a locked out feeder.

Prior to the implementation of this system, Con Edison’s approach to troubleshooting a feeder was to go halfway out on the circuit, and begin tracing and testing. The implementation of the Reactance to Fault (RTF) application enables the utility to pinpoint the location of the fault, significantly reducing the average restoration time. (Con Edison reduced the average restoration time by about one hour!) See Operations Control Centers.

The system also lets an operator know if the fault type is of a hazard level where company safety rules require special precautions for manhole entry, or prevent entry, depending on the specific hazards encountered (called C & D faults in Con Edison lexicon).

6.13.6 - Duke Energy Florida

Operations

Outages - Restoration

People

For network issues, the Network Specialists and Electrician apprentices who are part of the Network Group serve as first responders in a system outage, and are responsible for fault location. For example, Dispatch will send Network Specialists as first responders to a smoking manhole evens. Off hours, such as nights and weekends, Troublemen would serve as first responders.

For non-network issues, such as troubleshooting an automated transfer switch (ATS), Troublemen serve as first responders and are responsible for fault location. Troublemen report to a field supervisor, and are organizationally part of Duke Energy Florida’s PQR&I group. Troublemen work closely with the dispatchers at the DCC.

All supervisors at Duke Energy Florida have an “on call” responsibility. Supervisors rotate their on-duty responsibility.

Process

In Clearwater, the dispatchers at the DCC monitor feeder cables and can identify faults, usually when a breaker trips. In addition, dispatchers may receive indication from remote reporting faulted circuit indicators installed at network feeder sectionalizing switches. In general, the dispatcher relies on field crews to identify which fault indicators (FCIs) are tripped, and locate faults.

Any switching performed on the network during fault events at a site is performed by network work crews in the field. In non-network areas, field switching during fault events will be performed by Troublemen. At remotely operated substations, DCC will open breakers. If manual switching is required at a substation, Substation Electricians are sent to the substation to perform switching. See Operations Practices – Clearances.

Permanent repairs to faults are not always performed immediately when a feeder opens because the network system has enough contingency to pick up the load. In St. Petersburg, when an ATS successfully transfers, crews may also wait until the next day to address the issue. If necessary, crews will identify and isolate the faulted segment to ensure safe delivery of power to customers.

Radial feeders with no contingency will be repaired immediately after fault location by Troublemen and Dispatch.

Technology

Duke Energy Florida has SCADA control and monitoring at its substation breakers. In addition, for network feeders, they have installed remote reporting faulted circuit indicators at network feeder sectionalizing switch locations. These devices are hardwired to pole mounted devices which communicate back to the DCC via a 900 MHz radio system.

Duke Energy Florida has expanded its application of SCADA to monitor and control its automated transfer switches (ATS), which are prevalent in the primary / reserve feeder scheme used to serve customers outside of the network in Clearwater and in St. Petersburg.

Duke Energy Florida’s historic cable design has used separable connectors, such as the use of T-body connections for straight splices. This type of design enables field crews to separate cable sections, facilitating the fault location process.

Duke Energy Florida uses ARCOS to handle worker call outs in response to outages after hours. ARCOS is a Software as a Service (SaaS) solution for utilities to respond, restore and report in real-time for day-to-day events and emergencies. The software is cloud-based and include callout, scheduling, and crew management functions. ARCOS lists of crew members with skills and contact information are populated by Duke Energy Florida and updated as crew member information and job skills change.

6.13.7 - Duke Energy Ohio

Operations

Outages - Restoration

People

Duke Energy Ohio has a troubleshooter position called the “Trouble Man”. Trouble Men report to the Trouble Desk, part of Distribution Operations. Organizationally, Trouble Men are not part of the Dana Avenue underground group, but work closely with Dana Avenue resources in emergency situations. In addition to troubleshooting, Trouble Men perform switching on the system.

The Dana Avenue field force is on a rotating callout list that is based on the hours worked also, field employees can voluntarily carry a pager if they want to get the first call.

Dana Avenue supervisors rotate the callout duty responsibility. If a network cable fails, the trouble desk will page the duty foreman, and the foreman will assemble the necessary crews to respond to the emergency.

Dana Avenue underground crews are also responsible to respond to non-network and emergencies. Cable Splicers and Network Service personnel are normally assigned secondary repairs on the overhead system.

Designers and engineers serve as “Assessors" in an outage. The Network Project engineer, part of the Distribution Design organization, coordinates these Assessors.

Duke has documented procedures for responding to emergencies of certain types. For example, they have a procedure for responding to a secondary cable fire, a procedure for responding to a manhole fire (See Attachment I), and a procedure for operating the network under emergency conditions (See Attachment J). Documentation of emergency response procedures is the responsibility of the Network Planning Engineer.

Process

Duke Energy Ohio does perform periodic black start drills. Network feeders are not included in black start drills.

Technology

Duke Energy Ohio does have the ability to pick up multiple network feeders at one time via a switch at the substation. Training for the Trouble men includes the operation of the group feeder pickup switch.

Duke Energy Ohio has a GIS system and an Outage Management System (OMS). Their GIS system, Smallworld, drives the OMS. Their OMS is called DOMS, and is an Oracle based system.

6.13.8 - Energex

Operations

Outages - Restoration

(Rapid Response)

People

Energex has rapid response crews located in their various service centers, referred to as hubs. The rapid responders are comprised of electrical fitter mechanics, which is the highest capability journeyman position at Energex. (Electrical fitter mechanics are both fully qualified electricians, and fully qualified “fitters,” which refers to line construction and other mechanical aspects of the journeyman level). Within the Central Business District (CBD), substation fitter mechanics, who are qualified to work with the relay operated switchgear (breakers) that are part of three-feeder mesh, serve as rapid responders. Substation fitter mechanics are a bit more specialized than the electrical fitter mechanic position.

Rapid response crews work two shifts, a 6:00 am to 2:00 pm shift, and a 2:00 pm - 10:00 pm shift, 7 days per week. Energex utilizes a “stand by” roster, which it uses to call out to standby rapid response crews on the night shift. Within the Central Business District (CBD), Energex also holds a substation crew (substation fitter mechanics) on standby. Note that workers on standby may take vehicles home with them so that they can respond more rapidly (each crew member takes a vehicle home).

Energex has certain rapid responders who serve as specialists, including responders who address the low-side secondary wiring that goes from devices such as pole mounted re-closers to the control box mounted at the base of the pole.

Energex also has certain rapid responders who specialize in performing voltage investigations. Energex has a high level of voltage complaints / inquiries due to the high level of photovoltaic (PV) system penetration, mainly, roof top solar panels. (Energex, in total, has about 800 MW of distributed PV.) Often, these voltage inquiries are complaints from customers that their PV systems are not exporting into the grid, because of settings in the inverters to assure that voltages stay within the prescribed voltage limits (+/- five percent of nominal by law).

In response to voltage complaints, the rapid responders go out to the site and troubleshoot the problem. The rapid responders may apply voltage / load recording devices at the customer premise or on the low-voltage network to analyze the signal. For the most complicated problems, Energex may involve the Power Quality group for assistance in resolving issues (see Figures 1 to 4).

Figure 1: Energex rapid responder holding a recording device installed at a low-voltage mini pillar, in response to a customer voltage inquiry

Figure 2: Note the simple, but innovative extension collar placed on top of the mini-pillar, allowing room for the recording device to be placed inside the pillar

Figure 3: Rapid response bucket truck

Figure 4: Ladder truck used in the CBD

Process

Rapid responders work at all sorts of facilities, including low voltage, medium voltage, high-voltage substations, performing switching, making repairs, etc. Rapid responders typically are assigned maintenance work to fill the gaps between rapid response opportunities.

Technology

Rapid responders work in two-man crews and are assigned a bucket truck in the suburban and rural areas and either a specialized van, or ladder truck within the CBD.

Rapid responders utilize a mobile dispatch system called Field Force Automation, a Ventyx System.

6.13.9 - ESB Networks

Operations

Outages - Restoration

People

Network operations at ESB Networks, including troubleshooting and outage restoration, are the responsibility of Operations Managers and Customer Service Supervisors, part of the Operations Group. Organizationally, the Operations group, part of Asset Management, is comprised of two Operations Management centers, one North and one South, a System Protection group, an Operations Policy group, and a Systems Support group.

ESB Networks has two central operations centers, North and South, but it is soon moving to a single central control center. ESB Networks has a Customer Services Supervisor for each of its 35 MV geographic areas, who focus on MV and LV distribution.

Process

Outage calls from customers are entered into the ESB Networks OMS system. Their customer record, in SAP, is tied to OMS, such that each customer can be linked to its electrical location, enabling ESB Networks Network to know which MV station each customer is fed from.

OMS is used by where control room operators and Customer Services Supervisors to track outages. The system issues an order to the ESB Networks Dispatch Centre, which is also housed in the Operation Centre. Dispatchers issue orders to Operators to investigate outages during normal working hours, or to Network Technicians to investigate outages at night.

Control room operators update OMS to reflect the real time conditions of the system, as they sectionalize to restore customers. The OMS is also used to develop switching orders for the MV system.

In the case of a wide-spread outage, incoming calls are pushed to an interactive voice response (IVR) system that gives them specific outage information and the estimated time for recovery. Through its IVR, ESB Networks provides a default ETR of 2 hours for a fault in a rural area, and 1 hour for a fault in an urban area. Network Technicians or field operators can override the system ETR with a realistic estimate after arriving at the site.

ESB Networks has a good track record for restoration. Tariffs of €8 per customer out and €10 per hour of outage are assessed by the regulator.

Technology

The ESB Networks OMS system is tied to its extensive SCADA network, and breaker operations are represented in the OMS in real time.

ESB Networks has implemented OMS On line, a tool that enables any employee to go into the system and view MV outages, as well as comments and other information associated with the outage.

At the time of the immersion, ESB Networks was implementing Power Check, a system that provides a view of outage conditions to the customer via the computer or through a smart phone app.

6.13.10 - Georgia Power

Operations

Outages - Restoration

People

Troubleshooting and restoration of outages falls primarily with the Georgia Power Underground Network Operations and Reliability group, part of Network Underground. Test Engineers, who are part of the Operations and Reliability group serve as first responders. The Network Control Center is responsible for issuing clearances and directing maintenance crews to affected areas of the network. The Operations and Reliability group is supported by field maintenance and trouble-shooting crews comprised of Cable Splicers, Duct Line Mechanics, WTOs, and their supervisors.

Process

In the event of an outage, Test Engineers serve as first responders, and crews are mobilized and dispatched when needed to repair and restore service.

Because the Georgia Power underground network is designed to N-1, it has seen few outages that result in full customer outages. In case of an outage, the Operations and Reliability group can re-route network load to other networks when possible.

UG resources are sometimes called upon to work as overhead service repair crews during storms. Georgia Power will assemble two man crews assigned to a small bucket truck to focus on service repair (from the transformer to the house). Once per year, UG employees are re-certified to be able to use a bucket truck.

Technology

The Georgia Power Operations and Reliability group has an extensive Network Control Center for monitoring and troubleshooting its network underground systems. During peak loading periods, resources within Operations will perform analyses of forecasted loads and system limits to assure that there is adequate reserve capacity in normal and first contingency conditions.

Georgia Power has mobile transformers for backup of some substations and is in discussions with neighboring utilities for cooperative service sharing of power transformers in case of emergency.

During emergencies where additional manpower is needed, the company initiates its ARCOS callout system. This automated phone system calls the roster of “on-standby” personnel and directs them to call their supervisors for instructions. Maintenance crews and other designated personnel are expected to be on stand-by and have a response requirement: they must respond to at least 50 percent of all emergency, off-hours calls annually. Georgia Power also has a volunteer list for those who want overtime, and volunteers are first in the ARCOS calling queue. Note that all employees of a classification are grouped together for call out, even if they work in different groups.

6.13.11 - HECO - The Hawaiian Electric Company

Operations

Outages - Restoration

People

HECO utilizes an employee classification called “Primary Trouble Man” or PTM. PTM’s are responsible for operating the distribution system, responding to trouble, and for obtaining clearances and placing safety tags. Organizationally, the PTM’s are part of the Construction and Maintenance organization, although they work closely with the Dispatchers in System Operations. PTMs work alone as one man crews. They are assigned light duty trucks equipped with the tools they need to perform their job.

Outage restoration of the underground system is performed by a combination of the PTMs, who troubleshoot and sectionalize, and the Cable Splicers in the Underground Group, who make repairs to the underground system. Both of these groups work closely with the Dispatch Center, who manages the restoration.

Process

PTM’s are available as first responders to troubleshoot outages. In some cases the PTM’s can restore service through switching or through making simple repairs. They can often identify and isolate a failed cable section, for example, enabling the UG group to schedule the fault location and cable repair. In other cases, UG Crews must be called in to assist with the repairs during the emergency.

HECO uses an Outage Management system that they report has been “highly useful” for them. The system provides an actual customer count based on the circuit configuration and protective device that operated. The system has representations of entire feeders, and knows which customers are served by what transformers and on what circuits they reside. The system is kept up to date to reflect field conditions.

HECO does not have written procedures to guide the Dispatchers in the event of the loss of all of their network feeders, or how to respond to a network emergency such as a manhole fire.

HECO is currently in the process of updating their written Blackstart procedure.

Technology

HECO utilizes an outage management system (Siemens) to facilitate outage determination and restoration. Their system resides on a circuit model that is built from their GIS system.

The Dispatch Center has two operating engineers who are modeling the OMS system and review the circuit configuration to assure that the circuit models are accurate and functional within OMS. As field changes occur, the Mapping section makes permanent additions or revisions to the circuit models in GIS. The operating engineers then “build” the circuits electrically within OMS.

HECO is in the process of implementing a new customer information system that will tie into OMS.

6.13.12 - National Grid

Operations

Outages - Restoration

People

Troubleshooting and restoration of outages may involve multiple groups at National Grid.

Maintenance Mechanics within NY Underground East are responsible for troubleshooting network feeders, performing switching on the network (outside the substation), and and in performing fault location.

The National Grid Regional Control Center includes Regional Operators who provide switching orders to direct switching and tagging, and issue clearances, and Substation Operators who perform switching at the substations. Field switching is directed by the Regional Operators and performed by the Maintenance Mechanics within the UG group.

Restoration activities may involve the planning engineers, who may be consulted for guidance to reconfigure the system to restore service.

Process

National Grid does perform periodic load shed drills for the network.

When National Grid crews shoot trouble on the underground system, they document their findings on an Underground Trouble / Splice Log. See Attachment H . This procedure is documented in their Electric Operating Procedures (EOP).

Technology

The Regional Control Center uses Small World GIS and power on as their outage management tool.

6.13.13 - PG&E

Operations

Outages - Restoration

People

Troubleshooting and restoration of outages may involve multiple groups at PG&E.

The M&C Electric Network group resources respond to routine emergencies / outages.

PG&E uses a position called a Cableman, part of the Restoration Group (not part of the M&C electric Network organization), who troubleshoot the underground distribution system and perform restoration activities. The cablemen work rotating shifts and provide 24/7 coverage. Restoration activities are directed by the distribution operators.

PG&E Operations Centers include distribution operators who provide switching orders to direct switching and tagging, and issue clearances, and switchmen who perform field switching. Distribution operators work closely with the cablemen and the cable splicers within the M&C Electric Networks group to perform restoration activities and provide support to the M&C Electric Networks group.

Restoration activities may involve the network planning engineers, who may be consulted for guidance in reconfiguring the system to restore service.

For outages involving major customers, Major Account resources are involved in coordination with customers throughout the restoration.

Process

PG&E does perform periodic black start drills. These drills include processes for picking up network feeders.

Technology

Cablemen have mobile data terminals installed on their trucks.

6.13.14 - Portland General Electric

Operations

Outages Restoration

Emergency preparedness and response in the network is a shared responsibility among multiple groups, including the System Control Center (SCC), Distribution Engineers, and CORE underground group.

System Control Center (SCC): The SCC is usually referred to as Load Dispatch, and operators are known as load dispatchers, who are managed by the Transmission and Distribution (T&D) Dispatch Manager. The SCC has two distribution control regions and dispatchers are assigned geographically. From Monday to Friday, two dispatchers cover each of the two PGE regions.

One of the regions and therefore one of the dispatch desks includes downtown Portland and the CORE network. Dispatchers rotate between the two desks so that all dispatchers gain experience working with the network. The SCC employs eight dispatchers total who rotate between the desks on 12-hour shifts. Dispatchers are salaried employees (non-bargaining).

In real time, load dispatchers respond to alarms for feeder breaker lockouts on network feeders. If a network feeder locks out, the dispatcher calls the duty engineer and duty general foreman (DGF) of the CORE underground group. The CORE underground group performs the troubleshooting and determines the restoration approach.

Note that while PGE has a remote monitoring system in its network, it does not send alarms associated with network protector behavior from this system to the dispatchers, as this information could overwhelm the dispatcher. However, dispatchers have access to the remote monitoring system so that they can proactively ascertain conditions on the network.

Line dispatchers know a range of systems, including Maximo, Asset Resource Management (ARM) Scheduler, and ArcFM. They should also understand the PGE-IBEW work rules and related Oregon Public Utility Commission (OPUC) regulations. Line dispatchers must have an associated degree or 1-3 years of experience in a related field.

Distribution/Network Engineers: Three Distribution Engineers cover the underground network and are responsible for supporting the operation of the network, including assisting dispatchers and field force with emergency preparedness and response. The Distribution Engineers are not based in the Portland Service Center (PSC) or CORE group. The Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards, oversees them. The underground Distribution Engineers are qualified electrical engineers.

CORE Underground Group

The craft workers assigned to the CORE group, a part of the PSC, focus specifically on the underground CORE, including both radial underground and network underground infrastructure in downtown Portland. Their responsibility includes operations and emergency response of the network infrastructure. An Underground Core Field Operations Supervisor leads the CORE group. This supervisor reports to the Response & Restoration Area Line Manager (ALM).

Special Tester: PGE CORE has a Special Tester position, who is a journeyman lineman with additional training and technical skills. Special Testers are actively involved with troubleshooting the system, including responding to voltage complaints and fault location. The Special Tester usually partners with cable splicers, working as part of a crew.

Process

In an emergency involving the network, the SCC works closely with the CORE Underground group and Distribution Engineers to respond. The response depends on the situation. As an example, PGE described a situation in which it had a smoking manhole and lost two of four primary feeders supplying a network. After conferring, the distribution engineer and load dispatcher decided to drop the network to avoid overloading of the equipment.

PGE has developed a safety procedure that informs emergency operating procedures for abnormal conditions in the CORE area. The procedure is focused on safety, including guidance for notification and securing the area to protect workers and the public. To develop the incident-specific response, PGE relies on the experience of its people to make these decisions. It has not developed written guidelines related to unforeseen events occurring on the network, such as when to drop the network or how to respond to a smoking manhole.

During an emergency,PGE follows the principles of the incident command system (ICS). Employees are well-versed in ICS at the management level.

Emergency Drills: PGE conducts system-wide outage restoration drills once a year, prior to the fall storm season. In the past, this included some scenarios that involved the CORE network system. The scenarios that impact the network have historically been associated with the substation. PGE also conducts annual earthquake drills, a tabletop exercise that sometimes involves the network substations.

The Business Continuity Group develops and runs emergency drills. While network scenarios have been included at the substation level, these drills have historically not been used to simulate problems with network infrastructure beyond the substation.

Incident Management Center: Portland has seen the United States’ first incident management center to promote disaster preparedness. The center, operated by PGE in partnership with Western Energy Institute (WEI), Concordia University-Portland, and Organizational Quality Associates (OQA), provides training and education for utilities. The new Incident Management for Utilities National Training Center is located at Concordia University’s Columbia River Campus, close to Concordia’s Center for Homeland Security Studies and Homeland Security Simulation Center. The simulation laboratory offers training in incident management and emergency response, sharing instructional resources and supporting mutual aid [54].

Compliance Training: PGE conducts periodic compliance training, including training to assure that employees properly respond to emergencies. Compliance training includes vault rescue, pole top rescue, and all other federally mandated training. The vault rescue class is a company-wide training program undertaken annually, with workers training in a shallow vault. Because the CORE group often works in deeper vaults than the one used in training, it has augmented this training with more specific vault rescue training geared to the network vaults. This training takes place in a live vault. PGE also provides annual computer-based training on confined space practices.

Fire Department Training: PGE may coordinate with the Portland Fire Department (PFD) for training and cover what actions to take if there is a fire in a vault or manhole. PGE used to run exercises on a yearly basis with the PFD and intends to reestablish these. If a vault rescue is needed, the Portland Fire Department (PFD) utilizes their own rescue equipment. The PFD’s response time is good because it operates from locations across the downtown area.

Overhead Training: CORE journeymen need the experience of working on primary overhead lines so that they are qualified to work on the overhead system and participate in restoration work when needed. By design, the CORE supervisor ensures that his journeymen gain this experience on an annual basis through the performance of simulated training. The training yard is used to set up a simulated scenario with de-energized lines so that the journeymen can practice working with overhead systems. Underground linemen generally work in two-man crews on wire-down situations during a storm.

Accident Response: During an accident, PGE procedures dictate that the crew should call the SCC with the relevant information. In addition, either the crews or SCC contact emergency services. The SCC completes an online form that is distributed to approximately 150 people automatically, and calls out the safety coordinator responsible for the network. In addition, PGE has a Crisis Response Team that responds to situations of employee injury. Representatives of this team travel to the hospital with the injured employee and notify the family. Using this team removes the burden from the SCC. This protocol was implemented approximately 10 years ago [51].

Technology

Because of its inherently redundant design, most network system outages do not result in customer outages.

PGE migrated to an Oracle NMS outage management system, which is based upon WebSphere technology [34]. Oracle NMS is a scalable distribution management system that manages data, predicts load, profiles outages, and supports automation and grid optimization. The system combines the Oracle Utilities Distribution Management and Oracle Utilities Outage Management systems in a single platform. The system supports outage response and the integration of distributed resources [35].

Oracle NMS blends SCADA function and geographic information system (GIS) models to combine as-built and as-operated views of the system. The application includes a number of advanced distribution management functions, including network status updates in real time, monitoring and control of field devices, switch planning and management, and load profiling. Oracle NMS can integrate with other SCADA and GIS systems, and monitors network health using data from a number of systems. The NMS includes a simulation mode for training and supports switch planning and control.

Oracle NMS maintains a network model that handles the whole grid, includes every device, and integrates with existing systems using standards-based protocols, such as Inter-Control Center Communications Protocol (ICCP), Common Information Model (CIM), and MultiSpeak-based web services. The system can also integrate with a range of GIS and Advanced Meter Infrastructure (AMI) systems [36].

PGE’s NMS/OMS integrates outage information and location, switching functions, and work management. The system allows operators to see present system status and other operational data, and a data model predicts outage locations [35]. During outage events, operators can manage outage calls, assign and manage crews, and use the Maximo database to locate assets in relation to customers without power. The OMS also integrates with the GIS and Customer Information System (CIS), which allows customers to access outage information [15, 34,]. Other functions within the OMS include the following:

Automatic Vehicle Location (AVL): As part of the new OMS, the AVL allows crew locations to appear on the NMS map. This allows operators to dispatch the closest crew to an outage. Asset Resource Management (ARM): PGE can now route service work and design construction orders through Maximo to WebSphere, and from there to the ARM system. Crew information from laptops can be sent to the system for retrieval. Oracle Utilities Analytics (OUA): Using OUA, operators can view if a crew dispatch is successful, and the system allows crews to view any pending work orders in their feed. Safety functions: The OMS uses the AMI to improve safety during outages. The AMI pings meters to determine on/off status during an outage event, allowing operators to determine if outages can be cleared from the OMS and free crews for other restoration priorities. In addition, meters send a “last gasp” message to the AMI system when they are about to run out of power.

Concordia University-Portland and Western Energy Institute. “Nation’s First Incident Management Center for Utilities Launched.” Press release, April 20, 2015. https://centerforemergencysolutions.com/sites/default/files/Utility-Incident-Training-News-Release.pdf (accessed November 28, 2017).
R. Lewis II. “Mobile Tools Maximize Productivity at PGE.” Transmission and Distribution World, January 27, 2015. http://www.tdworld.com/features/mobile-tools-maximize-productivity-pge(accessed November 28, 2017).
D. Handova, “PGE: Driving Customer Value With Network Management Systems.” EnergyCentral.com. http://www.energycentral.com/c/iu/pge-driving-customer-value-network-management-systems(accessed November 28, 2017).
Modernize Distribution Performance All the Way to the Grid Edge. Oracle, Redwood Shores, CA: 2015. http://www.oracle.com/us/industries/utilities/network-management-system-br-2252635.pdf(accessed November 28, 2017).
Modernize Grid Performance And Reliability With Oracle Utilities Network Management System. Oracle, Redwood Shores, CA: 2014.
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).

6.13.15 - SCL - Seattle City Light

Operations

Outages - Restoration

People

SCL’s procedures for responding to network emergencies are not formally documented. SCL does not perform regular drills to practice restoration procedures to the network.

Process

Outage Drills

SCL does not regularly conduct drills to practice restoration of outages to the network. Note that SCL Operators do conduct routine outage drills / blackstart drills; however, these drills normally are not focused on responding to network problems.

Design

From a design perspective, SCL breaks the network load into small, isolated “sub-networks” to limit the number of customers exposed to an outage in the event of loss of any one sub-network.

Operations Practices — Emergency Response/Restoration

During high load conditions, the System Operator polls the network using the DigitalGrid (Hazeltine) system four or five times a day to understand field loading and voltage conditions. SCL System Operators maintain a list of customers that are fed by each network feeder so that they can contact customers to curtail load during critical periods.

The Operations Center does not have a means for a group load pickup for network feeders, nor a written procedure that describes the processes for responding to a network blackout. The last time they encountered the need to pick up multiple feeders, they sent multiple crews to various locations and performed a countdown — three, two, one, close — to close multiple switches at the same time.

6.13.16 - Survey Results

Survey Results

Operations

Outage Restoration

Survey Questions taken from 2018 survey results - safety survey

Question 18 : For 208 V network protectors, do you de-energize the network transformer before removing the network protector fuses?

Question 19 : For 480 V network protectors, do you de-energize the network transformer before removing the network protector fuses?

Survey Questions taken from 2015 survey results - Operations

Question 114 : For 208 V network protectors, do you de-energize the network transformer before removing the network protector fuses.

Survey Questions taken from 2012 survey results - Operations

Question 7.10 : Do you have documented, up to date procedures for responding to network emergencies?

Question 7.12 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders)

Survey Questions taken from 2009 survey results - Operations

Question 7.13 : Do you have documented, up to date procedures for responding to network emergencies? (This question is 7.10 in the 2012 survey) (This Question is 7.10 in the 2012 survey)

Question 7.14 : Do you have a procedure that provides guidance in responding to vault fires?

Question 7.15 : If so, does it provide guidance to an Operator indicating when it is necessary to de-energize a network due to the emergency?

Question 7.16 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders) (This question is 7.12 in the 2012 survey) (This question is 7.12 in the 2012 survey)

6.14 - Picking Up Multiple Feeders after a Network Outage

6.14.1 - AEP - Ohio

Operations

Picking Up Multiple Feeders after a Network Outage

Technology

As AEP is updating its network substations, replacing mechanical relays with microprocessor based relays, it is installing master trip and close systems for networks that enables group feeder trip or pick up from the distribution control center or the station. The system includes the ability to enable or disable any of the particular feeders in a network group.

6.14.2 - Ameren Missouri

Operations

Picking Up Multiple Feeders after a Network Outage

People

Ameren Missouri has the ability to pick up multiple feeders after a network outage, via a group pick up switch at the substation.

Process

At the substation, Ameren Missouri has the ability to either open an entire network, or close the entire network (all feeders simultaneously) using a group feeder pick up switch.

6.14.3 - CEI - The Illuminating Company

Operations

Picking Up Multiple Feeders after a Network Outage

People

The responsibility for restoring outaged network feeders lies with the Distribution System Operator, in conjunction with the UG network Service Department.

Process

In the event of the loss of all network feeders, CEI does not have a method for picking them up simultaneously. If this were to happen, CEI would have to assign switchman to each feeder and close the feeders individually and simultaneously.

Technology

Network feeders, supplied at 11kV out the Hamilton substation, are not individually remotely controlled through SCADA. The DSO can obtain status information on these feeders and can remotely control the bank breaker at the sub, but not the individual feeders.

CEI does not have the ability to remotely pick up multiple network feeders after a network outage.

6.14.4 - CenterPoint Energy

Operations

Picking Up Multiple Feeders after a Network Outage

Process

In the event of the loss of all network feeders, CenterPoint has a method for picking them up simultaneously. If this were to happen, CenterPoint would close the transformer breaker with the feeder circuit breakers already closed.

6.14.5 - Con Edison - Consolidated Edison

Operations

Picking Up Multiple Feeders after a Network Outage

People

The System Operations Control Center operators.

Process

Outages

Con Edison’s System Operations Control Center has control of primary feeders. If a feeder trips, it is the responsibility of this control center to clear the feeder. More specifically, the System Operations Control Center is responsible for tasks such as troubleshooting the feeder, applying grounds, performing testing, and using Con Edison’s Reactance to Fault (RTF) system to predict the location of the fault.

Because of Con Edison’s network design and N-2 contingency planning, most faults that result in feeder lockouts (“Open Autos,” in Con Edison lexicon) do not result in customer outages. For reports that do come in from customers, a ticket is created by the Con Edison Call Center in their outage management system with a customer address. The linkage between the customer’s account and the electrical location is not automatic. The Distribution Operator adds a structure number to the outage ticket, indicating the location on the electrical system. When this assignment is complete, information about these outage tickets can be displayed on the map. Con Edison is working on automating the process for assigning a structure number to a customer address.

When the fault is located and the feeder is scheduled for work, the System Operations Control Center hands the feeder over to the Manhattan (or other regional) Control Center to accomplish the work.

When work is done, the Manhattan Control Center gives control of the feeder back to the System Operations Control Center. System Operations verifies that the feeder is ready to be re-energized by test, and then puts the feeder back in service.

Con Edison Operators can view the status of feeders on their “Feeder Board,” available through their Heads Up Display (HUD). One feature of this display is that if two feeders are out of service, the feeder board highlights common holes — that is, vaults or manholes that contain both out-of-service feeders.

Con Edison carefully manages the time of the outage of a feeder. Feeder restoration time during hot periods at Con Edison has been significantly reduced, from about 36 hours to around 13 hours on average. The utility’s target is to have feeders out of service for no more than 14.7 hours during high temperatures. (14.7 hours was arrived at by targeting reductions in the various components that comprise outage duration.). Note that this target applies to both unplanned feeder outages (Open autos) and planned outages.

Technology

Picking up Multiple Feeders in the Event of a Network Outage

Con Edison has installed a network start-up and shutdown panel for picking up multiple feeders at one time in the event of the loss of an entire network. The panel brings the controls for all breakers to two points in the station, because stations are designed to service two networks. The panel is connected to the operator at the System Operations Control Center.

Con Edison has a scheme to shed load as the frequency drops or if the rate of change in the frequency exceeds a given threshold. The system prioritizes the feeders that it drops. For example, the scheme sheds overhead load first.

6.14.6 - Duke Energy Florida

Operations

Picking Up Multiple Feeders after a Network Outage

Process

In the event of an outage, field crews would go to each vault and check to see that all protectors are closed with the handles in the auto position. Then, Troublemen at the substation would reenergize two of the three feeders supplying the network (close the breakers) simultaneously. Finally, the third feeder would be reenergized.

Technology

The DCC does have the ability to remotely operate the feeder breaker for the network feeders in Clearwater. They do not have a group feeder pick up switch, to close breakers simultaneously.

6.14.7 - Duke Energy Ohio

Operations

Picking Up Multiple Feeders after a Network Outage

People

Duke Energy Ohio has the ability to pick up multiple feeders after a network outage, via a group pick up switch at the substation.

Duke has a documented process to describe using this feature and periodically tests this functionality.

The training received by every trouble man includes operation of the group feeder pick up.

Process

At the substation, Duke has the ability to either open an entire network, or close the entire network (all feeders simultaneously) using the group feeder pick up switch.

Figure 1: Group Feeder Pickup Switch (Note instructions for correct operations displayed on clip board)

6.14.8 - Georgia Power

Operations

Picking Up Multiple Feeders after a Network Outage

Process

Georgia Power is in the process of installing group feeder switches at select substations to pick up multiple feeders after a network outage. At these substations, Georgia Power would then have the ability to pick up an entire network from another bus segment at the station by closing the feeders simultaneously.

6.14.9 - HECO - The Hawaiian Electric Company

Operations

Picking Up Multiple Feeders after a Network Outage

People

The responsibility for restoring outaged network feeders lies with the Dispatch Center, in conjunction with the C&M Underground Group.

Process

In the event of the loss of all network feeders, HECO does not have an automated method for picking them up simultaneously. If this were to happen, HECO would have to pick up the feeders individually using SCADA, or assign a switchman or PTM to each feeder and close the feeders individually and simultaneously.

Technology

Network feeders can be remotely monitored and controlled through SCADA at HECO.

6.14.10 - National Grid

Operations

Picking Up Multiple Feeders after a Network Outage

People

Distribution operators within the regional control center are responsible for executing network load shed and restoration.

National Grid has a well written procedure that provides operating guidelines for a network load shed and restoration. The guideline includes network primary cable ratings, network secondary cable ratings, detailed descriptions of required operator action in contingency situations, detailed descriptions of the potential results of an various primary feeder contingencies on the network during peak conditions, and procedures the operator must follow in the event that the shedding of network load is ordered.

Process

National Grid does not have a network group feeder pickup switch that simultaneously opens or closes network feeder breakers.

Rather, their procedure requires the opening of substation bank breakers in order to drop network feeder load simultaneously, followed by the opening of the individual breakers, then followed by the closing of the bank breakers to restore any radial (non-network) circuits. The procedure also describes switching to restore network load.

Technology

National Grid does not have a network group feeder pickup switch that simultaneously opens or closes network feeder breakers.

6.14.11 - PG&E

Operations

Picking Up Multiple Feeders after a Network Outage

People

PG&E has the ability to pick up multiple feeders after a network outage, via a group pick up switch at the substation.

Process

At the substation, PG&E has the ability to either open an entire network, or close the entire network (all feeders simultaneously) using a group feeder pick up switch.

Technology

PG&E has embarked upon a five year project to implement a new fiber optic based SCADA monitoring system for their network. The new system will have group open, group close, transfer trip capability, controlled from the operations center.

6.14.12 - Portland General Electric

Operations

Picking Up Multiple Feeders after a Network Outage

People

System Control Center (SCC): Load dispatchers at the SCC have SCADA control of network feeders.

Process

Load dispatchers in the SCC notify the general foreman before they close any breaker to ensure that the crews are not currently working in any of the vaults on that feeder.

Technology

PGE has a simultaneous close capability at its network substations that closes all network feeder breakers at the same time. It does not have a group open switch.

6.14.13 - SCL - Seattle City Light

Operations

Picking Up Multiple Feeders after a Network Outage

Process

The Operations Center does not have a means for a group load pickup for network feeders, nor a written procedure that describes the processes for responding to a network blackout. The last time SCL encountered the need to pick up multiple feeders, they sent multiple crews to various locations and performed a countdown – three, two, one, close – to close multiple switches at the same time.

SCL’s procedures for responding to network emergencies are not formally documented. SCL does not perform regular drills to practice restoration procedures to the network. Note: SCL does document and drill restoration procedures for outages to the non-network parts of their system. These drills normally exclude outages to network facilities.

6.14.14 - Practices Comparison

Practices Comparison

Operations

Group Network Feeder Pickup

6.14.15 - Survey Results

Survey Results

Operations

Picking Up Multiple Feeders after a Network Outage

Survey Questions taken from 2012 survey results - Operations

Question 7.12 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders)

Survey Questions taken from 2009 survey results - Operations

Question 7.16 : Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders) (This question is 7.12 in the 2012 survey)

6.15 - Primary Trouble Man (PTM)

6.15.1 - HECO - The Hawaiian Electric Company

Operations

Primary Trouble Man (PTM)

People

HECO utilizes an employee classification called “Primary Trouble Man” or PTM. PTM’s are responsible for operating the distribution system, responding to trouble, and for obtaining clearances and placing safety tags. Organizationally, the PTM’s are part of the Construction and Maintenance organization, although they work closely with the Dispatchers in System Operations. See Attachment K

PTM’s work alone, as a one-man crew. They will perform switching on HECO’s distribution system up to 25kV. At 15kV they will switch with facilities energized. At 25 KV, PTM’s will only switch de-energized facilities.

PTM’s are assigned light duty trucks equipped with the tools they need to perform their job.

PTM’s receive 6000 hours of training from both HECO and from the State of Hawaii. This includes training and certification from the Northwest Lineman’s College.

HECO has also implemented a training program where Trouble Dispatchers spend time in the field with PTM’s to become familiar with the PTM role and to build relationships between these two key work classification types. (See Trouble Dispatcher Training).

Process

At HECO, PTM’s perform all of the sectionalizing required for the crews to obtain clearance to perform work on a circuit. In contrast to a “substation operator” position common at many utilities, the PTM’s will operate devices out on the distribution system. This includes operating overhead and padmounted switches, cutouts, transformer primary switches, and lifting elbows on dead front equipment. PTM’s will place safety tags at the direction of the dispatcher to indicate isolated cable sections. PTM’s will respond to trouble, determine and isolate the location of faults, and restore service to customers where possible.

PTM’s work very closely and collaboratively with Cable Splicers from the underground group. By focusing on operation of the system, the PTM’s effectively free the UG crews to focus on construction and maintenance activity.

Figure 2: PTM using Chance tester

Figure 2: PTM operating transformer switch

Figure 3: PTM opening cutout

Figure 4: PTM preparing to open padmounted switchgear

Technology

PTM’s are assigned light duty trucks outfitted with the tools and equipment they need to perform their job. These trucks are equipped with mobile data units.

Figure 5: PTM Truck

6.16 - Remote Monitoring - SCADA

6.16.1 - AEP - Ohio

Operations

Remote Monitoring - SCADA

People

AEP Ohio has a remote monitoring system installed in its networks.. The data monitored can vary depending on the level of monitoring in each vault, but includes protector status information, transformer data, and vault sensor information such as thermal event monitoring.

At the time of the practices immersion, monitored data had not yet been made available to the dispatch center, though this is planned for the future. At the time of the practices immersion, AEP Ohio had embarked upon the implementation of a new system that will enhance the monitoring and control capability of the system. This effort, planned for completion in 2018, is being led by the Network Engineering Supervisor and is being supported by a contractor.

Process

AEP Engineers can monitor network protector status, such as voltage, current, and whether the protector is opened or closed, as well as some vault and transformer sensors, such as thermal detection through its remote monitoring system. This system uses the Eaton VaultGard system, which provides data monitoring from the network protector MPCV relays and other sensors and provides a communications platform (see Figure 1).

Figure 1: Wall-mounted control box for Eaton VaultGard

Technology

The enhanced network communications and control system will be built on a redundant, dual-loop fiber-optic network. The new network was successfully piloted in Canton and will be deployed in Columbus.

The new remote monitoring system will expand AEP Ohio’s monitoring and control capability, and engineers are in the process of deciding on the specific items to monitor. Items being considered include traditional measures such as loading, voltage, equipment status, fluid in the vault, fluid in the protector, and fire detection, as well as other measures such as dissolved gas monitoring, and rapid transformer pressure rise monitoring in selected vaults. AEP Ohio is also considering an enhancement that would enable the VaultGard system to gather information to perform secondary diagnostics.

AEP Ohio will have two network monitoring boxes wall-mounted in its vaults. One box contains the fiber-optic termination; the second contains microprocessor controls and interfaces to the network protector and any other remote sensors or controls to be installed in the vaults. Maintenance, inspection, and replacement of communications systems components and batteries are being added to NEED used by AEP for tracking asset inspection information and for managing maintenance.

6.16.2 - Ameren Missouri

Operations

Remote Monitoring - SCADA

People

Ameren Missouri has an existing remote monitoring system installed in their underground network system. This system uses ETI electronic metering in the network protector relay to monitor selected points within the vault, and aggregate them at a collector box mounted on the vault wall. This box communicates wirelessly over the cellular network.

Ameren Missouri implemented the system quickly in the aftermath of a particular event. Their post event analysis revealed that additional monitoring might have prevented the incident. In order to implement remote monitoring of their network quickly, Ameren Missouri visited a neighboring utility and adopted a similar approach.

Process

Using the ETI electronic relay in network protectors as part of its remote monitoring system, Ameren Missouri monitors various points within the vault, including voltage by phase, amps by phase (can monitor even with the protectors open), protector status via a switch installed on the NP handle position, moisture content within the protector, transformer oil top temp and water level in the vault via a float to detect standing water. Note that they are not using fire alarm systems in the vault.

The monitoring points are aggregated at a box mounted on the vault wall that communicates via cellular wireless through a third party called Telemetric. Telemetric is a third party vendor who aggregates the information from the remote monitoring system at their operations center in Idaho, and provides the summary of that information back to Ameren Missouri via software from Telemetric PowerVista by Sensus. See Attachment K.

The remote monitoring system records load readings every 12- 15 minutes and saves hourly averages to Ameren Missouri’s load reporting system. Ameren Missouri has the ability to poll the system to ascertain vault statuses such as NP position or oil top temperature. Ameren Missouri can also obtain graphical displays of historical readings from the system software.

The system issues emails and alarms to key operation supervisors triggered by certain readings, such as whenever a network protector opens.

Note that while the system offers the ability to remotely control the network protectors, Ameren Missouri has chosen not to implement this feature because of security concerns associated with the cellular system and third party involvement.

Ameren Missouri engineers noted that the implementation of this system has helped them identify places in the network where the system may operate differently than expected. They cited spot network locations where protectors were opening under lightly loaded conditions as an example. They also noted that they have changed relay settings on protectors at numerous locations where the system revealed improper settings.

The system has been fully operational for about two years. For the first year after the installation of the remote monitoring system, the information was being monitored by a small group of engineers to work out any problems. After one year, the system was turned over to the System Dispatch Center, with information from the system available to dispatchers via their SCADA screens.

Monitoring Indoor Rooms

Ameren Missouri is also in the process of implementing automated indoor room transfer schemes that would provide the ability to transfer load from the primary to reserve feeder either remotely from the dispatch center, or automatically though a transfer scheme.

Ameren Missouri’s current standard calls for two manual switches. If they lose a radial feeder, they must manually transfer the entire load on that feeder to reserve feeders to restore power and before implementing fault locating. This load transfer process is time consuming.

Ameren Missouri is considering a standard that includes two stand alone switches with an automatic transfer scheme. These new installations would provide a cabinet near the vault door so that the switches could be open remotely from the door as well as from the SDC using remote monitoring and control technology. They are considering an auto transfer scheme where the load swaps to the reserve feeder automatically, and are investigating the role of a DMS to arbitrate these decisions.

Technology

To implement their remote monitoring system, Ameren Missouri replaced all network protector electromechanical relays with electronic relays from ETI. Richards Manufacturing, the maker of the ETI relay, provided wiring and retrofit kits for both the Westinghouse and GE style network protectors.

At the time of the practices immersion, Ameren Missouri was investigating replacing protectors with a style that enables them to rack the breaker off the bus with the door closed and then rack it completely out.

Figure 1: Remote Monitoring Communication Box

Figure 2: Remote Monitoring Communication Box, mounted on vault wall

Figure 3: Indoor Room Transfer Scheme

6.16.3 - CEI - The Illuminating Company

Operations

Remote Monitoring - SCADA

People

The CEI underground system is operated out of the Northern Region Regional Dispatch Office (RDO). Distribution System Operators (DSO) utilizes the company’s EMS system within provides monitoring and control capability.

Technology

CEI has little monitoring and control capability beyond the substation.

Network feeders, supplied at 11kV out the Hamilton substation, are not individually remotely controlled through SCADA. The DSO can obtain status information on these feeders and can remotely control the bank breaker at the sub, but not the individual feeders.

CEI is not utilizing any remote monitoring of network vaults and associated equipment.

Most of the 4kV system (non-network), which services a significant portion of the underground, is limited to status monitoring (open / closed), with no control. Many of these feeders are set with one shot to lock out, with no automatic reclosing.

6.16.4 - CenterPoint Energy

Operations

Remote Monitoring - SCADA

People

CenterPoint has implemented remote monitoring infrastructure in its network vaults. About ten years ago, CenterPoint embarked on a network rehabilitation effort that included replacing all older network protectors with ones that have communication enabled relays. At present, most network protectors in the CenterPoint system can be remotely monitored and controlled.

In addition, CenterPoint is presently expanding the level of monitoring and control beyond network in its larger vaults, to include things such as vault primary breaker status, transformer information (loading, oil temperature, etc), and water level alarms.

The design and implementation of the remote monitoring and control system is being led by a Consulting Engineer within the Major Underground Engineering department. The pulling of fiber to provide the communications backbone for the system is performed by Cable Splicers, with the fiber being pulled through the CenterPoint duct bank system. The Network Testers within the Relay group perform all the installation of sensors and control boxes and make all connections.

Process

All network protectors in the CenterPoint Major Underground system are equipped with communication enabled relays. From these units CenterPoint can remotely monitor network protector status, remotely operate the units, and obtain current and voltage readings.

In practice, CenterPoint is currently using this technology to remotely monitor equipment, but not to remotely control devices, as they have not yet reviewed and revised their clearance procedures to assure continued safe system operation.

The remotely monitored information is available to certain employees within Major Underground, such as planning engineers, and operations managers on the CenterPoint intranet. Alarms from remotely monitored equipment are sent via pagers to Crew Leaders and the duty foremen.

CenterPoint ultimately plans to provide information from their remote monitoring system to the Dispatchers, either directly, or through some other system such as a Distribution Management System. However, at the time of this writing they have not yet deployed remote monitoring of network equipment in dispatch, as they are still in a learning mode. CenterPoint considers this information to be secondary to SCADA as a tool for a dispatcher to monitor and control the system.

Currently, the remotely monitored information is being used as an early warning system. Major Underground resources receive an alarm, and they will respond. However, CenterPoint ultimately plans to use this information to revisit their maintenance approach. They hope to move away from their current cyclical approach to a more “just – in – time ” approach based on real time information about equipment status and condition.

Technology

The heart of CenterPoint’s remote monitoring and control system is the Cutler-Hammer MPCV (micro processor controlled) communication enabled relay, by Eaton. From these units, installed in their network protectors, CenterPoint can remotely monitor network protector status, remotely operate the units (although in practice, they do not), obtain current and voltage readings, and alarm things such as temperature, and water intrusion levels.

CenterPoint is also installing “intelligent” relays (SEL) in vaults to expand their remote monitoring capabilities. For example, in high side spot networks, CenterPoint is replacing electromechanical relays with the “intelligent” relays. Intelligent relays are also being installed in all 34.5 kV vaults. New construction is being designed with intelligent relay panels, even if the fiber backbone is not yet in place, so that they are ready to be connected to the communications system at a later date.

Figure 1 and 2: 'Intelligent: Relay Panel'

The remotely monitored information is available to selected CenterPoint employees through the CenterPoint intranet. The information is communicated via custom software that interfaces with the proprietary information provided by the Cutler-Hammer network protector relays and the SEL relays.

Certain employees can access remotely monitored information on the CenterPoint intranet, using computers in their trucks with wireless capability. CenterPoint reports that most of the Network Testers in the Relay group use this information routinely.

When CenterPoint first implemented the remote monitoring system, the communications medium was a phone line with a modem, tied into a communications module. Today, the main communication backbone is a fiber ring, pulled through CenterPoint’s duct system, which serves the down town and medical center locations. CenterPoint also uses DSL lines at selected locations.

6.16.5 - Con Edison - Consolidated Edison

Operations

Remote Monitoring - SCADA

People

The Distribution SCADA department is made up of 10 engineers, who are responsible for all the Distribution SCADA beyond the area substation.

Process

Con Edison uses a Remote Monitoring System (RMS) in every one of its network transformer vaults to remotely monitor and communicate information back to the office.

Technology

The RMS system uses power line carrier (PLC) technology to communicate monitored information from transmitters located in each vault, over the 60-cycle electric signal, to receivers located at the substation.

The RMS in use at Con Edison was originally designed at Con Edison’s request in the 1970s, by Hazeltine, with installation of devices beginning in 1982. The RMS system is made up of transmitters located in each of the transformer vaults, pick-up coils on every feeder at the substation that detect the PLC signal, and receivers at the substation that gather the information detected for a given network. From the substation, information is communicated back to the central office using telephone frame relay lines (TCPIC lines), that provide near-virtual connectivity, enabling Con Edison to download information from every receiver about every one minute.

At the substations, Con Edison is using receivers developed by Digital Grid. The utility has experienced good performance from these receivers. Con Edison is currently testing a receiver developed by ETI and is in the process of replacing older Hazeltine receivers with these newer units.

At network transformer vault locations, Con Edison uses transmitters from ETI and Digital Grid. Many existing installations are equipped with older transmitters from Hazeltine and BAE. The transmitter is connected to one phase of the network protector. The power connection is to network side of the network protector (always powered), and the signal wire connection is to the transformer side, so that if a network protector opens on light load, there is still a signal. In area substations that supply two networks, the transmitters on each network are connected to and transmit information over different phases.

As Con Edison has been using RMS for years, it has different “generations” of systems in place. In the first-generation installations, the RMS system monitors the three-phase % percent loading, and five status points such as network protector status or transformer temperature alarm status. In the second-generation installations, the RMS monitors three-phase % loading, three-phase voltage, eight status points, and two analog readings. In the latest generation installations, the transmitters have additional processing capability and can monitor things such as transformer tank pressure, oil temperature, and oil level status. The utility is also monitoring the Oil Minder System in those vaults that contain them.

Con Edison is effectively using its intranet to give employees access to this remotely monitored data. The utility has developed an on-line system, Net RMS, which enables all employees to view the information from their computers, including field laptops. The system is tied in with SCADA, so it displays which feeders are open and closed. The system also displays the % offload that will be picked up by the nearby vaults if a given feeder locks out, a useful tool in contingency planning.

Con Edison is planning to expand functionality of its RMS to be able to communicate with the network protector relay, and to gather additional information such as network protector temperature.

6.16.6 - Duke Energy Florida

Operations

Remote Monitoring (SCADA)

(Network Monitoring)

People

Duke Energy Florida performs monitoring of its Clearwater and St. Petersburg network infrastructure at its Distribution Control Center (DCC). The DCC group works closely with the network Group and field crews. While all dispatchers are responsible for monitoring and control of both the entire radial and network systems, select employees at the DCC have extensive network underground experience.

In addition, remote monitoring of network vaults is performed by the Network Group; specifically, Electric Apprentices and Network Specialists who work in that group.

Process

Using a combination of SCADA and Sensus software, Duke Energy Florida has the ability to monitor every network vault supplying the Clearwater network.

Network Protector Monitoring

Duke Energy Florida uses the Eaton VaultGard communication platform for recording and aggregating data from the network protector microprocessor (MPCV) relay as well as from other vault sensors (Qualitrol). This information is communicated through a Sensus cellular monitoring system to a central server every half hour. Within the Network Group, information about the protectors provided by the Sensus system is monitored twice per day (see Figures 1 through 3). Note that the Sensus system is read only, with the functionality to remotely control equipment being disabled for security purposes.

Figure 1: Network protector (CM22 with MPCV relay)

Figure 2: VaultGard and Qualitrol collection boxes mounted on vault wall

Figure 3: Wall-mounted antenna for communication with Sensus system

Monitored information includes information about the protector itself, such as protector status (open or closed), how many times a protector has opened and closed and amperage, as well as information from other vault sensors, such as transformer oil temperature, and the status of the sump pump.

Information communicated by Sensus is provided to the DCC twice per day, morning and evening, and is routinely monitored by experts from within the Network Group, who also have access to the Sensus data. Daily, the Network Group records information monitored through this system.

DCC control screens indicate network protector status using color coding. From the main screen (provided by Sensus), operators can switch views to list the entire system of protectors, or select condensed lists queried by user defined criteria, such as number of operations to determine in which vaults, protectors are pumping or cycling.

By clicking on an individual network protector, operators can see how many times it has reported, what data it has reported, etc. Historical information is also available for each protector in graphic format. If operators receive alerts (the system communicates alarms based on predefined triggers, such as a drop in voltage) or find potential problems, they notify the field crew supervisor for a vault/manhole inspection. If network protector data is not received over Sensus, this would indicate the need for a repair inspection.

A resource (Network Specialist or Electrician Apprentice) within the Network Group monitors the network protector information daily and exports the data into graphs. Data is aggregated by day, month, and year, enabling seasonal analysis of the performance of the network protector fleet. The high level of network protector data collected provides engineers and planners with current and historic information, which informs their decisions. More importantly, it quickly reveals network protector issues and outages that are in need of inspection and/or repair.

In Clearwater, roughly one-third of all network protectors are open during any given 24-hour period due to light loading, particularly at night and during off peak months, and for the loss of a feeder.

The Sensus system is only used to monitor information - the functionality associated with remotely control equipment was disabled for security purposes. There are no plans to implement remote operation of network protectors in the Duke Energy Florida system.

Duke Energy Florida has not installed the Sensus monitoring system within its St. Petersburg spot network vaults.

Network Feeder Sectionalizing Switchgear (Rocker Arm (RA)) SCADA

Duke Energy Florida also utilizes its SCADA network to monitor and control its RA switchgear in Clearwater, using older radio communications. The RA devices are also equipped with remote reporting (through SCADA) fault monitoring using self-resetting Faulted Circuit Indicators (FCIs).

In practice, Duke Energy Florida has experienced communications issues with the radio system. Therefore, these switches are typically opened and closed by crews in the field when necessary. As these RA switches are about to be replaced with newer switchgear, Duke Energy Florida plans to upgrade to a newer communication platform.

ATS SCADA

Duke Energy Florida expanded its application of SCADA to monitor and control its automated transfer switches (ATS), which are prevalent in the primary / reserve feeder scheme used to serve customers outside of the network in Clearwater and in St. Petersburg. One complication to the addition of this monitoring was that the company did not anticipate the volume of alarms/alerts on the ATS systems. Since the network group was responsible for initially installing the new ATS system SCADA, the response fell to that group as well. As a result, the network group has stepped up the frequency of ATS Inspections to lower the volume of alerts.

DSCADA Migration

Duke Energy Florida is planning to deploy Distribution Supervisory Control and Data Acquisition (DSCADA) system-wide, such that it will provide for supervisory control over both the ATS’s and the network feeder sectionalizing. All ATS’s currently have the new DSCADA. Once new sectionalizing switches (replacing the RAs), RTUs, and an upgraded communications system are installed, the new sectionalizing switches can be linked to the system-wide DSCADA.

Alarms and Alerts from Sensus

The Sensus system includes an alarm and alert function — if a system threshold is crossed, an alarm is immediately sent in the form of text or email to Underground department staff (Network Specialists and crew Supervisor(s). The system enables anyone working on the network system to sign up to receive Sensus alarms, including authorized contractors. Account Managers utilize this feature for early warnings of potential problems, and to notify customers when load has been moved to the reserve feeder (in an auto transfer scheme), and that they are operating temporally with no contingency.

Technology

All vaults with network protectors report data in real time to the Duke Energy Florida DCC over wireless cellular communications using Sensus software for electronic monitoring. Daily, weekly, monthly, and yearly reports can be generated and printed or displayed at any time.

Duke Energy Florida uses Eaton VaultGard and Qualitrol data aggregation to its Sensus central monitoring system at the DCC. RA switchgear is over an older DSCADA system. ATS systems are on a newer DSCADA command and control system. RAs use FCIs over SCADA.

Network vaults are equipped with the VaultGard system, for monitoring network protector information. They are equipped with a Qualitrol system, for monitoring transformers and other vault information. Data from the Qualitrol system and from protectors are aggregated by the VaulGard system and communicated over a cellular network to the Sensus group (a third party), who then presents the information back to the Underground operations center.

Data is aggregated and sent to Sensus approximately every 30 minutes. The main monitoring system is then updated with reports from this aggregated data by Sensus three times per day. Frequent, 30-minute polling of data from locations is performed to keep the cellular connection active. When the systems were polled less frequently, the group experienced some loss of cellular connections. Operators can also go onto the system and get real-time results and updates on-demand. Although the network system group is satisfied with the Sensus capabilities and quality of monitoring, as upgrade plans move forward, the group will investigate if there are any other platforms that could be used.

The company has applied the VaultGard and Sensus monitoring to the vaults supplying the Clearwater grid network. All St. Petersburg monitoring is performed during regular, on-site maintenance. There is one spot network location with SCADA monitoring of the network protectors. The company is considering expanding the Sensus monitoring to St. Petersburg, but first must upgrade the current cellular communications infrastructure. (The current Sensus system communicates over 2G cellular.)

Duke Energy Florida is considering an upgrade to its cellular infrastructure, as its communications carrier will phase out the existing 2G system over the next few years. Duke Energy Florida is collaborating with Eaton (VaultGard), Sensus, and Qualitrol for a smooth upgrade plan to the new cellular infrastructure and monitoring system. All systems must communicate seamlessly, so it is essential that all the monitoring equipment and software vendors are is sync with Duke Energy’s requirements.

All communications equipment has been tested and hardened for cybersecurity. Their cellular communication carrier has partnered with Duke Energy to secure the systems.

6.16.7 - Duke Energy Ohio

Operations

Remote Monitoring - SCADA

People

Duke Energy Ohio is in the early stages installing remote monitoring within their network infrastructure. The effort is being led by the Network Planning Engineer, in partnership with the Asset Manager, Network Project Engineer, and the Dana Avenue supervision.

Duke presently has SCADA monitoring and control of the network feeder breakers, and alarms from its fire protection system.

Process

Duke Energy Ohio has been installing devices capable of remote monitoring and control in their network in tandem with their network infrastructure refurbishment efforts. (Duke has embarked upon a 10 year network refurbishment effort - see Network Rehabilitation ). Their goal is to rollout remote monitoring and control capability to 95% of their network installations.

In particular they have standardized on the Eaton CM52 network protector with MPCV communication enabled relays. As they replace or rebuild a network protector, they install communication enabled devices.

Duke field resources are installing the communication backbone. They are planning to complete a few pilot installations of remotely monitored network infrastructure in 2010.

Technology

At present, Duke Energy Ohio has little remote monitoring and control ability beyond the network feeder breaker. They have embarked upon a multiple year program to install remote monitoring in conjunction with network equipment refurbishment.

Duke Energy Ohio is installing Eaton CM52 network protectors with MPCV communication enabled relays.

Duke Energy Ohio is installing a hard wire fiber optic communication backbone. Duke field resources are pulling the fiber.

6.16.8 - Energex

Operations

Remote Monitoring - SCADA

People

Energex has 22 staff members called switching coordinators who operate its central control center on rotating shifts. The people in the control center rotate their positions on a regular basis, and any operator can monitor and/or control any segment of the Energex power grid, including the CBD underground network.

Switching coordinators are typically drawn from field staff ranks, usually either substation technician or mechanic and rapid response, with training specifically for the control room operation.

Control

Engineers who focus on telecommunications and SCADA control of the distribution systems within the CBD are organizationally part of the Standards group, within the Asset Management team. Their role is to modernize the Energex systems for better remote control and monitoring through its telecommunications network.

Up until a few years ago, Energex had separate engineering teams for SCADA and telecommunications. As the company saw the growth and usefulness of integrating remote monitoring and control capability in the greater design and operations of the Energex systems, these two groups (SCADA and Telecommunications), were brought back into the main Asset Management business. In the field, a group of paraprofessionals and engineering support personnel manage the work issued by Asset Management. The paraprofessionals have substation, telecommunications, and SCADA experience.

As a result of this realignment, SCADA/telecommunications has become more an integral part of the entire design and planning processes within Energex. The paraprofessionals handle installation and wiring of telecommunications, SCADA, and smart control systems. These crews install intelligent relays and data acquisition modules at substations as well as wire communications back to the control center.

Process

Control

Beginning in 2012, Energex began to implement a technology upgrade to both standardize automation and control technologies, and to cover a greater portion of its system-wide network. To this end, Energex has deployed a new Operational Technology Environment (OTE) in two network operation centers. These centers are separate from the corporate IT applications and systems, for both security and efficiency, and are in place to exclusively serve the evolving telecommunications and SCADA operations at Energex. For example, the OTE provides a secure IT environment for key operational systems, such as SCADA and Telecommunications applications. The OTE isolation from any outside network is a notable practice, as it protects the system from outside tampering, malicious software code, or cyber threats, all of which are concerns in the electric power industry today.

Energex utilizes SCADA facilities to perform remote monitoring and control of bulk supply stations, zone substations, and some rural substations and customer substations. The Substations Automation Control Systems (SACS) at zone and bulk substations provide the following functions:

Volt Var Regulation (VVR)
Plant Overload Protection System (POPS)
Remote Terminal Unit (RTU) functions

Each SACS is equipped with a Human Machine Interface (HMI) for control and monitoring operations by Energex personnel.

Throughout the 11 kV CBD and zone substations, Energex now has telecommunications and SCADA systems in place. Energex has full remote control over the three-feeder mesh network (See Network Design).

In expanding its remote monitoring and control capability to the distribution system, Energex’s initial focus was the 11 kV overhead systems, adding recloser automation to increase reliability.

Energex has now shifted its automation focus to the underground network. Energex has implemented a program to install monitoring system on new and existing distribution transformers, both overhead and underground, to increase knowledge of the loading and power quality associated with low voltage assets.

Technology

Energex has basic alarming installed in their medium voltage substations, such as alarms for an open circuit breaker, and general alarms, such as alarms for a battery charge, or sump pump. Substations within buildings may also have fire alarms that tie to the fire brigade station.

Communication is hard-wired from medium voltage stations back to an RTU at the station that supplies the primary feeder. From that station, information is communicated back to the SCADA system over a wide area network (WAN).

Some models of air-insulated transformers also send back data about the transformer condition to the control center. In addition, its human-machine interface (HMI) software is connected to cellular network interfaces located at all substations. Crews can then remotely monitor information from these local substations, such as alarms and alerts from SCADA-attached controls to the network.

Control

Numerous distribution feeder auto change- over schemes are deployed throughout their system as applications running within their Substation Automation Control System (SACS), or in Remote Data Concentrators (RDC). In addition, Energex is using a new DMS system (PowerOn DMS) for monitoring and controlling its distribution network.

Energex is focused on the following on-going technology initiatives and deployments related to telecommunications:

Standardized communications

Energex has deployed industry-standard Internet Protocol / Multi-Protocol Label Switching (IP/MPLS) communication networks to support current and future operational systems. By using industry standard Ethernet/IP for its base communication with remote devices and controls, the company has a broader range of tools, controls, and applications at its disposal, and a low risk of communication network obsolescence.

Optical fibre

Energex has committed to using optical fibre as the preferred physical media for its communication network links between substations. Fibre is fast, efficient, and is the IT industry medium of choice for telecommunications. Energex specifies fibre cabling in all new substations, and in the refurbishment of existing substations. In addition, to save on deployment costs, optical fibre links are included as part of new or refurbished distribution feeder projects. This approach leaves gaps that must be filled in by other projects – Energex has a focused program to fill in these gaps.

Replacement of obsolete equipment

Much of the existing copper cabling used in the Energex communication network is 30 to 40 years old, and nearing the end of its design life. The company is replacing this cable with optical fibre cable wherever practical. Similarly, the majority of its existing operational telecommunications network that covers the bulk and zone substations uses Plesiochronous Digital Hierarchy (PDH) technology, no longer supported by original vendors. Energex is in the process of replacing these links with fibre-based IP/MPLS wherever possible, or by using its secure mesh radio links that are common in its distribution system network.

Expansion of Distribution system SCADA (DSS)

Energex uses a secure mesh radio network to monitor and control DSS devices, such as reclosers and load break switches. They have expanded coverage by deploying additional head ends and repeaters to support the throughout the region to support remote monitoring and control of an additional approximately 500 DSS devices. Energex notes that this has significantly improved its network reliability and helped it meet its service target performance incentive scheme (STPIS) goals.

Future technology projects

In addition to its IP/MPLS and fibre standardization, Energex will leverage the data and new network capabilities in a number of ways. For example, with better data acquisition, the company will increase its knowledge of the loading and power quality of its low voltage assets. This will be critical to understanding and addressing issues associated with the challenges associated with technology changes such as the increasing penetration of distributed generation on the system.

In cooperation with Ergon Energy, Energex has embarked on a Joint Smart Grids Program to trial the use of smart asset management approaches to maximize the value of capital expenditure, or even defer projects that may not be found cost-effective after analysis in its distribution network. This program will involve technology trials in a targeted area north of Brisbane.

Energex also plans to focus on greater integration of substation secondary systems, including protection, SCADA, and telecommunications. Work underway includes time synchronization of protection relays, relay interface and coordination with SCADA, and migration of auto reclose functions from SACS to the protection relays to enable additional operational modes to provide improved worker safety.

6.16.9 - ESB Networks

Operations

Remote Monitoring - SCADA

People

Network operations at ESB Networks, including remote monitoring of the network, are performed by Operations Managers within the Operations group, part of Asset Management.

Organizationally, the Operations group is comprised of two Operations Management centers, one North and one South, a System Protection group, an Operations Policy group, and a Systems Support group.

The operations group includes MV managers, called a Customer Services Supervisor, for each of its 35 MV geographic areas, responsible for monitoring and controlling the MV and LV network.

Process

ESB Networks has deployed SCADA at most (98%) of their 38:10kV substations.

In medium and low voltage networks in Dublin, they have little remote monitoring beyond the substation. At the time of the immersion, they were piloting the use of remotely monitored and controlled devices at a medium voltage station (10-kV : LV), in Dublin.

ESB Networks’ OMS system provides an extremely detailed view of the network to the operator. The OMS prediction can point to a particular LV outlet coming out of any MV station. There are typically four LV outlets out of each MV station. These MV circuits are available to the operator in a schematic view.

Note that in their overhead 10 kV and 20 KV networks, ESB Networks has widely deployed SCADA to over 1000 switch locations.

Technology

ESB Networks utilizes the ABB Network Manager 3 (NM3) SCADA system, tied to its Oracle Utilities OMS system.

6.16.10 - Georgia Power

Operations

Remote Monitoring - SCADA

People

Test Engineers in the Network Operations and Reliability Group are responsible for remotely monitoring the network system. The Network Operations and Reliability group, led by a manager, is part of the Network Underground group, a centralized organization that manages all network infrastructures at Georgia Power.

Georgia Power has a Network Control Center, manned by Test Engineers, for monitoring and controlling network infrastructure. All existing vaults have remote monitoring equipment installed on network protectors that is tied in with SCADA. Communications to the central control room is through multiple avenues, including DSL, a dedicated licensed cellular, a dedicated radio network (SouthernLINC, a Southern Company radio network), and fiber optic network. When a new vault is built, Operations commissions it, performs the system testing, and makes certain SCADA is set up to remotely monitor the vault, and then is involved in the ongoing operations and maintenance monitor of each vault.

The Test Engineers are four-year or two-year associate-degreed Engineers. Test Engineers are responsible for network system operation, and work closely with maintenance crews, Test Technicians, Key Account representatives, and the Distribution divisions (Non – network operations) of Georgia Power.

Process

The Network Operations and Reliability group, from the Network Control Center, monitors every network customer vault and Georgia Power vault location, including attributes such as voltage, current, temperature, and vault fluid levels. In some locations, the center monitors custom sensors that are installed for monitoring fan operation, or doors being open or closed, for example.

Remote monitoring of the Georgia Power underground network system has been in use since 1990. The Network Control Center uses dedicated radio and cell frequencies to connect to SCADA systems in every vault. In addition, the center can monitor AMI metering at customer sites.

The Georgia Power Network Control Center only monitors and responds to alarms within the underground network system and its dedicated SCADA equipment. Non – network distribution infrastructure is operated by a separate Distribution Control Center. However, the Distribution Control Center is responsible for monitoring and controlling network feeders. So the opening or closing of a network feeder breaker is performed by the Distribution Control Center, in coordination with the Network Control Center.

Technology

All network protectors are connected to the Network Operations center by a SCADA system that runs on DSL, radio frequency, or fiber network connection to the Network Control Center. Protector monitoring and opening/closing of protectors can be performed remotely by operators within the Network Control Center (See Figure 1 and Figure 2). Remote monitoring and control of protectors has been in place at Georgia Power for about 15 years.

Figure 1: Network Operations console

Figure 2: Network Operations console

All network protectors are connected to the Network Control Center by a SCADA system, ESCA (Alstom). This is the same SCADA system used for substation control and their distribution automation system. The system communicates by DSL, radio frequency, or a fiber network connection to the network operations center where protectors are monitored by the Network Operations staff. Remote monitoring has been in place at Georgia Power for 15 years.

The Network Operations center typically monitors the following information from the network protectors:

Current
Voltage
Protector Open or Closed
Fluid in the vault
Fluid in the protector

Access to the Network Control Center is locked for use by authorized personnel only, and operators must securely log into the Control Center console(s) once inside.

Figure 3: Submersible vault wall – mounted remote monitoring system control box

6.16.11 - HECO - The Hawaiian Electric Company

Operations

Remote Monitoring - SCADA

People

The HECO underground system is operated out of the Dispatch Center. The Dispatch Center is comprised of two dispatch desks, and one supervisory desk. The dispatch desks in include the “Load dispatch” desk and the “Trouble dispatch” desk. HECO does not have a distinct desk or dispatcher position for monitoring and operating its network infrastructure.

Technology

HECO has little monitoring and control capability beyond the substation breakers. Most 12kV feeders do have SCADA monitoring and control at the breaker. Network feeders, also supplied at 12kV, are remotely controlled and monitored through SCADA.

Distribution circuits below 46kV are not shown on their EMS map board, with the exception of the 12kV system in Waikiki which supplies their network secondary system.

HECO is not utilizing any remote monitoring of network vaults and associated equipment, with the exception of some water level alarms in certain vaults.

6.16.12 - National Grid

Operations

Remote Monitoring - SCADA

People

National Grid has remote monitoring and control of all network feeders in New York East at the substation.

National Grid does not have any remote monitoring of their underground network system beyond the feeder breaker, primary or secondary. The only exception to this is Henry St. Station in Glens Falls, one of two stations feeding a small network in the city of Glens Falls.

Process

National Grid’s Distribution Planning group has developed a specific recommended strategy for upgrading the secondary network system, which includes the addition of remote monitoring. In developing this strategy, each network was studied to determine whether to keep the network, expand it, shrink it, or eliminate it. The specific investment strategy for each network would be dictated by this overarching direction. As an example, an investment for remote monitoring may be an appropriate strategy for a network planned for expansion, but not for a network planned for elimination.

Technology

Part of National Grid’s strategy for upgrading the network system is to test the viability of technology for remotely monitoring and controlling the network. This pilot will be targeted at a small network system for which National Grid has determined a strategy of either contract, maintain, or expand. The pilot will include technology to monitor and control network equipment, and be compatible with National Grid’s SCADA system.

The pilot is planned to include:

Network Protector Master Relay (may vary between relay manufacturers)

Network voltages
Differential voltages
Phasing voltages
Phase angles
Current - phase a, phase b, phase c
Transformer voltages
Power
Power factor
Relay state/status
Relay calling for trip, close, float
Block from closing

Auxiliary inputs:

Transformer:
- Pressure sensor
- Low oil level sensor
- Temperature sensor
Network protector:
- Temperature inside network protector
- Pressure sensor
- Breaker problems (some network protectors have diagnostics)
- Fluid level
Vault:
- Vault water level
- Vault temperature
- Unauthorized entry alarm

6.16.13 - PG&E

Operations

Remote Monitoring - SCADA

People

PG&E has an existing remote monitoring system installed in their underground network system. They have embarked upon a five-year project to replace the existing network remote monitoring system with a modern system that provides increased monitoring and control.

PG&E’s current SCADA system was installed in the mid 1980’s. The system provides some remote monitoring information including open/close status of network protectors, and load current on the feeders (through the protectors). The current system, however, has no control capabilities. PG&E does have remote monitoring and control of the feeder breaker.

The current SCADA computer system is maintained by the corporate Information Technology Department, and not by Distribution Operations. A crew of five (5) contract technicians is responsible for the maintenance of the system, supervised by a senior PG&E telecommunication engineer.

The information provided by the SCADA system (loading and protector status) can be accessed by PG&E personnel through the “Network Historian”, a PG&E developed graphical computer system. This system provides authenticated users a 15-minute delayed graphical representation of the underground system, and corresponding status of the network protectors. Users can drill down as well as aggregate load information using this software system.

Due to the importance of the five-year project to replace and upgrade the SCADA monitoring system in the network, PG&E has assigned a senior engineer to manage the project. This engineer will work with contracted field crews to install the new SCADA equipment. For example, the installation of the sensors on existing equipment was contracted to one vendor, who had the expertise with the equipment currently installed. The pulling of fiber was contracted to another vendor.

Process

Beginning in 2009, PG&E began to upgrade the existing system by installing fiber, adding sensors, and replacing the electro-mechanical relays in the network protectors with microprocessor controlled relays that are connected to SCADA remote terminal units.

Also in 2009, PG&E piloted the project and refined the implementation plans based on lessons learned from the pilot. For example, the pilot revealed the need to hire a contractor to install the new sensors because of the expertise required to do so (drilling, thermal welding, etc).

In 2010, PG&E implemented the new SCADA on half of a feeder group (34kv). In 2011, they will complete the installation of the new system in that feeder group, and in subsequent years, expand the installation to the rest of the system. The project is scheduled to be completed within 5 years.

Some of the features of the new system include:

Installation of new fiber optics. The fiber optic system will be aligned with the network it is designed to work with. The fiber optic network is designed to be self healing, that is, looped to and from the same substation. This will enable the continued monitoring of the network group even if the fiber optic cable or SCADA system is damaged at any single point. For example, if the system is compromised at a certain location (for example a “dig-in”), communications would automatically be routed from the other direction.

PG&E is installing additional fiber count so that the system is “smartgrid” ready and can be used for potential future applications such as demand side management, and distributed generation (DG) dispatch.

Installation of a complete monitoring system that that includes pressure, temperature, and oil level on each chamber, NP tank pressure, voltage, and current. PG&E is also considering adding hydrogen gas monitoring, Total Dissolved Combustible Gas (TDCG) sensors, and additional vault monitoring, such as intrusion sensors, in a later phase of the project.

The monitoring system will also include vault attributes such as SCADA battery level, distributed generation monitoring, motion detection, smoke alarm, ventilation, oil in water, sump monitoring, and sectionalizing switch position. (Network feeders are designed with sectionalizing switches. These switches will be tied to SCADA, but PG&E will not add remote control to these devices until a later date).

Remote operating capabilities for the network protectors will include remote open/close and station transfer trip.

Unlike the current system, the individual network loops will match the associated network group to provide for group operation and monitoring capabilities. This will enable PG&E to control the network group as a whole (close and open the group) in case of a fire in a vault. This eliminates the need to program, which individual component on the network would be opened, and instead the whole group would be disabled. In addition the new SCADA system provides a “transfer trip” capability whereby should the substation breaker be “tripped”, all of the Network Protectors on that feeder would be notified via the SCADA and trip automatically rather then waiting for internal relays to pick-up a reverse feed. This will prevent the hanging of Network Protectors, and speed up the clearance process that PG&E currently uses.

Technology

In 2009, PG&E began to upgrade their system, replacing electro-mechanical relays in protectors that were connected to SCADA remote terminal units. They chose the Eaton MPCV relays and Eaton VaultGard translator units with Qualitrol sensors to report on transformer oil. The Eaton VaultGard translates Eaton’s relay protocol to PG&E’s preferred protocol, DNP.

Every vault will be fitted with a fiber transceiver (Model 570) H&L Instruments (hlinstruments.com). This is a self-healing loop system, which heals itself in less than four milliseconds. It is able to carry up to 128 channels of communications at up to 115kbaud, and includes two Ethernet ports, which will allow the VaultGard’s web server to be viewed at the distribution control center as well as in the vault.

Figure 1: Network transformer with remote monitoring. Note transformer monitor panel mounted on top of unit

Figure 2: Close up of transformer monitoring panel

6.16.14 - Portland General Electic

Operations

Remote Monitoring - SCADA

People

PGE has a remote network monitoring system installed at all network vault locations that gathers and reports information from the network protector relay.

Network monitoring is the responsibility of various groups including the System Control Center (SCC), Distribution Engineers, and the CORE underground group.

The SCC is usually referred to as Load Dispatch, and operators are known as load dispatchers who are managed by the Transmission and Distribution (T&D) Dispatch Manager. The SCC has two distribution control regions and dispatchers are assigned geographically. From Monday to Friday, two dispatchers cover each of the two PGE regions.

One of the regions and therefore one of the dispatch desks includes downtown Portland and the CORE network. Dispatchers rotate between the two desks so that all dispatchers gain experience working with the network. The SCC employs eight dispatchers total who rotate between the desks on 12-hour shifts. Dispatchers are salaried employees (non-bargaining).

Load dispatchers have SCADA installed on network feeder breakers. At one of its two network substations, a feeder lockout results in an alarm and page being sent to a preset distribution list, including the Distribution Engineers and CORE group supervisor. If a breaker locks out on a network feeder, the dispatcher calls both the duty engineer and duty general foreman (DGF) in the CORE underground group. The DGF assembles the appropriate crew to respond to the alarm, isolate the fault, and resolve the issue.

Though PGE has a remote monitoring system installed at each network protector location, this system is not connected to the SCADA system. PGE does not bring alarms from this monitoring system back to the dispatch center, as it does not want to inundate the dispatchers with alarms from protectors that may have opened under light loading conditions. Dispatchers can call up the network monitoring system on custom screens developed in Pi (OSIsoft). In the event of a network feeder lockout, dispatchers can access the remote monitoring system to confirm that the network protectors have opened.

Distribution Engineers and all CORE group resources can access remote monitoring system information through the Pi system. The network monitoring system is checked daily for any issues, but no paging notifications or alarms are triggered.

Process

At the substation level, PGE has SCADA monitoring and control on the network feeder breaker, and can receive alarms from one of the two stations supplying networks. Note that with the completion of PGE’s new substation, PGE will have alarming on all network feeders.

At each network vault, PGE can remotely monitor information at the network protector, including the voltage and all three-phase currents on both the transformer and bus sides of the protector. In addition, PGE can monitor the real and reactive power, power factor, temperature, and whether the network protector is open or closed.

The monitoring system is known internally as the “blue wire” system, as the twisted pair wires feeding into each protector are blue. PGE’s looped fiber system converts and communicates information from the protectors.

Load dispatchers, Distribution Engineers, and CORE underground resources have access to the remote monitored information through the “Pi” system (OSIsoft) using customized interface screens developed by PGE. Users can select any network and see the voltages and currents on each NP, as well as determine whether they are open or closed.

When a network feeder is opened as part of planned work using a shutdown order, the CORE group is responsible for checking the remote monitoring system to confirm that all the network protectors have opened. Load Dispatch performs a secondary verification when crews and substation wiremen call to request rack-out and tagging of the substation breaker. If the system indicates that a protector is still closed, the dispatcher contacts the responsible individual listed on the shut-down order to notify the individual that a particular NP still shows as closed, and to investigate.

PGE is utilizing the remote monitoring system to better understand the health of the network. For example, PGE uses the system to determine locations where protectors may be open and drive analysis.

Technology

Remote Monitoring: PGE is using the Eaton Mint II system (Master Incom Network Translator) with a PowerNet server platform interface and with the optic fiber to the Mint II monitors set in a H&L Fiber Loop configuration. The H&L Instruments system converts the fiber communications to the protocol used on the NPs, and vice versa.

Figure 1: MINT II

At present, PGE only uses the system for monitoring and not for control. PGE is assessing the Eaton VaultGard monitoring system to harden the system, using the looped fiber optic communications already installed throughout the downtown area. The reason for looking at VaultGard is that it is a web-based protocol with integrated software that allows a higher degree of control.

Most of the monitored information is sent to and stored in an OSIsoft Pi system. Pi allows engineers and operators to view the load flows at each network protector. The Pi system can collect large volumes of data from multiple sources and helps users view, analyze, and share information [52].

H&L Model 570 INCOM Communications Adapter: The adapter translates Eaton Cutler-Hammer INCOM network signals to and from ten-character ASCII-encoded message format. The INCOM Communications Adapter is installed in the Model 570 Transceiver in the factory, and it translates daisy-chained signals from the INCOM protocol devices to the H&L Fiber Loop III system. It translates signals from a number of devices, including multiple microprocessor communications variant (MPCV) relays in the network protector, IQ analyzers and meters, and switchgear [53].

Figure 2: H&L fiber optic transceiver

Communications System Upgrades: PGE has acquired a 220 MHz radio spectrum block to replace its older land mobile radio system. The utility also acquired a 700 MHz spectrum block to serve data transmission requirements, including distribution automation, SCADA, demand management, and customer smart devices. In 2018, PGE intends to complete the process of installing base stations to provide connectivity across the system.

In addition, PGE intends to phase out the leased copper lines used to connect SCADA with its substations, and replace them with a private Ethernet network by 2020 to support the monitoring of thousands of data points in each substation [15]. For generating plants and T&D substations, PGE uses high-reliability optic fiber for monitoring and control. Retail meters send information via a wireless network at low speed, and some substations use low speed connections or cellular systems.

Figure 3: Vault wall-mounted control box

6.16.15 - SCL - Seattle City Light

Operations

Remote Monitoring - SCADA

Technology

Remote Monitoring of the Network

SCL has installed a system developed by DigitalGrid, Inc. (formerly Hazeltine, and referred to by SCL employees as “the Hazeltine System”) to monitor their network equipment. This system uses power line carrier (PLC) technology for communication. (Communication signals are sent through existing utility power cables) SCL has been using this system for years, and has some degree of remote monitoring in all network vaults.

The DigitalGrid system is used to monitor:

current
network protector status
voltage
power factor
digital and analog sensors
vault ambient air temperature
various flags, such as:
- B - Network Protector Open
- C – Transformer Oil Temp
- E – Transformer Oil Level
- G – Smoke (currently being piloted)

The system also has alarm features for current, voltage, network protector pumping, sensors, and flags, and is tied in with the Distribution Operator consoles.

SCL utilized a pilot approach to evaluating and selecting their monitoring technology. They established pilots with products from three different vendors. In the process, SCL evaluated not only monitoring capability, but also control technology, because they are interested in implementing distribution automation in their network. (More specifically, they are seeking ways to be able to remotely operate network protectors, and to shift load from one primary feeder to another.) The result of this evaluation was that the DigitalGrid system that they have in place best suits their monitoring needs. SCL is still interested in piloting network distribution automation.

Monitoring

SCL does not use distribution-level SCADA on their network, but they do have access to the remote monitoring system (DigitalGrid). They have a separate console for accessing this remote information, and alarms from this system are available at each dispatcher console.

The SCL Dispatchers have access to the NetGIS system through a network viewer. This viewer enables them to view the contents and configuration of each network vault.

Operations Practices — Vault / Network Fires

SCL’s current design standard calls for fire protection heat sensors and temperature sensors in their vaults. The heat sensors are designed to open all the network protectors in the vault when the heat sensor registers 225°F. The temperature sensors send an alarm to the dispatcher at 40°C. (SCL utilizes temperature sensors in about 20% of their network transformer locations. They are actively adding locations, with a goal of 100% coverage.)

6.16.16 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 9.4: Network SCADA Systems

6.16.17 - Survey Results

Survey Results

Operations

Remote Monitoring - SCADA

Survey Questions taken from 2019 survey results - Inspection Practices survey

Question 29 : For primary sectionalizing or tie points installed on your Urban UG system, excluding auto transfer schemes at customer sites, are the switches manually or automatically controlled?

Question 30 : Do you remotely sense / monitor information about devices beyond the primary feeder substation breaker?

Question 31 : If you are remotely monitoring information about equipment beyond the primary feeder breaker, is this information tied in with your SCADA System?

Question 32 : On your network system, do you have the ability to remotely control switches, network protectors or other devices on your system beyond the substation breaker?

Question 33 : If so, what devices are remotely controlled?

Question 34 : On your non- network urban underground system, do you have the ability to remotely control switches, or other devices beyond the substation breaker?

Question 35 : If so, what devices are remotely controlled?

Survey Questions taken from 2018 survey results - Asset Management survey

Question 30 : Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 31 : If you remotely monitor information about network devices, please indicate what information you are monitoring.

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 21 : Do you remotely sense / monitor information about network devices / vaults beyond the primary feeder substation breaker?

Question 22 : If you remotely monitor information about network devices / vaults, please indicate which of the following you are monitoring. (Check all that apply)

Survey Questions taken from 2015 survey results - Operations

Question 107 : Do you have a dedicated operator within your dispatch center/control room for operating the network?

Question 108 : Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 109 : If you remotely monitor information about network devices, please indicate what information you are monitoring. (check all that apply)

Question 110 : If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA system?

Question 111 : Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker?

Question 112 : If so, what devices are remotely controlled? (check all that apply)

Survey Questions taken from 2012 survey results - Operations

Question 7.2 : Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 7.3 : If you remotely monitor information about network devices, please indicate what information you are monitoring. (Check all that apply)

Question 7.4 : If you are using remote sensing, how is the information communicated? (check all that apply)

Question 7.5 : If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA System?

Question 7.6 : Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker?

Question 7.7 : If so, what devices are remotely controlled?

Question 7.8 : If you do remotely control devices, indicate from which location(s) you have the ability to do so.

Question 7.9 : If you are remotely monitoring and/or controlling network equipment, what vendor/system are you using?

Survey Questions taken from 2009 survey results - Operations

Question 7.2 : Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 7.3 : If you remotely monitor information about network devices, please indicate what information you are monitoring. (Check all that apply)

Question 7.5 : If you are using remote sensing, how is the information communicated? (check all that apply) (This question is 7.4 in the 2012 survey)

Question 7.6 : If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA System? (This question is 7.5 in the 2012 survey)

Question 7.7 : Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker? (This question is 7.6 in the 2012 survey)

Question 7.8 : If so, what devices are remotely controlled? (This question is 7.7 in the 2012 survey)

Question 7.9 : If you do remotely control devices, indicate from which location(s) you have the ability to do so. (This question is 7.8 in the 2012 survey)

Question 7.10 : If you are remotely monitoring and/or controlling network equipment, what vendor/system are you using? (This question is 7.9 in the 2012 survey)

6.17 - Sound Coil

6.17.1 - CEI - The Illuminating Company

Operations

Sound Coil

People

The Sound Coil is an induction device used by CEI underground crews to aid in determining whether or not a cable is energized. It was developed by a CEI employee and has been used at CEI for many years.

Process

CEI crews utilize a device called a Sound coil, to aid them in feeder identification, and in determining whether or not a cable is energized. See Determining a Feeder to be De-energized. The UG Electrician will simply attach the device to the cable and listen for a tone, which would indicate that the cable is energized.

The sound coil is not “foolproof”. CEI has experienced dead cables that emit a tone.

CEI relies on a combination of its manhole prints and the sound coil device to identify de - energized cables.

Technology

The Sound coil is an induction pick up coil that sounds a tone if the cable is energized. The device works on both lead and non-lead cables, and is used a tool by CEI crews to indentify a cable.

Figure 1: CEI Sound Coil

6.18 - Temporary Overhead Jumpers

6.18.1 - HECO - The Hawaiian Electric Company

Operations

Temporary Overhead Jumpers

People

When HECO experiences a failure in a direct buried secondary or service cable, they will make a temporary repair that may involve the installation of a temporary overhead jumper. Temporary Overhead Jumpers are usually installed by Overhead C&M crews.

Process

HECO’s current standard is to install all underground facilities, primary and secondary, in conduit. Primary conduits are concrete encased as are secondary mains and services to commercial customers. Other secondary and service conduits are direct buried.

However, HECO has significant amounts of older distribution where the secondary or service conductors themselves are direct buried, and many have bare concentric neutrals. Consequently, HECO has experienced significant secondary and service failures with this cable.

When HECO experiences a failure in a direct buried secondary or service cable, they will dispatch a Primary Trouble Man (PTM), who will troubleshoot the problem and attempt to make a temporary repair. In some cases, the PTM will call out an Overhead C&M crew to make a temporary repair that involves the installation of an overhead jumper lashed to overhead facilities, such as the street light system. A PVC pipe will be used as a riser, and the jumper will extend from the pad mounted transformer through the riser overhead, and then to the customer’s meter base, “jumping” the failed underground cable and restoring service to the customer (see pictures below).

One challenge HECO faces is the timely scheduling of the permanent repair, which will involve running a conduit to replace the service or secondary cable section. As a result, these temporary jumpers may stay in place for a long time.

Technology

Figure 1: Temporary Jumper Installation Note the riser (PVC Pipe) guyed to the transformer

Figure 2: Temporary Jumper Installation Close up of OH wire egress from transformer in flexible pipe

Figure 3: Temporary Jumper lashed to street light structure

Figure 4: Temporary Jumper Installation Meter base attachment

6.19 - Three Phase Transformer Change Outs – Hot Cap Proc

6.19.1 - HECO - The Hawaiian Electric Company

Operations

Three Phase Transformer Change Outs – Hot Cap Procedure

People

“Hot capping” is a process that is performed by the Cable Splicers of the Underground Group at HECO, in combination with the PTM’s, when changing a three phase transformer. The term “hot cap” refers to the placement of a cap on a cable system connector, such as a splice, elbow, or T body, after separating the connector. After the cap is installed, the feeder is reenergized, thus the term “hot cap”. At HECO, the term “hot cap” refers to a three part (and three day) process used to change a three phase transformer that involves the installation of a hot cap.

The PTM’s perform the switching in three phase transformers required to de-load the feeder. The UG group performs the hot cap itself as well as the replacement of the transformer.

Process

HECO’s standard design for serving three phase customers with pad mounted three phase transformers is to run two primary feeders (12kV) to the transformer, with one being the normal feed and the other being a back up feed. The feeders are brought into a manhole or hand hole in front of the transformer where taps are fed into the transformer from the main feeder through separable connectors such as T – bodies.

The three phase transformers HECO uses contain an internal primary switch. (In locations where they have transformers without an internal switch, the design includes a separate switch.) When HECO must replace one of these three phase transformers, they implement a process called a “Hot Cap”, that enables them to isolate and replace the transformer with out interrupting service to customers (other than the customer for whom the transformer is being changed). As described above, the procedure is referred to as a hot cap because it involves the placement of a hot cap at one of the taps.

The Hot Cap procedure involves many switching steps, and is scheduled over a three day period.

Step One involves performing switching to unload the alternate feeder feeding the transformer to be changed. This involves going to each three phase transformer normally served by this feeder, and switching the load to an alternate feeder. After the feeder is unloaded, the feeder is opened, so that a crew can cut or separate the line going from the hand hole into the transformer, and cap it. The feeder is then re-energized – so the capped cable becomes a “hot cap”.

Step Two involves performing switching to unload the normal feeder serving the transformer so that it can be opened, de-energizing the transformer to be changed. To accomplish this, a PTM would go to every transformer served by this feeder and switch the load to an alternate feed. After this feeder is opened, and the transformer to be changed is deenergized, a crew would change the transformer. When the feeder is closed, the transformer would be energized, restoring service to the customer.

Step three involves performing switching to again unload the alternate feeder so that the hot cap can be repaired. After, more switching is performed to return the system to a normal configuration.

Technology

This process utilizes three phase transformers with internal primary switches and designs that utilized separable connectors.

Figure 1: Picture of three phase transformer with internal primary switch

7 - Planning

7.1 - Asset Management

7.1.1 - AEP - Ohio

Planning

Asset Management

People

Asset management, including the prioritization of new service, refurbishment, repairs, and civil works, is performed by the AEP Network Engineering group in tight collaboration with other Distribution Services organizations that are part of the AEP parent company. The company employs two Principal Engineers and one Associate Engineer who serve as asset managers for the AEP Ohio networks in Columbus and Canton. These engineers are geographically based in downtown Columbus at its AEP Riverside offices, and are organizationally part of a Network Engineering group that provides direct engineering services to the AEP Ohio network, and consulting support services to the other AEP operating companies. Columbus-based Network Engineers work in collaboration with other AEP Distribution services organizations and the Network Engineering Supervisor. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the Director of Engineering Services who in turn reports to the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues. This committee oversees asset management activities within AEP Ohio.

Regular inspections of network assets, including manholes, vaults, transformers, network protectors, and duct lines are performed by AEP by a combination of resources. When assets are in need of maintenance, the inspections are used to determine the appropriate remediation of the finding, and the priority of the solution, whether it be deploying new assets or performing repairs. AEP Ohio has a field inspector position whose primary job is to perform asset inspections. This role is also performed by Crew Supervisors.

Process

A notable practice at AEP Ohio is its use of a comprehensive asset management system (Network Electric Equipment Database System - NEED) for organizing information about asset performance and prioritizing asset work. During the regular inspection process of its assets in the field, Crew Supervisors report any assets that need attention, such as crumbling vault concrete, leaking transformers, etc. These inspection results are logged into the AEP’s NEED, an electronic database of assets and asset conditions. The AEP Ohio Network Engineering group, in tight communication with the Network Standards Committee, has developed expected repair schedules that are triggered by the severity of the inspection findings. NEED is used to trigger inspection and maintenance sheets in accordance with these schedules.

Note that cable assets are also compiled in CYME SNA and exported to AEP’s geographic information system (GIS) system for access throughout AEP.

Technology

Inspections are logged into the AEP NEED database, a work management system.

7.1.2 - Ameren Missouri

Planning

Asset Management

People

Asset management for network equipment is the responsibility of multiple individuals at Ameren Missouri, as it does not have a distinct asset management organization. Rather, asset management duties are distributed among responsible individuals within Energy Delivery Technical Services and Energy Delivery Distribution Services.

Local Distribution Planning is responsible for making investment decisions based on their analyses of the implications of forecasted load on the system. Local distribution planning for both the network and non network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division. The Underground Division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP.

Decisions about investment in network equipment such as transformers and network protectors are the responsibility of Distribution Operations, and are based on equipment condition as determined through inspection and maintenance findings. This group, led by a manager, reports organizationally to the Vice President of Energy Delivery Distribution Services. Distribution Operations is comprised of both the field resources (Distribution Service Testers) who perform network equipment inspections and conduct network equipment maintenance, and the engineering resources who analyze the information from the inspection activity and make decisions of whether to repair or replace network equipment based on the findings.

Decisions about investment in maintenance or repairs of structures such as manholes, faults, or duct banks are the responsibility of engineers responsible for civil and structural design within Energy Delivery Technical Services. This group is responsible for determining inspection approaches for structures, and for developing strategies for responding to inspection findings. In addition, this group develops standards for structure design and repair. For example, this group was responsible for changing Ameren Missouri’s vault standard to include requirements such as a thicker ceiling to meet a traffic rating requirement, and using larger grate openings.

Finally, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network, cable and network transformer replacement strategies, development of route diversity criteria, development of the criteria for manhole covers, and a criterion for conduit system replacement.

Process

The Underground Revitalization Department is taking a broad strategic view of Ameren Missouri’s network assets, and is serving as the prime asset manager through their work to develop revitalization plans. This five-man team is identifying problems with the current infrastructure, and using this to create a strategy for revitalizing the system balancing cost, practicality, reliability, and capacity.

They have formed nine strategy teams focused in the following areas:

Route Diversity
Distribution Automation and SCADA
Sectionalizing
Inspection and Maintenance
Cable Diagnostics
Manhole Covers
Conduit Systems
Cable Replacement
Transformer Replacement

Two further groups will be added in the future as the project enters the implementation phase:

Reducing Collateral Damage
MLK (new switching station) Cutover Strategy

The teams are developing strategies, as well as detailed plans for applying those strategies to the downtown infrastructure.

At the time of the practices immersion, all but two of the strategy teams had drafted their strategies, helping the underground group decide exactly what is required and exactly what improvements need to be made to the network. The improvements and upgrades to the system are expected to span ten years, but Ameren Missouri believes in developing all of the strategies at the outset, and training in – house people who will be involved with the process from the very start, and thus develop an intimate knowledge of the systems.

Ameren Missouri is moving to a condition-based approach for equipment replacement, following an assessment of the performance and condition of a line or component. Ameren Missouri has implemented a two-year inspection cycle for network vaults and a four-year cycle for network manholes. They have developed a draft criteria used to evaluate, manage, and prioritize replacement of network transformers and protectors within downtown St. Louis. These criteria are based on key considerations such as the transformer’s age, location, physical condition, loading, history with similar transformers styles, and oil quality. Note that at the time of the EPRI practices immersion these criteria were in draft form.

See Design – Network Revitalization for more information. for more information.

7.1.3 - CEI - The Illuminating Company

Planning

Asset Management

People

FirstEnergy has both a Corporate Energy Delivery Asset Management organization focused on company wide asset management issues and CEI regional individuals within their Engineering Services group focused on CEI asset issues. The Asset Management organization was formed at FirstEnergy in 2007 to focus on asset health and performance and to optimize investments. The group’s mission is to maximize the value of T&D asset investment by assessing the health and condition of the infrastructure, and developing strategies in alignment with corporate and business objectives. Regional asset management is performed by individuals within the regional Engineering Services organization.

The Corporate organization has a forward looking focus, identifying new methods and guidelines, and providing assistance to the field. The group is focused on three Asset Management sub processes – Capital Project Prioritization, Compliance Oversight, and Asset Health and Condition. A Senior Engineer within the Asset Health and Condition group is focused specifically on the underground asset health issues.

Regional Asset Management focuses on the specific challenges faced by each region. Until a recent company reorganization, regional Asset Management was a distinct department that reported directly to a Regional President. As part of the reorganization, FirstEnergy elected to weave regional asset management resources into the Engineering Services organization. Regional asset management individuals develop strategies for extending asset life, and include Circuit Reliability Coordinators (CRC’s) who perform field reliability audits. The initially focus of Asset Management has been primarily on the overhead distribution system. Asset Management plans to get more involved in underground asset management in the near future.

See Network Reliability Index - People

Process

One focus of the Asset Management group is asset health and condition. In this area, they are focused on the development of Health Manuals, the development of performance scorecards, and on business case analysis. They endeavor to stay current on industry trends, and are involved in industry organizations in an effort to bring back and apply best practices at FirstEnergy.

For example, they are investigating diagnostic testing methods for cable in order to develop diagnostic testing guidelines. In doing so, they have attended industry conferences and are involved with leading cable diagnostic initiatives underway at organizations such as the CDFI (NEETRAC), IEEE, and AEIC.

They have produced a draft Underground Health Manual that defines underground equipment types, provides a high level asset inventory, describes FirstEnergy preferred practices for the inspection and maintenance of underground assets, and describes methods for consistently performing and documenting reliability assessments and developing an underground health scorecard. See CEI Urban Network Practices Report (1015894) .

The Asset Management group has developed a “scorecard” for power transformers and is presently working on developing a scorecard that will rank underground feeders.

The corporate group also provides guidelines and templates to assist the regions in developing business cases for projects. These guidelines help the Regions to value projects so that they can better prioritize. The Corporate templates provide a guideline, but the regions have the ultimate say in project rankings as they may have local knowledge of reliability or other issues that rank one project more highly than another.

Technology

For business case development, FirstEnergy is utilizing a prioritization tool called the ECAT model, developed with the assistance of Navigant Consulting.

The tracking of individual facilities is maintained by the Region. Asset information is kept either in maps, GIS, or SAP depending on the asset type. For assets with a defined maintenance period (like manholes, network transformers and network protectors), the assets and the maintenance plans are housed in FirstEnergy’s SAP system. This system defines the maintenance period and “schedules” the maintenance by moving the work to the FirstEnergy scheduling system (CREWS).

For example – manholes are to be maintained once every five years. The Manhole records are housed in SAP, and have a maintenance plan assigned. As the maintenance of a particular group of manholes comes due, the SAP system will move the work to Crews, so that a scheduling employee can create a work request out of the CREWS system to complete the maintenance.

The completion of the maintenance work on underground distribution assets is tracked manually at CEI.

FirstEnergy presently has no complete Asset Register for recording and reporting distribution asset performance information. They are in the process of installing Cascade, a system that will house all inspection data and will interface with other key systems such as CREWS, their outage management system (Power On), etc. Cascade will track inspection and maintenance accomplishment and provide CEI with record of what field inspectors are finding. They will be able to perform inspections using hand held devices and the data collected will feed cascade.

The actual maintenance record for Substation assets will reside in Cascade. For distribution assets, the final maintenance record will reside in either SAP or their GIS system (to be determined).

To perform field assessments, the CRC’s are recording information using Panasonic “Tough Books”.

7.1.4 - CenterPoint Energy

Planning

Asset Management

People

CenterPoint Energy does not have a distinct network Asset Management organization. Rather, network asset management activities such as analysis of equipment performance, and asset investment planning and implementation are incorporated into CenterPoint’s Major Underground Organization.

7.1.5 - Con Edison - Consolidated Edison

Planning

Asset Management

People

Con Edison does not have a distinct network Asset Management organization. Rather, network asset management activities such as analysis of equipment performance, and asset investment planning and implementation are incorporated into Con Edison’s overall Network Organization.

7.1.6 - Duke Energy Florida

Planning

Asset Management

People

Power Quality, Reliability and Integrity (PQR&I) has responsibility for all Asset Management at Duke Energy Florida. Within that department, network assets throughout Florida are managed by three Asset Managers.

One Asset Manager, based in Clearwater, is assigned to managing network assets, including secondary cable, as well as other assets such as capacitors, regulators, electronic and hydraulic reclosers, and sectionalizers.

Another Asset Manager in PQR&I manages underground primary cable assets, including primary network cables, the cable testing program, single-phase and three-phase transformers, and transformer paint repair.

A third Asset Manager within PQR&I manages programs for replacement, repair, and inspection of switchgear and automated transfer switches (ATS).

Asset managers are not required to hold four-year degrees; however, all have extensive OJT and electrical engineering training.

In the past, switchgear, cable, and the network equipment were the responsibility of one Asset Manager. Currently, the management of network assets by the PQR&I Asset Management group is spread out over three Managers: one for cable assets, one focusing on switchgear, and another for all other network equipment. All three act as a Network Asset Management team, with complete communication and collaboration. Even though asset responsibility has been divided up, all three members have the capability of stepping in to help in any area in case of vacations, leave, etc.

The PQR&I Governance organization gives the Network Asset Managers the ability to shift funds between areas (switchgear, cable, and equipment, for example). If funds are underutilized in one area, they can be reallocated to another area in need. Governance can also step in and reallocate under-utilized funds from completely different operating units corporate-wide to fund areas of need.

Duke Energy Florida is utilizing a contractor to perform their cable replacements in Clearwater and St. Petersburg. The contractor crews are supervised by two Network Specialists to provide oversite and coordination to the contractor crew. The contractor performs all aspects of the work, including cable pulling. The contractor will obtain and hold clearances, though the work of executing the switching to obtain the clearance is performed by Duke Energy employees.

Process

Led by the Asset Manager responsible for primary cable systems, Duke Energy Florida conducts routine cable diagnostic testing to determine the integrity of its primary cables, utilizing the services of a cable diagnostic testing contractor. Cable testing is age-based – with cables selected for testing that are 25 years or older, or that are suspect based on performance. Duke Energy Florida tests 80 segments per month over a nine-month period per year. The diagnostic testing performed by the contractor is not feasible in all situations, depending on factors such as manhole placement, circuit configuration, circuit condition, or feeder operation. Cable replacement decisions are driven by diagnostic test results. Depending on test results, the PQR&I group will determine whether a cable has integrity and remaining life or needs replacement. If replacements need to be made, the other Asset Managers who deal with circuit components are consulted to identify equipment replacement needs on the identified circuits.

Duke Energy also performs routine cable replacements that are based on cable age and performance history, rather than on diagnostic testing results. This is the case in St. Petersburg, where older cables are being replaced based on age and performance history, as these cables were not appropriate candidates for diagnostic testing (because of significant branching of cable sections.) Note that the Integrity Engineer within PQR&I tracks cable outages even if customers are not affected. The PQR&I organization has decided that piece-meal repair or replacement of small sections of cable is not an efficient way to rehab aging cable systems as this approach generates many small and ultimately more expensive jobs. Rather, Asset Management seeks to replace whole sections of cable identified for replacement by age, performance history, or diagnostic test results.

At the time of the practices immersion, Duke Energy Florida had not tested the three feeders supplying the Clearwater network.

Asset Management is in the process of incorporating cable testing prior to energization of new cables into their program. The company believes this commissioning testing to be a good quality control check that can forestall outages.

In addition to cable replacement, the PQR&I Asset Management group also maintains listings of components targeted for replacement, including older T – Body (medium voltage 600 A separable connector) locations, and secondary mole locations. The Manager uses a spreadsheet to organize, prioritize and schedule replacement of these components, and seeks to incorporate the component replacements with associated cable replacements wherever possible. The costs of these repairs are included in the budget established for the cable replacement.

The asset management group has also targeted oil insulated underground primary switches for replacement, prioritizing these devices for replacement based on age and condition, impact on operations, and concerns for safety during operation. Duke Energy is replacing these oil-filled devices with solid dielectric vacuum switches.

Technology

Duke Energy Florida uses contractor cable testing that includes a checklist of over 170 cable conditions. The specific approach to diagnostics is proprietary.

7.1.7 - Duke Energy Ohio

Planning

Asset Management

People

Duke Energy has an Asset Management organization that includes a group referred to as Reliability and Integrity (R & I) Planning^[1]. Within this group (R & I) there are resources focused on distribution integrity, looking at such things as inspection and maintenance approaches for assets of different type, and resources focused on reliability performance. This group is centered in Charlotte, with two resources, one Integrity resource and one Reliability resources focused on supporting Duke Energy Ohio, as well as other areas of the company.

The Asset Manager for Distribution Integrity collaborates closely with the network planning engineer (Part of the Distribution Planning organization), the network engineer, Dana Avenue construction supervisors, and the Asset Manager for Reliability. In addition, the asset management group works closely with the standards department.

Process

The Asset Manager for Distribution Integrity works very closely with the DANA Underground group to develop appropriate inspection and maintenance and rehabilitation activities for network equipment. The R & I asset managers serve as internal consultants to operating areas such as the Dana Underground group. They focus on getting the appropriate resources in place to allow the operating areas to “get on with their job". One area of initial focus for the asset manager for distribution integrity was to work with the construction group to identify the need for an engineering position focused on the network.

When the R & I group was formed their first task was to learn what activities were taking place at Dana Avenue. For example they looked at the inspections that were underway. One of the first activities they got involved with was looking at issues with spare parts of network equipment. They worked closely with a network engineer, network planning engineer, and Dana Avenue construction supervision to identify appropriate quantities of spare equipment for the network. They also assisted Dana Avenue with establishing an inventory record.

A key focus of the asset management group is collecting data about asset type, vintage, condition, and performance and assisting the operating area by developing recommended maintenance, inspection and equipment replacement strategies and justifying the cost of those programs.

Some examples of new programs and changes to programs made at Duke Energy Ohio with the input from asset management are transitioning from monthly to quarterly manhole inspections, investing in refurbishing approximately 25 manholes per year, adding Tan Delta VLF testing as a cable diagnostic technique, inspecting terminations, refurbishing network protectors (replacement and implementation of microprocessor controlled relays), and incorporating the use of infrared cameras in inspections.

The asset management organization has been instrumental to identifying and justifying budget dollars to invest in asset performance.

Technology

Duke has an asset information system. Within this system Duke can compare investments across the enterprise (Duke serves customers in five states). The system looks at such things as net present value, reliability, legal exposure, reputation, safety, and mandated programs. Duke is using an asset management system developed by Davies Consulting (Davies AIS system).

^[1] In addition to R&I Planning, the Asset Management organization consists of Distribution Planning, Transmission Planning, and Portfolio Management.

7.1.8 - Energex

Planning

Asset Management

People

Energex has an Asset Management organization responsible for managing the network infrastructure to yield expected results (reliability, for example), and for making asset investment decisions. The Asset Management organization is led by an Executive General Manager, and includes organizations that support the management of assets including the Network Capital Strategy and Planning group, the Network Optimization group, the Data Services and Demand Management group, the Systems Engineering group, the Network Maintenance and Performance group, as well as the Metering, Safety and Environmental groups.

Process

Energex uses PAS 55 standards for the optimal management of physical assets. Energex uses a program called Condition Based Reliability Maintenance (CBRM), which seeks to develop a health index and risk score for all assets, and use that information to drive decisions such as maintenance approach and replacement criteria. The company utilizes a combination of asset age and condition identified through inspection and diagnostic testing to determine a health score.

The risk score examines operational performance and impacts on safety to identify a level of risk associated with each asset. The results of this program drive the company’s investment in refurbishment. Note that its program does not define specific actions based on scores. Rather, these indicators point Energex managers to scrutinize the performance of a particular asset class more closely. It is this additional scrutiny and investigation that results in action.

Once every five years, Energex approaches their regulator with their investment plans, including investments in system refurbishment driven by their CRBM program. Examples of some asset refurbishments driven by this program include:

Replacement of obsolete relays with microprocessor based relays
Replacement of oil circuit breakers with gas insulated breakers
Replacement of gas cables (transmission)
Rehabilitation of the pit and duct system in the Central Business District (CBD).
Based on problems with the older duct system, much of which was comprised of clay tile ducts, and given the rapid anticipated of load growth in the CBD, Energex embarked upon a five-year program to upgrade their pit (manhole) and duct (conduit) system. This program included:
- Installation of new duct bank (5 x 3 ) in the electricity supply corridor - Energex implemented this program in conjunction with a city program to upgrade the pedestrian foot path, as the Energex duct system is located beneath the footpath.
- Upgrade deteriorated pit locations, including civil work, and re-racking of conductors.

Energex has had difficulty applying this program to the 11 kV and low-voltage cable fleet population within the CBD, as the company does not have good records of asset type and vintage. Energex does not perform routine diagnostic testing of cables, other than troubleshooting (fault finding), and new cable commissioning tests (DC or AC hi-pot). The company does not have a cable replacement strategy for the cables within the CBD. Note that they utilize both PILC and XLPE cable in the CBD.

Technology

Energex uses Condition Based Risk Management System (CBRM) software from EA Technology to track the health and condition of assets throughout the underground system. The system assigns a health index and risk score for all the assets in each class, such as circuit breakers, transformers, etc. Length of time in service, test results, and any refurbishment work is input into the system. The system can “score” some assets based on aging mechanisms housed within the system that can be used to predict potential end-of-life. Actual refurbishment and replacement work is driven by the calculated health scores.

7.1.9 - ESB Networks

Planning

Asset Management

People

The Asset Management organization at ESB Networks consists of an Asset Investment Group, a Program Management Group, an Infrastructure Stakeholder Manager, an Assets & Procurement group, a Finance and Regulation Group, and an Operations Management group.

The Asset Investment group includes a Specifications Manager, and both generation and “Network” investment groups that perform the planning and design of ESB Networks T&D infrastructure.

The Network Investment groups are responsible for producing plans to invest in network assets that are “Least Cost and Technically Acceptable (LCTA).” ESB Networks Network representatives noted that they believed their company to be entering a period in which capital dollars will be constrained, and that developing optimum investment plans because critically important.

The Network Investment groups are set up geographically, with one group focused on the North, and the other focused on the South. This set up matches the organization structure of the construction organization, which is also split between north and south.

Process

The Network Investment groups plan and design the system. They analyze historic system loading and voltage performance, and consider anticipated load growth and new customer loading in developing investment plans. As with most planning organizations, they consider key system requirements around continuity of service, losses, power quality, operational switching arrangements, and environmental issues.

The Network Investment group performs regular reviews of their overall investment plans on five-year cycles, including the overall HV Network investment plan, the Dublin HV investment plan, as well as individual area plans (MV).

7.1.10 - Georgia Power

Planning

Asset Management

People

Network Assets are tracked and maintained by multiple groups a GA Power, including the engineering group, field workers, construction resources, and maintenance crews in the Underground Network group. The Network UG Engineering group, together with the Network Operations and Reliability group, Area Planning, and in consultation with Georgia Power senior leadership, is responsible for making investment decisions for the network systems, based on their analyses of the implications of forecasted loading on the system, contingency analysis, and assessment of system conditions as determined by inspection and maintenance activities.

Local distribution planning for the network underground infrastructure in Atlanta and other Georgia metropolitan areas, such as Savannah and Macon is the responsibility of the engineering group within the Network Underground Division. The Network Underground Division is led by the Network UG Manager, and consists of both engineering and construction resources responsible for the network infrastructures.

Decisions about investment in network equipment such as transformers and network protectors are the responsibility of Network Engineering group, and are based on equipment condition as determined through inspection and maintenance findings. This group reports organizationally to the Network UG manager, leader of the Network Underground division.

Projects of $2 million or less are brought before the Regional Distribution Council for approval. This group which meets monthly is comprised of the leaders of various Georgia Power Regional offices, and includes the Network UG manager. Any projects that require more funding (> $ 2 M) are sent to the vice president over the Network Underground group and upper management for review and funding approvals.

Network Operations and Reliability is comprised of both the field resources (field inspectors and field test engineers) that perform network equipment inspections and conduct network equipment maintenance, and the engineering resources that analyze the information from the inspection activity and make decisions of whether to repair or replace network equipment based on the findings. The Network Operations and Reliability group reports to the Network UG Reliability Manager.

Decisions about investment in maintenance or repairs of structures such as manholes, vaults, or duct banks are the responsibility of engineers responsible for civil and structural design within the Network Underground Engineering group. This group is responsible for determining inspection approaches for structures, and for developing strategies for responding to inspection findings. In addition, this group develops standards for structure design and repair. For example, this group was responsible for implementing the SWIVELOC™ manhole cover design to selected manhole locations (See Figure 1 and Figure 2.).

Figure 1: SWIVELOC Installation

Figure 2: SWIVELOC – underside of cover

Process

Asset information is housed in the Georgia Power GIS system, implemented about four years ago. The party responsible for the installation of the asset inputs the data into the asset record within the GIS system. For example, the Network Underground Test Technician responsible for commissioning a new protector installation is responsible for entering information about the protector into GIS. The GIS system tracks most network asset information, including manhole and vault drawings, nameplate information of the assets therein, and records of the inspection and maintenance activity performed at those locations.

If an individual at Georgia Power wants asset information on a particular vault, for example, he can look up the vault in GIS and can see information about the vault design, and all the nameplate information on transformers, types of protectors, etc. Because Georgia Power is on a five-year cycle for maintenance, crews are still identifying and recording serial numbers and other details associated with equipment to bring the asset register up to date.

Records are kept for all inspections as well, but if everything is found to be normal, only the name of the inspector, the location, and the date are retained in the Asset database. If there’s an exception, a note is entered into the GIS system that the location needs maintenance and that follow-up is required. Georgia Power does not keep photos as a standard procedure, as locations may change, be modified, and photographs may be misinterpreted or become quickly out of date.

Note that cable vintage is not being tracked in the asset data base. (With cable, vintage information is located on the cable itself; solid dielectric has date information on the outside, while lead has date information on the inside.)

Joints and splices are recorded in a separate Access database right now. These joint and splice records capture who prepared the joint and whether it is an EPR, lead or transition joint. The location of cable limiters are not directly recorded in the GIS but are shown on maps that are then imported into GIS. Protector maintenance and models, sizes, etc. are also input into the Access database, and then imported into GIS.

Technology

Georgia Power uses both an Access database and its GIS system (ESRI) to track equipment information, and a maintenance record. Information from the Access database, including protector information and joints and splices, are input or imported into the company’s GIS system from Access.

It is the responsibility of the construction, maintenance, and engineering staff to input information into the appropriate system(s) when equipment, maintenance, or other assets are put into service, inspected, or repaired. Maintenance and inspection crews gather information such as transformer template information as they inspect or visit undocumented assets during their routine duties.

A new inventory control system (“Maximo”) includes tracking of cable and materials available in the warehouse by a commodity number. Maximo is used for a broad range of functions, and there has been some discussion of whether it can also be used to issue, track and house maintenance records from inspections and trouble tickets.

7.1.11 - HECO - The Hawaiian Electric Company

Planning

Asset Management

People

Asset Management is a relatively new group at HECO, formed in late 2008. The group, led by an Asset Manager, was formed to coordinate many of the asset management activities in place among the various functions at HECO. These activities include asset performance assessment and evaluation, investment optimization, project selection and prioritization. The focus of this group includes all distribution, transmission, and substation assets.

The new group will be comprised of a manager and six slots for employees. The manager hopes to fill these slots with engineers, who will focus on different asset types (An engineer to manage transformer assets, for example). At the time of the EPRI immersion, HECO had filled one position, a person to focus on capital project prioritization. Since the immersion, HECO has filled an engineer position for asset manager for cables, with an initial focus on distribution cables. Asset Management works very closely with the Engineering department and the Technical Services Division.

Even after these positions are filled, the Asset Manager intends to the organization to be a virtual one, in that functional managers will continue to be involved in asset health assessment, project prioritization, and other collaborative activities. The Asset Manager specifically noted the need to collaborate with the C&M Planning group of the C&M Underground Division, who is capturing and recording asset health information from inspections, in determining the optimum inspection portfolio.

Process

One role of the Asset Management group at HECO is to prioritize capital projects. HECO performs an analysis on all capital projects with a cost greater than $100,000. This analysis involves using a scoring matrix to rank projects in 7 different categories and develop a relative weighting for each project. This weighting is used by management to determine which projects to include in the work plan. This is particularly useful for projects near the “cut line”, based on anticipated available funding.

Note that this approach applies only to projects greater than $100K. For projects less than $100K, HECO creates blanket orders. For budgeting of blanket orders, the previous year’s costs are simply increased by a fixed percentage to determine an estimated cost for the coming year.

HECO is not yet utilizing this type of weighting for Operations and Maintenance activities. The Operations and Maintenance budgets are developed by trending from previous year spends. Asset Management intends to move to a program driven maintenance budget.

Another role of Asset Management is to analyze the health and performance of assets and develop programs that invest in maintaining or extending the life of these assets in an optimum way. For example, HECO is presently studying cable performance and developing a cable replacement program. This study involves understanding what cable types they have in place, what the performance has been, and what the likely failure modes of these cable types are. Working with EPRI and with KEMA, HECO has developed models for 15kV URD cable failure performance based on their cable fleet’s historic performance, industry knowledge, and some innovative analysis techniques. These models can be used to predict future failure performance and make investment decisions. Using this information and with assistance from KEMA, HECO is presently developing a cable replacement strategy.

The Asset Manager noted that the “Asset Wall” created by the anticipated wave of increased failed cables represents one of his greatest concerns and challenges.

Asset Management is also reassessing certain practices in place at HECO to assure that they make sense moving forward. For example, in analyzing cable fleet performance, HECO has concluded that they will have to significantly increase the amount of cable they replace each year to maintain desired levels of system reliability. Using current practices, the costs of this additional replacement activity is significant. Asset Management is re-examining HECO’s current practice of using a jacketed, water block, tree retardant XLP insulated cable in a concrete encased conduit. For example, “Is encasing the conduit in concrete necessary?” “Perhaps placing it in a direct buried conduit is satisfactory”.

Asset Management will develop recommendations of what work (Inspection, Maintenance, Replacement, for example) is to be performed on assets of various types. The Asset Manager noted that they may develop more formalized service level agreements that document these expectations in future.

Technology

For business case development and project prioritization, HECO is utilizing an asset life cycle analysis tool developed by KEMA. KEMA is also assisting HECO with the data analysis and work plan development.

HECO does not yet have a complete Asset Register for housing information about assets. For substation equipment such as breakers and substation transformers, their asset register is fairly robust. They are recording substation information in a product called Ellipse by Mincom.

For distribution assets, HECO has not yet recorded any information about Underground assets in an “Asset Register” such as Ellipse. Distribution asset information is currently kept in their GIS and mapping systems.

7.1.12 - National Grid

Planning

Asset Management

People

National Grid has a strong focus on asset management. Organizationally, they have an Asset Management group led by a senior vice president. This group is comprised of Asset Strategy, Distribution Planning, Investment Management, Transformation (a business transformation group), and Engineering.

The Asset Strategy group is responsible for establishing high level policies and strategic direction.

The Distribution Planning group works between the Asset Strategy group and the implementation of their strategies, developing principles and standards that ultimately drive work procedures.

The Investment Management group provides the project justification and determines the priority for specific projects. All spending plans are developed based on project category, priority, budget class, available budget, and resources. Capital projects are ranked based on the measure of risk and the improvement opportunity associated with the project, identified by their single project prioritization scores. This group maintains a Corporate Risk Registry which is a ranked list of potential investments ordered by risk. Projects are assigned a priority number generated by a project risk/prioritization decision support matrix that assigns a project risk score based upon the estimated probability and consequence of a particular system event occurring. The project priority score takes into account key performance areas such as safety, reliability, environmental, and cost. The project priority score is a tool that helps investment management identify optimum projects for investment. Projects are added to a Corporate Risk Register, a ranked listing of potential investments ordered by risk.

Having a single score associated with each potential investment gives a common method to assess risk across the business. This provides transparency to the executive and allows the amount of risk being mitigated in each line of business to be compared and factored into the overall capital plan. It also provides important information to assist with regulatory dialogue and debate.

National Grid has been actively focused on developing and asset management centric culture. For example, they have implemented practices that conform to principles out lined in PAS55, the British Standards Institution’s (BSI) Publicly Available Specification for the optimized management of physical assets. This specification provides definitions and requirements for establishing and verifying an asset management for all types of physical assets. One example of a PAS 55 requirement adopted by National Grid is the practice of revisiting their procedures (such as Electric Operating Procedures (EOP’s)) on a three year cycle to assure they are current.

Process

Historically at National Grid, there had not been much maintenance visibility for distribution network assets. Network systems are inherently reliable based on their design. As with most utilities, the implementation of asset management processes at National Grid is more mature for substation assets than for distribution assets.

National Grid plans to roll critical distribution assets, such as network transformers and protectors, into the tool set they have established for managing substation assets. An example of this is their use of technologies such as the Cascade system to record information about and manage distribution assets.

National Grid has established an asset register for distribution assets. For most distribution assets, National Grid’s GIS system (Smallworld) serves as the asset register. For network assets however, Cascade will serve as the asset register, as the GIS system does not adequately represent the network infrastructure, National Grid is loading network protector and network transformer information into the asset register (Cascade).

National Grid has recently standardized its maintenance approach to network equipment, increasing the frequency of inspection from historical practice. One driver of this increased maintenance frequency is the need to gather more data such as loading information. Because National Grid has no remote monitoring on their network system (beyond the substation feeder breaker), the only opportunity they have to gather information about the equipment, whether condition information or loading information, is during field inspections. In general, network facilities in the Albany network are well-maintained. See Preventive Maintenance and Inspection for more detail on their approach.

The Distribution Planning group has developed a specific recommended strategy for upgrading the secondary network system, which includes the addition of remote monitoring, increased maintenance, and network transformer oil testing such as dissolved gas analysis. In developing this strategy, each network was studied to determine whether to keep the network, expand it, shrink it, or eliminate it. The specific investment strategy for each network would be dictated by this overarching direction. For example, remote monitoring might appropriately be implemented in networks slated for expansion, but might not be considered for networks planned for elimination.

A specific study of the network secondary distribution system serving Albany was performed as part of this process. The study included an analysis of thermal and voltage limits applied to the anticipated 2015 peak loading levels during normal, single and double contingency conditions. In addition this study analyzed the expected performance of the secondary network system for solid faults on secondary cables. Recommendations from this analysis include specific system reinforcements to meet anticipated peak loading levels and the application of cable limiters on each end of secondary mains and at secondary junctions.

The identification of secondary network system upgrades was prompted by an analysis performed by Distribution Planning to answer the question of whether outages to secondary network system, such as certain notable outages experienced by some other utilities, could potentially occur at National Grid. The analysis concluded that yes, the underlying issues that led to those other noteworthy outages, existed at National Grid and could potentially result in outages. The project to upgrade secondary networks has been added to the National Grid corporate risk register.

Process: Project Risk Scoring

Projects are assigned a prioritization score and added to the Corporate Risk Register, a ranked listing of potential investments ordered by risk. High scores correspond to high priority projects, and certain types of projects (e.g. diagnostic projects, and projects to comply with regulatory directives) are assigned a high priority score regardless of their risk impacts. The prioritization or risk score represents the risk that exists if a project is not completed, and thus a higher risk rating means a project is more urgent or useful.

The project prioritization score is based on an economic and impact-based measurement of three factors: Safety, Environment, and Reliability. The scores in these areas are calculated with the help of a decision support matrix, which accounts for the estimated probability of a particular system event, and the consequence of that event should it occur. A Microsoft Excel-based tool is used to aid the scoring process.

Overall Scoring Procedure

The first step is a classification process to identify project impact areas. A description of the project, along with the scope, justification and benefits is made, and the impact on safety, the environment and reliability is estimated. In most cases, the safety and environmental impacts of projects are lower than the reliability impacts.

Risk scoring is done according to the following principles. Both the cost (impact) and probability (likelihood) of a risk are important. An event that has a probability of happening only once every thousand years, but has a very high economic cost if it does, may end up with a lower risk score than a common event that costs much less per occurrence. For each category of risk (environment, safety, and reliability), impacts and likelihoods are estimated and used as indices in a matrix to calculate one blended risk score for each category (Table 1). The impact score is based on the monetary cost of a potential outcome, and there are seven levels from very low to very high (or one to seven). In terms of economic impact, levels are assessed on an exponential scale; the highest score outweighs the lower scores. Level seven represents an impact of greater than $40 million, whereas level one has an impact of less than $10000. A likelihood measurement is also assigned to one of seven numeric categories, corresponding to very low to very high likelihood, and can be considered the probability or projected time to failure. This is based on a probabilistic model considering the likelihood of failure in each year. So, for example, a constant probability of 25 percent per year can be considered a time to failure of four years.

Table 1: Blended Risk Score Matrix

Impacts and likelihoods are used to look up the blended risk scores, which span values from 1 to 49. Values lower than 15 are considered low risk (green); 16 to 30 are medium risk (yellow); and greater than 40 are considered high risk (red).

The overall project priority score is the maximum of the safety, environmental, and reliability risk scores. This is considered preferable to using some kind of averaging scheme, as low risks in two areas should not be allowed to diminish the projected cost of a very high risk in one particular area. The impact score is assessed on an exponential scale, such that a high impact score in one category will almost always outweigh lower level impacts in other areas. Most projects are expected to have a single driver that dominates the risk assessment.

Impact assessment is based on the economic cost of an impact (and carbon emissions for environmental risks). Events with lower projected costs are assigned lower impact scores.

The likelihood score can be considered a projected time to failure and is based on probabilistic models and / or historic performance of the components involved.

In some cases, a failure of an asset considered in the primary project will only have an impact in cases where a secondary component also fails, such as a network distribution system with redundancy. In cases where a coincident event is required for the failure to have an impact, the combined probability (or time to failure) is calculated with the help of a table that takes as input the likelihoods of both the main asset and secondary asset failing. For example, if the primary component has an expected failure time of four years, but a secondary asset that is required for the impact has an expected time to failure of 25 years, the combined likelihood score is lowered to account for the secondary failure required.

As described already, project prioritization scores are entered into the Corporate Risk Registry to assist with decision making by the Investment Management group. Some projects may be considered mandatory, such as projects to comply with targets set by regulators. Mandatory projects are assigned a project priority score of 49 (the maximum) regardless of other risk measurements. Some example scores for real-world projects are shown in Table 2. These project prioritization scores are entered into project funding requests, along with other pertinent details.

Table 2: Project Prioritization Scores with Impacts and Likelihoods

Assessing the impacts and risks for a project can be less than straightforward, especially in cases where the project is non-homogeneous. As an example, a rehabilitation project on a New York sub-transmission line, which was in generally poor condition, had a minor subset of poles that were in very poor condition and thus had a very high replacement priority. The whole project could be assigned a high risk score reflecting the worst subset of assets (the subset of poles), and thus funding the entire project, or it could be scored differently by recognizing the risk of the overall project could be reduced by just replacing the worst condition assets now. This would let the remaining assets stand alone with a lower risk score and be prioritized accordingly.

National Grid continues to develop the project prioritization process. Some questions and improvements being assessed include revisiting the combination of environmental, safety, and reliability scores. Currently, the maximum score is taken as the overall project prioritization score. However, there may be a better way to combine them numerically to reflect the combined risk. Another option being considered is to simplify the risk assessment process by assigning all projects in the same category with a category-based project prioritization score. In this way, all projects of the same scope and type (for example, all spacer cable replacement programs) would be assigned the same project prioritization score.

Technology

National Grid is loading network protector and network transformer information into Cascade, which will serve as the asset register.

National Grid uses a system called Computapole to record maintenance and inspection information. National Grid intends to migrate this information to Cascade.

National Grid utilizes a prioritization decision support matrix that is used to determine project risk by weighing the anticipated probability and consequence of a particular event occurring. For example, an asset failure could be scored based on the probability or time to failure, and the consequences if indeed that asset would fail. Microsoft Excel-based tools are used for calculating the blended risk scores and deriving the combined prioritization score based on the reliability, safety, and environmental risk categories.

PeopleSoft project funding request forms contain entries for the project prioritization score, which is factored into the funding requests. “Power Plant” software also takes project prioritization scores, along with the category from which it was derived (reliability, safety, or environment).

7.1.13 - PG&E

Planning

Asset Management

People

PG&E has effectively implemented an asset management process for network equipment. They have assigned a specific person as the “Manager of Networks”, part of the Distribution Engineering and Mapping organization. This asset manager is responsible for determining the investment, maintenance and replacement strategies for network assets including network transformers, network switches, and network protectors. Note that the asset management of cables and cable accessories is the responsibility of a different asset manager at PG&E, located within Distribution Standards.

The manager of networks is both an electrical engineer, and an attorney. He collaborates closely with the network planning engineer (Reliability and Planning), cable experts within Standards, and the Maintenance and Construction Electric Network group, the organization responsible for the execution of the asset strategies developed by the Manager of Networks.

EPRI observed strong working relationships between the manager of networks, and other key PG&E resources focused on network management. The manager of networks was visible and known to the field force, periodically meeting with field crews to review topics of interest.

The manager of networks has a well documented asset strategy for managing network assets. See Attachment A.

Process

PG&E has implemented asset management processes for network equipment. The asset manager is the asset owner, and is responsible for making decisions about assets and developing appropriate investment plans. These plans are then given to the maintenance and construction electric networks group to implement.

The asset manager has developed a life cycle plan that includes strategies for PG&E’s networks. These strategies are described in asset management lifecycle plan document. See Attachment A. The document includes general strategies for replacement of network equipment, maintenance, safety, and other strategies such as training and workmanship, accountability, network information tracking, organization design, and continuous improvement.

The strategy document further details the projects and programs have been implemented by PG&E to support the strategies. Examples of specific work being performed in the network in support of these strategies include:

Installing a state of the art fiber optic SCADA monitoring system to be used for establishing a real-time monitoring and condition based maintenance system. This system will include “self-healing” fiber optics to support the new SCADA system and provide for operational control, improved low-side protection and safer clearance procedures.
Replacement of deteriorated network protectors, transformers and other major components.
Use of dry type transformers in high rise buildings, where possible, or natural ester oil in explosion resistant transformers where dry type units cannot be used.
Installation of a new manhole cover system designed to improve safety and reduce risk of collateral component and infrastructure damage.
Continued improvement of the SAP based maintenance system to provide for a more efficient and consistent maintenance program for the networks.
- The SAP system provides tracking and data recording, automated trigger of follow-up maintenance based on oil testing, automated updates to a centralized asset register, automatic generation standard metrics and reports
Development of a condition based maintenance program to complement the SAP system.
- Recognizing that condition based maintenance programs are more mature in substation applications, the asset manager is planning to model the condition based maintenance approach being used in substations at PG&E for network assets. The condition based maintenance system is a comprehensive monitoring and tracking system that will add the following functionality into the SAP based system:
  - Integrates data from disparate data sources (for example, data from the oil sampling program presently being tracked on spreadsheets).
  - Moves from the use of manual checklists to mobile electronic data pads that check crew work and activities as it is being performed.
  - System will perform complex algorithms using asset characteristics, calculation parameters, maintenance performance history and operational events. As an example, these algorithms can tell the crews to replace the incoming lead cable leads on a primary transformer termination chamber versus just changing out the oil based on historical oil sampling and replacement information.
  - Execute various workflow scenarios while providing full integration with SAP based maintenance and the asset registry. This will also relieve some of the administrative and clerical work associated with entering data and will help to reduce data entry errors.
  - Trend laboratory data and other data for analysis including oil diagnostic testing, EC notifications, individual repair items, etc.
Implementation of a maintenance programs designed to meet the strategies described above and ensure regulatory compliance
- Maintenance strategies including annual oil sampling/pressure testing, network protector maintenance, vault maintenance, SCADA maintenance, and oil replacements.

Technology

Information about network systems is housed in two data repositories, PG & E’s SAP system, and their “Network Historian”.

The SAP system serves as an asset register, keeping information about assets including what was maintained, and who maintained it, and triggering maintenance orders based on predetermined criteria.

The network historian is an internally developed software application that provides the asset manager review of the condition of the network based on information monitored by the remote monitoring (SCADA) system. The network historian contains information such as historic loading, and network protector status, used by both the asset manager and planning engineers.

As PG&E implements a new SCADA system on their networks, the network historian will be the repository of the additional monitored information. The condition based maintenance functionality being implemented in their SAP system for network equipment will utilize data stored in the network historian. The asset manager is currently reviewing internal needs to identify the specific data, and data views that will be necessary in the network historian.

7.1.14 - Portland General Electric

Planning

Asset Management

People

PGE employs a Manager of Strategic Asset Management and Geo-Spatial Information, who oversees a department responsible for all aspects of asset management, including the downtown network. The department uses reliability reporting and analytics, undertakes root cause analyses for the transmission and distribution (T&D) systems, and provides support for the Outage Management System.

The Strategic Asset Management Team:

Includes an engineer focusing on reliability reporting and data analytics management of strategic assets
Supports and manages the OMS, especially the OMS model. The department’s focus covers asset management, reliability, and analytics.
Performs reliability and root cause analyses, as well as supports the asset models derived from health indexing of condition-based assets

The network issues are spread among a team of people, with no single individual responsible only for the network. The three Distribution Engineers covering the underground network work with the organization to provide technical data about the system. They are overseen by the Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards.

PGE also has a number of Internal Subject Matter Experts with in-depth knowledge of particular assets and systems. An experienced employee with a good understanding of assets and components supervises the storeroom.

PGE initiated a PAS55 program for asset management and contracted with third-party experts to assist them in developing asset management processes and a Microsoft Excel-based risk analysis model.

Process

Strategic Asset Management Program

PGE originated the Strategic Asset Management Program in 2013 to address concerns about aging assets within the company and reduce associated risk exposures. PGE performed a PAS55 assessment and now conforms with ISO 55001 standards.

Defining Risk: The process led to the development of a strategy and highlighted the need to provide a consistent definition for the nature of “risk,” because it was defined differently in different areas of the company. The company wanted to apply risk in a consistent fashion that was accurate and applicable to T&D. The standard definition for risk that PGE uses is:

The likelihood or probability of failure of a component multiplied by the consequence (of the failure)

In general, risk can be conveyed as points or in dollars. PGE opted to classify risk in terms of dollars, which led to a shift in departmental emphasis towards proactive investments in system assets. Across the enterprise, the utility has developed risk models that shape the majority of capital investments currently undertaken. Initially, the models focused on core asset management tasks, such as identifying assets that needed replacement. Lately, PGE is developing new tools to help determine different risk mitigation activities such as shifting loads and installing automation (see Figure 1).

Figure 1: Strategic asset management, risk assessment methodology

PGE developed the initial risk assessment models in Excel spreadsheets, for which the utility sought advice from an external consultant. The main intention was to create a transparent and flexible system rather than a “black box.”

Likelihood of Failure: The likelihood of failure is based on the type of asset, and PGE has developed failure curves for each asset type and individual asset. The data also includes condition information for assets, and the company is developing health indices for each asset according to age. PGE uses this methodology for each of the vital assets in the T&D system, including substation transformers, components, and materials including cables, switches, and breakers. Importantly, PGE evaluates every individual asset rather than developing aggregate figures. For example, when calculating the risk for a specific network protector, the age and condition are usually known. If this data is not available, it is sourced from industry information and cross-checked with Internal Subject Matter Experts.

Consequence: For every risk, PGE calculates the consequences by assessing the ramifications of a number of potential scenarios for each failure type. For example, although the majority of network protector failures may not pose severe consequences, one case could lead to a catastrophic failure. PGE assigns a dollar value to each scenario and, for each event, cost is calculated by:

Cost for PGE to replace the asset
Direct outage cos,
Customer costs including:
- Customer-affected costs, depending on the type of customer, length of outage, and customer loads. This is aggregated to calculate a dollar value.
- Interruption and duration costs are applied to the calculation. For example, an interruption for a residential customer could cost $7.00 initially, but cost a further $4.00 per hour if the outage is prolonged.

This cost is then multiplied by the probability, to derive a risk dollar value for the asset in question. To develop this model and the costs, PGE used a study that Pacific Gas & Electric (PG&E) performed in 2012 [1], and an ICE study that Lawrence Berkeley Laboratory performed.

Overall, the risk models are used to support decisions rather than act as tools for making decisions. One of the major challenges found when evaluating the network with these asset models is that, in most cases, when there is an outage on the network, there is no customer outage or interruption because of the contingency built into the network design. Therefore, any modeling based on customer outage and the severity of such incidents is slightly compromised by the fact that the network is very reliable and has multiple contingencies. This is similar to the PGE transmission system, which is also very reliable with multiple contingencies.

In Figure 2, the orange line shows the risk for an existing asset, while the dashed blue line shows the annualized cost of replacing the asset. Therefore, in some cases, coping with the increased risk is preferable until it becomes cheaper to replace the asset. Undertaking this kind of modeling requires a range of different talents and expertise covering engineering, operations, and economics.

Figure 2: Deciding when to replace an aging asset

Additional Parameters: PGE is trying to capture additional, less-tangible parameters, such as safety, and incorporate them into the model. Refinements will incorporate injuries, including work-related injuries caused by dealing with certain types of equipment.

PGE is revisiting the key drivers for asset health and trying to gain a better understanding of how to convert age and condition into an index, and highlight key metrics/indices that help engineers understand trends over time. It is also important to understand that tests for some asset types give results that require immediate action, while some results influence long-term asset management.

Network Asset Management: The asset management program remains under development for the network system, and PGE is unsure if it has enough information to build an accurate model. In addition, floods and earthquakes need to be taken into consideration as part of the model. For all radial assets, the number of customers served is known. For the network model, the total load for a spot served by the network is used, allowing the model to calculate the likelihood the network will fail at that point.

Change Management: To introduce the new asset management system,PGE developed a change management program to implement the program smoothly. This new approach to asset management has been well accepted outside the network system. The approach is slowly being accepted on the network where, for example, engineers have pointed out that the network’s substations carry high risks. The model clarifies the two aspects of risk, namely the probability and the consequence, giving a better picture of the overall risk and preventing engineers from becoming too focused on only one aspect.

Portfolio Management Model: The asset management model will be developed alongside a Portfolio Management Model that will include:

Political/regulatory specifications
Environmental considerations
Safety aspects
Implementing a remote monitoring system
Replacing network protectors. In the last five years, the company has replaced slightly more than one third of the network protectors with an all “dead-front” design (Eaton CM52) for safety reasons.
Lead cable replacement in targeted for high-risk vaults.

Non-Asset Risk: The risk assessment model has also been applied to non-asset risk, such as interruptions that vegetation, public intervention, and human error cause. This will enable PGE to fully understand the full breadth of the risks and accept that failing assets/equipment are not the only causes and drivers of risk.

Risk and Replacement Programs: At present, PGE has not used the system for any specific replacement programs on the network. PGE has emphasized other areas of the company and will further refine the model before it will suit the network. In addition, other programs are already focusing on the network. For example, the detailed root cause assessment – the Performance Improvement Assessment (PIA) – has driven the lead cable replacement program.

Network Improvements: In the last 10 years, PGE has invested in bolstering the network, including:

PGE uses a model to underpin a proactive replacement program for reinforcing the civil infrastructure of vaults and manholes, including the replacement of manhole lids. In addition to the modeling, findings from vault inspections and from equipment testing, such as oil sampling, drive asset replacements and upgrades.

Technology

2020 Vision Program: PGE has initiated the 2020 Vision Program, which is comprised of several projects to transform the existing technology into a more integrated platform. It will streamline the number of applications and vendors used to leverage technology and improve work processes. Part of this includes developing a single work and asset management system, which will include:

Figure 3: 2020 Vision Program

Maximo Mobile and Scheduling
Geospatial Information System and Graphic Work Design replacement (GIS/GWD)
Outage Management System replacement (OMS).

Maximo for Utilities 7.5
Geographic Information System (GIS) – ESRI ArcGIS

PGE’s asset management program uses IBM’s Maximo for Utilities 7.5 system, which supports asset management processes for T&D utilities. Maximo can be integrated with a number of systems, including fixed-asset accounting, mobile workforce management solutions, and graphical design systems. The Maximo Spatial system is compatible with map-based interfaces, such as ESRI ArcGIS, and follows J2EE standards.

Maximo for Utilities supports operations across a number of areas, including integrated fixed-asset accounting. The Spatial Asset Management module includes a map-based interface to track assets and locate work order and/or service request locations . The PowerPlan Adapter is a corporate-level suite intended to facilitate accounting during operations. The system automates asset lifecycle management and supports compliance monitoring.

To support asset management, engineers use ArcFM, which is built upon ESRI’s ArcGIS system and is linked to the Maximo system. GIS is used to map assets and circuits, and can be linked to the customer information system and other enterprise applications. The maps provided with ArcGIS include facility maps, circuit maps, main line switching diagrams, and a service territory map .In 2017/18, PGE will investigate processes for transferring ArcGIS/ArcFM information into CYME, which will require a software development from the vendor, Schneider Electric.

7.1.15 - San Diego Gas and Electric

Planning

Asset Management

San Diego Gas and Electric Tee Modernization Program

Summary

To illustrate how asset management can help utilities channel resources to the right areas, this case study examines how San Diego Gas & Electric (SDG&E) addressed performance issues with Tee-body connectors. Faced with systemic failures in these components, the utility used risk management techniques to create a predictive model and a cost-effective replacement policy.

The program drew upon the utility’s existing risk-based approach to strategic asset management, using enterprise system data and analysis to refine maintenance and replacement programs. SDG&E already used this approach when developing a cable replacement program for unjacketed cables with high failure rates, and the lessons learned provided a good foundation for solving the issues with Tee-bodies.

Tee-body connectors are a relatively minor component used extensively on SDG&E’s underground distribution system. In manholes and hand holes, some units started to fail, causing extensive outages that proved difficult and time consuming for crews to repair. Accordingly, SDG&E developed a model to aid in identifying candidates for replacement, and a consequent program that replaced high risk Tee-bodies as well as installed Cooper Load Break Connectors (CLEER 600A connectors) in vulnerable locations.

Overview of SDG&E

A subsidiary of Sempra Energy, San Diego Gas and Electric (SDG&E) is a regulated utility that distributes electricity and natural gas to 3.6 million customers. Alongside 873,000 natural gas customer meters, SDG&E serves 1.4 million electricity customer meters including 1.27 million residential customers, 158,000 commercial customers, and 46,000 street light customers. To provide services to its customers, the utility employs over 4,000 people.

The utility’s service territory of 4,100 square miles (10,600 square kilometers) stretches across San Diego and southern Orange County, in California. The system includes 134 distribution substations and 225,697 poles, with 10,558 circuit miles located underground and 6,527 overhead. Most of the utility’s distribution circuits operate at 12kV, with the remaining 4kV systems presently undergoing conversion.

Strategic Asset Management Strategy (SAM)

At 62%, SDG&E’s ratio of underground to overhead systems is much higher than other Californian investor owned utilities. This can lead to higher costs such as, for example, traffic control for manhole maintenance, or the extra labor needed to troubleshoot problems on the underground. The higher cost associated with managing underground systems elevates the need to assure prudent and cost-effective investment. Consequently SDG&E has deployed an asset management program that maximizes investments by targeting resources where most needed.

SDG&E’s Strategic Asset Management (SAM) program uses ISO 55000 standards, with a specialized team responsible for implementing the program across the business. The utility’s evolving asset management approach will facilitate governance, analytics, and data management across all business units. The integrated strategy includes planning, design, construction, and maintenance, and uses a life cycle strategy for assets within each asset family covering record keeping, replacement strategies, and performance indicators.

Asset families represent a broad grouping of assets, such as “distribution underground or overhead transmission”. Each asset family is comprised of asset classes, such as distribution underground cables or distribution underground transformers, both part of the distribution underground family.

For each asset class, SDG&E has developed an asset ownership hierarchy, where specific people, usually directors, are assigned strategic oversight for the asset class. This structure is part of the overarching policy for planning, design, and construction across the company, promoting consistency and integration.

SDG&E’s asset management program uses a risk-based approach to prioritize remedial actions. Each asset class has a life cycle strategy that defines the records to be kept about asset and supporting systems, the maintenance and replacement approach, and performance monitoring and measures. SDG&E is required to report risk mitigation strategies with the California Public Utilities Commission (CPUC).

SDG&E’s growing asset management program promises to deliver cost effective risk mitigations and provide the maximum value to ratepayers.

Software

At the heart of its asset management strategy, SDG&E uses an enterprise system and database to manage information and produce outputs that can be used to quantify risk. The utility’s Enterprise Risk Management System (ERM), presently SAP, holds most of the data, and the system meshes with the GIS mapping and financial systems.

Last year, SDG&E performed a gap analysis of the existing systems, including GIS, financial systems, and the SAP enterprise resource planning software, to determine how these systems could support the developing asset management system and maintain data integrity. The analysis recommended three upgrades that would support future asset management:

Enterprise Asset Management (EAM): Provide a data lake and platform that integrates all key data from the various systems, especially the critical data needed for decisions.

Asset Performance Management System (APM): Offers a tool to help analysts understand asset health, performance, and condition.

Asset Investment Prioritization Tool (AIP): Prioritize and rank investments based on strategic factors such as safety, reliability, and the regulatory environment.

Corrective Maintenance

SDG&E’s strategic asset management program helps engineers determine if maintenance practices, especially for corrective maintenance, are optimal. The program, as it evolves, will help the utility assess which programs will be cost effective and provide maximum impact with respect to lifecycle costs, regulatory requirements, reliability, and integrating future technologies. The ISO 55000 framework will help SDG&E shift its focus from “how to do” to “what to do”, and identify the risks and opportunities for a particular action, while improving the value of assets.

At present, SDG&E asset managers develop risk scores for certain asset types such as poles, cables, and cable accessories such as Tee-bodies. These risk scores are developed by looking at various asset characteristics such as vintage, manufacturer and performance history, and are used to prioritize investments. The effectiveness of corrective maintenance can be assessed by understanding and quantifying the impacts of corrective maintenance investment on asset risk as determined by the risk scores. At present, circuit risk scores used to prioritize investment are relatively simple, as they are static and not updated in real time to capture new events. As the asset management system evolves, the utility will develop a dynamic risk management tool that uses machine learning to draw inferences and predict risk in real time. SDG&E will move towards models developed in-house rather than “black box” models provided by external consultants.

Unjacketed Cables

When first faced with the issue of failing Tee-bodies, SDG&E’s engineers could draw upon the lessons learned from its very successful cable replacement program. In the 1980s and 1990s, the utility saw a spate of cable failures affect unjacketed cables installed in the 1960s and 1970s. Accordingly, the utility set up a program to mitigate this issue by collecting cable data information from the field and cross referencing with purchase records and other records to determine the extent of this cable type on the system. With the support of a consultant, SDG&E assessed the data and established the failure rates for in service unjacketed cables according to cable vintage. Initially, the utility performed the analysis in Excel before creating a comprehensive cable failure database that they continue to populate with new data. Throughout the 1990’s, SDG&E focused on proactively replacing unjacketed cables, with a particular emphasis on replacing 750 Al and 1000 Al unjacketed cables along feeder mains, which had been significant contributors to SAIDI.

While the cable replacement program produced significant improvements in SAIDI, underground cable failure rates again increased in the early 2000s. Further analysis showed that jacketed cables installed between 1977 and 1983 were responsible, even though they were not the oldest cables on the system. Because engineers were not fully sure where this cable type was installed, they developed a database that assembled information gathered from the field, from work order information extracted from existing databases, and from information identified and entered from older paper records. This database was used to prioritize the cable replacement program. The new cable replacement program proved very effective and failure rates fell significantly.

When SDG&E began to experience failures of Tee-body connectors used on the underground system, it leveraged its experience and approach with cable replacement to address the problem.

Problem/Challenges with Tee Bodies

Despite SDG&E’s very successful cable replacement project, the utility began to experience outages on its underground distribution system due to failures of 600 amp Tee-body connectors fitted across the system. Although Tee-bodies are relatively simple components, a failure can result in an entire circuit outage, with a large impact on overall reliability.

Tee-body units can cause high SAIDI outages because they are usually located within manholes and hand holes. These can be difficult to access, and are often flooded and require a pumping truck, making it difficult for crews to locate and rectify any problems. Because SDG&E has over 140,000 handholes and 3,000 manholes on its system, the utility needed a targeted, cost-effective program based upon risk to address replacement of this component.

Solution/Model Description

The Tee Modernization Program (TMP)

SDG&E, aware of the reliability problems posed by the units, initiated the Tee-body Modernization Project. Initially, this project assessed a number of options, such as changing the Tee-body design or using different components to replace the Tee-body. After developing a capital project and budget to assess the issue, SDG&E asked NEETRAC to perform a root cause analysis. The study produced varied reasons for failure, and the fact that Tee-bodies are “minor” components and rarely tracked in detail, made failure rate analyses difficult. The study identified number of potential issues:

Missing bleed wires,
Eroded/missing copper foil wrapped around the connector, probably due to age and/or flooding,
Failure of the double ended connector plug,
Problems with workmanship and installation practices.

See Figure 1.

Figure 1: 600 A Separable Connector (Tee-body) Cutaway

Of these, the double-ended connector plug joining multiple Tee-bodies, known as the “football”, proved to be the main cause. Early versions of this connector plug used an epoxy material in the center that was found to be prone to cracking, especially if crews used the incorrect torque during installation. SDG&E switched to a molded unit in 2012, which is center-torqued and less prone to failure, but numerous epoxy versions remain on the system.

See Figure 2.

Figure 2: (Left) Connector plug (Epoxy material). (Right) Connector plug (molded unit)

To solve the Tee-body problem, SDG&E proposed:

Replacing the epoxy footballs with molded footballs, Installing Cooper Load Break Connectors (CLEER 600A connectors) in selected locations.

Developing a Predictive Model

Using its asset management approach, SDG&E implemented a model-driven risk analysis for determining candidate Tee-bodies for replacement, allowing engineers to assess the most effective way to mitigate the issue and prioritize which units to replace.

Initially, SDG&E devised a “heat map”, a visual depiction on a map of where all Tee-body failures occurred since 2002. The map depicts all relevant historical information and includes:

Flooding information for manholes, Location information, Available fault current in substations. Engineers rarely tracked Tee-bodies (a minor component) with the same granularity as larger components, and the GIS system does include the level of detail that would indicate the specific location of Tee-bodies, or supporting information such as vintage or type. The scarcity of data meant that analysts used outage reports and equipment failure reports to develop an Excel based model to evaluate risk and prioritize replacements.

Teradata Analysis

For the next stage of the process, SDG&E engaged an analytics specialist, Teradata , to review the problem and propose a root cause. Teradata drew data from SDG&E’s work order history, installation history, and outage history to develop a “best guess” age for the Tee-bodies.

Teradata also developed a “Hazard Value”, which predicted the chances that an individual Tee-body will fail and cause an outage. Teradata’s model used a machine learning process to determine this value and included two assumptions:

If a particular manhole contains a failed Tee-body, then adjacent circuits in the same manhole are more likely to undergo a Tee-body failure.

Locational predictions are important, because a cluster of Tee-body failures in a given area means that Tee-bodies of a similar age in close proximity are more likely to fail, as they are likely of similar vintage and exposed to similar conditions.

SDG&E learned a lot from this initial analysis and discovered that many of the Tee-body failures occurred at locations between the substation breaker and the first interruption device. Initially, engineers suspected that this could be because these components see high fault currents, and that this might increase the degradation rate.

SDG&E’s Unified Model

Although Teradata’s model proved useful, SDG&E wanted to create a model that blended the data from Teradata with their own data. To achieve this, the utility developed a multi -attribute risk model that considered both the predictor (probability) and the consequence of Tee-body failure for each circuit under analysis.

See Figure 3.

Figure 3: Tee-body Risk Analysis Model

Modeling Predictors

The probability factors, or predictors, used in the model contain the following elements:

Number of 600A Tee Failures
Number of 600A Cable Failures
Number of 200A Connector Failures
Number of 200A Cable Failures
Bus Fault Current

In addition, the utility included the two Teradata-developed factors:

Average “Best Guess” Age of Tee-body
Average “Hazard Value”

The values for failures by circuit were drawn from the equipment failure report database. For each of the predictive factors, the model uses normalized values. To create the normalized values, the model divides the original value by the system average do develop a “per unit” value.

Modeling Consequences

Assessing risk uses a matrix expressing a function of the probability of an event and the consequences of the event. With risk-based approaches, assessing both the probability of a failure and the consequences of the failure are equally important.

For the model, SDG&E uses a normalized consequence figure with two values:

Normalized Customer Minutes: For every location on a circuit, if an outage occurred, what are the total customer minutes expected? This number is generated by looking at historical average customer minutes of interruption at each location for every given outage. If everything else is equal, a circuit accumulating more customer minutes is generally more difficult to repair and carries a higher risk.

Normalized Customer Count: This describes the number of customers on a circuit, because a circuit heavily loaded with customers delivers larger consequences and higher SAIDI when an outage occurs.

In order to produce the final “Total Risk Score” for Tee-bodies on each circuit, the model uses the weighted sum of the various predictors multiplied by the weighted sum of the consequence values.

See figure 4.

Figure 4: 'Total Risk Score' Formula

The “Total Risk Score” allows SDG&E to rank projects and determine where remedial action will prove most effective. The model also allows users to adjust the various weightings, over time, as the utility gathers more data and root cause information.

Model Performance

The model has performed well. SDG&E used a validity evaluation to assess its risk predictions, comparing the locations of actual Tee-body failures with the risk scores produced by the model. Engineers who performed the validation categorized any location which was predicted in the top 25% highest risk as a “true” prediction, anything in the top 25-50% as a “near” prediction, and the remainder as a “miss”.

SDG&E also tested the hazard scores and age values produced by Teradata, especially Teradata’s prediction that Tee-bodies of approximately 12 years of age were more likely to fail (even more likely than older units). Engineers assessed the average age of failed Tee-bodies at locations which received a high-risk score in the model and found that they were, on average, 11 years old. This suggests that results of the Teradata prediction are reasonably accurate, and the utility is further exploring the data.

Age may well be an important factor behind failure, and because the utility has no records of age for the Tee-bodies, they will continue to use Teradata’s “predicted” age value. SDG&E is also refining the data gained from the outage management system and will continue to amend the model as new issues emerge, as part of the dynamic, machine-learning process.

The Model in Practice

With the model in place, SDG&E’s engineers developed a plan to convert the predictions into practice. The utility looked at the circuit rankings and selected suspect circuits, using the predicted age and hazard values, before using a “scoping” process to inspect the highest risk locations. Crews begin their inspections at the substation and follow the primary cable, assessing which Tee-bodies are present in each manhole/hand hole.

With scoping complete, engineers complete a pre-design review, where employees/contractors look at manholes and assess the feasibility of installing a replacement Tee-body or a CLEER device. Because the highest risk failures occur before the first interruption device, causing a full circuit outage, SDG&E emphasizes replacement of higher risk Tee-bodies in these manholes. In select locations, crews will replace Tee-bodies and with CLEER device that provides additional operational flexibility (see below).

To support information gathering and provide additional data, SDG&E developed a Tee Modernization Program Field Reporting form for the pre-design inspection. The electronic form helps crews provide information about the condition of manholes and Tee-bodies, such as whether the manhole was flooded or the Tee-body overheated. In short, SDG&E can collect more data to refine and enhance the model as part of the dynamic asset management process. As part of the Tee Modernization Program, SDG&E ensures that internal crews (non – contractor) perform a proportion of the work to ensure that they develop the right skills and knowledge to maintain and replace units.

CLEER Devices

SDG&E is selectively replacing Tee-bodies with a Cooper Load Break Connector (CLEER 600A connector) . CLEER devices installed in manholes achieve two main purposes:

They replace the Tee-bodies,
They allow easier sectionalizing and support better operability of the circuit

These connectors:

Are rated as loadbreak switches
Have fault-closure capability
Do not require any unbolting of connections to operate
Provide a visible break and visible ground connection.

See Figure 5.

Figure 5: Cooper CLEER

SDG&E is installing CLEER devices as Tee-body replacements in selected locations to increase operational flexibility. At present, SDG&E is not using the CLEER units to break load. The devices enable crews to isolate faulted circuit sections and restore circuits quickly without having to disassemble 600 amp Tee-bodies.

Engineers noted that selected manhole locations must be large enough to accommodate the device. SDG&E avoids installing the CLEER devices in manholes with existing switches, because these locations don’t require the additional operating flexibility provided by the CLEER device.

They material cost of the CLEER device is about six times more than Tee-bodies, but the labor unit costs to install and to “operate” are significantly less. Crews can install a new T-connector and CLEER device in about two hours, as opposed to over six hours for a set of Tee-bodies.

For asset management, CLEER devices have their own mapping symbol on the GIS, making it much easier to track the devices and analyze their performance. Engineers are assessing a handhole version of the CLEER device that can operated from outside the hole.

Future plans/next steps

SDG&E intends to inspect 50 – 70 structures per year, totaling approximately 200 T- body devices. They are intentionally limiting the number of replacements while they test their model and enhance its capabilities.

For example, the model’s next version will include the number of customers per protective zone rather than the total number of customers on a particular circuit. In addition, based on experience with the model, SDG&E experts now believe that the 12kV substation bus fault current input into the model is not a significant contributor to the risk prediction and will exclude it from the amended model.

The risk-based approach to asset management and corrective maintenance is working well across the system, and is helping SDG&E target resources where most needed. With the use of a model-based predictive system, the utility is overcoming the complexities posed by the large number of assets on its distribution system.

7.1.16 - SCL - Seattle City Light

Planning

Asset Management

People

Organization

Network Planning at Seattle City Light is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A: SCL - Org Chart . The Network Design Department focuses exclusively on the planning and design of SCL’s networks.

Although SCL does have a separate planning group that performs distribution planning activities for SCL’s non-network distribution system, this group does not do the planning associated with the network. All cable ratings, load flow and voltage studies, master load flow analysis, assignment of feeders to load additions, area studies, etc. associated with the network are performed by the Network Design Department staff.

(Note that SCL is currently implementing an Asset Management organization. At the time of this writing, SCL had not yet decided whether certain tasks currently performed by the Network Engineering group will be moved into the Asset Management organization.)

The Network Design Department is made up of a System Group (eight engineers) and a Services Group (eight engineers). These engineers do all of the planning and engineering for the network (the System Group), as well as interface with network customers for load additions, new loads, etc. (the Services Group). The individuals in this group are four-year degreed engineers. The senior level engineer position at SCL requires a PE license. The engineers at SCL are represented by a collective bargaining agreement (IBEW).

Technology

Network Maps and Asset Records

SCL utilizes a home-developed system called NetGIS. NetGIS is their repository for network asset records, and also the product they use to produce network maps. NetGIS is not a full, graphical GIS system with electric connectivity. Rather, it enables SCL to produce CAD maps, and to maintain records associated with each network vault. Note that their load flow analysis product is not tied in with NetGIS.

More specifically, SCL personnel can obtain maps from the system, and can click onto a vault to obtain a description of the equipment contained in the vault including:

Splice type and information
Ductbank configuration
Civil information
Ground points
Busbar

When a change is made to the network, the GIS section updates the network feeder maps in NetGIS.

7.2 - Cable Rating

7.2.1 - AEP - Ohio

Planning

Cable Rating

People

Cable rating is performed by the AEP Network Engineering, which is organizationally part of the AEP parent company. Network Engineering includes two Principal Engineers and one Associate Engineer who perform network planning and engineering, including cable rating, for the Columbus and Canton urban underground networks. These engineers are geographically based in downtown Columbus at its AEP Riverside offices. Columbus-based Network Engineers perform cable ratings in collaboration with AEP Distribution and the Network Engineering Supervisor. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the Director of Engineering Services who in turn reports to the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues. This committee will discuss and recommend cable ratings modeling approaches to be applied to AEP networks.

Process

AEP Ohio Network Engineers use the published thermal ratings of primary and secondary cables available from the manufacturers as a basis for cable rating models. These ratings tables contain thermal capabilities consistent with normal and emergency temperatures and are input into CYMECAP for further analysis. According to the AEP Network Planning Criteria guide, “the tables use the methods of J.H. Neher and M.H. McGrath. These tables also contain impedance data to be used in computer studies and to support network plans. To insure consistency, only data from these tables is to be used in network planning studies.” These methods are incorporated in the CYMCAP tool used by AEP Ohio Engineers.

The Network Engineers also analyze other factors to determine the thermal resistivity, including the type of backfill, duct line configuration, and results from thermal resistivity measurements. Thermal resistivity information is also entered into the CYMCAP software, which generates adjusted cable ratings for the region.

Technology

Cable ratings are based on published charts from manufacturers and the AEP parent company. This data, along with local variables that can affect the ratings, such as soil type, is used in CYMECAP to arrive at ratings curves. This modeling provides accurate ratings for use in the field for AEP Network Engineers. The CYMCAP cable rating module is used for both primary and secondary feeder ratings (see Figure 1).

Figure 1: CYMCAP software module for rating cable thermal resistance

[Source:CYME International T&D ]

7.2.2 - Ameren Missouri

Planning

Cable Rating

People

Responsibility for producing tables that provide cable ampacity ratings at Ameren Missouri lies with Distribution Planning and Asset Performance. This group, led by a manager, is staffed with four-year degreed engineers, and includes the Standards Group as well as a planning engineering Group. Organizationally, Distribution Planning and Asset Performance is part of Energy Delivery Technical Services, reporting to a vice president.

Local distribution planning of both the network and non-network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division. The Underground Division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineers in this group are responsible for applying the company’s standards, derating cables appropriately based on their duct bank configuration when performing designs.

Ameren Missouri has produced tables that provide cable ampacity ratings for various types of cable based on size, type, and duct bank configuration. These tables are maintained by the Standards Group.

Process

Ameren Missouri has generated tables that provide cable ampacity ratings for various types of cables based on duct bank configuration. These cable ratings provide guidance to field engineers to derate the cable to a certain level based on field conditions, such as the duct bank configuration.

The cable ratings are fairly conservative. The tables were developed by the Standards Group 15 to 20 years ago, and are not routinely revisited.

Technology

The information in the cable ampacity tables presently used at Ameren Missouri was generated by hand, and using an Ameren Missouri cable rating program.

7.2.3 - CEI - The Illuminating Company

Planning

Cable Rating

People

The Planning and Protection Section uses manufacturer published ratings for cables in performing loading studies. Depending on the situation, they may use adjusted ratings that are provided by either the Underground / LCI Section of Engineering Services group or by the corporate Design Standards group.

In the past, CEI had developed and published specific cable ratings for cables of various types and in various scenarios (Normal ratings for winter and summer, emergency ratings, ratings in various duct bank configurations, etc.). In addition, the corporate Standards group also publishes cable ampacities lists with de-rating factors based on duct bank configuration. The Dispatch office keeps a copy of these ratings.

CEI does not periodically revisit and update the ratings list without some indication of a change in conditions. The current practice at CEI is to re-rate cables on an “as need” basis. This re-rating is performed by either the Underground / LCI Supervisor within the CEI Engineering Services department or a Senior Engineer within the corporate Design Standards group.

Process

CEI has documents that provide cable ratings for each feeder. For example, when CEI moved to the use of EPR cables, they computed the cable ampacities of EPR cables for various duct configurations. Note that FirstEnergy has made a decision not to de-rate cables in cable risers (above ground).

CEI does not systematically perform calculations and update cable ratings on their cables based on system conditions and configuration. Instead, their Engineering department will perform cable rating calculations in response to a particular project need. For example, “I need another 20 amps, can I get it?” In response to such a request, either an engineer in the Underground / LCI section of the Engineering Services group, or an engineer within the corporate Design Standards group will perform the cable rating calculations.

Technology

When a specific calculation is needed, cable ampacity ratings are computed manually by the Underground / LCI Section of Engineering Services using the Neher-McGrath method. The corporate Design Standards group is utilizing a Cable Ampacity Software package to assist in performing cable rating calculations.

7.2.4 - CenterPoint Energy

Planning

Cable Rating

People

At CenterPoint, cable rating is performed by the Electric Distribution Planning department (Planning group). This group is not part of the Major Underground group organizationally. One planning resource, an Engineering Specialist, is assigned full time to work in Major Underground, in a matrixed arrangement.

The Planning group is comprised of 21 total resources, including 2 Lead Engineers. Each of the Lead engineers has about 6 -8 people reporting to them. These folks are either 4 year degreed engineers, or technical experts. CenterPoint aims to have a balance between Engineers and Technicians.

CenterPoint encourages its engineers to obtain their PE license. The PE license is required to become a Senior Engineer.

Process

In 2004, the Engineering department of the Major Underground group engaged a contractor to perform an analysis of CenterPoint feeder ampacities and produce updated ampacity tables for their 12kV and 35kV cables.

The study included a review of CenterPoint’s distribution duct banks to identify duct sections that are most likely to have high cable temperatures. In general, the duct bank sections that were selected had a high number of feeders in the same duct bank and / or a relatively deep installation depth.
The method involved installing sensors and fiber optic cables within selected duct banks to perform temperature measurements to verify the accuracy of calculations performed within cable ampacity programs. Measurements were taken at 18 different duct bank sections on two different occasions (the last weeks of July and August). The temperature monitors recorded temperatures of a vacant duct at one meter intervals between manholes.
The contractor also performed an analysis of hourly load data for the feeders in the duct bank to determine and correlate the daily peaks and load /loss factors to the distributed temperature measurements. This information was then used to perform cable ratings calculations on other feeders.
The contractor produced a detailed report of CenterPoint Feeder ampacity tables.

The Planning group does perform a global recalculation of the cable ratings on a regular basis. They will review a circuit rating with respect to adding new load or pulling in a new feeder on an as needed basis. They will also perform analysis in response to feedback from the field that certain areas may be getting hot, or from information about feeder loading gathered from their substation monitoring system. A feeder that is “near the limit” may warrant a careful look at the duct bank configuration and analysis of the cable ampacity.

CenterPoint noted that they have had little experience of burned up cables due to overload.

Technology

When a specific calculation is needed, cable ampacity ratings are computed by the Planning group using CymE CAP cable rating software.

7.2.5 - Con Edison - Consolidated Edison

Planning

Cable Rating

People

Rating of cables for network feeders and network cable sections is performed by the Network Engineering and Planning group. Responsibilities of this group include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.

Process

Distribution network feeder and cable section ratings are calculated by using the Con Edison Poly-Voltage Load Flow (PVL) system. The system considers the impacts of soil type and temperature. The system does not automatically consider the proximity of electrical facilities to steam mains.

Technology

Load Flow System – Poly-Voltage Load Flow (PVL)

Con Edison utilizes a distribution load flow application called Poly-Voltage Load Flow (PVL). The PVL application is actually a suite of applications that was developed in house over a 20-year period of continued development. In addition to aiding engineers in performing load flow analyses, the PVL system is used to build feeder and transformer models, develop network transformer ratings, develop network feeder and cable section ratings, model area substation outages, and identify short-circuit duty at customers sites, etc.

7.2.6 - Duke Energy Florida

Planning

Cable Rating

People

Cable Ratings for cables used by Duke Energy Florida are published and maintained by its Standards Group. Network Planners and Designers used these published ratings to determine cable loading limits.

Process

Duke Energy Florida’s standard feeder cable for non-network applications is 1000MCM Al XLPE. For network feeders (in Clearwater), their standard size is 4/0 CU XLPE, with pockets of 750MCM AL XLPE in place in some areas.

When planning additions or refurbishments, designers adhere to the Cable Ratings.

Standards arrives at its ratings using manufacturers’ specifications and through testing of sample cables. All Duke Energy Florida Engineering personnel have access to the standard ratings through CYMCAP. Additionally, CYMCAP is run to determine case-specific cable ratings if the cable is constructed differently than manufacturers’ specifications, or there are characteristics of the cable run that may impact the cable rating (such as multiple cables in a duct bank).

Technology

The Standards Group maintains Cable Ratings in CYMCAP, available to all Engineers.

7.2.7 - Duke Energy Ohio

Planning

Cable Rating

People

Cable rating for network feeders is the responsibility of the network planning engineer.

Process

For planning, Duke Energy Ohio uses standalone, 90° loading limits. The planning engineer noted that for radial systems the 90° loading limits work well because the other equipment has similar equivalent ratings. Moreover, radial feeder duct banks aren’t that crowded.

Duke Energy Ohio uses the CYMCAP cable ampacity calculation software. The planning engineer has access to CYMCAP studies for primary cables produced by previous planners. The planning engineer is presently evaluating the results from the earlier studies to determine the appropriate cable rating for network feeders. CYMCAP will be used to update ratings for feeders that have changed since the prior studies.

Secondary cables have been rated by hand calculations by prior planning engineers.

Technology

Duke Energy Ohio uses the CYMCAP cable ampacity calculation software.

The planning engineer maintains a file of cable ratings for network feeders.

For radial feeders, Duke publishes both the normal rating in emergency rating of the feeders on the feeder maps. For network feeders, feeder ratings are not published on the maps.

7.2.8 - Energex

Planning

Cable Rating

People

Cable rating is performed by engineers within the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

Energex has performed studies to determine cable ratings for feeders supplying their CBD. These cable ratings consider factors such as anticipated operating temperatures, soil conditions, and duct back configuration. Energex cable ratings are published in a database of ratings, called the ERAT system, and also included in the tables associated with their load flow tools. For example, all cable ratings are housed within the DINIS load flow product used for analysis of their 11 kV primary system feeding the CBD.

Energex does not normally de-rate cables in performing its normal designs. However, in special situations, the company may perform cable ratings analysis using CYMCAP ^[1] to identify situation specific ratings.

Figure 1: Sample Energex cable rating criteria for XLPE cables

Technology

Cable ratings are housed within the DINIS load flow product used for analysis of their 11 kV primary system feeding the CBD. In special situations, Energex may perform cable ratings analysis using CYMCAP to identify situation specific ratings.

^[1] CYMCAP, Cable Ampacity Calculation software, from CYME, a Cooper Power Systems company.

7.2.9 - ESB Networks

Planning

Cable Rating

People

Cable rating at ESB Networks networks is performed by planning engineers within the Network Investment groups – two groups responsible for planning network investments in the North and South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Cable rating is performed by planners, with one planner focused on HV planner and four focused on MV planning. Most of these individuals are degreed engineers, but some are “Technologists,” who have developed their expertise through field experience.

Cable planning standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

The Dublin MV underground network is operated at 10 kV. The 10 kV system is supplied from either a 38 kV system or from a 110 kV system. ESB Networks has 31 38:10kV stations, and 7 110 kV:10kv stations.

ESB Networks takes a highly planned approach to rating cabling throughout its network. Ratings are documented in the company’s Cable Manual for use by planners and by maintenance personnel. Each cable type receives not only a standard rating but also summer and winter peak ratings. The ESB Networks rating system also takes into consideration factors such as the number of feeders, clearances based on circuit / duct configuration, and any likelihood of thermal bottlenecks.

Ratings include the following factors:

Soil thermal resistivity
90 ° C maximum operating temperature
Burial depths of 0.45 m for LV, 0.75m for MV, and 0.9 m for HV
A 5 ° C winter rating and a 15 ° C summer rating
150 mm spacing of circuits between ducts

Solid paper cable is rated at 65 ° C operating temperature and fluid-filled cable at 85 ° C. All cable is buried in ducts at minimum depths, but may be buried lower depending on soil conditions. If there is an inquiry concerning a load, the engineer must consult with the planning group to assure the proper cabling is used for the load it will carry. This ensures that cabling used is within ESB Networks-documented design limits.

In selecting cable size, ESB Networks assesses factors such as long-term economic loading to justify cable size, short circuit capacity and any likely derating factors, such as bunching of cables in the vicinity of substations, burial depth, crossing bad ground, and crossing other cables. (See Figures 1, 2, and 3).

Figure 1: ESB Networks derating profile

Figure 2: Cable derating factors

Figure 3: ESB Networks circuit spacing standards

Cable selection criteria include the following factors:

Current rating
Voltage drop
Short circuit rating
Mechanical strength
Cost of losses
Lifecycle costs over 25 years

Note that due to the high concentration of salt in the air, corrosion of cable is a great concern for ESB Networks. The company is actively seeking best practices in corrosion mitigation. ESB Networks asks its cable suppliers to provide at least a five-year cable warranty that covers corrosion.

Technology

ESB Networks has a comprehensive cable rating manual (“Cable Book”), which includes cable-rating illustrations. The manual is available online for ESB Networks personnel. ESB Networks also uses CYME Power Engineering® software for cable-rating information.

7.2.10 - Georgia Power

Planning

Cable Rating

People

Planning of the network underground infrastructure in Atlanta and other metro underground systems (Savannah, Macon, and et al.) is the responsibility of the Area Planners assigned to these metro areas and the Network UG engineering group within the Network Underground Division. The Network UG Engineering group, within the Underground Network Division, is led by a Manager, and is comprised of engineers and technicians responsible for the network. Engineers within this group work with Area planners, and with principal engineers who are part of the Underground Network Division to plan the network system, including cable rating.

Process

Much of the cable rating and cable selection is a direct result of Georgia Power duct line configurations. In many urban areas, Georgia Power has been constrained to using lead cable due to smaller duct lines already in place, but the emergence of reduced-diameter EPR cable has made it possible to replace failed 300 mcm PILC with 350 mcm EPR Georgia Power has not entirely stopped installing PILC, however, as it has been highly reliable. They use 300 MCM three-conductor paper/lead compact sector lead cable in many places (See Figure 1 and Figure 2); in other areas they EPR insulated cables. In some cases of lead cable failures, Georgia Power may replace it with EPR.

Figure 1: PILC Cable, sector shaped conductors

Figure 2: PILC Cable, joint preparation

Historically, cable ratings were developed manually by a Principal Engineer within the Network UG Engineering group. Cable rating charts were developed based on standards from cable rating books, as well as system specific characteristics such as soil type. For example, in Savannah, where there is a great deal of sand that may dry up in summer months, ratings are adjusted based on anticipated high duct line temperatures. The engineering group has taken sample measurements from there to make more accurate cable ratings. The system-wide goal is a peak of no more than 90 percent of rating. If a system is at 91 percent of rating, for example, it is watched closely. When it approaches 97-98 percent, it usually receives immediate funding.

Georgia Power is in the process of implementing modeling software (CYMCAP) that is highly flexible and accounts for a number of variables in its cable-rating sub-module, including duct bank design, cable design, soil and backfill, and temperature. Nonetheless, they still retain both historical and objective system observations to augment their cable ratings before any deployment. Secondary cables can also be rated and modelled in the system.

Technology

Cable ratings are based on manually developed charts by the Underground Network engineering group. Georgia Power is increasingly using CYMDIST and the CYMCAP cable rating module for cable rating, including the secondary, as well as augmenting the software modeling with field samples and system observations.

7.2.11 - HECO - The Hawaiian Electric Company

Planning

Cable Rating

People

The Distribution Planning Division uses manufacturer published ratings for cables in performing loading studies. The Technical Services Division, within the Engineering Department performs cable rating calculations.

Depending on the situation, HECO may require the calculation of normal and emergency cable ratings in a certain duct bank configuration. Should the Planning group require a cable rating calculation, they will provide the information (duct bank configuration, for example) to the Technical Services Division who will perform the cable rating calculations.

The System Operator has a list of emergency cable ratings for 46kV and 138kV lines, but not for the lower primary voltage lines.

Process

HECO has documents that provide cable ratings for each feeder as part of its standards book. These ratings include normal and emergency ratings. HECO does not periodically revisit and update the ratings list without some indication of a change in conditions. Because HECO uses a standard duct bank configuration upon which the ratings are based, the tables do not need to be updated very often.

The current practice at HECO is to re-rate cables on an “as needed” basis, such as a specific project where the duct bank configuration may be modified, or the addition of load to a cable near its limit.

Technology

The Technical Services Division is utilizing USAmp + Cable Rating Software, by USi to assist in performing cable rating calculations.

7.2.12 - National Grid

Planning

Cable Rating

People

Cable ratings are performed by the field engineers that work in the distribution planning area. For example, the field engineer who focuses on New York’s Eastern division, including Albany, would be the engineer to perform cable ratings for the Albany network.

National Grid uses historic cable ratings published in tables, and uses these numbers for routine situations. On a case-by-case basis, field engineers may calculate cable ratings where they believe conditions might limit the available capacity of a particular cable.

Process

Cable ratings for network infrastructure are reviewed as part of an overall analysis of the network, performed on a five year basis at National Grid. Field engineers will model the system to identify potential areas of impact. Planning engineers use a conservative loading level as a threshold for these studies – normally well below the rated thermal limits of the cable - and identify areas where this may be exceeded. Part of this process may include an analysis of cable ratings on a case-by-case basis where the particular configuration of cables suggest the need to specifically re-rate a cable or cable section (such as proximity to a steam main, for example).

Technology

National Grid Albany uses a cable rating software called USAmp + by USi to aid them in calculating cable ratings in complicated situations. Note that in these situations, the field engineer may enlist the services of other National Grid engineers who are experienced with the software to perform the calculations.

7.2.13 - PG&E

Planning

Cable Rating

People

The PG&E Standards department publishes tables that show cable ampacity ratings. These tables include ratings for various conductor configurations and load factors^[1] .

^[1] Defined by PG&E, for the purpose of cable rating, as the ration of peak loading to average loading.

Process

PG&E calculates cable ratings by looking at both heat dissipation based on the conductor configuration, and on load factor. For example, they will provide a cable rating for a conductor configuration of six equally loaded conductors (6 ELC); that is, a cable that has six other cables surrounding it all having the same loading. Similarly, they will show cable ratings that factor in heat dissipation based on fewer cables surrounding the cable. The higher the ELC, the lower the rated capacity of the cable.

PG&E also considers the load factor. For example, they will publish a cable rating at a 75% load factor; that is, they assume that the cable carries peak load 75% of the time, and is not heavily loaded the remainder of the time. PG&E will also publish cable rating values for different load factor levels. The lower the load factor, the higher the rated capacity of the cable.

The planning engineer uses the cable rating to ascertain what loading the network can support, and to make planning decisions, such as when to reinforce the infrastructure.

Technology

PG&E is presently implementing the CYMCAP cable ampacity calculation software. Historically, they have worked from tables to develop cable ratings.

7.2.14 - Portland General Electric

Planning

Cable Rating

People

Network Engineering develops and maintains the standards for the network, and these are then forwarded to the Standards Department. For example, Network Engineers developed the cabling rating standards for the network. Distribution Network Engineers assume responsibility because the Standards Department lacks the necessary network expertise. Distribution Engineers also provide the loading information used to create CYME and PSSE models.

The Manager of Distribution Engineering and T&D Standards oversees the Standards Department, and their emphasis is the overhead and underground residential distribution (URD) systems rather than the network system. The group underwent recent reorganization recently and employs one technical writer and four standards engineers.

Process

Cables: PGE generally uses flat strap EPR 500 MCM copper medium-voltage cables in its network, as three triplexed conductors fit into its 3.5 in. (8.9 cm) diameter clay conduits. In certain applications, the company uses a reduced insulation 750 MCM copper cable that fits into 4 in. (10.2 cm) conduits. For taps into a network vault, PGE typically uses 1/0 copper cables. PGE has lead cable installed in both its network primary and secondary. The company has a proactive effort underway to replace primary lead cables with EPR insulated cables in its network primary.

Engineers use modeling tools to keep track of cable ratings. PGE uses CYMCAP to determine cable ratings, and the Transmission and Distribution Planning and Standards Department have developed peak cable rating guidance. The company uses these standards to specify the allowable normal and emergency loading for all cables on the network. PGE is improving its processes for documenting and standardizing equipment and procedures on the network, including cable ratings.

To isolate areas of the distribution system where cables may be overloaded, Planning Engineers use CYMEDIST for the radial system and PSSE for the network. Using base case models and seasonal loading data, under different contingencies, engineers can ensure that lines do not exceed 67% of their normal seasonal thermal rating on the radial system, which translates to two-thirds of the normal capacity for a standard feeder. On the network, base loadings specify that no line should be loaded at more than 88% on the network. PGE prioritizes any areas of concern for equipment upgrades^[1].

Distribution Temperature Sensing (DTS): In PGE’s DTS pilot, the company installed real-time line sensors on six network feeders to provide temperature readings for underground cables at two-second intervals. Because temperature influences capacity, the sensors may show where system upgrades may be required. In addition, the system could allow PGE to locate hotspots that indicate a potential cable failure. PGE has included the DTS in the new substation intended to begin operation in 2018-2019^[2].

Technology

PGE uses CYMCAP to calculate ampacity and temperature rises for power cables, helping planners and designers maximize performance. The system models steady-state and transient cable ratings. CYMCAP uses Neher-McGrath and IEC-60287 methods, and provides a graphical representation for most power cable types. The library contains cable data and supports updates. The system recognizes a variety of installation practices, including direct burial, thermal backfill, ducts, and duct banks. The library also includes databases with load curves and different heat sources.

The transient thermal analysis can calculate the ampacity, temperature, or time taken to reach a certain temperature. It can use user-defined load profiles for circuits and handle multiple cables for every installation, with circuits loaded simultaneously or one-by-on^[3]. PGE also uses CYME and PSSE to model base case scenarios on the radial and network systems, which allows planners to determine where cable loadings may exceed recommended levels.

Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).
CYME. “Power Cable Ampacity Rating.” CYME.com. http://www.cyme.com/software/cymcap/ (accessed November 28, 2017).

7.2.15 - SCL - Seattle City Light

Planning

Cable Rating

People

Organization

Network Planning at Seattle City Light is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A: SCL - Org Chart. The Network Design Department focuses exclusively on the planning and design of SCL’s networks.

Although SCL does have a separate planning group that performs distribution planning activities for SCL’s non-network distribution system, this group does not do the planning associated with the network. All cable ratings, load flow and voltage studies, master load flow analysis, assignment of feeders to load additions, area studies, etc. associated with the network are performed by the Network Design Department staff. (Note that SCL is currently implementing an Asset Management organization. At the time of this writing, SCL had not yet decided whether certain tasks currently performed by the Network Engineering group will be moved into the Asset Management organization.)

The Network Design Department is made up of a System Group (eight engineers) and a Services Group (eight engineers). These engineers do all of the planning and engineering for the network (the System Group), as well as interface with network customers for load additions, new loads, etc. (the Services Group). The individuals in this group are four-year degreed engineers. The senior level engineer position at SCL requires a PE license. The engineers at SCL are represented by a collective bargaining agreement (IBEW).

Culture

The Network Engineering group has a close working relationship with the Civil and Electrical construction and maintenance groups within the Area Field Operations – Network Department and the Distribution Operations Department. EPRI observed high levels of mutual respect between these groups, and high confidence by the field organizations in the planning and design decisions made by the Network Design Department.

SCL has remained committed to the network engineering department staffing levels, hiring new engineers into the network area to fill vacancies. SCL has no formal training program for network engineers. However, network engineers are sent to special classes on network equipment, etc. as part of their ongoing development.

Process

SCL rates cables at 90 ˚ C; that is, they develop a cable ampacity rating that limits the conductor heating to 90 ˚ C. SCL does not develop an emergency or 24-hour rating for feeders. They plan their system to the 90 ˚ C limit. SCL develops feeder specific ratings based on field conditions. Using software, they develop ampacity ratings for circuits that consider factors such as cable type, duct bank configuration, soil resistivity, proximity of foreign utilities, design temperature (90 ˚ C), load factor (80%), etc. SCL performs both a summer and winter analysis. The summer ratings, which are the most conservative, are typically used for planning purposes.

SCL re-rates cables any time conditions in the field change that could affect cable rating, including the addition of another parallel circuit, the addition of a foreign utility such as a steam line, a new cable in the duct bank, etc. The specific cable ratings are entered into the load flow software for planning analysis.

Technology

SCL has been using a mid-1990s cable rating computer product called USAmp developed by USi. Within this software, SCL maintains a file containing cable specifications. The software enables planning engineers to specify the Rho (ρ – resistivity) based on the use of concrete duct bank, the diameter and wall thickness of the duct bank, pertinent dimensions such as the distance between conductors and between conductors and the wall of the duct bank, and other components such as the load factor and design temperature. The software generates cable ratings that are used for planning. SCL is currently using a cable rating product developed by CymE. SCL will also be using ETAP, which performs cable rating as well.

7.2.16 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter 5 - Ampacity of Distribution Cables

7.2.17 - Survey Results

Survey Results

Planning

Cable Rating

Survey Questions taken from 2015 survey results - Planning

Question 33 : To what level of circuit loading (in % rated circuit capacity) do you design for normal conditions?

Question 34 : To what level of circuit loading (in % rated circuit capacity) do you design for a contingency situation?

Survey Questions taken from 2012 survey results - Summary Overview

Question 1.12 : Average primary circuit loading under no contingencies? (In percent of circuit rating)

Question 1.13 : Average primary circuit loading under the worst contingency that is planned for? (Percent of circuit rating)

7.3 - Cable Replacement Strategy

7.3.1 - AEP - Ohio

Planning

Cable Replacement Strategy

Network Revitalization

People

Network revitalization, improvements, and refurbishment are planned by the AEP Ohio Network Engineering group in tight collaboration with its parent company. The company employs two Principal Engineers and one Associate Engineer to perform all network design and planning activities for the Columbus and Ohio urban underground networks. These engineers are geographically based in downtown Columbus at its AEP Riverside offices, and organizationally part of the parent company Distribution Services organization. The Network Engineering group reports to the AEP Network Engineering Supervisor, who ultimately reports the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues. This committee can and does recommend system revitalization, improvements, and refurbishments for the AEP Ohio networks to the parent company. After approval from the AEP parent company, AEP Ohio Network Engineering and the AEP Network Engineering Supervisor plan the revitalization projects and oversee their completion.

Process

AEP Ohio has a number of on-going network revitalization and refurbishment projects in the works, including the following:

Replacement of Secondary Cable

After incidents involving fire in manholes caused by faulty secondary cables in 2014, the parent company, AEP, determined that an investigation team should look into the incident and report its findings. The investigation included the following:

On-the-ground inspection of cables in duct lines by camera
Scientific modeling of the existing secondary cable and its loads
Load flow models to identify cables that are overloaded or nearly fully loaded
Examination of failed secondary cable at AEP Ohio, as well as outside testing by third-party consultant

The summary report of these investigations determined that the secondary styrene butyl cable was the cause of the fire due to cracked insulation. Network engineering analysis found that its insulation breaks down due to overheating and may produce combustible gases. Network Engineering has performed load analyses that have identified the cable runs most at risk and are a priority in the replacement process.

The summary report in AEP Ohio served as a basis for examination of all network grid systems in the AEP operating companies. It was found that other locations may need to rehabilitate secondary cabling as well.

In response, AEP formed a Project Management Team to initiate and lead a program to inspect and replace selected secondary cables throughout the AEP system.

AEP Ohio and all AEP network operating groups have prioritized the secondary cable replacement according to conditions (see Figure 1).

Figure 1: AEP mitigation and prioritization strategy for secondary cable replacement

The cable replacement project, totaling $300 million for all of AEP, will result in replacement of nearly 202,600 circuit feet of secondary cable in AEP Ohio. System-wide, AEP will replace in excess of 900,700 circuit feet of secondary cable. This massive undertaking also led AEP to reinforce its existing network inspections to aggressively perform the following throughout the AEP operating companies:

Visually inspect every manhole and vault
Note not only secondary cable conditions, but also note conditions of every other network component in the manhole and vault, including transformers, switches, primary cables, etc.
Record all inspections of manholes and vaults into the system-wide asset tracking database called NEEDS (Network Electrical Equipment Database System)

To help drive the system-wide inspections and spur replacements and repairs, a Gantt chart and a system dashboard were put in place and updated weekly to track the progress of the inspections and replacements program (see Table 1 and Figure 2).

Table 1: Portion of weekly dashboard report on secondary network inspections. (See Appendix D for a sample of the entire spreadsheet)

Figure 2: Sample of Gantt chart for AEP Operating Companies’ inspection and rehabilitation schedule

Secondary butyl and other cable (such as cloth PILC and older durasheath XPLE) are being replaced with 750 EAM insulated cable. The 750 EAM cable was chosen by the engineers because it fits in the current duct lines and has the capacity and thermal rating required by the network. The older butyl cable was rated at 70 degrees C, whereas the 750 EAM is rated at 90 degrees C (see Figure 3).

Figure 3: 750 EAM secondary replacement cable rated at 90 degrees C

In addition, AEP Ohio has found that secondary lead cable in its system, when hot, can cause fires that threaten other cables in the duct lines. Therefore, lead cables are also scheduled for replacement under this revitalization and refurbishment project (see Cable Replacement).

Network Protectors

All 480 volt network protectors in AEP Ohio are scheduled for upgrades to Eaton model CM52 protectors as well as older 216 volt units. Many have already been installed. The CM52 offers greater safety, flexibility, and data collection and operation via the new fiber-optic SCADA system, also under deployment (see Design - Network Protector Design ). All network protectors have microprocessor based relays.

Fire Protection

Eaton High Thermal Event Systems are being deployed on high value 480 volt spot networks located in building vaults. If a fire is detected, the system automatically trips, isolating the affected transformer or bus before fire can spread.

SCADA Fiber-Optic Cables

The entire SCADA communications network is being upgraded to a double-loop, fully-redundant fiber-optic cable network. The new SCADA network cable is fast, lightweight, and fault tolerant (see Remote Monitoring).

Network Transformers

AEP Ohio is updating all its transformers to dry type units without an integrated primary switch as older systems come out of service. These newer transformers will require less maintenance for AEP Ohio. The network unit will include a wall-mounted solid dielectric vacuum switch to separate the transformer from the primary

Technology

AEP Ohio uses CYMCAP and CYME SNA modules for its cable ratings, load analyses, and network circuit modelling. Its NEED database tracks all system serialized assets and their conditions as recorded by inspections. NEED also includes civil asset information such as underground vault and manhole structures.

7.3.2 - Ameren Missouri

Planning

Cable Replacement Strategy

People

Ameren Missouri has a formal cable replacement program. The program is focused mainly on replacing a faulty URD cable, and takes advantage of techniques such as directional boring.

A criterion for replacement of cables in the urban underground system is under development by the Underground Revitalization Department. This criterion will provide for the testing, replacement, maintenance and improved utilization of cable systems within downtown St. Louis, and will include plans for non-jacketed and jacketed PILC cable cloth covered secondary cable, and 15 kV solid dielectric cables. The strategy will also include guidelines for 15 kV bolted separable splices.

Ameren Missouri has not historically performed routine diagnostic testing of network cables (other than fault location testing and some proof testing after cable repair). They have joined the Cable Diagnostic Focused Initiative (CDFI), and have recently performed some cable diagnostic tests working with the CDFI to evaluate test methods.

Process

Draft Asset Strategies for various cable types are under development at Ameren Missouri. The following table, excerpted from the Draft Ameren Missouri Cable Replacement Criteria, summarizes their proposed strategy for each cable type.

Figure 1: Current Asset Plan

7.3.3 - CEI - The Illuminating Company

Planning

Cable Replacement Strategy

(Predictive Cable Failure Initiative)

People

The Predictive Cable Failure Initiative is a FirstEnergy wide effort led by the corporate Distribution Planning and Protection department. The group is made up of representatives from FirstEnergy operating companies, including CEI, and is charged with developing recommendations for cable testing, maintenance and replacement approaches at First Energy that optimize investment, and reliability.

Process

The group has analyzed cable performance and has identified eight key factors that can be used to assess cable failure risk. They have researched various cable diagnostic alternatives, and have documented the costs and benefits of various testing alternatives. They have laid out what a full cable testing program would look like, including an estimate of costs and system impacts.

The group is in the process of developing a final recommendation.

7.3.4 - Duke Energy Florida

Planning

Cable Replacement Strategy

People

Duke Energy Florida has a formal primary cable replacement program in place, which includes replacement of cables for both network and non-network feeders. The replacement program is a two-year program, with a goal to replace 60,000 feet of older cable per year in the South Coastal Region.

The cable replacement is being performed by contractor crews (six people), who are performing the complete installation, including cable pulling and cable splicing. The crew is on a two-year contract, working on 35-40 cable pulling locations that involve network infrastructure. The contractors provide all equipment, such as cable pulling gear, heavy trucks, etc. The crews start the workday at a remote mustering point, and report to a Duke Energy Network Specialist who has been temporarily upgraded to serve as a contractor supervisor. Because of the size of the project, it is also being managed by the Resource Management group, who meets twice per month with the contractor for progress updates.

In addition to the cable replacement program, Duke Energy Florida network crews are replacing secondary mole connections throughout the Clearwater network system for network hardening. Duke Energy Florida has proactively targeted replacement for older mole connections in manholes prone to long periods of time underwater. Duke Energy Florida has found that these secondary cable mole connections are subject to bloating and cracking over time.

Process

One driver for the cable replacement program was that the company had experienced a high amount of faults on older cables due to a deterioration of the metal center plug used at T-body connections. The engineering group decided to replace the metal body center plugs and cable to harden the underground network system. Figure 1 shows a typical center plug with a metal ring used on the Duke Energy Florida network system.

Figure 1: Center plug with metal ring

Historically, Duke Energy Florida’s cable design called for the use of T-bodies (600A separable connectors) for both straight as well as Y and H splices, so that cables could be easily separated for fault locating, maintenance and for future system enhancements. Historically, the center plugs used in the T-bodies were designed with an exposed metal ring which was prone to deterioration with age and with prolonged submersion in water. Figure 2 shows a crack on a failed center plug with a metal ring.

Figure 2: Crack in failed center plug

Recognizing they had a high concentration of cables with the T bodies with the suspect center plug component in downtown St. Petersburg, and that the cables were of an older vintage (early 1980s) nearing the end of the cable life, Duke Energy Florida elected to perform a targeted cable replacement, rather than solely replace the center plugs associated with T bodies. Figure 3 shows the replacement center plugs currently being installed. Figure 4 shows a close up of the Elastimold center plug without an exposed metal body.

Figure 3: Replacement center plugs

Figure 4: Close-up, replaced plug, no metal exposed

Duke Energy Florida noted that it is virtually impossible to just replace the center plugs, because before unbolting and parting the cable, their process calls for spiking the cable to confirm that it is de-energized, thus damaging additional infrastructure that must be replaced. When they encounter a vault or manhole that contain T-bodies with the older center plugs, they will not enter the hole while the cable is energized. They will schedule for replacement, sectionalizing to de energize and isolate the section, before performing replacement with new components.

Duke Energy Florida has already identified approximately 43 locations with T-body connections with the older style center plugs to be replaced. At most of these locations, the T-bodies are submerged. Their experience has shown failures often occur after the water is removed. The primary reason for the failure is because the water serves to pass the electrical stresses across the center plug. After the water is removed, the plugs tend to fail because of additional electrical stress on the plug.

Duke Energy Florida is also performing a further assessment in the other portions of its service territory to identify other cable populations that may also be built with T-bodies with the metal ringed center plug component, in order to determine whether to expand the replacement program.

Technology

Duke Energy Florida is installing Elastimold K651CP connecting plugs as replacements for the older metal body T plugs previously used. The Elastimold K651CP is a deadbreak connector that can be removed when the cable is energized to facilitate work on the connected cable.

7.3.5 - Duke Energy Ohio

Planning

Cable Replacement Strategy

People

Duke invests in cable replacement of poor performing feeders and of PILC feeder sections.

A priority list is developed by the Asset Manager, based on cable diagnostic test results.

Process

The list of circuits to be changed out is driven by test results. Tan delta testing may produce results that suggest that the cable system may be prone to failure (significant dielectric loss or change in measure losses). From those test results, crews will perform an investigation of the feeder, using TDR to find the problems, and popping manhole lids to investigate, and identify condition.

For lead feeders, Duke will target the entire feeder for replacement.

7.3.6 - Energex

Planning

Cable Replacement Strategy

People

Energex has an Asset Management organization responsible for managing the network infrastructure to yield expected results (reliability, for example), and for making asset investment decisions, such as cable replacement. The Asset Management organization is led by an Executive General Manager, and includes organizations that support the management of assets including the Network Capital Strategy and Planning group, the Network Optimization group, the Data Services and Demand Management group, the Systems Engineering group, the Network Maintenance and Performance group, as well as the Metering, Safety and Environmental groups.

Process

Energex uses PAS 55 standards for the optimal management of physical assets. Energex uses a program called Condition Based Reliability Maintenance (CBRM), which seeks to develop a health index and risk score for all assets, and use that information to drive decisions such as maintenance approach and replacement criteria. The company utilizes a combination of asset age and condition identified through inspection and diagnostic testing to determine a health score.

The risk score examines operational performance and impacts on safety to identify a level of risk associated with each asset. The results of this program drive the company’s investment in refurbishment. Note that its program does not define specific actions based on scores. Rather, these indicators point Energex managers to scrutinize the performance of a particular asset class more closely. It is this additional scrutiny and investigation that results in action.

Energex has had difficulty applying this program to the 11 kV and low-voltage cable fleet population within the CBD, as the company does not have good records of asset type and vintage. Energex does not perform routine diagnostic testing of cables, other than troubleshooting (fault finding), and new cable commissioning tests (DC or AC hi-pot). Thus, the company does not have a cable replacement strategy for the cables within the CBD.

Note that they utilize both PILC and XLPE cable in the CBD.

Technology

Energex uses Condition Based Risk Management System (CBRM) software from EA Technology to track the health and condition of assets throughout the underground system. The system assigns a health index and risk score for all the assets in each class, such as circuit breakers, transformers, etc. Length of time in service, test results, and any refurbishment work is input into the system. The system can “score” some assets based on aging mechanisms housed within the system that can be used to predict potential end-of-life. Actual refurbishment and replacement work is driven by the calculated health scores.

7.3.7 - ESB Networks

Planning

Cable Replacement Strategy

People

Much of the cable installation and replacement in the ESB Networks underground network is performed by contractors. In the past, graduate student engineers were used on line work, but this has become far less frequent in recent years. Otherwise, cable replacement and installation is performed by Network Technicians, who work on all cable voltages.

ESB Networks has a four-year apprentice training program for attaining the journeyman Network Technician position. Network Technicians who worked as cable jointers work closely with both the Training group and the Asset Management groups at ESB Networks. Network Technicians readily bring information about problems with particular cable joints back to these groups.

The Training and Underground Networks group within the Assets & Procurement organization share the process of performing forensic analysis of failed joints and in preparing the failed component summary reports. Within both groups, ESB Networks has significant cable/cable accessory expertise. Both groups work closely with Network Technicians to ensure that they understand the science of cable joints and have an appreciation for the importance to long-term joint reliability of performing the proper steps associated with cable joint preparation.

Process

ESB Networks has installed significant amounts of MV (10-kV and 20-kV) cables over the past 10 years. Thirty-four percent of the total in-service MV cable has been installed in the past few years. Most of this installation has been outside of Dublin, in both rural and urban areas. Figure 1 shows the total amount of installed MV cable from 2000 to 2012.

Figure 1: Installed MV cable

ESB Networks has also installed significant amounts of LV cables – used for their LV network mains. Thirty-seven percent of the total in-service LV network cables have been installed within the past seven years (statistic includes replacement of cables). Figure 2 shows the total amount of installed LV cable from 2000 to 2012.

Figure 2: Installed LV cables

Technology

ESB Networks has embarked on a five-year cable replacement program and is spending €11.4M on replacing oil filled cables and terminations due to higher than acceptable failure rates in recent years. The company is also replacing lead cable by retrofitting 38 kV PILC cables with XLPE, especially within the business district.

ESB Networks’ approach in developing its replacement plan includes determining ESB Networks’ overall risk profile, comparing age versus performance of cables older than 65 years. In all, ESB Networks will replace 18 km of cables that are the critical feeds for the city. ESB Networks estimates this replacement will reduce the risk of failures by approximately 50 percent. As part of its replacement program, ESB Networks is also targeting older (pre-1982) XLP insulated cables, as this cable had been experiencing an average of eight faults per 100 km.

7.3.8 - Georgia Power

Planning

Cable Replacement Strategy

Cable Replacement

People

Georgia Power utilizes a combination of PILC cable and EPR insulated cable in its Atlanta network. They continue to use lead cable in some locations where they may be limited by conduit size, or locations where they may require a Y splice in a limited space. However, the company is increasing its use of EPR cable for new installations where practical.

Note: in Savannah, Georgia Power has replaced its lead secondary cable with EPR insulated cable.

Cable replacement is supervised by a senior engineer in the Network Underground group. Senior Cable Splicers within the group perform any needed cable replacement.

The Georgia Power Network Underground group has not historically performed routine diagnostic testing of network cables other than fault location testing and some proof testing after cable repair. Therefore, cable is replaced on an as-needed basis as determined by inspection, cable failure, or on recommendation of the supervising engineer.

Process

Because of its durability and space constraints in older duct lines Georgia Power is maintaining the use of lead cables in its four-inch duct lines and wherever it is currently performing well (See Figures 1 through 3.). If a lead cable fails in a larger duct or a manhole with room to accommodate newer EPR cable splicing, the group will replace the lead with EPR insulated cables and accessories. (Georgia Power engineers noted that an EPR-type Y-splice at 20kV takes up virtually all the wall space in the manhole at most locations, and thus reduces their flexibility for future expansion. A lead Y splice is far more compact.)

Figure 1: Lead cable joints

Figure 2: Lead cable joint preparation

Figure 3: Lead secondary cables – Atlanta

The Network Underground group is concerned that there is only one domestic source for its lead cable, and thus may become more aggressive in the future in replacing lead, particularly if a smaller form-factor EPR proves reliable (See figure 4.).

Figure 4: EPR secondary cables – ring bus, Savannah

Technology

Georgia Power‘s lead cable system is extremely reliable. They establish performance goals for cable in terms of cable failures per year. For example, the goal for 2013 was to have no more than 23 cable failures. Cable failure performance is tied in with the overall performance management process at Georgia Power.

The utility industry is moving away from the use of lead-covered cables because of limited availability, environmental concerns, and complex splicing and terminating requirements. GPC’s Network Underground group is actively researching and testing other cable types as a replacement for lead. They are using more solid-dielectric cable at medium and low voltage. New and improved cold-shrink splices and terminations are being evaluated and will accelerate the move toward solid-dielectric cable.

7.3.9 - HECO - The Hawaiian Electric Company

Planning

Cable Replacement Strategy

(Cable Replacement Strategy Development)

People

A large portion of HECO’s service territory is served with 15 kV underground distribution. HECO has several different types of cable in the ground, including PILC, HMWPE, and XLPE. Like most utilities, the earliest installations of the XLPE cable were installed around 1970 and are nearing the end of their life.

Prior to the recent implementation of an Asset Management organization, asset management activities were being performed by various departments including the Technical Services Division within Engineering. Engineers within the Technical Services Division have been involved in an effort to determine what the optimum cable replacement strategy should be based on the historic and predicted failure of cables of different vintages and types.

HECO engaged the support of EPRI in conducting a study to improve their ability to perform quantitative analysis of the URD 15kV cable fleet in order to develop business cases and asset management strategies surrounding this cable. The specific objectives of the study were:

Improve quantitative cable fleet management ability
- Develop asset management based fleet analytics
- Maximize value of available data
Gain better understanding and clarify strategic view of future resource needs
Provide results useful for development of business cases and asset management strategies to support budgeting process

See Attachment - A

Process

HECO’s historic approach has been a reactive one based on an assessment of the reliability of feeders / feeder sections. Annually, engineers within the Technical Services Division would review the historical reliability performance of feeders, looking at things such as major outages, breaker trips, and number of customers affected to identify the worst performing underground feeders. On those feeders, the engineers would then “dig deeper”, looking at “cable cards” upon which is recorded the details of the outages experienced on the feeders. From this analysis, the engineers within Technical Services would develop either diagnostic strategies, such as performing VLF testing on suspect cable sections to better understand the condition of the cable insulation weaknesses, or replacement strategies.

HECO is currently in the process of developing a more formal strategy for cable replacement. This effort is being led by Asset Management and supported by KEMA.

7.3.10 - National Grid

Planning

Cable Replacement Strategy

People

National Grid has developed a formal primary underground cable replacement strategy that includes primary network cables. The strategy does not apply to URD cables, underground primary cables serving pad mounted transformers, or to sub-transmission cables. The intent of National Grid’s strategy is to eliminate all primary underground cable more than 60 years old from the system within fifteen years.

Process

National Grid does not have a central repository of age data for primary underground cable. However, in New York, they do have plant accounting records and limited age data stored at local levels.

From this information, National Grid performed an analysis in 2008 that revealed that approximately half of the in-service primary underground cable was more than 20 years old, and nearly eight percent was more than 60 years old.

In establishing a strategy for addressing aging underground primary cable, National Grid examined several scenarios, each based on setting a target for the maximum allowed age of underground primary cable installed, and then determining the annual replacement level required to achieve a condition of zero cable older than the target age within a fixed period of time. The scenario selected was to use an upper age limit of 60 years as a target.

Using the 60 year age target, they considered three replacement rates: an “aggressive” rate, requiring 10 years to achieve no cable older than target; a “moderate” rate, requiring 15 years to achieve no cable older than target; and a “sustained” rate, requiring 20 years to achieve no cable older than target. They selected the moderate rate program, requiring an annual replacement of approximately 90 miles per year.

In projecting the costs of the program, National Grid developed estimated costs per mile to install cable in existing duct, and estimates to install cable and duct.

7.3.11 - PG&E

Planning

Cable Replacement Strategy

People

PG&E does not have a formal cable replacement program for their network system. Rather, they have implemented diagnostic testing of network feeders and will replace bad cable sections revealed by the testing.

Most of the primary system supplying the 12kV network is PILC, and is highly reliable. PG&E replaces lead cable with lead cable, other than in areas where they must transition to dead front equipment terminations. The 750 copper EPR with the flat strapped neutral is sometimes used as replacement for PILC cable where duct size is limited.

For their 35KV networks, which utilize XLPE cables, PG&E is replacing failed cable sections with EPR insulated cable.

7.3.12 - Portland General Electric

Planning

Cable Rating

People

PGE has a proactive cable replacement program aimed at replacing PILC primary network cables with EPR insulated cables.

Three Distribution Engineers focus on both the networks and non-network infrastructure in the CORE. The engineers provide technical data and perform risk assessments used for the Strategic Asset Management Program, which evaluates the economic benefits of programs, such as cable replacement.

The CORE underground falls within the Portland Service Center (PSC). The resources focused on the CORE are responsible for both non-network (radial) underground and network systems. The CORE resources perform cable replacement.

Process

The PILC network cable replacement program is part of an initiative called the Performance Improvement Assessment (PIA), which utilizes detailed root-cause analyses performed by the Network Engineers to drive actions to improve performance. The scope of the program is to replace all current lead primary feeders with EPR insulated cables. PGE is focusing on replacing primary cables before moving towards a proactive secondary lead cable replacement program planned for the future. PGE often performs lead cable replacement at night because of city restrictions on closing the streets during the day.

As part of its Strategic Asset Management Program, in 2013, PGE developed an economic lifecycle model to evaluate cable, using data gathered by crews over the past 40 years. This supported a model that used the correlation between age and insulation type, which recommended a program of replacement and/or injecting XLPE cable.

PGE assessed that targeted cable replacement would improve reliability by removing a significant risk posed by aging cable. As part of a strategic asset management program, PGE’s model evaluated approximately 11,300 conductor miles (18,185 km) of cable and determined which sections were most likely to experience failure. After this, the model determined which areas would cause the most disruption according to loading and/or customer numbers. In total, PGE has replaced 203 conductor miles (327 km) of cable.

Note that the use of the economic lifecycle model described above has not yet been applied to network cables. Because the replacement of lead cables in the network was already occurring from the PIA, the Strategic Asset Management Group deferred inclusion of an analysis of network cables in the economic lifecycle model though it still plans to include it in the program.

PGE does not presently perform any routine diagnostic cable testing on the network. In the past, they have performed some diagnostic testing on primary network cables crossing the river. Before commissioning new cable or returning a de-energized primary circuit to service, crews perform a direct current (DC) high potential (hipot) test. Very low frequency (VLF) testing is performed on the getaway cables at substations. PGE is not performing a tan delta test.

Technology

For connecting lead cable to EPR, PGE uses Raychem Transition Splices. Although the company prefers pulling EPR all the way, that is, fully replacing the lead cable with EPR insulated cable, the Raychem splices are used if this is not possible.

Before cutting a cable, crews test it using a device called a hummer to verify its de-energized state. If the cable is energized, the device will “hum” significantly. Note that use of the hummer is not foolproof. PGE relies on a combination of maps, tags, and the hummer device to identify de-energized cables. The standard work practice is to cut a cable remotely by placing a “guillotine” cutter on the cable and activating it from outside the vault.

Figure 1: A 'hummer' to verify the de-energized state of a cable

7.3.13 - Survey Results

Survey Results

Operations

Cable Replacement Strategy

Survey Questions taken from 2018 survey results - Asset Management survey

Question 26 : Are you implementing targeted replacement programs for any of the following equipment?

Question 27 : If Yes, are any of your replacement programs Aged based, such as replacing all transformers >50 years old?

Question 28 : If Yes (to question 26), are any of your replacement programs Design based, such as replacing all high rise fluid filled transformers with dry type units, or replacing a certain type of cable?

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 18 : Are you implementing targeted replacement programs for any of the following equipment? (check all that apply)

Question 19 : Are any of your targeted replacements driven by equipment that is beyond a particular age?

7.4 - Circuit Modeling

7.4.1 - AEP - Ohio

Planning

Circuit Modeling

People

The circuit modeling and analysis of network feeders for AEP Ohio is performed by the AEP Ohio Network Engineers, which is part of the Network Engineering group within AEP Distribution. Note that this group also provides consultative support to network planners at the other AEP operating companies.

Process

The Network Engineers, working with AEP Distribution, maintain circuit models of all circuits and network feeders within the AEP Ohio underground systems in CYME. The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. Forecasts from the parent company look 10 years ahead, and include historic peak loads and anticipated/planned new projects with significant input from the AEP Ohio Engineers who have specific information concerning new projects planned in their area. The calculated monthly load flows are also reviewed by AEP Distribution Planners to better provide forecasting of loads.

Downtown Columbus is a stable network. The AEP Ohio Engineers plan on maintaining its existing network and adding additional capacity to the downtown using radial distribution. Most planning activity is focused on improving the existing network with refurbishment and modernization projects.

Engineers model the system, and perform analyses to understand anticipated requirements. For both circuits and network feeders, planning engineers will perform Single and Double Contingency Configuration studies. From this analysis, planning engineers determine where reinforcement is necessary to be able to reliably serve customers in the Double Contingency Configuration that is standard in AEP Ohio’s Columbus network.

Technology

AEP Distribution provides circuit and distribution information to AEP Ohio. Then, load flow and secondary network analysis is performed in CYME® Secondary Grid Network Analysis (SNA) software system (see Figure 1). The AEP Ohio Network Engineering group also uses kWh data captured through remotely monitored meters and uses sophisticated algorithms to convert this data to identify peak loads on the network. This peak load information is shared with AEP Distribution monthly. With this captured data and the CYME circuit analysis software, AEP Ohio Network Engineers have a solid basis for Circuit and Load Flow modeling on their networks.

Figure 1: CYME load flow analysis software used by AEP Distribution to aid in Circuit Modelling for AEP Ohio

7.4.2 - Ameren Missouri

Planning

Circuit Modeling

People

Network planning, including modeling and analyzing network feeders, is performed by the Engineering group within the Underground Division. The Underground Division, led by manager, consists of both engineering and construction resources responsible for the downtown infrastructure. The Engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues. The engineers are four-year degree positions. Energy Services Consultants have a combination of years of experience and formal education, including two year and four year degrees. The engineers are nonunion employees; the Estimators are in the union.

Process

The network engineers maintain circuit models of all network feeders within the DEW load flow product.

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. Engineers model the system, and perform analyses to understand anticipated requirements.

For network feeders, planning engineers will perform contingency studies, modeling networks with each primary feeder out of service to identify areas of needed reinforcement to supply the network in a contingency.

For radial feeders, planning engineers will perform contingency studies (N-1 planning) to assure that they can pick up customers with reserve feeders within the emergency ratings of the transformer and cables. More specifically, they model the distribution system with one feeder out of service, simulating customers connecting to reserve feeders. From this analysis, planning engineers determine where reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Technology

Ameren Missouri uses the Distribution Engineering Workstation (DEW) load flow product to model their network system. This software, developed by EPRI, and Electrical Distribution and Design, Inc (EDD), a company affiliated with Virginia Tech University, is an open architecture application that contains 20 analysis and design calculations applicable to distribution systems.

For networks, this model is manually populated and maintained by the planning engineers. For radial circuits, DEW imports information and attributes from Ameren Missouri’s GIS system, and imports load information from a transformer load management (TLM) system.

The model includes a graphic representation of the primary, secondary, and network unit. For example, when modeling the feeder out of service, DEW will model all the protectors opening.

Note that at the time of the practices immersion, Ameren Missouri had assembled a list of desired enhancements to the DEW product.

7.4.3 - CEI - The Illuminating Company

Planning

Circuit Modeling

People

The CEI Planning department develops circuit models to perform various circuit analyses. The CEI Planning department is comprised of 4-5 Planners and 2-3 Protection Engineers. All members of the group are four year degreed engineers.

Process

When a new load is anticipated to connect to the system, the Planning engineer will model the new load by attaching the load to the appropriate node in the circuit model, and running a normal configuration load flow as well as several contingency scenarios. The results of this analysis will generate system reinforcement project ideas that are sent to Engineering for design.

Technology

For Network analysis, CEI utilizes a load flow product called PSLF – Positive Sequence Load Flow Software, by GE Energy.

For performing short circuit calculations, CEI is utilizing the CAPE software from Electrocon International.

FirstEnergy is in the process if moving from using Windmill load flow software to CYME load flow software. They ultimately intend to apply CYME to network analysis.

7.4.4 - CenterPoint Energy

Planning

Circuit Modeling

People

Circuit Modeling at CenterPoint is performed by the Electric Distribution Planning department (Planning group). This group is not part of the Major Underground group organizationally. One planning resource, an Engineering Specialist, is assigned full time to work in Major Underground, in a matrix arrangement.

The Planning group is comprised of 21 total resources, including 2 Lead Engineers. Each of the Lead engineers has about 6 -8 people reporting to them. These folks are either 4 year degreed engineers, or technical experts. CenterPoint aims to have a balance between Engineers and Technicians.

CenterPoint encourages its engineers to obtain their PE license. The PE license is required to become a Senior Engineer.

Process

The Planning group has modeled their entire distribution system, including the network. They run GIS extracts to obtain background maps, transformer sizes, etc., and import into their modeling software. They also import circuit loading information from SCADA and demand information from large customers. Planners also have access to real time information from CenterPoint’s remote monitoring system.

When a new load is anticipated to connect to the system, the Planning engineer will model the new load by attaching the load to the appropriate node in the circuit model, and running a normal configuration load flow as well as several contingency scenarios. The network model is used to plan for contingency situations, revealing potential overloads both in primary feeders, and in the networked secondary system.

Where possible, they use specific measured demand data in their models. Where specific transformer loading information is not available, they will apportion load measured at the circuit level along the circuit based on transformer capacity.

The results of this analysis will generate system reinforcement project ideas that are sent to Engineering within Major Underground for design.

Technology

CenterPoint is using the CymE Power Systems Analysis Framework (PSA) software suite. CenterPoint has recently implemented CymE’s network modeling software.

CenterPoint engineers noted that much of the work they do involves custom modeling to analyze the economics of various options.

Planners will compare information from their real time monitoring system to values produced by their analysis software to validate their models.

CenterPoint is in the process of installing automated meters at all distribution locations (a 5 year initiative) that will provide measured (15 minute) load information from all metered locations. They plan to integrate this information into their model.

The Planning group noted that in the future, as “smart systems” are implemented at CenterPoint, a new, Distribution Management System (DMS) controller may “do the modeling” of circuits. In any case the Planning engineers will be tightly integrated into this process.

See Network Planning - Technology

7.4.5 - Con Edison - Consolidated Edison

Planning

Circuit Modeling

People

Circuit Models are developed by the Network Engineering group using Con Edison’s Poly-Voltage Load Flow (PVL) software.

Con Edison has formed a PVL users group that meets bi monthly to discuss issues associated with the PVL. The PVL Users group is made up of approximately 50 people from both the regions and corporate, including network model maintenance people, designers, supervisors, engineers, engineering managers, and support personnel. Approximately 15 members attend any one meeting.

Process

To perform load flows, circuit models are brought into PVL from the mapping systems.When the circuit information is brought into PVL, the new information overlays the existing circuit model already in the system. Once the model is brought into PVL, all users use the same model. When a circuit is brought into PVL, people responsible for model maintenance ensure that the PVL model has electrical connectivity and is in synch with the mapping system.

Load flows are conducted for a variety of reasons.

Planning engineers run base case load flows, N-1 cases, and N-2 cases. For each contingency, the PVL output tells you what is overloaded in tabular and graphical formats.
Planning engineers use PVL to assist in short-range and long-range planning. For example, the system is used to analyze conceptual projects to split existing networks into smaller networks
For new business, engineers run the existing case, and then re-run it with the new business load added to understand the loading and voltage implication of the new load.
Region Engineering runs feeder loading studies in advance of the summer to identify anticipated overload conditions.
The system is also used to understand the loading implications of different restorations scenarios in an outage.

Technology

Load Flow System – Poly-Voltage Load Flow (PVL)

Con Edison utilizes a distribution load flow application called Poly-Voltage Load Flow (PVL). The PVL application is a suite of applications that was developed in house over a 20-year period of continued development. In addition to aiding engineers in performing load flow analyses, the PVL system is used to build feeder and transformer models, develop network transformer ratings, develop network feeder and cable section ratings, model area substation outages, and identify short-circuit duty at customers sites, etc.

PVL can use real-time readings from transformer vaults (gathered through Con Edison’s Network Remote Monitoring System [RMS]) for building the network load model. If needed, demands can be spotted at customer service points, using information such as customer kWh consumption and real-time transformer readings.

The PVL system can also perform cable section ratings. The system considers the impacts of soil type and temperature. The system does not automatically consider the proximity of electrical facilities to steam mains.

Operators are able to take advantage of the functionality of PVL through a real-time version known as AutoWOLF, which takes the base model and applies real-time conditions. For example, real-time transformer loading information would populate the model from RMS system. Knowledge of open feeders would populate the model from SCADA. When a circuit locks out, AutoWOLF automatically runs the system peak case, the current case, and the projected peak case, so that that information is available to an operator. The operator can look at the loading on the other feeders and try to determine which feeders to watch.

7.4.6 - Duke Energy Florida

Planning

Circuit Modeling

People

Network planning at Duke Energy Florida, including modeling and analyzing network feeders, is performed by the Network Planning group, which is organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I), led by a Director of PQR&I for Duke Energy Florida.

To perform planning work, the Network Planning group divides the Duke Energy Florida territory into four separate zones. The cities of Clearwater and St. Petersburg, part of the South Coastal Region, are included in one of the four zones. Every zone is assigned a Lead Planning Engineer and Senior Planning Engineer, who are responsible for all distribution planning activities within the zone.

Engineers/Planners in these zones work on Reliability as well as Planning. Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time planning reliability and infrastructure upgrades.

All Planners have four-year degrees in Electrical Engineering, a requirement for the position.

Process

The Planning Engineers maintain circuit models of all network feeders. The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading.

Load growth on the Clearwater network has been flat. St. Petersburg has seen some load growth, with most new loads being serviced by a primary and reserve feeder scheme with an automated transfer switch.

Planning Engineers model the system and perform analyses to understand anticipated requirements. For network feeders, Planning Engineers will perform contingency studies, modeling networks with each primary feeder out of service to identify areas of needed reinforcement to supply the network in a contingency. In locations where customers are service by a primary and reserve feeder scheme, engineers will model the distribution system with one feeder out of service, simulating customers connecting to reserve feeders. From this analysis, Planning Engineers determine where reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Technology

Network Planners use CYME Power Engineering software to perform load flow calculations on primary feeders. The underlying circuit models were originally built from manual circuit maps, and then updated with required details to perform load flows. Note that Duke Energy Florida does have its network primary feeders modeled in its GIS system, but is not importing these circuit models into CYME for the purpose of updating and performing load flow analysis on network feeders, as the network feeder configuration does not change much year-to-year. Rather, the network circuit feeder model is already loaded in CYME and is updated with peak loading information from the Feeder Management System.

Duke Energy Florida does not use software to model their network secondary. Rather, they perform real-time monitoring of secondary loading using a Sensus (Telemetrics) remote monitoring system that provides information from the vault, aggregated at the Network Protector relay. Within the Network Group, information such as secondary loading is monitored twice per day.

Duke Energy has implemented a Florida Primary and Secondary Network Improvement Plan, which has identified network modeling ability (secondary) as a key gap. As a consequence of this effort, they have initiated an effort to update their existing electronic files of secondary network information and will select an appropriate planning and load modeling tool for the future. In addition, they are working on developing a sustainability plan to assure that up-to-date secondary models are maintained.

7.4.7 - Duke Energy Ohio

Planning

Circuit Modeling

People

Historically, the planning Department models the network using spreadsheets. This model includes ties between customer loads and secondary bus sections within specific manholes.

More recently, Duke Energy Ohio is using SKM power tool up as a planning tool to model the network system. Information from the spreadsheets is manually entered into the SKM tool to perform load flow analysis, and run “what if” scenarios.

Process

The planning engineer has focused recently on bringing this model up to date. The model includes the street grid, including transformers by location, and including transformer sizing and impedance. The model has been updated to include new cables that Duke has recently changed. The model also contains updated loading information, including the loading of particular buildings. This loading information comes from several sources. Larger commercial customers have demand meters. Load readings are housed in the Duke energy billing system and for larger customers (over 300 KW) the customer provides a phone line and loading information flows back to the company’s billing system through the phone lines.

The planning engineer has also utilized the services of a co-op student to comb through the billing system and identify customer loading set off of the street grid.

Note that the updating of the network model is a manual process, updated once every three years. The model does not automatically import information from Duke Energy Ohio’s GIS system. (the network secondary system is currently not modeled in Duke’s GIS system). A longer term goal of the Planning Engineer would be to have the ability to automatically update the system model for analysis from the GIS with the push of a button.

Technology

Duke Energy Ohio is using SKM power tool up as a planning tool to model the network system. The SKM power tools product enables them to model secondary load flows.

The data for the model is housed and maintained in an Excel spreadsheet by the Network Planning Engineer.

7.4.8 - Energex

Planning

Circuit Modeling

People

Circuit modelling is the responsibility of the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

Engineers and designers within the Planning Group use automated systems to model current and anticipated load flows in normal and contingency situations, to identify necessary enhancements to the distribution system.

Technology

For transmission planning, Energex is using PSSE (Siemens). For its 33-kV system, Energex uses PSS Sincal by Siemens. For the 11 kV system, Energex uses DINIS by Fujitsu to calculate load flow. Load flow products include automated tools to apply forecasts and calculate thermal and voltage issues. Energex also uses CYMCAP by Cyme International in its cable ratings area to account for parallel cable and varied duct configurations, etc.

7.4.9 - ESB Networks

Planning

Circuit Modeling

People

Distribution planning, including modeling and analyzing feeders, is performed by planning engineers within the Network Investment groups – responsible for planning network investments in the North, and the other for planning in the South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists,” who have developed their expertise through field experience.

Planning standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

Planning engineers perform circuit modeling and analysis, including loading studies, contingency analysis, voltage drop analyses, harmonic and flicker analyses, and motor start analyses for the ESB Networks MV (10-kV and 20-kV) distribution systems. For analysis of their MV system, ESB Networks utilizes SynerGEE, with circuit models established from their GIS system.

In their design, ESB Networks uses an extensive LV secondary system, fed from larger three-phase transformers. In analyzing the LV system, planning engineers seek to maximize the allowable voltage drop on the secondary system, and minimize the voltage of the MV system. As a rule of thumb, ESB Networks allows up to a seven percent drop in the secondary voltage on the secondary fed from the MV underground primary system. ESB Networks Network engineers noted that they usually encounter demand/capacity constraints before encountering voltage problems on the secondary. Note that the LV system is not modeled in SynerGEE,

Technology

For performing circuit modeling and analysis, ESB Networks is using SynerGEE to model their MV primary feeders and 38-kV systems. Note that ESB Networks has modeled their feeders in a GIS database, and uses this information to build the circuit models within SynerGEE.

For analyzing their 38-kV meshed transmission system supplying Dublin, and for modeling their 110-kV transmission system, engineers are using PSS Sincal.

For performing analysis of its extensive LV secondary system, ESB Networks uses a home-grown Excel spreadsheet tool. This tool includes a voltage drop calculator.

7.4.10 - Georgia Power

Planning

Circuit Modeling

People

Network planning, including modeling and analyzing network feeders, is performed by the engineering group within the Network Underground organization within Georgia Power. The Underground group, led by the Network Underground Manager, consists of both engineering and construction resources responsible for the network underground infrastructure at Georgia Power. The Engineering group, led by the Network Underground Engineering Manager, is comprised of Engineers and Engineering Representatives concerned with the planning, design, and any service issues. The engineers are four-year degreed positions, while Engineering Representatives have a combination of years of experience and formal education, including two-year and four-year degrees.

In addition to the engineers within the Network Underground Engineering group, the Network Underground group has two Principal Engineers who report to the Network UG Manager.

The Network Underground group also works closely with Area Planning Engineers. Organizationally, Area Planners sit outside the network Underground group, but have a dotted line reporting to engineers within the Network Underground group.

Process

The network engineers maintain circuit models of all network feeders within the Georgia Power underground systems. The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. Forecasts typically look three years ahead, and include historic peak loads and anticipated/planned new projects. Downtown Atlanta is now a relatively stable network. Most planning is focused on selected metro Atlanta projects such as expansion of the network in Buckhead where they are experiencing higher demand, and on accommodations for the new football stadium.

Engineers model the system, and perform analyses to understand anticipated requirements. For network feeders, planning engineers will perform contingency studies, modeling networks with each primary feeder out of service to identify areas of needed reinforcement to supply the network in a contingency.

They model the distribution system with one feeder out of service, simulating customers connecting to reserve feeders. From this analysis, planning engineers determine where reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Technology

The underlying circuit models were originally built from scratch from a basic sketch of the network, and then filled in with details. Georgia Power then used its GIS system model as a base, traced it, and then manually entered the data into its CYME program. Note that Georgia Power elected to manually enter data in to CYME rather than import from their GIS. The reason for this decision was to be able to attain one-foot accuracy for cable lengths on both the primary and secondary circuits.

Using the CYMDIST load flow routine, Georgia Power can model primary system flows and meshed flows in the secondary. Georgia Power is also obtaining actively updating the accuracy of the models, validating with information from its newer meter data information systems where they are installed.

7.4.11 - HECO - The Hawaiian Electric Company

Planning

Circuit Modeling

People

The Distribution Planning Division performs circuit analysis at HECO. The Distribution Planning Division is part of the System Integration Department. This group performs all distribution planning at 46kV and below.

The group is led by a Principal engineer and is comprised one lead distribution engineer, and 5 planning engineers who do all of the distribution planning work for the island of O’ahu.

Process

HECO is currently in the process of installing a load flow software product to model circuits and perform analysis. Historically, HECO has not modeled circuits using a geographic tool. Instead, they have analyzed circuits by using loading information from different points along a circuit recorded on Excel spreadsheets.

Technology

HECO historically has not used a load flow software product to model circuits. They are in the process of installing SynerGEE, a load flow software product from GL Industrial Services. This product will interface with HECO’s GIS system and be able to import up to date circuit models. This software will facilitate their ability to perform contingency analysis. They are targeting year end (2009) for implementation of this software.

7.4.12 - National Grid

Planning

Circuit Modeling

People

At National Grid, network planning is performed by the Distribution Planning Organization, led by a Director. Organizationally, the Distribution Planning Organization is part of Distribution Asset Management, and is comprised of resources in both a central location (Waltham Massachusetts), and distributed throughout National Grid. About two thirds of the organization is centralized, with the remaining third decentralized.

The Distribution Planning department is comprised of Field Engineers who report to managers of Field Engineering for both New York and New England, Capacity Planning resources also reporting to a manager, and engineer personnel who have broad system responsibilities.

The Distribution Planning department is comprised of capacity planning resources, engineer personnel who have broad system responsibilities, and field engineers who report to managers of Field Engineering for both New York and New England.

The planning engineers who focus on the Albany network include a field engineer who works in the Albany office and focuses primarily on both radial and network underground systems for National Grid’s New York Eastern Division, and an engineer situated in Waltham, who has network engineering responsibilities across the system. These engineers have responsibility for both network planning and network design.

Both of these engineers are four-year degreed engineers, and are not represented by a collective bargaining agreement (exempt).

National Grid has up-to-date standards and guidelines for the network infrastructure. In addition they have up-to-date planning criteria that address network planning.

Process

National Grid has SCADA installed to monitor loading at the substation. They are able to obtain historic 15 minute interval load data as measured at the substation.

Planning engineers use this information as well as information from National Grid’s customer information system (CSS) to develop distribution feeder models. Customers within the CSS system are flagged as network customers. This identification as a network customer brings up certain fields to the aid engineers in assigning that customer to the appropriate buss within the secondary network system. The information from CSS is exported to a spreadsheet that is used by engineers to create the network system models.

Planning engineers have created models for the majority of the National Grid networks.

Technology

National Grid planning engineers use the PSSE power flow product to model and perform power flow analysis of the network system, and use a product called Aspen to perform fault analysis. (The Aspen product is also used by the System Protection group at National Grid.)

Note that the PSSE power flow product provides steady-state analysis. It cannot model network protectors (for example, back feed through the protectors).

In non-network areas, National Grid uses CymDist as a modeling tool, which has been integrated with their GIS system. National Grid has not applied this to the network system, as their GIS system does not model a meshed system.

7.4.13 - PG&E

Planning

Circuit Modeling

People

Network planning, including modeling and analyzing network feeders, is performed by the Planning and Reliability Department. This department is led by a Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution planning. Both network planning engineers are four year degreed engineers.

The planning engineers are represented by a collective bargaining agreement (Engineers and Scientists of California).

Process

The network engineer maintains circuit models of all network feeders within the EasyPower load flow product.

When a new customer, such as a high-rise building, desires connection to the PG&E network system, it files an application for service with the Service Planning Department. This department is responsible for gathering and validating loading information. They are also familiar with the electrical system, and can determine whether or not the new customer will be served by the network or radial system.

The network planning engineer will perform a low flow analysis to understand the impact on the system of the additional load in both the normal case and the contingency (n-1) case, in order to determine how to serve the load. For example, if adding the new load (and associated capacity) to the grid aids the overall grid in a contingency situation, engineers may decide to add the load to the grid. Conversely, if not, they may leave the customer on a spot network.

Technology

PG&E uses the EasyPower^[1] load flow product from ESA to model their network system. This model is manually populated and maintained by the Planning engineer. This product allows for modeling of primary and secondary load flows. The EasyPower models are not tied in with PG&E’s GIS system. The planning engineer reports being satisfied with this planning tool. Note that PG&E uses a different load flow product for analyzing its radial system (PG&E EDSA system).

At the time of this immersion, PG&E was implementing the CYMEDIST (by CYME) load flow product for performing analysis of their radial system. In a subsequent phase of their project, they plan to implement the use of CYMEDIST as their network planning tool as well. A challenge for them will be the conversion of data from EasyPower to CYMEDIST.

^[1] http://www.easypower.com/

7.4.14 - Portland General Electric

Planning

Circuit Modeling

People

Several groups are involved in circuit planning for the network system. For PGE, the Transmission and Distribution (T&D) Planning organization oversees the planning process for network and non-network systems,and performs contingency analyses with CYME and PSSE. APlanning Engineer with a four-year degree in engineering covers the PSC.

Three Distribution Engineers that work on the underground network provide the system operating information used to create and update models in CYME and PSSE. The Distribution Engineers are not based in the PSC service center or CORE group, and are overseen by the Eastern District Central Supervisor. The Planning Department is responsible for producing the “Weak Link Report,” which covers both the radial and network system and shows system peak loadings in summer and winter.

Because external projects drive much of the planning on PGE systems, the utility employs Service & Design Project Managers (SDPMs). SDPMs have a defined role and work almost exclusively on externally-driven projects, such as customer service requests, and liaise with new customers when designing services. Because the network includes many commercial customers with high energy demands, the Major Account Representatives responsible for the network provide any information about potential load changes from customers.

Process

Load Growth Studies: PGE performs load growth studies on the network when there is a specific need due to anticipated changing loads and customer demand. A Major Account Representative informs these studies and reports any anticipated changes to the load that a customer will undertake.

Reporting:The Planning Department creates bi-annual reports on the network loading, the “Weak Link Report,” which covers both the radial and network system. The report examines the system peak loading for the summer and winter, with network data sourced from the substations. PGE does not use the monitoring data that is currently received from the network protectors for modeling or planning. It is only used for operations.

PSSE Load Modeling Software: For the network system, PGE uses the Siemens PSSE modeling software for both the primary and secondary network models. Planners collaborate with Distribution Engineers to obtain the most up-to-date model in PSSE, including manually entering loading information. The load data is derived from the customer meters, and gathering and entering this information is a labor-intensive process. PGE’s network load is relatively flat, but the utility is anticipating an increase in the next few years due to an expansion of the retail sector in the downtown area.

Technology

PGE uses a number of information technology (IT) systems to model the system. For the radial system, PGE uses CYME/CYMDIST to model the system for both planning and reliability analyses. To model the network system, engineers use Siemens PSSE software for the primary and secondary network, using data from customer meters to develop a base case and highlight where normal and peak loading exceeded recommended limits.

Because PSSE is unable to monitor single-phase loads and cannot model loops, PSC will add the secondary network to CYME, using the GIS system to model and display loops. For mapping, PGE uses ArcFM on top of ArcGIS. The company is presently working with the ArcFM vendor to enable its use with CYME.

7.4.15 - SCL - Seattle City Light

Planning

Circuit Modeling

People

Network Planning at Seattle City Light is performed by the Network Design Department, which is part of Energy Delivery Engineering. The Network Design Department focuses exclusively on the planning and design of SCL’s networks.

The Network Design Department is made up of a System Group (eight engineers) and a Services Group (eight engineers). These engineers do all of the planning and engineering for the network (the System Group), as well as interface with network customers for load additions, new loads, etc. (the Services Group). The individuals in this group are four-year degreed engineers. The senior level engineer position at SCL requires a PE license. The engineers at SCL are represented by a collective bargaining agreement (IBEW).

Process

To perform load flows and voltage analyses, SCL engineers can call up a feeder, enter the changes, and solve the case. The output report is tabular, not graphic. The output indicates the load flow and voltage at each node.

Technology

SCL uses a load flow and voltage drop analysis software package developed in house (legacy software). The software is nodal but not graphical.

7.4.16 - Practices Comparison

Practices Comparison

Planning

Circuit Modeling

2015 Survey Results

Older Survey Results (2012)

7.4.17 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.11 - Network Computer Modeling

7.4.18 - Survey Results

Survey Results

Planning

Circuit Modeling

Survey Questions taken from 2015 survey results - Planning

Question 47 : Do you use software to perform network circuit analysis? (load flow studies, voltage drop analysis, etc)

Question 48 : If yes, are you using the software for…

Question 50 : In your network system analysis, do you model operation of network protectors due to reverse flows in your system?

Survey Questions taken from 2012 survey results - Planning

Question 3.15 : Do you use software to perform network circuit analysis? (Load flow studies, voltage drop analysis, etc)

Question 3.16 : If Yes, are you using the software for?

Question 3.17 : If you are using load flow software, please indicate which software product(s) you are using.

Question 3.18 : How do you collect network load data for modeling purposes?

Question 3.20 : In your network system analysis, do you model operation of NP’s due to reverse flows in your system?

Survey Questions taken from 2009 survey results - Planning

Question 3.10 : Do you use software to perform network circuit analysis? (Load flow studies, voltage drop analysis, etc) (This question is 3.15 in the 2012 survey)

Question 3.11 : If Yes, are you using the software for? (This question is 3.16 in the 2012 survey)

Question 3.14 : If you are using load flow software, please indicate which software product(s) you are using. (This question is 3.17 in the 2012 survey)

7.5 - Contingency Planning

7.5.1 - AEP - Ohio

Planning

Contingency Planning

People

Network planning at AEP Ohio, including contingency planning of the network, is performed by its Network Engineering group in tight collaboration with its parent company. The company employs two Principal Engineers and one Associate Engineer to facilitate network underground contingency planning for the Columbus and Canton urban underground networks. These planners are geographically based in downtown Columbus at its AEP Riverside offices. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the Director of Engineering Services who in turn reports to the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues.

Process

The network contingency planning process involves running load flows to compare system loading under first and second contingencies to the feeder ratings and identify and resolve any anticipated violations. AEP uses CYME and its SNA (secondary grid network analysis) module for performing network load analysis for the AEP Ohio group.

Reliable contingency operations depend on a thorough and thoughtful network design. One unique and long-standing practice employed by AEP Ohio’s underground network group is its use of N-2 network reliability in Columbus. As outlined in the Network Planning Criteria guide (see Attachment C) , Columbus operates in a Double Contingency Configuration (N-2). Adhering to these criteria, AEP Ohio urban networks in Columbus are designed to be served by up to six network feeders sourced from a single network station. The feeders must come from at least three low voltage buses, with no more than two network feeders per bus. These low voltage station buses are connected in a complete ring with closed tie circuit breakers between all buses. Multiple station transformers are connected so that a minimum of two transformers operate in parallel during operation. A third unit is used as a ready reserve hot spare. Circuit breakers are then used to automatically remove any faults from service without impacting normal operations. This provides N-2 service to all existing customers in the downtown region. All stations have a minimum of three transformers, some with as many as five or six.

AEP Ohio is not actively seeking to expand its network underground system, nor is it attempting to shrink its underground system. The Columbus urban area has four separate networks – North, South, Vine, and West – supplied from three substations. Each network is supplied from 138 kV/13.8 kV Δ -Y network transformers. All four networks are served by six feeders at 13.8 kV – each group of six originating from a single substation. There is no overlap in these networks. Each is built to N-2 reliability. In Columbus, the Vine network primarily serves spot networks in a high-rise area of downtown (Vine station), with some mini-grids at 480 V. The other three networks (North, South, and West) serve a mix of grid (216 V) and spot loads. Canton has one network supplied at 23 kV.

Technology

All network underground contingency plans are based on the company’s Network Planning Criteria guide from the AEP parent company, available in hard copy and online.

AEP uses the CYME SNA (secondary grid network analysis) module for performing network load analysis, including contingency analysis for the AEP Ohio group.

7.5.2 - Ameren Missouri

Planning

Contingency Planning

People

Distribution planning, including contingency planning of the network, at Ameren Missouri is performed by resources in several groups.

Area planning for the distribution system is the responsibility of Distribution Planning and Asset Performance. This group, led by a manager, is staffed with four-year degreed engineers, and includes the Standards Group as well as a planning engineering Group. Organizationally, Distribution Planning and Asset Performance is part of Energy Delivery Technical Services, reporting to a vice president.

Local distribution planning of both the network and non-network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division. This division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues. The engineers are four-year degree positions. Energy Services Consultants have a combination of years of experience and formal education, including two year and four year degrees. The engineers are nonunion employees; the estimators are in the union. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP.

Finally, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. This group’s role includes addressing issues such as the development and updating of network planning criteria. At the time of the practices immersion, the revitalization team had developed a series of planning criteria documents, including criteria for contingency planning. Organizationally, the Underground Revitalization Department is part of the Underground Division.

Process

Ameren Missouri designs its networks to N-1. However, Ameren Missouri plans for a substation bus outage and, if they lose any one bus, they may lose two feeders supplying a given network. The system is designed to handle this particular N-2 contingency.

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications of anticipated new forecasted loading. Engineers model the system, and perform analyses to understand anticipated requirements. For network feeders, planning engineers will perform contingency studies, modeling networks with each primary feeder out of service to identify areas of needed reinforcement to supply the network in a contingency.

For radial feeders, planning engineers will perform contingency studies (N-1 planning) to assure that they can pick up customers with reserve feeders within the emergency ratings of the transformer and cables. More specifically, they model the distribution system with one feeder out of service, and the models simulate customers connecting to reserve feeders. From this analysis, planning engineers determine places where reinforcement is necessary to be able to reliably serve customers in a contingency situation.

The revitalization team has developed draft planning criteria that includes:

System: Bus outage will not result in any customer outages that cannot be restored by reserve feeder switching, either by manual switching operations or automatic transfer equipment
System: N-2 for grid network (primary feeders)
System: N-1 for spot networks
System: N-1 for radial circuits, any time of year
Single contingency: Loss of all cables in manhole, all load can be picked up with exception of load supplied directly from manhole OR maximum of 6 MVA of radial load
Single contingency: The loss of any single network transformer in a spot network shall not result in any outages to customers
Single contingency: Loss of all cables in any duct bank, all load can be picked up with exception of load supplied directly from duct bank (ducts peeling off to a customer) OR maximum of 6 MVA of radial load

Note that at the time of the practices immersion, this criterion was under consideration at Ameren Missouri.

Technology

Ameren Missouri uses the DEW load flow product to model their network system. For networks, this model is manually populated and maintained by the planning engineers. The model includes a graphic representation of the primary, secondary, and network unit. For example, when modeling the feeder out of service, DEW will model all the protectors opening. Note that at the time of the practices immersion, Ameren Missouri had assembled a list of enhancements they desire to the DEW product.

For radial circuits, DEW imports information and attributes from Ameren Missouri’s GIS system, and imports load information from a transformer load management (TLM) system.

7.5.3 - CEI - The Illuminating Company

Planning

Contingency Planning

People

Network Contingency Planning at CEI is performed by the Planning and Protection Section of the Engineering Services Department (CEI Planning Group). The group is part of the CEI Engineering Services department, and is led by a supervisor who reports to the Engineering Manager. The group is responsible for all distribution planning and protection, from 36kV and below. The CEI Planning Group is comprised of 4 Planners and 3 Protection Engineers. All members of the group are four year degreed engineers. The Planning Supervisor noted that he prefers candidates for the CEI Planning Group to have their Professional Engineer (PE) license.

Process

CEI’s standard network contingency planning is N-1; that is, they plan the network system such that all the system components, including primary feeders, secondary cable mains and taps, and transformers are sized to be able to carry the load within “specified thermal and voltage limits” during peak conditions when any single network feeder is out of service. Contingency planning criteria for network systems is described in the First Energy Underground Network Design Practice, 11-350. See Attachment A.

Regional Engineering Services is responsible to review new service load additions of 100kW or greater to assure that secondary cable sections and network transformation are sufficient during both normal and contingency situations.

The Planning and Protection Section does not regularly revisit and update their network load models and review potential contingency situations, as the network is very lightly loaded, and its configuration remains relatively unchanged. They will revisit these models in particular instances, where changes are anticipated to the system.

The Planning and Protection Section does regularly (annually) revisit and update their load models and review potential contingency situations for their Non network systems. Their planners divide the service territory into sections, with each planner having responsibility for particular substations. Planners will update their circuit models and perform load flow studies to understand and identify system reinforcement needs. This information is also fed into a corporate model that looks at the larger loading picture.

In CEI’s non – network, radially fed 11kV ducted conduit system, N-1 reliability is provided through the use of a “spare feeder” that feeds into larger customers and is available as a back up in case of the loss of one of the main feeders. In some cases, an automatic throw over scheme exists between the normal and spare feeder. CEI has one spare feeder backing up every six normally fed feeders into larger customers in downtown Cleveland. See “11kV Non – network Service to Large Customers ” for a more detailed discussion of this design.

In CEI’s 4kV radial distribution system, N-1 reliability is provided through manual tie points between feeders. In the event of a feeder outage, customers are restored through manual sectionalizing.

Technology

For Network analysis, CEI utilizes a load flow product called PSLF – Positive Sequence Load Flow Software, by GE Energy.

Note that FirstEnergy is in the process if installing CYME load flow software. They ultimately intend to apply CYME to network analysis; however, its functionality in this area is still being evaluated.

7.5.4 - CenterPoint Energy

Planning

Contingency Planning

People

Contingency planning at CenterPoint is performed by the Electric Distribution Planning department (Planning group). This group is not part of the Major Underground group organizationally. One planning resource, an Engineering Specialist, is assigned full time to work in Major Underground, in a matrix arrangement.

The Planning group is comprised of 21 total resources, including 2 Lead Engineers. Each of the Lead engineers has about 6 -8 people reporting to them. These folks are either 4 year degreed engineers, or technical experts. CenterPoint aims to have a balance between Engineers and Technicians.

CenterPoint encourages its engineers to obtain their PE license. The PE license is required to become a Senior Engineer.

Process

CenterPoint’s distribution system is designed to N-1. When performing contingency planning for the loss of a substation transformer, they will assume that the strongest unit in the station fails. They will also reduce the rating of the remaining bank(s) by 5% in anticipation of some phase imbalance in a contingency configuration.

CenterPoint’s normal design configuration provides adequate capacity to carry load in a single contingency. For situations where a substation transformer is highly loaded, CenterPoint has implemented programming at certain stations that will swap loads to alternate sources in the case of the loss of a substation transformer, helping them to defer the investment to increase transformer capacity. This programming moves loads among transformers within a station and from station to station to provide service continuity in a contingency situation during peak periods by optimizing the distribution of load among transformers.

See Distribution Automation Control in Contingencies

For the underground system, CenterPoint’s approach to contingency planning exceeds their written criteria in that they plan for the loss of an entire station, not just the loss of one bank in the station. CenterPoint cited one instance where they built overhead 35kV ties to a particular key station to assure that they had adequate tie ability in anticipation of the catastrophic loss of that sub.

CenterPoint also uses portable substations and maintains an inventory of spare transformers.

The Electric Distribution Planning group does regularly (annually) revisit and update their load models and review potential contingency situations for their system. Planners will update their circuit models and perform load flow studies to understand and identify system reinforcement needs. CenterPoint will annually produce a 5 year construction budget that includes a list of the proposed feeder reinforcements, transformer additions, etc.

In CenterPoint’s non – network, radially fed 12kV and 35kV ducted conduit system, N-1 reliability is provided through the use of an “emergency feeder” that feeds into larger customers and is available as a back up in case of the loss of one of the main feeders. In some cases, an automatic throw over scheme exists between the normal and emergency feeder. In some cases CenterPoint has split the customer’s load such that each portion is normally fed by a different feeder.

In addition, N-1 reliability is provided through manual tie points between feeders. In the event of a feeder outage, customers are restored through sectionalizing.

Technology

For contingency analysis, CenterPoint is using CymE Power Systems Analysis Framework (PSA) software suite. They also recently implemented CymE’s CYMDIST (SNA), Secondary Network Analysis module.

CenterPoint is using Smart Cascade and Smart Distribution Automation Control System (DACS) to be able to move load from one sub transformer to another as part of a single contingency situation. (Note that this technology is not being used in substations with dedicated underground circuits.)

CenterPoint is also using an automated capacitor system that turns capacitors on an off based on actual loads and readings. (Note that this technology is not being used in substations with dedicated underground circuits.)

7.5.5 - Con Edison - Consolidated Edison

Planning

Contingency Planning

(Planning for Contingencies)

Process

Electric facilities in the borough of Manhattan, by law, must be underground. Also by law, the design criterion is N-2; that is, the system must be able to withstand the failure of any two components during peak periods, without resulting customer outages. Note that the Queens, Brooklyn, and the main sections of the Bronx are also designed to N-2. The rest of the Con Edison system is designed to N-1.

Technology

Load Flow System – Poly-Voltage Load Flow (PVL)

Con Edison utilizes a distribution load flow application called Poly-Voltage Load Flow (PVL). The PVL application is actually a suite of applications that was developed in house over a 20-year period of continued development. In addition to aiding engineers in performing load flow analyses, the PVL system is used to build feeder and transformer models, develop network transformer ratings, develop network feeder and cable section ratings, model area substation outages, and identify short-circuit duty at customers sites, etc.

To perform load flows, circuit models are brought into PVL from the mapping systems. The secondary system is kept in one mapping (GIS) system (different from location to location), and the primary feeders are kept in another mapping (GIS) system. Con Edison reflects all system changes on its mapping systems. Feeder maps within Manhattan are updated in 24 hours as changes occur. Secondary side maps are not updated as quickly, but are very frequently updated. These GIS systems are maintained by the mapping organization.

When the circuit information is brought into PVL, the new information overlays the existing circuit model already in the system. Once the model is brought into PVL, all users use the same model. When a circuit is brought into PVL, people responsible for model maintenance ensure that the PVL model has electrical connectivity and is in synch with the mapping system.

Load flows are conducted for a variety of reasons.

Planning engineers run base case load flows, N-1 cases, and N-2 cases. For each contingency, the PVL output tells you what is overloaded in tabular and graphical formats.
Planning engineers use PVL to assist in short-range and long-range planning. For example, the system is used to analyze conceptual projects to split existing networks into smaller networks
For new business, engineers run the existing case, and then re-run it with the new business load added to understand the loading and voltage implication of the new load.
Region Engineering runs feeder loading studies in advance of the summer to identify anticipated overload conditions.
The system is also used to understand the loading implications of different restorations scenarios in an outage.

PVL can use real-time readings from transformer vaults (gathered through Con Edison’s Network Remote Monitoring System [RMS]) for building the network load model. If needed, demands can be spotted at customer service points, using information such as customer kWh consumption and real-time transformer readings.

The PVL system can also perform cable section ratings. The system considers the impacts of soil type and temperature. The system does not automatically consider the proximity of electrical facilities to steam mains.

Operators are able to take advantage of the functionality of PVL through a real-time version known as AutoWOLF, which takes the base model and applies real-time conditions. For example, real-time transformer loading information would populate the model from RMS system. Knowledge of open feeders would populate the model from SCADA. When a circuit locks out, AutoWOLF automatically runs the system peak case, the current case, and the projected peak case, so that that information is available to an operator. The operator can look at the loading on the other feeders and try to determine which feeders to watch.

During emergency conditions, Con Edison assigns engineers assigned to the control room to monitor system loading. During normal conditions, the operators monitor the system themselves.

Con Edison has formed a PVL users group that meets bi monthly to discuss issues associated with the PVL. The PVL Users group is made up of approximately 50 people from both the regions and corporate, including network model maintenance people, designers, supervisors, engineers, engineering managers, and support personnel. Approximately 15 members attend any one meeting.

7.5.6 - Duke Energy Florida

Planning

Contingency Planning

People

Network Planning at Duke Energy Florida, including contingency planning of the network, performed by Planning Engineers who are organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I). This group is led by a Director of PQR&I for Duke Energy Florida.

In addition, contingency studies are performed by the Grid Management group, organizationally aligned with the Distribution Control Center, and responsible for establishing contingency plans and restoration plans.

To perform planning work, the Network Planning group divides the Duke Energy Florida territory into four separate zones. The cities of Clearwater and St. Petersburg, part of the South Coastal Region, are included in one of the four zones. Every zone is assigned a Lead Planning Engineer and Senior Planning Engineer, who are responsible for all distribution planning activities within the zone, including contingency planning, to assure that the network system will operate reliably with the loss of any one feeder during peak load conditions (N-1).

Engineers/Planners in these zones work on Reliability as well as Planning. Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time planning reliability and infrastructure upgrades.

All Planners have four-year degrees in Electrical Engineering, a requirement for the position.

Process

Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time focusing on reliability and infrastructure upgrades. Capacity studies, for both normal and contingency conditions, are triggered by new load additions.

Part of Duke Energy Florida’s process for assuring adequate capacity in peak load conditions under a first contingency is their network planning criteria which requires that downtown feeders supplying the network or that are part of a primary / reserve feeder loop scheme are designed to carry no more than 6MW. This planning criteria provides reserve capacity in urban areas of Duke Energy Florida to be able to supply N-1 reliability. In contrast, radial feeders outside of the downtown area may be loaded to 12MW.

Technology

Network Planners use CYME Power Engineering software to perform load flow calculations on primary feeders.

Duke Energy Florida does not use software to model their network secondary. Rather, they perform real-time monitoring of secondary loading using a Sensus (Telemetrics) remote monitoring system that provides information from the vault, aggregated at the Network Protector relay. Within the Network Group, information such as secondary loading is monitored twice per day.

7.5.7 - Duke Energy Ohio

Planning

Contingency Planning

People

Distribution planning, including contingency planning for the network underground system, is performed by the Distribution Planning department.

Duke Energy Ohio has assigned an engineer within the Distribution Planning group to focus on the network.

The engineer who focuses on network planning, is a four year degreed engineer. This engineer works very closely with the engineering department and the construction department to plan the network.

Process

Duke Energy Ohio’s networked system is designed to n-1. That is, the system is designed to ride through the failure of any one component during a system peak.

Part of the planning process at Duke is for the Planning Engineer to model the system with anticipated loading, and then model the impact of the loss of key components in the system; that is, assure that the system can carry the anticipated peak loading in an N-1 contingency. From this analysis, the Engineer will identify system improvement opportunities to meet Duke’s N-1 planning criteria requirement.

Duke is presently compiling a listing of older and damaged equipment that require repair or replacement, so that they can proactively anticipate the loss of this equipment. From this analysis, the Planning Engineer, working with the Construction department, has recommended changes to the spare equipment inventory, including network transformers and network protectors, so that Duke can react quickly to the loss of a piece of equipment. Duke Energy Ohio’s has a targeted spare pool of 10% (one unit of every type for each ten installed).

Duke Energy Ohio does not have a written contingency plan that describes the specific actions to take with the loss of a feeder.

Technology

Duke Energy Ohio is using SKM PowerTools up as a contingency planning tool for the network^[1] .

The planning engineer has focused recently on bringing this model up to date. The model includes the street grid, including transformers by location, and including transformer sizing and impedance. The model has also been updated to include new cables that Duke has recently changed.

The model also contains updated loading information, including the loading of particular buildings. This loading information comes from several sources. Larger commercial customers have demand meters. Load readings are housed in the Duke energy billing system and for larger customers (over 300 KW) the customer provides a phone line and loading information flows back to the company’s billing system through the phone lines.

The Load modeling system is used to perform “what if” scenarios, to understand the impact of the system in a contingency, and to identify areas for system reinforcement.

^[1] Note that outside the network, Duke is using the SynerGEE system analysis product.

7.5.8 - Energex

Planning

Contingency Planning

People

Contingency planning is performed by the Network Capital Strategy and Planning Group, which is part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

For the distribution network, planning engineers conduct an annual review of the substations supplying the medium-voltage infrastructure (110- kV:11 kV stations supplying the Central Business District (CBD)). This analysis includes a study of the substations and the 11 kV feeders to identify anticipated deficiencies in capacity, voltage levels, and fault levels in a contingency situation. Energex engineers perform over 800 contingency studies per year focused on this system, looking at all possible N-1 scenarios annually.

Energex plans to N-2 for its 110-kV transmission feeders, and plans to N-1 for its transmission substations and medium-voltage distribution system.

Energex’s contingency planning approach for the 11 kV feeders is to only load them to no more than 75 percent of the rated capacity of the feeder. This enables them to go “from four to three,” meaning that they can carry the load from the loss of any one feeder by transferring the load to three other feeders.

Note that for the three feeder 11 kV meshed network that services the downtown CBD, the loading on any one feeder is held to 66 percent, so that, in the case of the loss of any one feeder, any load on that feeder can be carried by the other two. See Network Design for more information on Energex’s three feeder 11 kV meshed network.

Technology

Energex performs load studies as part of its contingency planning process using the SINCAL^[1] and DINIS^[2] automated tools.

^[1] PSS®SINCAL, a Siemens product.

^[2] Distribution Network Information System (DINIS), a Fujitsu product.

7.5.9 - ESB Networks

Planning

Contingency Planning

People

Distribution planning, including contingency planning, at ESB Networks Networks is performed by planning engineers within the Network Investment groups – one responsible for planning network investments in the North, and the other for planning in the South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists” who have developed their expertise through field experience.

Planning standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

Planners design the system to N-1, with most supplies having a “forward feed” (preferred) and a “standby feed” (reserve). The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications of anticipated incremental forecasted loading. Planners (engineers and technologists) model the system, and perform analyses to understand anticipated requirements, including contingency studies (N-1 planning) to assure that the company can pick up customers with standby feeders within the emergency ratings of their transformers and cables (long-term cyclical overloads of no more that from 125-150 percent of rating, and short-term (emergency) loading of no more than 150-180 percent of rating). From this analysis, planners determine what reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Technology

For performing MV (10 and 20 kV) and for some 38-kV circuit studies, ESB Networks is using SynerGEE (GL Group). The company has tied this tool to its GIS database.

7.5.10 - Georgia Power

Planning

Contingency Planning

People

Network planning at Georgia Power, including contingency planning of the network, is performed by resources in several groups. The company has both Area Planning and Distribution Planning. Area Planners are responsible for different network areas in the state, such as Atlanta, Savannah, Macon, Augusta, Athens, Valdosta, and Columbus and are responsible for the substations in those areas to make sure the transformers have the capacity to handle projected loads. Area Planners evaluate Contingency Reserves for N-1 reliability of the network. For example, if Georgia Power has three transformers at a substation, with one bank serving the network, then one of the responsibilities of an Area Planner is to insure that if a network bank fails for whatever reason, then the other two transformers have the capacity to instantaneously pick up the full load of the failed network bank. This guarantees a high level of customer reliability.

Distribution planning associated with network feeders is performed by engineers located within the network underground group. They are responsible for feeder planning, including contingency planning of the networks. In delivering N-1 reliability, they assure that the networks can operate reliably with the loss of any one feeder on the peak day. They also perform studies to assure the robustness of the secondary infrastructure. Distribution (network) planners work closely with the Area planners.

Process

Part of the process for assuring reliable contingency operations involves de-ratings of system components based on studies to determine where heat build-up is the highest. These de-rated values for components, such as cables in ducts, provide a conservative starting point for contingency analysis.

Engineers will utilize the CYMDIST modeling program to develop location specific models of various duct bank configurations, loads, cable and equipment sizes and types. Contingency analysis involves modeling the loss of any one component and analyzing the implications on the remaining system, and identifying places where remediation may be necessary.

Contingency planning is based on N-1. It is not the Area Planner’s job to insure there is enough capacity in the event of multiple transformer failures at a substation, (an N-2 or greater condition). In the unlikely event that multiple transformers are down, Georgia Power can cut distribution, split the network, or take other proactive measures.

One unique long standing practice employed by Georgia Power is to re-rate substation transformers based on loading and individual test results for determining reserve contingency. By examining test criteria and the particular characteristics of a given transformer, as well as the load profile on that particular transformer, Georgia Power may find the transformer capable of peak loads of 115 to 130 percent of nameplate ratings. The company then knows they have that, more realistic reserve capacity in an emergency. Note that this re-rating depends in part on the transformer having opportunities to cool down, so it may not be applicable to transformers serving constant heavy loads.

Overall, the Atlanta urban network is not heavily loaded, and the company has even seen a drop in demand during the economic downturn as buildings in the downtown area are vacated. Most network segments are loaded to about 70 percent of capacity.

Georgia Power is not actively seeking to shrink its network underground system. In fact, in addition to Buckhead, Georgia Power is adding network transformers at three other substations. If the company sees the need for more capacity that requires expansion of the network, the company adds it. For example, in downtown Savannah, a historical district that cannot have its buildings demolished or removed, a number of new shops, condos and businesses are opening up, so load is increasing there.

Technology

Georgia Power has recently acquired CYMDIST to model the entire secondary and primary grid. The program is designed for planning studies and simulating the behavior of electrical distribution networks under different operating conditions and scenarios. It includes several built-in functions that are required for distribution network planning, operation and analysis. The model Georgia Power has developed is extremely accurate including cable systems, cable ratings, cable capacities and specifications. The Area Planner keeps detailed spreadsheets, continually updated, on upcoming and ongoing projects. The Georgia Power GIS system also tracks network statistics, so that if a particular network segment reaches a threshold, it is tagged for the Area Planner and Network Engineering group. Typically Georgia Power prefers to keep capacities in the 70 to 90 percent range, and any transformer or network segment exceeding 90 percent is prioritized and tagged for the Area Planner and engineering for more capacity.

7.5.11 - HECO - The Hawaiian Electric Company

Planning

Contingency Planning

People

Contingency planning at HECO is performed by Distribution Planning Division. The Distribution Planning Division is part of the System Integration Department. This group performs all distribution planning at 46kV and below.

The group is led by a Principal engineer and is comprised one lead distribution engineer, and 5 planning engineers who do all of the distribution planning work for the island of O’ahu. All of the engineers in the group are four year degreed engineers.

Process

HECO’s distribution system is designed to N-1; that is, they plan their system such that all the system components, including primary feeders, secondary cable mains and taps, and transformers, are sized to be able to carry the load within specified thermal and voltage limits during peak conditions when any single component is out of service.

All three phase distribution transformers in their radial distribution system are fed by two primary feeders, a normal and alternate feeder that can carry the load in the event of the loss of the primary feeder. All single phase underground designs are looped, such that load can be picked up from an alternate direction in the event of an outage.

HECO is using a modular substation philosophy, with a typical substation using a small (10 mVA) transformer with two circuits fed out of the sub. With the loss of a substation transformer, the system is designed that the loading can be shifted (through manual sectionalizing) and supported by adjacent stations in peak periods. In addition, HECO has two mobile subs (one 5 MVA and one 10 MVA), and three spare 10 MVA units.

HECO has over 250 10 MVA units on their system.

HECO will perform studies annually to assure that the remaining components in a contingency scenario can carry the load without exceeding the emergency rating of the component.

Technology

HECO historically has not used a load flow software product to aid them in distribution planning. They gather and record feeder loading and transformer loading information using an EXCEL spreadsheet. Load flows for contingency analysis are calculated manually.

HECO is in the process of installing SynerGEE, a load flow software product from GL Industrial Services. This product will interface with HECO’s GIS system and be able to import up to date circuit models. This software will facilitate their ability to perform contingency analysis. They are targeting year end (2009) for implementation of this software.

7.5.12 - National Grid

Planning

Contingency Planning

People

National Grid’s Distribution Planning Organization, led by a Director, performs network planning, including contingency planning. Organizationally, the Distribution Planning Organization is part of Distribution Asset Management, and is comprised of resources in both a central location (Waltham Massachusetts), and distributed throughout National Grid. About two thirds of the organization is centralized, with the remaining third decentralized.

The distribution planning department is comprised of capacity planning resources, engineer personnel who have broad system responsibilities, and field engineers who report to managers of Field Engineering for both New York and New England

The planning engineers who focus on the Albany network include a field engineer who works in the Albany office and focuses primarily on both radial and network underground systems for National Grid’s New York Eastern division, and an engineer situated in Waltham, who has network engineering responsibilities across the system. These engineers have responsibility for both network planning and network design.

Both of these engineers are four-year degreed engineers, and are not represented by a collective bargaining agreement (exempt).

National Grid has up-to-date standards and guidelines for the network infrastructure. In addition they have up-to-date planning criteria that address network planning.

Process

The National Grid Albany network is designed to N-2. That is, it is designed to ride through the failure of any two components during a system peak with only minor overloads to network transformers, primary feeders and secondary mains.

National Grid has SCADA installed to monitor loading at the substation. They are able to obtain historic 15 - minute interval load data as measured at the substation. Planning engineers use this information as well as information from National Grid’s customer information system to develop distribution feeder models. Customers / customer load are assigned to certain network busses to model the system. Engineers model the system at peak load, at 90% of peak load, and in both the n-1 and n-2 contingency situations.

Distribution planning analysis includes analysis of both potential thermal overloads and voltage issues. When assessing loading impacts of devices such as transformers, National Grid uses 120% of nameplate for single contingency and 140% of nameplate for double contingency.

The network in Albany is summer peaking. Typically, planning studies for the network are performed in the spring and may project anticipated system loading multiple years in the future. In addition, the analysis may also include a fault current analysis to understand the ability of the system to properly clear faults.

For the Albany network system, field engineers have performed analyses of contingency situations in the network to understand and to provide emergency plans and guidelines to the Regional Control Center of the ability of the system to handle various load levels in a contingency. These guidelines, for example, would indicate at various load levels, the capability of the system to carry the load with certain feeders out of service. (For example, at “x” % loading, the network system could sustain the loss of “y” number of primary feeders without having to shed load. National Grid has documented this analysis, and will perform network drills annually to rehearse emergency operating procedures in the network.

Technology

National Grid planning engineers use the PSSE power flow product to model and perform power flow analysis of the network system, and use a product called Aspen to perform fault analysis. (The Aspen product is also used by the System Protection group at National Grid.)

Note that the PSSE power flow product provides steady-state analysis. It cannot model network protectors (for example, back feed through the protectors).

In non-network areas, National Grid uses CymDist as a modeling tool, which has been integrated with their GIS system. National Grid has not applied this to the network system, as their GIS system does not model a meshed system.

7.5.13 - PG&E

Planning

Contingency Planning

People

Network planning, including contingency planning, is performed by the Planning and Reliability Department. This department is led by Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution planning, including contingency analysis.

One of the two network engineers is relatively new to the department, and was assigned to receive training from the lead network engineer. Both network planning engineers are four year degreed engineers. They are represented by a collective bargaining agreement (Engineers and Scientists of California).

Process

PG&E’s network system is designed to n-1. That is, the system is designed to ride through the failure of any one component during a system peak, with only minor overloads to transformers, primary feeders and secondary mains during peak periods.

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new loading. This analysis is performed for both base case and for contingencies. For each network, a contingency study is run for each feeder supplying the network; that is, the planning engineer will model each circuit as being out of circuit, and rerun their load flows to identify overloads / circuit weaknesses in a contingency. (Six different contingency models are run, one for each primary feeder supplying a network).

Network planning, including contingency planning, is based on a peak load analysis, recognizing that the peak is only representative of loading for a few days each year. Planning engineers obtain monthly peak loads from the SCADA Historian^[1] and compare this to feeder ratings. Engineers may enter the SCADA readings into the load flow model and recalculate to see if there are any overloads. Alternately, they may simply compare the monthly peak values to previous peak load readings and circuit ratings. Also, planning engineers will ascertain the validity of any projected new load estimates, and run load flows to understand the implications of the added load.

Designing for the peak provides conservatism to the planning process. Planning engineers report that actual loading is always lower than loading projected by their load flow models, as these models are based on peak values and do not account for load diversity.

If the calculated circuit loading exceeds 110% of the either the circuit’s normal or emergency capacity ratings, the planning engineer will consider the circuit to be overloaded and recommend design changes to ameliorate the overload condition. PG&E uses the 110% level based on the fact that their load flow model uses all peak load values and thus doesn’t account for diversity. So, rather than reacting to modeled loads over the 100% rated values of circuits, they add the additional 10% since they know their models are conservative.

Technology

PG&E uses the EasyPower load flow product from ESA to model their network system. This model is manually populated and maintained by the planning engineer. The planning engineer reports being satisfied with this planning tool.

Note that PG&E is presently implementing the CYMEDIST (by CYME) load flow product for performing analysis of their radial system. In a subsequent phase of their project, they plan to implement the use of CYMEDIST as their network planning tool as well. A challenge for them will be the conversion of data from EasyPower to CYMEDIST.

^[1] PG&E’s SCADA provides three phase amp readings on all network feeders. Also, they have the ability to monitor loading on all network transformers through CT monitoring installed on the transformer secondary (at the NP). This information is housed in the PG&E SCADA Historian.

7.5.14 - Portland General Electric

Planning

Contingency Planning

People

Several groups are involved in contingency planning for the network system, although most operate across the enterprise. Overall, PGE’s network includes multiple redundancies within the system and is very reliable.

Across PGE, the Transmission and Distribution (T&D) Planning organization oversees the planning process for network and non-network systems, as well as performs contingency analyses with CYME and PSSE. Aplanning engineer with a four-year degree in engineering covers the PSC.

Three Distribution Engineers also work on the underground network, and they provide the system operating information used to create and update models in CYME and PSSE. The Distribution Engineers are not based in the PSC service center or CORE group, and are overseen by the Eastern District Central Supervisor.

The Planning Department is responsible for producing the “Weak Link Report,” which covers both the radial and network system and shows system peak loadings in summer and winter

Process

PSSE Load Modeling Software

For the network system, PGE uses the Siemens PSSE modeling software for both the primary and secondary network models. Planners collaborate with Distribution Engineers to obtain the most up-to-date model in PSSE, including manually entering loading information. The load data is derived from the customer meters, and gathering and entering this information is a labor-intensive process. PGE’s network load is relatively flat, but the utility is anticipating an increase in the next few years due to an expansion of the retail sector in the downtown area^[1].

Reporting: To support contingency planning, the Planning Department creates bi-annual loading reports, known as the “Weak Link Report,” which covers both the radial and network systems. The report examines the system peak loading for the summer and winter, using network data sourced from the substations to identify anticipated weak spots (areas of overload or voltage issues). At present, monitoring data received from the network beyond the station is not used for modeling or planning, and is reserved for operations.

Reliability Metrics: At PGE, reliability reporting uses SAIDI, SAIFI, and MAIFI to assess feeder performance, and feeder classification is used to determine the number and duration of outages for a particular customer. Network feeders are classified as urban, urban feeders and transformers are designed to the N-1 contingency, and these have high reliability.

Technology

PGE uses a number of information technology (IT) systems to model the system and plan for contingencies. PGE uses CYME/CYMDIST to assess the reliability benefits of projects on the radial system, and planners use the software to develop a base case and evaluate the system under N-0 and N-1 contingencies. For modeling the network system, engineers use Siemens PSSE software for the primary and secondary network, using data from customer meters to develop a base case and highlight where normal and peak loading exceeded recommended limits.

Because PSSE is unable to monitor single-phase loads and cannot model loops, PSC will add the secondary network to CYME, using the GIS system to model and display loops. For mapping, PGE uses ArcFM on top of ArcGIS. The company is presently working with the ArcFM vendor to enable its use with CYME.

PGE uses an Enterprise Resource Planning ERP system called PowerPlan, which has an Oracle attachment named “Pace.” This system provides canned financial data about projects. Other technologies used for planning include SharePoint, Field View, the PGE Engineering Portal, PI ProcessBook, and the T&D Database.

Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.

7.5.15 - SCL - Seattle City Light

Planning

Contingency Planning

People

Network Planning at Seattle City Light is performed by the Network Design Department, which is part of Energy Delivery Engineering. The Network Design Department focuses exclusively on the planning and design of SCL’s networks.

Although SCL does have a separate planning group that performs distribution planning activities for SCL’s non-network distribution system, this group does not do the planning associated with the network. All cable ratings, load flow and voltage studies, master load flow analysis, assignment of feeders to load additions, area studies, etc. associated with the network are performed by the Network Design Department staff. (Note that at the time of the EPRI practices immersion, SCL was implementing an Asset Management organization. At the time of this writing, SCL had not yet decided whether certain tasks currently performed by the Network Engineering group will be moved into the Asset Management organization.)

The Network Design Department is made up of a System Group (eight engineers) and a Services Group (eight engineers). These engineers do all of the planning and engineering for the network (the System Group), as well as interface with network customers for load additions, new loads, etc. (the Services Group). The individuals in this group are four-year degreed engineers. The senior level engineer position at SCL requires a PE license. The engineers at SCL are represented by a collective bargaining agreement (IBEW).

Process

SCL’s network system is designed to maintain N-1 load capability at peak load.

SCL has defined and documented network design criteria for Feeder Loading, Electrical System Construction, and Civil Construction (see below).

Network Design Criteria for Feeder Loading

Load feeders to maintain N-1 load capability at peak load.
Limit feeder imbalance to 20% at N-0.
Keep load current within constraints determined by loadflow and ampacity studies for existing plant.
Keep load current within constraints determined by loadflow and ampacity studies for new construction.
Account for diversity factor during feeder loading analysis.

Network Design Criteria for Electrical System Construction

Allow no more than two mainstem cables from any one sub-network per MH or street vault. There may be mainstem cables from other sub-networks present (subject to the same restriction) as well as branch cables.
Allow no more than four lateral feeders from any one sub-network per MH or street vault. This may change as a result of studies for ampacity evaluations of feeder laterals with high loads or near steam lines.
Size new mainstem feeders to match substation capacity, with allowances for feeder imbalance and reliability.
Require two half-lapped layers of arc-resistant tape to each primary feeder in MHs and street vaults.
Limit DC Hi-pot testing of 15-kV class cables to a maximum of 26 kV DC and 28-kV class cables to a maximum of 47 kV DC.
Use VLF testing for newer cable testing if separable from older cable sections. Note: This particular requirement has not yet been implemented. SCL is still examining the merits of VLF testing for cable
Do not allow construction of new 480-volt secondary grid networks.
Use limiters on both ends of all secondary bus ties.

Network Design Criteria for Civil Construction (Street Facilities)

All duct banks shall be encased in concrete.
All new system duct banks shall have 5-inch diameter conduits for system cables.
Steel ducts are required for shallow construction.
Every effort shall be made to install new duct banks a minimum of 15 feet away from any steam logs. If new duct banks will be within 15 feet, a cable ampacity analysis is required to determine potential mitigation actions.
If a duct bank must cross a steam log, insulation must be applied per SCL construction guideline NDK 150.
Fluidized thermal backfill (FTB) or controlled density fill (CDF) may be used to backfill around encased service ducts.
Use only fluidized thermal backfill (FTB) around encased system ducts.

Technology

SCL uses a load flow and voltage drop analysis software package developed in house (legacy software). The software is nodal but not graphical.

7.5.16 - Survey Results

Survey Results

Planning

Contingency Planning

Survey Questions taken from 2015 survey results - Summary Overview and Planning (Question 35)

Question 9 : Within your organization, do you have a distinct network engineering and network planning groups?

Question 35 : To what level of contingency do you plan your network?

Survey Questions taken from 2012 survey results - Planning

Question 3.2 : To what level of contingency do you plan your network?

Question 3.19 : Do you perform contingency analysis; that is, review loading and voltage with each feeder out of service? Do you perform contingency analysis; that is, review loading and voltage with each feeder out of service?

Survey Questions taken from 2009 survey results - Planning

Question 3.3 : To what level of contingency do you plan your network? (This question is 3.2 in the 2012 survey)

7.6 - Distributed Generation

7.6.1 - AEP - Ohio

Planning

Distributed Generation

(Distributed Cogeneration on the Network)

People

Network planning, including modeling and analyzing the requests to apply distributed generation to the network, is performed by the AEP Ohio Network Engineering group in tight collaboration with its parent company. The company employs two Principal Engineers and one Associate Engineer to perform network design at AEP Ohio for the Columbus and Canton urban underground networks. These engineers are geographically based in downtown Columbus at its AEP Riverside offices, and are organizationally part of the parent company. Columbus-based Network Engineers collaborate closely with the AEP Distribution Services organizations and the Network Engineering Supervisor. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning ultimately reports to the AEP Vice President of Customer Services, Marketing and Distribution Services.

Process

Requests for distributed generation at network locations are studied and evaluated on a case by case basis. There has been little or no demand for distributed generation within the Columbus and Canton networks, aside from an occasional use of solar panels to chop peak demand for certain customers. At this point no network customers are feeding excess generation into the AEP Ohio system.

For its network, the unofficial policy of AEP Ohio is to not import power from customers onto the network, as the current network design would not tolerate incoming current. DG feeding into the grid could cause protectors to open on low load or on backflow, affecting grid reliability. At the time of the EPRI practices immersion, AEP Ohio had not yet developed a formal policy for adding distributed generation on any of its network systems.

The company is working on preliminary studies to incorporate distributed generation on the network. After engineering and feasibility studies, small pilot or test implementations may be deployed at carefully controlled network stations.

7.6.2 - Ameren Missouri

Planning

Distributed Generation

People

System protection for both the network and non – network infrastructure serving Ameren Missouri, including system protection implications of distributed generation (DG) to the system, is performed by engineers within the System Protection Group. This group is part of Substation and Relay Maintenance, a group within Energy Delivery Technical Services at Ameren Missouri. This group provides system protection for the entire company, including power plant protection, transmission and distribution.

The System Protection Group, led by a Supervising Engineer, is comprised of 4-year degreed electrical engineers. System Protection engineers are non-union employees at Ameren Missouri.

While Ameren Missouri has received a significant number of requests to attach solar DG to their system, none of these requests have been in their network. At the time of the EPRI practices immersion, Ameren Missouri had not yet developed a policy for adding DG on the network system.

Process

Customers desiring interconnection to Ameren Missouri’s network system must work with Ameren Missouri to develop custom protection schemes that properly detect and isolate faults, and work harmoniously with the existing Ameren Missouri protection and control schema. These protection schemes can be quite complex, and involve communications between the customer and the company System Protection Group.

The state of Missouri requires Ameren Missouri to connect DG of 100 KW or less to their system. The customer must provide a visible disconnect, and must adhere to all standards associated with inverter devices. Ameren Missouri believes their current network system can absorb small amounts of distributed generation, though they have not received any requests.

Ameren Missouri is more concerned about DG additions to spot networks, as these installations can create potential protection issues, such as tripping protectors on reverse power. These installations may require changes in protector settings such as the addition of a time delay on the instantaneous trips setting. Spot network DG requests require strong communications between the customer and System Protection Group.

Note that Ameren Missouri has not yet developed a formal policy for DG on the network.

7.6.3 - CEI - The Illuminating Company

Planning

Distributed Generation

People

To date, CEI has had no experience with distributed generation requests on its downtown secondary network. However, FirstEnergy, company-wide, has been receiving many inquires (about four per day) about the connection of distributed generation to its system. Their experience is that about one request received in every two week period moves forward.

In response to these requests, FirstEnergy has formed a system wide team led by the corporate Distribution Planning and Protection group to develop the regulatory and technical requirements for an interconnection policy for distributed generation.

Process

FirstEnergy’s stance towards distributed generation is to be as receptive as they can be, while developing a formal policy that describes FirstEnergy policy and defines regulatory, protection and other technical requirements. This policy document, currently under development, will include connection requirements drawings for use by customers.

FirstEnergy desires to make the application process simple for customers, and to make reasonable efforts to accommodate customer requests to interconnect.

7.6.4 - CenterPoint Energy

Planning

Distributed Generation

People

To date, CenterPoint has not had any requests for distributed generation to connect with its 208 V secondary networks. They do have one solar connection to a spot network.

Company-wide, CenterPoint has been receiving inquires about the connection of distributed generation to its system. In response to these requests, CenterPoint has a group that focuses on interconnection requests that come into the company. These interconnection requests are addressed on a case by case basis.

Process

The CenterPoint interconnection group receives the request to interconnect and processes the application for connection to assure that the potential generator complies with the terms of both the CenterPoint interconnection agreement and PUC interconnection agreement. All requests for connection to underground distribution facilities are sent to the Major Underground Engineering Technical Group, who assists the DG group in designing enhancements to the protective scheme to accommodate the interconnection.

Note that from a planning perspective, CenterPoint treats distributed generators as non-firm generation.

7.6.5 - Duke Energy Florida

Planning

Distribution Generation

People

Requests for installing distribution generation on the Duke Energy Florida system are managed by the PQR&I Distribution Protection Automation and Control group.

Duke Energy Florida does have written guidelines for responding to customer requests to install distributed generation, but these guidelines do not specifically address requests for installing in a network location.

Process

At the time of the immersion, Duke Energy Florida had not received any requests for DG on their low voltage meshed system or on their spots.

7.6.6 - Duke Energy Ohio

Planning

Distributed Generation

People

Duke Energy has a System Protection group that performs protective device coordination on the network. One engineer within the group has become the distributed generation (DG) expert for Duke Energy Ohio, and responds to DG requests and establishes the appropriate system protection schema. This individual has also been instrumental in establishing DG policy and interconnection agreements.

The DG Engineer is currently training a second engineer to respond to distributed generation requests.

The DG Engineer works closely with the Network Engineer on DG issues within the network. This work includes sizing fuses and establishing settings for network protector relays in special situations. (Note that most network protector locations utilize standard relay settings.)

Process

At the time of the EPRI Immersion, the Duke Energy Ohio network system had one location (a 480V spot) where Duke had made changes to the electronic relaying settings at a network protector because of a distributed generation customer (backup generation application). At this location the customer can self generate but does not feed back into the Duke Energy Ohio system.

The DG Engineer decided on changes to the relaying of the network protector at this location – adding a little longer delay, so that the NP’s can ride through a small back feed, allowing the customer to close back into Duke’s system without an interruption.

7.6.7 - Energex

Planning

Distributed Generation

People

Distributed generation is subsidized by the Australian government through the AEMC. Consequently, Energex has experience significant growth in the number of residential and commercial customers who have adopted the use of the cogeneration, both in the CBD and outlying areas.

Process

As an example, Energex has experienced an exponential growth in the use of roof top photovoltaic (PV) systems by its customers as a result of government-subsidized rebates on solar panels, and a favorable rate to customers for selling power back into the grid. (The generated power is used by the customer, and customers can also sell excess power back into the grid.)

Technology

Energex has over 700 MW of PV connected (of a total load of about 3000 MW), a relatively high penetration of distributed PV. Energex’s penetration of solar jumped from 1000 PV systems to 200,000 systems based on a subsidy (rebate by the government for individual roof top solar panels) over the last four to five years. The company has experienced rapid expansion of PV, connecting approximately 3000 kW per month.

Energex noted that the addition of rooftop solar generation has introduced multiple technical challenges, including additional complexity in distribution planning, and a significant increase in power quality complaints (See Rapid Response).

One concern at Energex is the potential for an increase in customer installations of micro-turbines given the declining cost of natural gas (as a fuel). The utility needs to make certain customers are not overloading its systems with surplus energy and causing system instabilities. Until the utility has a way to reliably accommodate turbine-generated co-distribution, it is asking customers to forestall turbine installation. One technology Energex is examining closely is advancements in premises-based batteries, which would help solve system overloads and provide real benefit to both turbine users and its growing base of PV customers.

7.6.8 - ESB Networks

Planning

Distributed Generation

(Distributed Cogeneration on the Network)

People

Cogeneration planning on the network, particularly wind farm intermittent power generation, is performed by planning engineers within the Network Investment groups – one responsible for planning network investments in the North, and the other for planning in the South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists,” who have developed their expertise through field experience.

Planning standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

ESB Networks currently distributes 2 GW in Ireland through wind farms. The generation is available about 100 days per year. The goal of ESB Networks is to provide 20 percent of its available energy from these wind farms by 2020, conforming with a government renewable energy initiative requiring 20% of energy from renewables by 2020.

ESB Networks facilitates independent power producers (IPPs) but does not encourage or discourage connection. Decisions are solely based on network ability. The licensee buys and builds the site and can operate a network of wind generators. In preparation for any new installations, ESB Networks holds kick-off meetings with the licensee(s) for the purpose of providing technical expertise, technical protection issues, and safety associated with wind farm construction and operation. In certain situations, ESB Networks prefers that these farms are in proximity to its existing 110-kV stations, and the licensee can build the network up to the ESB Networks 110-kV node.

Because wind and thus wind generation output tends to peak at night when ESB Networks doesn’t have the demand for this generation, they are dealing with some resultant operational issues, such as stability issues, and high voltages on the medium voltage system.

Technology

Specifications for wind farm construction for owners/operators can be found online via the web. Wind farms purchase materials from an ESB Networks-approved list posted online, which is updated on a regular basis.

7.6.9 - Georgia Power

Planning

Distributed Generation

(Distributed Cogeneration on the Network)

People

Network planning, including modeling and analyzing the use of distributed generation, is performed by the engineering group within the Network Underground organization within Georgia Power. The Underground group, led by the Network Underground Manager, consists of both engineering and construction resources responsible for the network underground infrastructure at Georgia Power. The Engineering group, led by the Network Underground Engineering Manager, is comprised of Engineers and Technicians concerned with the planning, design, and any service issues. The engineers are four-year degree positions.

The Network Underground group also works closely with Area Planning Engineers. Organizationally, Area Planners sit outside the network Underground group, but have a dotted line reporting to engineers within the Network Underground group. Area Planners have a combination of years of experience and formal education, including two-year and four-year degrees. All are non-union employees.

Process

Requests for distributed generation at spot network locations are studies and evaluated on a case by case basis.

For the network, it is Georgia Power’s unofficial policy to not import power from customers onto the network secondary grid, although they suspect some will or do. The primary concern is that importing energy on the secondary might affect protector performance and/or reliability. For example, the Georgia Power secondary grid is lightly loaded, and DG feeding into the grid could cause protectors to open on low load or on backflow, affecting secondary grid reliability. At the time of the EPRI practices immersion, Georgia Power had not yet developed a formal policy for adding distributed generation on any of its network systems.

7.6.10 - HECO - The Hawaiian Electric Company

Planning

Distributed Generation

People

To date, HECO has little distributed generation connected to their system. When they do get requests to interconnect, their practice has been to hire a consultant to perform the interconnection study.

Process

HECO has had little experience with distributed generators requesting interconnection to their distribution system. Most of the interconnection requests they have had historically have been on their transmission system. They do have some small PV generators on their distribution, but these do not export to the grid.

HECO has developed performance standards, and power purchase agreement standard forms for interconnection requests, but these were developed primarily for transmission interconnections. These forms must be updated to accommodate distribution system requests.

To date, HECO has had no requests to connect DG to their network system.

7.6.11 - National Grid

Planning

Distributed Generation

People

National Grid has a Distribution Generation Services group that handles requests for interconnection to the distribution system, including the network. At the time of the writing of this report, National Grid was in the process of updating their procedures for interconnection of distributed generation to the distribution system.

In general, if the interconnection requests are small, the Distribution Generation Services group will respond directly to the customer. For larger requests, the distribution generation services group may engage the services of field engineers within Distribution Planning to perform impact studies. For these larger interconnection requests, an engineering team may be formed comprised of field engineers, distribution planning engineers, generation services personnel, and protection engineering personnel.

Requests to connect to the network involve analysis by field engineers to understand the potential requirements for safety equipment, protective relaying, metering and telemetry. This analysis includes determining the maximum allowed generator capacity on the network to avoid negative impacts, such as reverse power flows.

Process

National Grid’s documented interconnection procedure recognizes that interconnection to secondary network grids or secondary spot networks is an emerging topic which “(i) poses some issues for the Company, (ii) is not yet supported by any national engineering standard or practice, (iii) requires additional time for engineering analysis, and (iv) has the potential to cause the power flow on network feeders to shift (reverse) causing network protectors within the network grid to trip open”.

To ensure network safety and reliability, National Grid has not historically allowed synchronous and induction generators to interconnect to network systems. Inverter-based generators may be allowed on a case-by-case basis at the discretion of the company. The results of this analysis may allow interconnections with restrictions to avoid negative impacts on the secondary network system such as limited DG output relative to facility load, reverse power control measures, and transfer trip schemes.

7.6.12 - PG&E

Planning

Distributed Generation

People

PG&E has an Interconnection Services group that deals with issues associated with the connection of DG to the PG&E system. This group has well documented procedures and guidelines for interconnection of both rotating machine and inverter based generation to the PG&E system, including the network.

Interconnection services works closely with the network engineers within the Reliability and Planning group on DG issues within the network. This work includes sizing fuses and establishing settings for network protector relays in special situations.

Process

Customers who desire to interconnect to PG&E’s network system must work with PG&E to develop custom protection schemes that properly detect and isolate faults, and work harmoniously with the existing PG&E protection and control schema. These protection schema can be quite complex, and involve communications between the customer and company protection.

For example, for connection of new distributed generation to PG&E’s secondary spot network, the following requirements must be met ^[1] :

All of the network protectors on the Secondary Spot Network shall be replaced with Cutler Hammer CM52 network protectors equipped with MPCV relays.
Older style protectors (CM-22, MG-8, and CMD) may remain, provided that the network protector relays are replaced with MPCV relays or other PG&E-approved relays, capable of at least two set points, one with a time delay, and shall meet the following conditions:
- The Generator(s) plus the associated bus and/or cable to the main switch has a transient and sub-transient X/R ratio of nine (9) or less for all operating scenarios;
- Synchronization of each generator shall be supervised by a PG&E-approved Sync Check relay;
- In non-fault conditions, the generator breaker must operate in 1.5 minutes or less;
- Breakers separating all generation must open immediately without any intentional time delay under system fault conditions
Division’s Planning Engineer shall review network protector relays on the adjacent lines for relay coordination. If relay coordination’s are inadequate, the old relays must be replaced.
DG Producer will provide all necessary technical requirements as specified in Rule 21, including the protective device settings and frequency/voltage settings.
DG Producer will meet the minimum import requirements set forth below:
- The DG may not operate parallel operation unless a minimum number of network protectors are closed. The DG must trip instantaneously when the number of closed network protectors falls below the following the value [select appropriate value from this table]:


Quantity of Network Protectors in Vault	Minimum Number of Closed Protectors Required in Order for DG to Operate
2	2
3	2
4	2
5	3

When the number of closed protectors drops to 50% or lower then the generator must instantaneously trip.

A minimum import setting of ten percent (10%) of the nameplate rating of the largest single network transformer serving the PG&E secondary spot network bus where the DG is installed. Minimum import protection to be accomplished using a redundant PG&E-approved underpower (Device 37) relay or reversed power flow relay (Device 32). A meter with kVA summation of multiple services from the spot network bus is allowed on the common spot network bus through one or more Generators. If PG&E’s meters do not support summation and protection requirements, DG Producer shall be responsible for the cost of providing meters capable of supporting summation. If the minimum import is not met, the Generator(s) must trip within 15 cycles to ensure that the Generator(s) trip prior to the network protectors. Redundant protection of the net import minimum power must be provided.
A contact must be available on the existing network protectors to provide open/close status to the DG Producer’s trip devices via a GE C-30 controller or PG&E approved controller. The cost for controller along with the installation and operating and maintenance costs of the relay/controller will be borne by the DG Producer. The DG Producer shall install and terminate rigid grounded 2-inch conduit, and a pair of wires from the trip device to inside the transformer vault. The location of conduit core shall be reviewed and approved by PG&E.
DG Producer will provide 24VDC source from their battery with charging system for GE C-30 controller or PG&E approved controller.
PG&E will do the installation of GE C-30 relay/controller or PG&E approved controller in the property owner’s transformer vault. See attached schematic.

For example, normally set network protector relays are set to open on reverse current. Thus, a standard relay set cannot be used with distributed generation. The schema must include a feedback system from the customer’s generation to understand the generator output, and be able to change the control of the protector to account for the generation. In a fault, the SCADA system must be able to detect the fault and then send a signal to the protector to open so that it doesn’t enable the generator to reverse feed back into the fault.

Each situation must be addressed individually.

^[1] Excerpted from PG&E Electric T&D Capacity, Reliability, UG Asset Bulletin, Bulletin Number: 2004PGM-10, dated 11/01/2004.

7.6.13 - Portland General Electric

Planning

Distributed Generation

People

On the network, the Net Metering group and the Interconnection group oversee requests for distributed generation (DG). A Key Customer Manager (KCM) may refer customers wishing to install DG. PGE has nine KCMs reporting to the Manager of the Business Group. Generally, they are geographically distributed, and one KCM oversees network customers. Distribution Engineering and the System Protection Group handle particularly complicated requests and assess the technical requirements and difficulties.

Process

Like most utilities, PGE is experiencing an increasing number of requests to add DG to its system, including the network. For larger systems of over 50 kW, PGE may allow installations on the radial system. For the network, PGE limits customer -owned generations to less than 50 kW. Oregon statutes allow DG of up to 5% of the maximum load on spot networks. If a customer served by a spot network wants to install solar panels, for example, the KCM contacts PGE’s Interconnection Group.

PGE has a Net Metering Department, but requests for larger generation facilities are passed on to the Engineering Group. For example, in a case where a government entity wanted to add a solar array on top of a building, Distribution Engineering and System Protection worked out what was possible.

PGE is presently drafting an interconnection guideline that would cover the area network and specify how to accommodate DG on a network system. This is subject to the current Oregon statute, which stipulates that systems cannot exceed 10% of the off-peak minimum loading. Once this 10% is exceeded, no additional solar generation can be added.

The Oregon PUC sets Oregon’s interconnection standards for DG, which are based upon the Mid-Atlantic Distributed Resources Initiative (MADRI) standard. The PUC has developed interconnection procedures and application processes for non-net metered systems up to 10 MW and for systems of more than 20 MW. The latter is based on Federal Energy Regulatory Commission (FERC) regulations. At present, there are no standard processes for installations between 10 MW and 20 MW [1].

Distribution Resource Plan (DRP): PGE’s DRP identifies how and where DG can improve service and reliability within the context of a wider drive to incorporate renewable energy. PGE has undertaken a process of identifying any constraints on the system, by assessing the hosting capacity for each feeder and estimating how much DG can be installed safely.

Due to the lack of useful data across the electric distribution industry, PGE will continue long-term studies and pilots into DG at a feeder level^[2]. In terms of standards:

Customer generators must install and maintain a net metering facility complying with IEEE standards
Customer generators must maintain and install a manual disconnect switch that is accessible to utility workers
For facilities of lower than 600 volts, manual disconnects may not be required if an inverter of appropriate size is installed^[3]

Technology

PSSE and CYMDIST support the modeling of, and effects of, DG on a system.

P. Scheaffer. Interconnection of Distributed Generation to Utility Systems: Recommendations for Technical Requirements, Procedures and Agreements, and Emerging Issues. The Regulatory Assistance Project, Montpelier, VT: 2011. http://www.raponline.org/wp-content/uploads/2016/05/rap-sheaffer-interconnectionofdistributedgeneration-2011-09.pdf (accessed November 28, 2017).
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).
Oregon Public Utilities Commission, 2008, The Oregon Administrative Rules contain OARs filed through October 15, 2008,

7.6.14 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.14 - Closed Transition Switching and Distributed Generation

7.6.15 - Survey Results

Survey Results

Planning

Distributed Generation

Survey Questions taken from 2012 survey results - Distributed Generation

Question 9.1 : Do you allow inverter based generation to connect to the 208Y/120-volt area network?

Question 9.2 : If yes, What is the maximum allowed size for the inverter based generation at any given service?

Question 9.3 : Do you allow the inverter based generation to feed real power back into the secondary of the area network under unfaulted conditions?

Question 9.4 : Do you place any limits on the total amount of inverter based generation that can be connected to any given area network? If so, how is that defined?

Question 9.5 : Do you allow induction generators to connect to the 208Y/120-volt area network?

Question 9.6 : If yes, What is the maximum allowed size for the induction generation at any given service?

Question 9.7 : Do you allow the induction generator to feed real power back into the secondary of the area network under unfaulted conditions?

Question 9.8 : Do you place any limits on the total amount of induction generation that can be connected to any given area network? If so, how is that defined?

Question 9.9 : Do you allow synchronous generators to connect to the 208Y/120-volt area network?

Question 9.10 : If you do allow distributed generators to connect to your network, do you have a written guideline that defines the interconnection requirements?

Question 9.11 : Do you allow time delay tripping of network protectors that are supplying 208Y/120-volt area networks?

Question 9.12 : Are there any administrative codes, rules, regulations, etc established by Public Utility Commissions, Boards of Public Utilities, etc. that cover the connection of co generation to area networks in your service territory?

Survey Questions taken from 2009 survey results - Distributed Generation

Question 9.1 : Do you allow inverter based generation to connect to the 208Y/120-volt area network?

Question 9.2 : Do you allow induction generators to connect to the 208Y/120-volt area network? (This question is 9.5 in the 2012 survey)

Question 9.3 : Do you allow synchronous generators to connect to the 208Y/120-volt area network? (This question is 9.9 in the 2012 survey)

Question 9.4 : If you do allow distributed generators to connect to your network, do you have a written guideline that defines the interconnection requirements? (This question is 9.10 in the 2012 survey)

Question 9.5 : Do you allow time delay tripping of network protectors that are supplying 208Y/120-volt area networks? (This question is 9.11 in the 2012 survey)

Question 9.6 : Are there any administrative codes, rules, regulations, etc established by Public Utility Commissions, Boards of Public Utilities, etc. that cover the connection of co generation to area networks in your service territory? (This question is 9.12 in the 2012 survey)

7.7 - Distribution Automation Control in Contingencies

7.7.1 - CenterPoint Energy

Planning

Distribution Automation Control in Contingencies

People

Contingency planning at CenterPoint is performed by the Electric Distribution Planning department (Planning group). This group is not part of the Major Underground group organizationally. One planning resource, an Engineering Specialist, is assigned full time to work in Major Underground, in a matrix arrangement.

Technology

CenterPoint’s normal design configuration provides adequate capacity to carry load in a single contingency. For situations where a substation transformer is highly loaded, CenterPoint has implemented programming at certain stations^[1] that will swap loads to alternate sources in the case of the loss of a substation transformer, helping them to defer the investment to increase transformer capacity. This programming moves loads among transformers within a station and from station to station to provide service continuity in a contingency situation during peak periods by optimizing the distribution of load among transformers. The programming uses two systems developed by CenterPoint.

The first, called “Smart Cascade”, uses a substation standard relay scheme, and swaps loading between substation transformers within a station in an alternate configuration by open and closing selected bus breakers. With Smart Cascade active, if one transformer in a three transformer substation is out of service, feeders that are normally fed by that transformer will be rolled to selected bus sections to optimize the transformer loading. These selected bus sections may be different than the normal default in a contingency without Smart Cascade activated.

The second, called the “Distribution Automated Control System (DACS)”, swaps load between stations using radio controlled (900 MH) automated switches located on the distribution system. With DACS active, a feeder or feeder section may be rolled to an alternate substation in a contingency situation to relieve the loading on its normally fed substation transformer.

Note that the Smart Cascade and DACs systems are not active at all times. These systems are automatically “armed” when substation transformer loading moves to 95% of nameplate. At 85% loading, the system sends alarms / pages notifying selected CenterPoint personnel of the high loading. During lower load periods, Smart Cascade and DACS are not active, as CenterPoint’s normal substation and feeder configuration can carry the load adequately in a contingency.

The implementation of this system has enabled CenterPoint to defer the installation of additional substation transformers. Planning engineers can load the transformers a little higher in a normal configuration, because they have the ability to quickly shift some load elsewhere in a contingency.

See System Protection - Technology

See Contingency Planning - Process

^[1] Note that the technologies described in this section are not used in substations with dedicated underground circuits.

7.8 - Intermittent Supply Forecasting

7.8.1 - Energex

Planning

Intermittent Supply Forecasting

Process

Energex has a photovoltaic monitoring research project underway focused on gathering data to be able to better forecast power supplied by intermittent solar panel supplies, to determine battery storage requirements.

The project is focused on approximately 150 solar panel-equipped customers. The monitoring system is bringing back “one minute” data from the grid. So far Energex has amassed six terabytes of information for its study. The project includes the allocation of batteries for storage at the pilot sites, and will include battery monitoring.

Working with researchers, the Energex team is attempting to come up with network forecasting of intermittent supply, which is quite useful for battery storage.

Technology

The team is investigating a system that integrates solar panels with an intelligent inverter and a battery. By remote control, Energex could send parameters to the device for demand management and voltage management for the utility, and the customer could receive information and capability to change parameters to minimize his bill.

7.9 - Load Forecasting

7.9.1 - AEP - Ohio

Planning

Load Forecasting

People

Load forecasting is performed by the AEP Network Engineering, which is organizationally part of the AEP parent company. Network Engineering includes two Principal Engineers and one Associate Engineer who perform network planning and engineering activities, including load forecasting for the Columbus and Canton urban underground networks of AEP Ohio. These engineers are geographically based in downtown Columbus at its AEP Riverside offices. Columbus-based Network Engineers perform load forecasting working in collaboration with AEP Distribution and the Network Engineering Supervisor. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the AEP Vice President of Customer Services, Marketing and Distribution Services through the Director of Engineering Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues.

Process

AEP Distribution (part of the parent company) uses CYME and its SNA (secondary grid network analysis) module for initial network load analysis for the AEP Ohio group. Load forecasting is then made by AEP Ohio in Columbus and Canton based on both CYME SNA data from AEP Distribution and local peak load analysis. Local peaks are created from collected monthly meter records in its service area. From these records, engineers use algorithms to calculate total kilowatts (demand) from captured kilowatt-hour meter data, and then identify peak loads. Each engineer in the planning process reviews this load information regularly for any increased loads and adjusts the load flow accordingly. Engineers also have access to larger customer load information in the downtown area. For timelier and even more accurate load information, the AEP Ohio Network Engineering group is considering the use of smart meters in the downtown Columbus area for assistance in load analysis and forecasting.

A separate system, maintained by the AEP Distribution Systems Planning group, provides the local Network Engineering group with timely information on the larger loads coming into the AEP Ohio network underground area. There is distribution planning engineer within this group responsible for updating this system with forecasts for all circuits.

The AEP planning group can provide the Network Engineering group load forecasts for all circuits. Using this data on circuits, the local load information calculated from captured meter data, and forecasted growth rates for network feeders, the Network Engineering group can then provide ten-year network forecasts for its Columbus and Canton systems.

The planning process involves running load flow analyses to compare anticipated system loading to the feeder ratings and to identify thermal and voltage violations to the planning criteria in both normal and contingency situations.

Technology

AEP Distribution provides load flow analysis and other secondary network analysis data to the AEP Ohio Network Engineering group from its CYME® Secondary Grid Network Analysis (SNA) software system (seeFigure 1). The AEP Ohio Network Engineering group also uses kWh data captured through automated meters and uses sophisticated algorithms to convert this data to identify peak loads on the network. With this captured data and the CYME analysis from AEP Distribution, AEP Ohio Network Engineers have a solid basis for Load Forecasting.

Figure 1: CYME SNA load flow analysis software used by AEP Distribution to aid in load forecasting for AEP Ohio

7.9.2 - Ameren Missouri

Planning

Load Forecasting

People

Planning engineers within the Underground Division Engineering group are responsible for distribution planning, including feeder load forecasting for the network systems.

The Engineering group within the Underground Division, led by a Supervising Engineer, is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues. The engineering positions are four-year degreed positions. Energy Services Consultants have a combination of years of experience and formal education, including two year and four year degrees. The engineers are nonunion employees; the Estimators are in the union.

Process

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading.

This forecasted loading is based on a number of factors. Engineers will consider known projects that will add load to the system, estimated future load additions from vacant lots to be developed, and general growth rates. Engineers project five years into the future when performing load forecasting.

Engineers will temperature adjust their load forecasts based on an algorithm developed by corporate engineering that considers the probability of exceeding a given temperature based on historic weather experience.

The planning engineers gather system peak information from information recorded by SCADA. Ameren Missouri has remote monitoring of all network feeders as well as the ability to monitor loading on all network units through a remote monitoring system installed in their network.

Technology

Ameren Missouri uses the DEW load flow product to model their network system. For networks, this model is manually populated and maintained by the planning engineers. The model includes a graphic representation of the primary, secondary, and network unit. For example, when modeling the feeder out of service, DEW will model all the protectors opening. Note that at the time of the practices immersion, Ameren Missouri had assembled a list of desired enhancements to the DEW product.

For radial circuits, DEW imports information and attributes from Ameren Missouri’s GIS system, and imports load information from a transformer load management (TLM) system.

7.9.3 - CEI - The Illuminating Company

Planning

Load Forecasting

People

CEI Load Forecasting is performed by the Planning and Protection Section of the Engineering Services Department (CEI Planning Group). The group is part of the CEI Engineering Services department, and is led by a supervisor who reports to the Engineering Manager. The group is responsible for all distribution planning and protection, from 36kV and below. The CEI Planning Group is comprised of 4 Planners and 3 Protection Engineers. All members of the group are four year degreed engineers. The Planning Supervisor noted that he prefers candidates for the CEI Planning Group to have their Professional Engineer (PE) license.

The Regional Planning and Protection group is supported by a corporate Planning and Protection group. This group, the Corporate Planning and Protection group, has recently issued an updated Distribution System Planning Criteria document that defines the load forecasting process.

Process

Note: Because the network is so lightly loaded, CEI is not performing load forecasting on network feeders. However, much of the urban load in Cleveland is being served by non network feeders that are annually reviewed for loading.

A load forecast is calculated annually for each distribution substation power transformer and circuit exit. The forecast is calculated by reviewing historic peak loading recorded from substation inspection and SCADA information. This information and overall growth factors are entered into a system called Load Forecasting and Data Management System (LFDMS) to create historic peak load patterns for each transformer and circuit exit. CEI weather adjusts these peaks to normalize them from “abnormal” weather conditions to “normal” weather conditions using an 80 / 20 probability adjustment that assumes that 80% of summers were cooler than the peak, and 20% were hotter based on a calculation of the cumulative cooling degree days for the peak days. The process for performing this calculation is detailed in their Distribution System Planning Criteria document.

Technology

CEI is using a system called Load Forecasting and Data Management System (LFDMS) to record forecasting information and to create historic peak load patterns for each transformer and circuit exit.

Ultimately, FirstEnergy would like to be able to import information into LFDMS directly from CYME.

7.9.4 - CenterPoint Energy

Planning

Load Forecasting

People

Distribution load forecasting at CenterPoint is performed by the Electric Distribution Planning department (Planning group). The load forecasting process is documented - see Attachment A

The Distribution Planning group is comprised of 21 total resources, including 2 Lead Engineers. Each of the Lead engineers has about 6 -8 people reporting to them. These folks are either 4 year degreed engineers, or technical experts. CenterPoint aims to have a balance between Engineers and Technicians.

In addition the Planning group has a lead engineer specialist, who leads a computer support group comprised of 6 resources. These folks work with systems such as CymE, Microstation, LD Pro, etc.

Note that one planning resource, an Engineering Specialist, is assigned full time to work in Major Underground, in a matrix arrangement.

CenterPoint encourages its engineers to obtain their PE license. The PE license is required to become a Senior Engineer at CenterPoint.

Process

CenterPoint develops load forecasts for distribution planning purposes. These load forecasts account for uncertainty by using conservative assumptions including:

The forecast assumes a 102 F degree peak day temperature (CenterPoint system peaks usually occur in August.)
The forecast assumes any MW reduction from energy efficiency plans will be small and scattered
Other assumptions as defined in The Distribution and Transmission Planning Load Forecast Process document ( See Attachment A). Distribution Planning acquires new load inputs on a continuous basis throughout the year from area Service Centers for residential and small commercial customers and from the Key Accounts group for large distribution customers. The projected new loads may be adjusted based on historical trends or based on knowledge of the load profiles of similar customers. The projected new loads are then totaled by substation and input into a spreadsheet by year.

A growth factor is added to each substation area based on historical trends (CenterPoint has 49 years of loading history). Typically, this growth factor ranges from 0% in low growth areas to 7% in high growth areas. Planners may subtract anticipated load loss due to interconnections or energy efficiency programs.

The previous year’s actual summer peak loads for each substation are input into the spreadsheet and are added to the new projected loads to develop the load forecast for the next year by substation. The distribution load forecast is typically finalized in the fourth quarter of the year.

Once the load forecast is developed for a station, planners would then determine whether or not they need to address the substation capacity or the circuit capacity. In these cases a Planning engineer could perform an area study to optimize the distribution of loads between stations.

The Planning group annually revises the five year load forecast based on known and anticipated load projections.

See Load Relief - Process

Technology

CenterPoint is using spreadsheets and CymE load flow software to perform analysis.

7.9.5 - Con Edison - Consolidated Edison

Planning

Load Forecasting

Process

Load Forecasting — Ten-Year Electric Peak Load Forecast Description

Annually, the service area electric peak load forecast is developed for each of the major sectors of the economy, which includes commercial, residential, and governmental. The forecast predicts the maximum summer electric peak demand for the system.

The commercial forecast reflects three generic variables for the short- and long-term outlook: business conditions, economic conditions, and energy prices. The commercial forecast also reflects the impact of short-range construction activities within Con Edison’s service territory. The commercial sector accounts for approximately half of Con Edison’s^[1] peak load.

The residential forecast is based on projections of the number of households, number of appliances, household occupancy, and coincident use of appliances. Air conditioning load is the most important contributor to the residential load. The residential sector accounts for about one-third of the Con Edison’s^[2] peak load.

The governmental load is derived using information by customer class based on new business activities.

Key Drivers of the Electric Peak Load Forecast

Known Construction Projects - Known new projects predominantly include business activities such as planned construction projects or construction already under way. Projects are tracked to capture the effect on the electric peak load.
Economy - The economic factors used in the forecasting process are the New York City private nonmanufacturing employment metric and the U.S. Gross Domestic Product (GDP). Private nonmanufacturing employment includes all employment except government and manufacturing. GDP is the broadest measure of the economy’s health.
- The economic outlook that underlies Con Edison’s forecast recognizes the service area’s place in the world economy. The forecast assumes that New York City will continue to compete for national and international business throughout the forecast period with the same degree of success that it has had in recent decades.
Consumer Behavior - Consumer response to hot weather through air conditioning usage is the main driver of the residential peak load on a hot summer afternoon. Since air conditioning load makes up 75% of the residential peak load, Con Edison captures information on air conditioning usage and number of units through various surveys.
Technology - Improvements in equipment efficiency are captured for major appliances, such as air conditioners and refrigerators. These improvements are reflected in the electric peak load forecast.
Government Large infrastructure projects undertaken by the city, state, or federal governments are included in the peak load forecast.

Temperature Variable (TV) Used in Load Forecasting

What It Is

The temperature variable (TV) is a reference point that Con Edison uses in designing their electric transmission and distribution systems. The TV is used in calculating and forecasting future system loads, taking into account extreme summer weather conditions — sustained high temperatures and humidity over a three-day period — that they would expect to see in the metropolitan New York area in one of every three years.

What It Isn’t

As a reference point, the TV factor is a starting point for preparing for the effects of weather on electric loads, similar to the way in which building codes are starting points for designing and equipping homes and office buildings. It does NOT attempt to calculate or design for the worst weather Con Edison would expect to see in their region, nor does it serve as an “upper limit” design criterion for electric system components. Because Con Edison designs and builds the components of their transmission and distribution systems with significant “margin,” or conservatism, these systems have a great deal of aggregate resiliency. This means that the systems, including the distribution networks, can generally handle temperatures and consequent loads higher than those factored into the TV.

How It’s Calculated

The reference TV for Con Edison’s service area is a factor of 86° using Central Park weather. For Orange & Rockland Utilities (O&R), it is 85° using White Plains weather. In more easily understood terms, a TV factor of 86° is equivalent to a temperature and humidity Heat Index of 105° — an extremely high level at which the National Weather Service advises taking precautions against sunstroke, heat cramps, and heat exhaustion.

Specifically, the summer TV factor is calculated as a weighted average of the highest three-hour temperature (called dry-bulb) and humidity (called wet-bulb) readings each day between 9 AM and 9 PM. (Please note, dry-bulb temperature is the one familiar to most people, being the value used in all media weather pronouncements.) This temperature and humidity data helps determine the discomfort level of Con Edison’s customers, and their associated use of air conditioning.

Since heat “buildup” over a hot spell of a few days’ duration significantly increases air conditioning use and stress on Con Edison’s electric system, the formula for calculating the system TV on a daily basis incorporates three days’ worth of data. The current day’s weather is weighted at 70%, the previous day’s at 20%, and two days before at 10%. A factor of 86° for Con Edison equates to a condition that generally occurs in one of every three years.

How It Has Fared Through History

The TV reference factor has been in use as a planning tool for many years in Con Edison. A Con Edison review of data going back to 1953, when they started keeping relevant records, indicates that the TV factor of 86° or above is achieved approximately in one of every three years.

How Con Edison Compares to the Industry and the Region

Using a TV factor as a reference point is a standard planning practice throughout the utility industry. In fact, Con Edison is more conservative than most. They design to a standard that assumes “worse” and more prolonged weather than many other utilities, government agencies, and regional power pools.

Ten-Year Area Substation and Sub-transmission Feeder Load Relief Programs

Area substation transformer ratings (including breakers, bus, etc.) are calculated by Substation Equipment and Field Engineering. Transmission and Sub-transmission feeder ratings are calculated by Transmission Feeders Engineering.

Area substation transformer ratings and sub-transmission feeder ratings are calculated using appropriate first or second contingency ratings, and the capabilities of the area substations and sub-transmission feeders and load pockets are derived.

This data is then dovetailed with the ten-year independent load forecast, and the area substation load and capability tables are developed. Options are identified for needed load relief, including increased capability, transfer of load and/or peak demand reduction by DSM.

Through an iterative process with regional distribution engineering, the recommended load relief plan is developed and published as the substations and sub-transmission feeder load relief program. This program is a major feed into the five-year capital budget plan.

Technology

Load Flow System – Poly-Voltage Load Flow (PVL)

Con Edison utilizes a distribution load flow application called Poly-Voltage Load Flow (PVL). The PVL application is actually a suite of applications that was developed in house over a 20-year period of continued development. In addition to aiding engineers in performing load flow analyses, the PVL system is used to build feeder and transformer models, develop network transformer ratings, develop network feeder and cable section ratings, model area substation outages, and identify short-circuit duty at customers sites, etc.

To perform load flows, circuit models are brought into PVL from the mapping systems. The secondary system is kept in one mapping (GIS) system (different from location to location), and the primary feeders are kept in another mapping (GIS) system. Con Edison reflects all system changes on its mapping systems. Feeder maps within Manhattan are updated in 24 hours as changes occur. Secondary side maps are not updated as quickly, but are very frequently updated. These GIS systems are maintained by the mapping organization.

When the circuit information is brought into PVL, the new information overlays the existing circuit model already in the system. Once the model is brought into PVL, all users use the same model. When a circuit is brought into PVL, people responsible for model maintenance ensure that the PVL model has electrical connectivity and is in synch with the mapping system.

Load flows are conducted for a variety of reasons.

Planning engineers run base case load flows, N-1 cases, and N-2 cases. For each contingency, the PVL output tells you what is overloaded in tabular and graphical formats.
Planning engineers use PVL to assist in short-range and long-range planning. For example, the system is used to analyze conceptual projects to split existing networks into smaller networks
For new business, engineers run the existing case, and then re-run it with the new business load added to understand the loading and voltage implication of the new load.
Region Engineering runs feeder loading studies in advance of the summer to identify anticipated overload conditions.
The system is also used to understand the loading implications of different restorations scenarios in an outage.

PVL can use real-time readings from transformer vaults (gathered through Con Edison’s Network Remote Monitoring System [RMS]) for building the network load model. If needed, demands can be spotted at customer service points, using information such as customer kWh consumption and real-time transformer readings.

The PVL system can also perform cable section ratings. The system considers the impacts of soil type and temperature. The system does not automatically consider the proximity of electrical facilities to steam mains.

Operators are able to take advantage of the functionality of PVL through a real-time version known as AutoWOLF, which takes the base model and applies real-time conditions. For example, real-time transformer loading information would populate the model from RMS system. Knowledge of open feeders would populate the model from SCADA. When a circuit locks out, AutoWOLF automatically runs the system peak case, the current case, and the projected peak case, so that that information is available to an operator. The operator can look at the loading on the other feeders and try to determine which feeders to watch.

During emergency conditions, Con Edison assigns engineers assigned to the control room to monitor system loading. During normal conditions, the operators monitor the system themselves.

Con Edison has formed a PVL users group that meets bi monthly to discuss issues associated with the PVL. The PVL Users group is made up of approximately 50 people from both the regions and corporate, including network model maintenance people, designers, supervisors, engineers, engineering managers, and support personnel. Approximately 15 members attend any one meeting.

7.9.6 - Duke Energy Florida

Planning

Load Forecasting

People

Load forecasting is performed by the Planning Engineers, responsible for capacity planning, and who are organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I). This group is led by a Director of PQR&I for Duke Energy Florida.

Process

Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time focusing on reliability and infrastructure upgrades.

Capacity studies, for both normal and contingency conditions, are triggered by new load additions. When there is a call for any significant new load in the urban underground centers, Network Planners will model the impact of a proposed new load on the network using CYME®, looking at both normal conditions and contingencies. In addition, for large load additions, and for longer-term forecasting, planning will utilize a feeder load allocation program (FLAP). Planners input anticipated annual percent load increase expectations and known spot load additions into this system, and it will return an overall expected load forecast.

Network loading in Clearwater has remained flat. Duke Energy Florida is experiencing moderate load growth in St. Petersburg.

Technology

Network Planners use CYME Power Engineering software to perform load flow calculations on primary feeders.

The FLAP (feeder load allocation program) is used to develop load forecasts. When larger service loads are planned, this system will incorporate the impact of significant anticipated load additions on the overall forecast.

7.9.7 - Duke Energy Ohio

Planning

Load Forecasting

People

Load forecasting is performed by the network planning engineer. The load growth in downtown Cincinnati for the past six years has been flat, according to the planning engineer.

A weather adjustment factor is provided by the Customer Market Analysis group, a corporate group organization that does total system peak load forecasting for Duke Energy Ohio. Recent history shows a flat load growth on the network with and without weather normalization applied.

Process

System peak information is gathered by the Planning Engineer from information recorded through SCADA and stored in an OSI PI Historian.

Duke Energy Ohio has remote monitoring of about 50 to 60% of the substations within Cincinnati, primarily the larger stations. Each month, mobile operators visit all the substations and read and record the loading. (Note that both of the substations that supply the network are visited weekly by mobile operators to perform network protector drop tests.)

Every network feeder has the ability to supply amp readings back to the EMS system. Duke also has remote indication on total network power (megawatts, amps, VARs). All information read by the EMS system is saved in an OSI PI Historian.

The planning engineer has access to EMS data on his desktop. Consequently, he has good information on network loading based on the historical load information housed within the PI server. Note that, by design, the Network engineer within Engineering does not have access to the EMS and must coordinate with the Planning engineer to gather this information. This “check and balance” requires these two engineers to work in partnership to analyze the network system.

The planning engineer forecasts the load by “discrete input.” He takes the known loading and adds in anticipated new loads by feeder, by phase and by transformer.

Information about new loading comes from various sources. The planning engineer often tracks the proposals of new loads coming in. Much of the time, new load information is provided from the engineering department who deals with new customer requests. Sometimes new load information comes in the form of a request for a fault current. At other times, the planning engineer will be involved in an early planning meeting about a potential new load.

Several announced projects to be served from the network indicate the likelihood of increased load in the coming years. Once load growth is confirmed, the planning engineer has the capability to produce a trended load forecast.. The Planning engineer noted that his experience of downtown loads is that they vary less as a function of temperature than do other system loads (suburban and rural).

7.9.8 - Energex

Planning

Load Forecasting

People

Load forecasting is performed by engineers within the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

For planning purposes, Energex develops a load forecast that considers historic loading as a function of temperature and humidity, and forecasts peak loading. For planning, Energex applies a probability that actual weather conditions will exceed those used in the forecast. For normal condition planning, Energex uses a 10 percent probability that forecasted peak conditions will be exceeded (1 in 10 years). For contingency planning purposes, Energex uses a 50 percent probability that during a contingency, those peak loads will be experienced. Forecasts are articulated in the DAPR.

Technology

Energex uses three load flow packages, including one for the transmission side of the business (PSSE), and SINCAL and DINIS on the underground network to simulate the impacts of forecasted summer and winter loads on all Energex feeders.

See Intermittent Supply Forecasting

7.9.9 - ESB Networks

Planning

Load Forecasting

People

Load forecasting at ESB Networks networks is performed by planning engineers within the Network Investment groups – one responsible for planning network investments in the North, and the other for planning in the South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists” who have developed their expertise through field experience.

Planning standards and criteria for load forecasting are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

Planners look at previous peak demands in winter and summer months for forecasting purposes. Load forecasting has been problematic in recent years as ESB Networks has seen a drop in new customers. During the 1990s, relocation of many overseas companies to Ireland saw a rapid increase in demand for power, but that demand has fallen off. Nevertheless, forecasting must be performed to maintain operational efficiency and to inform its five-year asset review process, which is overseen by regulators. Load forecasting is reviewed on a monthly basis. The result of these efforts is a comprehensive five-year asset investment plan for meeting their service level targets.

The ESB Networks underground network has expanded by 100 percent over the last ten years. The organization expects further capacity expansion as wind farm projects, currently underway, come fully online in the near future. As a part of its load forecasting ESB Networks is also taking into account the need for replacing aging assets that would affect the reliability and availability of service in the urban underground.

As a customer quality target, ESB Networks requires customer voltages to remain at +/- 5% of nominal in normal situations, and +/- 10% of nominal in standby (contingency) situations. Load forecasting and system planning criteria also call for long-term cyclical overloads of no more that from 125-150 percent of rating for equipment, with a short-term loading of no more than 150-180 percent.

Technology

ESB Networks maintains yearly peak demand records and cable loading ratings for reference in its planning and GIS software. It uses a home-grown Excel spreadsheet for LV load drop calculations. Special Load Reading data (SLR) is captured bi-annually through ESB Networks’ SCADA network. Demand trends are tracked and reported in monthly meetings.

7.9.10 - Georgia Power

Planning

Load Forecasting

People

Load forecasting is performed by the Area Planner for new projects based on information from the Senior Engineers in the Network Underground division of Georgia Power. Senior Engineers and Area Planners are four-year degreed, non-union personnel. There is considerable communication between Area Planners, Senior Network Underground Engineers, and Georgia Power upper management in forecasting and planning loads in major metro areas served by the utility. Area Planners forecasting loads on the network plan on at least a three-year horizon with historical, engineering data, and marketing project forecasts to aid them.

Process

The planning process involves running load flow analyses to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading.

Network planning is based on a peak load analysis, using the previous summer’s peak (GA Power is normally a summer peaking company), recognizing that the peak is only representative of loading for a few days each year. In developing the load forecast, engineers consider known projects, estimated future load additions from new projects already in the pipe-line, and general growth rates. Engineers may also temperature-adjust their load forecast based on models developed by the engineering staff.

Engineers model the system, and perform analyses to understand anticipated requirements. For network feeders, planning engineers perform contingency studies, modeling networks with each primary feeder out of service to identify areas of needed reinforcement to supply the network in a contingency. Area Planning engineers perform contingency studies (N-1 planning) to assure they can pick up customers with reserve feeders within the emergency ratings of the transformer and cables. More specifically, they model the distribution system with one feeder out of service, simulating customers connecting to reserve feeders. From this analysis, planning engineers determine where reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Area Planners and Senior Engineers target no more than a 90 percent cable and/or transformer load; when either condition is imminent, Area Planners are informed and plans are made to increase capacity. Peak loads that sample highest average loading over a multi-year period are taken into account.

Technology

Georgia Power uses a GIS system, generic models based in CYMDIST, and spreadsheet data to track loads and provide guidance for planning. When loads approach 90 percent capacity, the affected grid is flagged in the system for Area Planners and action is taken to increase the network capacity, off-load to another network, or build another network. It should be noted that Georgia Power is not shrinking its network and is committed to increasing the network footprint where loading and customer demand dictate.

7.9.11 - HECO - The Hawaiian Electric Company

Planning

Load Forecasting

People

HECO Load Forecasting is performed by the Distribution Planning Division. The Distribution Planning Division is part of the System Integration Department. This group performs all distribution planning at 46kV and below.

Process

A load forecast is calculated annually for each distribution substation power transformer and circuit exit. The forecast is calculated by reviewing historic peak loading from the previous year recorded from substation inspections. This peak is combined with projected new loading information gathered provided by the Customer Installations Department (CID) to determine the load forecast.

The weather on O’ahu is fairly predictable from one year to the next. HECO noted that its actual experience of peak loading in a given year is normally fairly close to the forecast. This enables them to utilize the most recent year’s peak as a starting point without applying probabilistic methods to predicting the peak in the coming year. HECO’s peak usually occurs in either August or September.

Because HECO has limited application of SCADA, feeder loading forecasts are developed by apportioning the monitored substation loading over the feeders based on periodic feeder loading measurements called “Tong Tests”. Tong Tests are amp readings taken on each feeder four times per year – one winter, one summer, one day and one night measurement. These measures are used to forecast and model the feeder loading for analysis.

7.9.12 - National Grid

Planning

Load Forecasting

People

Load forecasting for network feeders is performed by the Distribution Planning department, led by a Director. This group also does distribution planning for both the network and non-network systems.

Load forecasting for network feeders is based on an overall system forecast developed by a National Grid load forecasting group, a corporate organization.

Process

Forecasting at the distribution level is an annual process. Distribution Planning receives a load forecast from a corporate group at National Grid who develops the load forecast. This forecast is built on several components, including historic loading going back 30 years, known anticipated spot loads in excess of 1 MW, and the forecasted economic outlook. The latter uses county level econometric data, that serve to predict energy requirements based on local economic variables, such as employment rates, The forecasting department obtains some key variables from external organizations such as Moody’s. Note that the forecasted summer peak demand growth rate also factors in the impacts of demand side management programs, anticipated to reduce the growth in peak demand by .3% per year over the next four years.

The Load Forecasting group has a weather normalization process that considers temperature and humidity over a three-day period. From this process, they develop provide to Distribution Planning three forecasts: a 50-50 forecast (normal) , a one in 10 year forecast, and the one in 20 year forecast. These probabilities provide planning engineers the likelihood of achieving peak loads in excess of the forecast values. For distribution planning, planning engineers use the most conservative forecast, the one in 20 year forecast.

Planning engineers take the summer peak forecast and apply that to the feeder level.

While National Grid’s approach to developing an overall forecast is fairly sophisticated, their ability to forecast at the feeder level is less so. This is in part because they lack remote monitoring and recording and thus base feeder forecasts on recorded meter readings that may not reflect the most current circuit configurations.

Overall, National Grid New York is experiencing about a one percent load growth, though the load growth in the network has been rather flat. Both commercial and industrial loading is declining with residential loading increasing at about two percent annually. The annual load factor is declining.

Technology

National Grid planning engineers use the PSSE power flow product to model and perform power flow analysis of the network system. For non network feeders they are using CymeDist which is integrated with their GIS system.

7.9.13 - PG&E

Planning

Load Forecasting

People

Load forecasting for network feeders is performed by the Planning and Reliability Department. This department is led by a Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution planning, including feeder load forecasting.

Both network planning engineers are four year degreed engineers. They are represented by a collective bargaining agreement (Engineers and Scientists of California).

Process

The planning engineer forecasts the load by “discrete input.” He takes the known loading and adds in anticipated new loads by feeder.

System peak information is gathered by the planning engineer from information recorded by SCADA and stored in the SCADA Historian. In projecting peak loading, engineers will use five years of loading history to account for periodic variations in load.

Planning engineers obtain monthly peak loads from the SCADA historian and compare this to feeder ratings. Engineers may enter the SCADA readings into the load flow model and recalculate to see if there are any overloads. Alternately, they may simply compare the monthly peak values to previous peak load readings and circuit ratings. Also, planning engineers will ascertain the validity of any projected new load estimates, and run load flows to understand the implications of the added load.

PG&E has remote monitoring of all network feeders. Also, they have the ability to monitor loading on all network transformers through CT monitoring installed on the transformer secondary (at the NP exit cables). This information is housed in the PG&E SCADA Historian.

The planning engineer has access to the SCADA Historian on his desktop. Consequently, he has good information on network loading based on the historical load information housed within the historian.

Technology

PG&E uses the EasyPower load flow product from ESA to model their network system. This model is manually populated and maintained by the Planning engineer. The planning engineer reports being satisfied with this planning tool.

Note that PG&E is presently implementing the CYMEDIST (by CYME) load flow product for performing analysis of their radial system. In a subsequent phase of their project, they plan to implement the use of CYMEDIST as their network planning tool as well. A challenge for them will be the conversion of data from EasyPower to CYMEDIST.

7.9.14 - Portland General Electric

Planning

Load Forecasting

People

Across PGE, the Transmission and Distribution (T&D) Planning organization oversees load forecasting for network and non-network systems. A Planning Engineer with a four-year degree in engineering covers the PSC. Three Distribution Engineers also work on the underground network, although they are not based in the PSC service center or CORE group. They are overseen by the Eastern District Central Supervisor and are responsible for updating the PSSE models covering the secondary network.

Other organizations involved in load forecasting include the Planning Group, which provides the “Weak Link Report,” which covers both the radial and network system and shows system peak loadings in summer and winter. Because the network includes many commercial customers with high energy demands, the Major Account Representatives responsible for the network provide any information about potential load changes from larger customers.

Process

Load Growth Studies: PGE does not conduct routine load growth studies on the network and only performs analyses when there is a specific need due to changing loads and customer demand. When needed, PGE uses system wide load growth studies, with updates from the major account representative who reports any anticipated changes to the load that a customer will undertake.

Reporting: The Planning Department creates bi-annual reports on the network loading, the “Weak Link Report,” which covers both the radial and network system. The report examines the system peak loading for the summer and winter, with network data sourced from the substations. The monitoring data that is currently received from the network is not used for modeling or planning; it is only used for operations.

PSSE Load Modeling Software: For the network system, PGE uses the Siemens PSSE modeling software for both the primary and secondary network models. Planners collaborate with Distribution Engineers to obtain the most up-to-date model in PSSE, including manually entering loading information. The load data is derived from the customer meters, and gathering and entering this information is a labor-intensive process. PGE’s network load is relatively flat, but the utility is anticipating an increase in the next few years due to an expansion of the retail sector in the downtown area.

PGE used PSSE to develop a sequence when splitting the Stephens Substation secondary network into two four-feeder configurations. System planners used PSSE modeling software to perform load analyses using peak demand data drawn from metered accounts on the network. The company used PSSE to assign appropriate nodes to the metered accounts, and the load was scaled to match a coincidental summer peak loading patterns.

PGE used this to develop a base case scenario with the loadings and voltage on lines, equipment, and buses for the Stephens network. Planners were able to ensure that no line would be loaded more than 100%, no grid transformers would be loaded more than 140%, and no spot network transformers would be loaded more than 130% during peaks. Base loadings specified that no line should be loaded more than 88% and that no transformer should be loaded more than 70%. Where outages would see equipment potentially exceed the loadings, PGE identified equipment upgrades [1].

Load Reduction and New Customers: As a wider philosophy, PGE is trying to maintain the network and reduce loads where possible. If a new customer enters the system on the periphery of the network system, they are usually added to the radial system rather than the network. The reason for this approach is that networks are expensive to maintain and build, so network access is reserved for customers with connections lying well within the network.

Customers on the periphery can request an alternative service to ensure reliability, which includes a service agreement and payment for the contingency service and the reserve capacity needed. This can also depend upon the load, with the enhanced service provided free for customers requiring over 18 MW loads. Customers with loads under 4 MW pay only for the feeder, and customers with 4-18 MW demands pay for the substation capacity.

Technology

To model the network system, engineers use Siemens PSSE software for the primary and secondary network, using data from customer meters to develop a base case and highlight where normal and peak loading exceeded recommended limits.

Because PSSE is unable to monitor single-phase loads and cannot model loops, PSC will add the secondary network to CYME, using the GIS system to model and display loops. For mapping, PGE uses ArcFM on top of ArcGIS. The company is presently working with the ArcFM vendor to enable its use with CYME.

Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.

7.9.15 - Survey Results

Survey Results

Planning

Load Forecasting

Survey Questions taken from 2015 survey results - Planning

Question 49 : How do you collect network load data for modeling purposes? (check all that apply)

Survey Questions taken from 2012 survey results - Planning

Question 3.17 : If you are using load flow software, please indicate which software product(s) you are using.

Question 3.18 : How do you collect network load data for modeling purposes?

Survey Questions taken from 2009 survey results - Planning

Question 3.14 : If you are using load flow software, please indicate which software product(s) you are using.

7.10 - Load Relief

7.10.1 - Ameren Missouri

Planning

Load Relief

People

Resources in several groups perform distribution planning of the network at Ameren Missouri.

Area planning for the distribution system is the responsibility of Distribution Planning and Asset Performance. This group, led by a manager, is staffed with four-year degreed engineers, and includes the Standards Group as well as a Planning Engineering Group. Organizationally, Distribution Planning and Asset Performance is part of Energy Delivery Technical Services, reporting to a vice president.

Local distribution planning of both the network and non-network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division. This division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues. The engineers are four-year degree positions. Energy Services Consultants have a combination of years of experience and formal education, including two year and four year degrees. The engineers are nonunion employees; the estimators are in the union. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP.

Process

Ameren Missouri’s St. Louis service territory contains four individual secondary network grids, each sourced by separate substation. Each of the networks is designed to N-1^[1] . However, Ameren Missouri plans for a substation bus outage and, if they lose any one bus, they may lose two feeders supplying a given network. The system is designed to handle this particular contingency – an N-2 situation.

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. Network planning is based on a peak load analysis, recognizing that the peak is only representative of loading for a few days each year. In developing the load forecast, engineers will consider known projects, estimated future load additions from vacant lots to be developed, and general growth rates. Engineers will also temperature adjust their load forecast based on an algorithm developed by corporate engineering.

Engineers model the system, and perform analyses to understand anticipated requirements. For network feeders, planning engineers perform contingency studies, modeling networks with each primary feeder out of service to identify areas of needed reinforcement to supply the network in a contingency. For radial feeders, planning engineers perform contingency studies (N-1 planning) to assure they can pick up customers with reserve feeders within the emergency ratings of the transformer and cables. More specifically, they model the distribution system with one feeder out of service, simulating customers connecting to reserve feeders. From this analysis, planning engineers determine where reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Technology

Ameren Missouri uses the DEW load flow product to model their network system. For networks, this model is manually populated and maintained by the planning engineers. The model includes a graphic representation of the primary, secondary, and network unit. For example, when modeling the feeder out of service, DEW will model all the protectors opening. Note that at the time of the practices immersion, Ameren Missouri has assembled a list of enhancements they desire to the DEW product.

For radial circuits, DEW imports information and attributes from Ameren Missouri’s GIS system, and imports load information from a transformer load management (TLM) system.

^[1] Note that at the time of the immersion, Ameren Missouri had drafted planning criteria that includes an N-2 design for the grid network primary feeders, and N-1 design for spot networks, and an N-1 design for radial feeders. This draft has not yet been adopted by Ameren Missouri.

7.10.2 - CEI - The Illuminating Company

Planning

Load Relief

People

The Planning and Protection Section performs annual studies of primary feeder loading to anticipate areas of overload and recommend remediation. These annual studies are limited to the non – network portion of the system.

Process

Because the load in the Cleveland network is forecasted to continue to decline, CEI does not perform annual analysis of network feeders other than to annually monitor peak loading and assure that the load continues to be well below the distribution network feeder capability. Consequently, CEI does not develop network feeder load relief plans.

For the radial underground distribution feeders, CEI annually compares the most recent historical peak distribution feeder loads against forecasted loads developed using their load flow software. It is from this analysis that CEI identifies load relief projects.

CEI aims to relieve all anticipated primary cable overloads through their regional planning process.

Technology

For Network analysis, CEI utilizes a load flow product called PSLF – Positive Sequence Load Flow Software, by GE Energy.

For non-network analysis, CEI is changing from Windmill to CYME. They ultimately intend to apply CYME to network analysis; however, its functionality in this area is still being evaluated.

7.10.3 - CenterPoint Energy

Planning

Load Relief

People

Load Relief plans at CenterPoint are developed by the Electric Distribution Planning department (Planning group).

The Distribution Planning group is comprised of 21 total resources, including 2 Lead Engineers. Each of the Lead engineers has about 6 -8 people reporting to them. These folks are either 4 year degreed engineers, or technical experts. CenterPoint aims to have a balance between Engineers and Technicians.

In addition the Planning group has a lead engineer specialist, who leads a computer support group comprised of 6 resources.

CenterPoint encourages its engineers to obtain their PE license. The PE license is required to become a Senior Engineer.

Process

The Planning group annually revises the five year load forecast based on known and anticipated load projections. (See Load Forecasting )

For substations, Planners input working loads into their models at a substation level. They gather loading information, anticipated new loads and load growth rates from the service centers and load it into a model for developing a forecast. Once the load forecast is developed for a station, planners would then determine whether or not they need to address the substation capacity or the circuit capacity.

Planning Engineers annually perform an analysis of the impacts of anticipated loading on every circuit and substation on the system. From this analysis, they identify areas where changes must be made to address overload situations. In some cases a Planning engineer will perform an area study to optimize the distribution of loads between stations. In others, individual feeder reinforcement projects are developed.

Technology

CenterPoint is using spreadsheets and CymE load flow software to perform analysis. They recently implemented CymE network modeling software. Planners perform circuit analysis to anticipate areas of overload, in both normal and contingency situations. From this, load relief projects are identified.

7.10.4 - Con Edison - Consolidated Edison

Planning

Load Relief

Process

Network Distribution Feeder Load Relief Programs

Distribution network feeder loads and ratings are calculated in parallel with the substation and sub-transmission feeder program. The most recent historical peak distribution feeder loads are compared against the network model results (using Con Edison’s circuit modeling tool [PVL]), and any differences are reconciled. The ten-year independent load forecast is applied to the feeders – identified significant additions (i.e., specific new business projects) are injected on the feeders that will serve them, and the remaining load growth is apportioned across the remaining feeders. Feeder ratings and the driving contingency conditions are calculated, and the feeder capabilities are developed.

It is from this analysis that Con Edison conceptualizes new load relief projects. Options are identified for needed network feeder load relief, dovetailing with the area substation load relief options discussed above. Through an iterative process between the Regional Distribution Engineering organization and Transmission Planning, the options are reviewed, and a recommended plan is decided upon.

Con Edison aims to relieve all anticipated primary cable overloads (won’t go above 100% loading), as determined by their analyses. Feeder relief is almost considered nondiscretionary for network feeders, because Con Edison does not have the same flexibility to transfer load as they do in the radial (non-network) parts of the system.

Load relief projects are designed between September and December, so that they can be built between January and June, prior to the upcoming summer loading season. Upcoming summer ratings reflect this work and are published.

Network Transformer and Secondary Mains Load Relief Programs

Network transformer and secondary mains relief follows an identical process as primary feeder relief. The same ten-year independent load forecast and the same network models are run. Transformer and main ratings and the driving contingency conditions are calculated, and the capabilities are developed. In addition to this, any transformer with recorded telemetry (Con Edison’s Remote Monitoring System [RMS]) from any historic peak period indicating capability issues are studied and relieved upon confirmation. All options are reviewed by the regional engineering department and once the plan is accepted, the project is issued to and completed by both the construction and construction management groups.

Technology

Load Flow System – Poly-Voltage Load Flow (PVL)

Con Edison utilizes a distribution load flow application called Poly-Voltage Load Flow (PVL). The PVL application is actually a suite of applications that was developed in house over a 20-year period of continued development. In addition to aiding engineers in performing load flow analyses, the PVL system is used to build feeder and transformer models, develop network transformer ratings, develop network feeder and cable section ratings, model area substation outages, and identify short-circuit duty at customers sites, etc.

To perform load flows, circuit models are brought into PVL from the mapping systems. The secondary system is kept in one mapping (GIS) system (different from location to location), and the primary feeders are kept in another mapping (GIS) system. Con Edison reflects all system changes on its mapping systems. Feeder maps within Manhattan are updated in 24 hours as changes occur. Secondary side maps are not updated as quickly, but are very frequently updated. These GIS systems are maintained by the mapping organization.

When the circuit information is brought into PVL, the new information overlays the existing circuit model already in the system. Once the model is brought into PVL, all users use the same model. When a circuit is brought into PVL, people responsible for model maintenance ensure that the PVL model has electrical connectivity and is in synch with the mapping system.

Load flows are conducted for a variety of reasons.

Planning engineers run base case load flows, N-1 cases, and N-2 cases. For each contingency, the PVL output tells you what is overloaded in tabular and graphical formats.
Planning engineers use PVL to assist in short-range and long-range planning. For example, the system is used to analyze conceptual projects to split existing networks into smaller networks
For new business, engineers run the existing case, and then re-run it with the new business load added to understand the loading and voltage implication of the new load.
Region Engineering runs feeder loading studies in advance of the summer to identify anticipated overload conditions.
The system is also used to understand the loading implications of different restorations scenarios in an outage.

PVL can use real-time readings from transformer vaults (gathered through Con Edison’s Network Remote Monitoring System [RMS]) for building the network load model. If needed, demands can be spotted at customer service points, using information such as customer kWh consumption and real-time transformer readings.

The PVL system can also perform cable section ratings. The system considers the impacts of soil type and temperature. The system does not automatically consider the proximity of electrical facilities to steam mains.

Operators are able to take advantage of the functionality of PVL through a real-time version known as AutoWOLF, which takes the base model and applies real-time conditions. For example, real-time transformer loading information would populate the model from RMS system. Knowledge of open feeders would populate the model from SCADA. When a circuit locks out, AutoWOLF automatically runs the system peak case, the current case, and the projected peak case, so that that information is available to an operator. The operator can look at the loading on the other feeders and try to determine which feeders to watch.

During emergency conditions, Con Edison assigns engineers assigned to the control room to monitor system loading. During normal conditions, the operators monitor the system themselves.

Con Edison has formed a PVL users group that meets bi monthly to discuss issues associated with the PVL. The PVL Users group is made up of approximately 50 people from both the regions and corporate, including network model maintenance people, designers, supervisors, engineers, engineering managers, and support personnel. Approximately 15 members attend any one meeting.

7.10.5 - Duke Energy Florida

Planning

Load Relief

People

Studies to forecast loading and to identify projects to relieve projected areas of overload are performed by the Planning Engineers, responsible for capacity planning, and who are organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I). This group is led by a Director of PQR&I for Duke Energy Florida.

Process

Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time focusing on reliability and infrastructure upgrades.

Capacity studies, for both normal and contingency conditions, are triggered by new load additions. When there is a call for any significant new load in the urban underground centers, Network Planners will model the impact of a proposed new load on the network using CYME®, looking at both normal conditions and contingencies. In Clearwater, Network linemen also have access to real-time secondary load data on network transformers through Sensus® monitoring. In addition, for large load additions, and for longer-term forecasting, planning will utilize a feeder load allocation program (FLAP). Planners input anticipated annual percent load increase expectations and known spot load additions into this system, and it will return an overall expected load forecast.

Actions to be taken based on anticipated load growth are based on an engineering analysis and are not informed by a written planning criteria. Note that at the time of the immersion, Duke Energy was in the process of consolidating historic Duke Energy and Progress Electric planning approaches into a system planning criteria, expected to be complete mid-2017. Network loading in Clearwater has remained flat. Duke Energy Florida is experiencing moderate load growth in St. Petersburg.

Technology

Network Planners use CYME Power Engineering software to perform load flow calculations on primary feeders.

The FLAP (feeder load allocation program) is used to develop load forecasts. When larger service loads are planned, this system will incorporate the impact of significant anticipated load additions on the overall forecast.

7.10.6 - Duke Energy Ohio

Planning

Load Relief

People

Distribution planning, including identifying areas requiring load relief in the network underground system, is performed by the planning department.

Duke Energy Ohio has assigned an engineer within the planning group to focus on the network. Note that this department also deals with substation and overhead distribution planning.

The engineer, who focuses on network planning, is a four year degreed engineer. This engineer works very closely with the Distribution Design (customer project) department and the Construction and Maintenance department to plan the network.

Process

Duke Energy Ohio’s network system is designed to n-1. That is, the system is designed to ride through the failure of any one component during a system peak.

In performing planning, the planning engineer takes load information and adds it to a spreadsheet that tracks loading by secondary grid, by customer service location, and by secondary bus. Information about new load additions comes to the planning engineer from various sources. Most of the time, information about new load additions comes from the customer project organization. Sometimes the planning engineer is informed about a particular project through participation in an early planning meeting, or through a fault current request.

The planning engineer will look at the loading trend over the past five years and compare the present conditions to the peak loading conditions over the past five years. Generic primary cable ratings are used in determining the available capacity. Through this analysis, the planning engineer will identify improvement opportunities in the system to meet anticipated loads and to address areas that may be overloaded.

Technology

Duke Energy Ohio is using SKM PowerTools up as a planning tool for the network^[1] .

The planning engineer has focused recently on bringing this model up to date. The model includes the street grid, including transformers by location, and including transformer sizing and impedance. The model has also been updated to include new cables that Duke has recently changed.

The model also contains updated loading information, including the loading of particular buildings. This loading information comes from several sources. Larger commercial customers have demand meters. Load readings are housed in the Duke energy billing system and for larger customers (over 300 KW) the customer provides a phone line and loading information flows back to the company’s billing system through the phone lines.

The Load modeling system is used to perform “what if” scenarios, to understand the impact of the system in a contingency, and to identify areas for system reinforcement for load relief.

^[1]Note that outside the network, Duke is using the SynerGEE system analysis product.

7.10.7 - Energex

Planning

Load Relief

People

Planning is performed by the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

The planning process includes a five-year rolling look at the system that includes an annual analysis of anticipated demands on every circuit, substation and substation transformer. Analyses include both normal loading and contingency loading situations. Demand is calculated on every circuit, station, and substation transformer in the Energex system.

When a planning engineer identifies a deficiency, he nominates a project to correct the problem. This nomination involves a high-level description of the work to correct the problem as well as a rough indication of the costs.

7.10.8 - ESB Networks

Planning

Load Relief

People

Distribution planning at ESB Networks is performed by planning engineers within the Network Investment groups – one responsible for planning network investments in the North, and the other for planning in the South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists” who have developed their expertise through field experience.

Planning standards and criteria are developed jointly between the Asset Investment group and the Strategy group, which is part of the Finance and Regulation group within Asset Management.

Process

Planners engineer the system to N-1, with most supplies having a “forward feed” (preferred) and a “standby feed” (reserve). The planning criteria for MV distribution requires customer voltages to remain at +/- 5% of nominal in normal situations, and +/- 10% of nominal in a standby (contingency) situations. Planning criteria also call for long-term cyclical overloads of no more than from 125-150 percent of rating for equipment, with a short-term loading of no more than 150-180 percent.

At the time of the practices immersion, ESB Networks has a program underway to convert their 10-kV distribution system to 20 kV. This conversion effort is underway outside of Dublin where the benefits of conversion are more readily realized. Note that the MV primary system serving the city of Dublin is operated at 10 kV.

Technology

For performing MV (10 and 20 kV) and for some 38-kV circuit studies, ESB Networks is using SynerGEE (GL Group). The company has tied this tool to its GIS database. For HV analyses (38 kV and 110 kV), ESB Networks is utilizing PSS® Sincal from Siemens.

7.10.9 - Georgia Power

Planning

Load Relief

People

Distribution Planners are responsible for loading of both distribution and network primary feeders, and work closely with the network Area Planners. Area Planners are responsible for planning upgrades of substations on the urban networks, while the Distribution Planners are responsible for planning upgrades of the primary feeders, including modifications for circuit load relief. The two groups work closely together. Both groups – Area Planners and Distribution Planners – work with the Network Underground design engineers during the design phase.

Planning of upgrades to the secondary grid is done by principal engineers in the Network Underground department.

Process

Although Area Planners are not responsible for the network loading, they are responsible for the load on the transformers. Therefore, the Area Planners must know the configuration and cable load of the entire urban network. Area Planners evaluate contingency reserve capacity to maintain N-1 reliability of the network. For example, if Georgia Power has three transformers at a substation, and one of the transformers supplies the Network, then one of the responsibilities of an Area Planner is to insure that if the Network Bank fails, for whatever reason, the other two transformers have enough reserve capacity to pick up the full load of the failed network bank. This guarantees a high level of customer reliability. As a result of this strategy, network substations are sized accordingly, so that they have enough capacity to handle any network segment with only two transformers regardless of the peak load.

The network planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. Network planning is based on a peak load analysis, recognizing that the peak is only representative of loading for a few days each year. In developing the load forecast, engineers will consider known projects, estimated future load additions from areas under development, such as downtown Savannah and Buckhead, and general growth rates. Engineers will also temperature adjust their load forecast based on previous historical data of high-peak temperatures, averaged over a number of years. Area Planners look four years ahead, forecasting the need for more capacity based on impending projects and demographic demands, such as the newly planned baseball stadium in Atlanta.

Area Planners trigger network planning changes based on the data they have, including the aforementioned load forecasts. In addition, Area Planners meet with senior engineers, marketing, and distribution engineers, every five to six months. The group examines proposed customer projects that are in the pipeline and determines whether the projects will be distribution (radial) based or network-based. The frequency of the meetings is a direct result of the number of projected projects and the likelihood they will come to completion.

Technology

Georgia Power has recently acquired CYMDIST to model the entire secondary and primary grid (See Figure 1). The program is designed for planning studies and simulating the behavior of electrical distribution networks under different operating conditions and scenarios. It includes several built-in functions that are required for distribution network planning, operation and analysis. The model Georgia Power has developed is extremely accurate including cable systems, cable ratings, cable capacities and specifications. The Area Planner keeps detailed spreadsheets, continually updated, on upcoming and ongoing projects. The Georgia Power GIS system also tracks network statistics, so that if a particular network segment reaches a threshold, it is tagged for analysis by the Area Planner and Network design groups. Typically Georgia Power prefers to keep capacities in the 70 to 90 percent range, and any transformer or network segment exceeding 90 percent is prioritized and tagged for the Area Planner and engineering for more capacity.

Figure 1: CYMDIST 7 Distribution Network simulation software with Network Editor

7.10.10 - HECO - The Hawaiian Electric Company

Planning

Load Relief

People

The Distribution Planning Division performs annual studies of primary feeder loading to anticipate areas of overload and recommend remediation. These annual studies apply to both the network and non- network feeders.

The Distribution Planning Division is part of the System Integration Department. This group performs all distribution planning at 46kV and below.

Process

For radial underground distribution feeders, HECO annually compares the most recent historical peak distribution feeder loads against forecasted loads. Because HECO has limited application of SCADA, feeder loading forecasts are developed by apportioning the monitored substation loading over the feeders based on periodic feeder loading measurements called “Tong Tests”. Tong Tests are amp readings taken on each feeder four times per year – one winter, one summer, one day and one night measurement. These measures are used to forecast and model the feeder loading for analysis.

From this analysis, HECO identifies feeders / feeder sections where the forecasted load is projected to overload the feeder. It is from this analysis that HECO identifies load relief projects.

HECO aims to relieve all anticipated primary cable overloads through their planning process.

Technology

HECO historically has not used a load flow software product to aid them in distribution planning. They gather and record feeder loading and transformer loading information using an EXCEL spreadsheet. Load flows for contingency analysis are calculated manually.

HECO is in the process of installing SynerGEE, a load flow software product from GL Industrial Services. This product will interface with HECO’s GIS system and be able to import up to date circuit models. This software will facilitate their ability to perform contingency analysis. They are targeting year end (2009) for implementation of this software.

7.10.11 - National Grid

Planning

Load Relief

People

A key focus of the Distribution Planning organization is identifying areas requiring load relief in the network underground system.

At National Grid, network planning is performed by the Distribution Planning Organization, led by a Director. Organizationally, the Distribution Planning Organization is part of Distribution Asset Management, and is comprised of resources in both a central location (Waltham Massachusetts), and distributed throughout National Grid (Field Engineers).

Centrally located resources include Capacity Planning resources who reporting to a manager, and engineering personnel, who have broad system planning and engineering responsibilities, Regionally located resources include Field Engineers who report to managers of Field Engineering for both New York and New England, About two thirds of the Distribution Planning organization is centralized, with the remaining third decentralized.

In general, short term planning activity (current year), including the identification of areas requiring load relief, is led by the field engineers located in the various regions. Longer term analyses (future years) is led by the central planners

The planning engineers who focus on the Albany network include a field engineer who works in the Albany office and focuses primarily on both radial and network underground systems for National Grid’s New York Eastern division, and an engineer situated in Waltham, who has network engineering responsibilities across the system. These engineers have responsibility for both network planning, including load relief, and network design.

National Grid has up-to-date standards and guidelines for the network infrastructure. In addition they have up-to-date planning criteria that address network planning.

Process

The planning process involves running load flows of distribution system models to compare present and anticipated loading to the feeder ratings and to evaluate the implications to the system. Planning engineers use 15 minute interval load information from SCADA as well as information from National Grid’s customer information system to develop distribution feeder models. Customers / customer load are assigned to certain network busses to model the system. Engineers model the system at peak load, at 90% of peak load, and in the n-1 and n-2 contingency situations. Peak load forecasts are developed for each feeder from overall system load forecasts. Overall, National Grid New York is experiencing about a one percent load growth, though the load growth in the network has been rather flat. Both commercial and industrial loading is declining with residential loading increasing at about two percent annually. The annual load factor is declining.

Distribution planning analysis includes analysis of both potential thermal overloads, requiring load relief, and voltage issues.

The network in Albany is summer peaking. Typically, planning studies for the network are performed in the spring and may project anticipated system loading multiple years in the future. In addition, the analysis may also include a fault current analysis to understand the ability of the system to properly clear faults. Note that while modeling and analysis for non network feeders occurs annually at National Grid, modeling and analysis of network feeders is not performed every year, and typically involves a multiple year projection of loading.

National Grid’s process for reinforcing system is that after performing the analysis planning engineers recommend capital improvements to the system. Major capital improvements, in excess of $1 million, flow to a distribution capital investment group, an internal committee that reviews and approves funding for major investments. Capital expansions under $1 million follow an internal National Grid level of signature authorization (LOSA) procedure.

Technology

National Grid planning engineers use the PSSE power flow product to model and perform power flow analysis of the network system, and use a product called Aspen to perform fault analysis. (The Aspen product is also used by the System Protection group at National Grid.)

Note that the PSSE power flow product provides steady-state analysis. It cannot model network protectors (for example, back feed through the protectors).

In non-network areas, National Grid uses CymDist as a modeling tool, which has been integrated with their GIS system. National Grid has not applied this to the network system, as their GIS system does not model a meshed system.

7.10.12 - PG&E

Planning

Load Relief

People

A key focus of the network planning engineer is identifying areas requiring load relief in the network underground system.

Network planning is performed by the Planning and Reliability Department. This department is led by a Principal Engineer, who is also the department supervisor. This group does distribution planning for both network and non-network systems. There are eight engineers that comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution planning. Both network planning engineers are four year degreed engineers.

The planning engineers are represented by a collective bargaining agreement (Engineers and Scientists of California).

Process

PG&E’s network system is designed to n-1. That is, the system is designed to ride through the failure of any one component during a system peak, with only minor overloads to transformers, primary feeders and secondary mains during peak periods.

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new loading. Network planning is based on a peak load analysis, recognizing that the peak is only representative of loading for a few days each year. Planning engineers obtain monthly peak loads from the SCADA historian^[1] and compare this to feeder ratings to identify locations that potentially overloaded. Engineers may enter the SCADA readings into the load flow model and recalculate to see if there are any overloads. Alternately, they may simply compare the monthly peak values to previous peak load readings and circuit ratings. Also, planning engineers will ascertain the validity of any projected new load estimates, and run load flows to understand the implications of the added load.

Designing for the peak provides conservatism to the planning process. Planning engineers report that actual loading is always lower than the loading projected by their load flow models, as these models are based on peak values and do not account for load diversity.

The planning process is used to identify areas requiring load relief. If the calculated circuit loading exceeds 110% of the either the circuit’s normal or emergency capacity ratings, the planning engineer will consider the circuit to be overloaded and recommend design changes to ameliorate the condition. PG&E uses the 110% level based on the fact that their load flow model uses all peak load values and thus doesn’t account for diversity. So, rather than reacting to modeled loads over the 100% rated values of circuits, they add the additional 10% since they know their models are conservative. They do this analysis for both base case and for contingency situations. (Six different contingency models are run, one for each primary feeder supplying a network).

Through this analysis, the planning engineer will identify improvement opportunities in the system to meet anticipated loads and to address areas that may be overloaded.

Technology

PG&E uses the EasyPower load flow product from ESA to model their network system. This model is manually populated and maintained by the Planning engineer. The planning engineer reports being satisfied with this planning tool.

Note that PG&E is presently implementing the CMEDIST (by CYME) load flow product for performing analysis of their radial system. In a subsequent phase of their project, they plan to implement the use of CYMEDIST as their network planning tool as well. A challenge for them will be the conversion of data from EasyPower to CYMEDIST.

^[1] PG&E’s SCADA provides three phase amp readings on all network feeders. Also, they have the ability to monitor loading on all network transformers through CT monitoring installed on the transformer secondary (at the NP). This information is housed in the PG&E SCADA Historian.

7.10.13 - SCL - Seattle City Light

Planning

Load Relief

People

Organization

Network Planning at Seattle City Light is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A. The Network Design Department focuses exclusively on the planning and design of SCL’s networks.

Although SCL does have a separate planning group that performs distribution planning activities for SCL’s non-network distribution system, this group does not do the planning associated with the network. All cable ratings, load flow and voltage studies, master load flow analysis, assignment of feeders to load additions, area studies, etc. associated with the network are performed by the Network Design Department staff. (Note that SCL is currently implementing an Asset Management organization. At the time of this writing, SCL had not yet decided whether certain tasks currently performed by the Network Engineering group will be moved into the Asset Management organization.)

The Network Design Department is made up of a System Group (eight engineers) and a Services Group (eight engineers). These engineers do all of the planning and engineering for the network (the System Group), as well as interface with network customers for load additions, new loads, etc. (the Services Group). The individuals in this group are four-year degreed engineers. The senior level engineer position at SCL requires a PE license. The engineers at SCL are represented by a collective bargaining agreement (IBEW).

Culture

The Network Engineering group has a close working relationship with the Civil and Electrical construction and maintenance groups within the Area Field Operations – Network Department and the Distribution Operations Department. EPRI observed high levels of mutual respect between these groups, and high confidence by the field organizations in the planning and design decisions made by the Network Design Department.

SCL has remained committed to the network engineering department staffing levels, hiring new engineers into the network area to fill vacancies. SCL has no formal training program for network engineers. However, network engineers are sent to special classes on network equipment, etc. as part of their ongoing development.

Process

SCL conducts a master load flow analysis twice per year using “extracts” from their monitored loading data after the summer and winter of each year. This master load flow analysis is performed on all network feeders. The analysis is performed by the Load Flow Engineer within the Network Design Department. This process is one of the drivers of reconductoring projects.

(Note: many feeders are analyzed more than twice per year because of load increases – see feeder assignment process discussion in next paragraph.)

SCL also performs a feeder load analysis as part of their Feeder Assignment process in response to anticipated new load. The term “Feeder Assignment” means determining which feeder or feeders will serve a new network load. A Network Services engineer requests the feeder assignment based on a new or supplemental load need. The System Engineer within the Network Design department performs an analysis to determine the best scenario for serving the new load. This analysis includes ensuring that the network design criteria are met, and that any feeder imbalance is restricted to less than 20%. (Note that about 80% of new load is served as a spot network, rather than tapping the existing network secondary.) See Attachment B.

When SCL performs a load flow analysis, they start off with the worst case (no accounting for diversity). They then re-run the case after applying a diversity factor.

Technology

Load Flow and Voltage Drop

SCL uses a load flow and voltage drop analysis software package developed in house (legacy software). The software is nodal but not graphical. To perform load flows and voltage analyses, SCL engineers can call up a feeder, enter the changes, and solve the case. The output report is tabular, not graphic. The output indicates the load flow and voltage at each node.

7.10.14 - Survey Results

Survey Results

Planning

Load Relief

Survey Questions taken from 2012 survey results - Planning

Question 3.17 : If you are using load flow software, please indicate which software product(s) you are using.

Survey Questions taken from 2009 survey results - Planning

Question 3.14 : If you are using load flow software, please indicate which software product(s) you are using. (This question is 3.17 in the 2012 survey)

7.11 - Network Planning

7.11.1 - AEP - Ohio

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Planning for the areas of this urban underground network immersion study, AEP Columbus and Canton, Ohio, is performed in Columbus by the AEP Network Engineering group, which is organizationally part of the AEP parent company. The company employs two Principal Engineers and one Associate Engineer to perform network underground planning for the Columbus and Canton urban underground networks. These planners are geographically based in downtown Columbus at its AEP Riverside offices. While the Columbus-based Network Engineers are responsible for network planning for all of Columbus and Canton, they work closely with distribution planners in the AEP Ohio system, such as Gahanna. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the Director of Engineering Services who in turn reports to the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues.

The AEP Network Engineering group oversees the distribution and network planning for Columbus and Canton, Ohio. In Columbus, AEP maintains N-2 reliability, including the substation, grid networks, and spot networks. This N-2 reliability is notable, as most urban underground network systems operate at an N-1 level. N-2 resiliency means that the system is planned to be able to carry peak load even with the loss of any two components. For example, N-2 insures that if any two transformers go down, additional transformation is available for picking up the network load and maintaining service. At spot network locations in Columbus, AEP uses a minimum of three transformers sized so that anyone can carry the load in the building in the event of the loss of the other two. Substations supplying the network utilize a ring bus design, and consist of three transformers, with one used as a ready reserve hot spare unit.

The Columbus Network Engineering group is responsible for analyzing the loading of both distribution and network primary feeders, and therefore works closely with the AEP Network Engineering Supervisor and the Distribution Systems Planning group who are responsible for distribution planning for the entire AEP system and its operating centers. Planning of upgrades to the secondary grid is also performed by the Network Engineering group in close collaboration with the AEP Network Engineering Supervisor and the parent company. The group oversees the planning of new customer service, rehabilitation of network systems, and relocation of any network service.

Process

Network Engineers must know the configuration and system loading of the entire urban network to provide N-2 reliability. For example, when achieving N-2 reliability, it is one of the responsibilities of Network Engineers to insure that networks be provided three or more independent transmission sources. Each high voltage transmission line should follow an independent route and originate from separate remote sources. As a result of this strategy, network substations are sized accordingly, so that they have enough capacity to handle any network segment regardless of the peak load and N-2 contingencies. All substations have at least three transformers; any one transformer can carry the network load if two go out.

The network planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. AEP Distribution uses CYME and its SNA (secondary grid network analysis) module for initial network load analysis for the AEP Ohio group. Network planning by AEP Ohio in Columbus and Canton is then based on CYME SNA data and local peak load analysis. Local peaks are derived from monthly meter records in its Columbus-Canton service areas. Engineers use algorithms to calculate peak kilowatts (demand) from captured kilowatt hour meter data and populate spreadsheets accordingly. Each engineer in the planning process reviews this load information regularly for any increased loads and adjusts the load flow accordingly. Engineers also have access to larger customer load information in the downtown area. For timelier and even more accurate load information, the AEP Ohio Network Engineering group is considering the use of smart meters in the downtown Columbus area for assistance in performing real-time load analysis.

A separate system, maintained by the AEP distribution planning group, provides the local Network Engineering group with timely information on circuit based load forecasts, including specific anticipated loads that will be added to the AEP Ohio network underground area. Forecasts are amended based on the actual metering algorithm information and load forecasts for new projects and anticipated new service, such as new public and private building and construction in the urban areas. Using this data on circuits and local load information, the Network Engineering group can model projected circuit loading for its Columbus and Canton systems.

AEP Ohio distribution networks are designed to be served by up to six network feeders from a single network station. The feeders must come from at least three secondary voltage buses, with no more than two network feeders per bus (see Figure 1). The substation secondary voltage buses are connected in a complete ring with closed tie circuit breakers between all buses. Multiple station transformers are connected so that a minimum of two transformers operate in parallel during normal operation. Circuit breakers are then used to automatically remove any faulted bus sections from service without impacting normal operations. This provides N-2 service to all existing customers in the downtown region. All stations have a minimum of three transformers, with some having as many as five or six.

Figure 1: Network Substation - Ring Bus Design with hot spare

AEP Ohio is not actively focused in either increasing or decreasing the size of its networks. Demand for network service remains steady, yet some newer customers have opted for radial distribution to cut their costs.

The Columbus urban area has four separate networks – North, South, Vine, and West – supplied from three substations. Each network is supplied from 138 kV/13.8 kV Δ -Y network transformers. All four networks are served by six feeders at 13.8 kV – each group of six originating from a single substation. There is no overlap in these networks. Each is built to N-2 reliability. In Columbus, the Vine network primarily serves spot networks in a high-rise area of downtown (Vine Station), with some mini-grids at 480 V. The other three networks (North, South, and West) serve a mix of grid (216 V) and spot loads. Canton has one network supplied at 23 kV.

Technology

The AEP Network Engineering group performs load flow analysis and other secondary network analysis data using the CYME® Secondary Grid Network Analysis (SNA) software system. The AEP Ohio Network Engineering group also uses kW-per-hour data captured through remote meters and uses sophisticated algorithms and analysis to convert this data to report peak loads on the network. With this captured data and the CYME analysis, AEP Ohio Network Engineers have a solid basis for distribution/network planning.

7.11.2 - Ameren Missouri

Planning

Network Planning

People

Resources in several groups perform distribution planning of the network at Ameren Missouri.

Area planning for the distribution system is the responsibility of Distribution Planning and Asset Performance. This group, led by a manager, is staffed with four-year degreed engineers, and includes the Standards Group as well as a Planning Engineering Group. Organizationally, Distribution Planning and Asset Performance is part of Energy Delivery Technical Services, reporting to a vice president.

Local distribution planning of both the network and non-network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division. This division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues. The engineers are four-year degree positions. Energy Services Consultants have a combination of years of experience and formal education, including two year and four year degrees. The engineers are nonunion employees; the estimators are in the union. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP.

Finally, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers (all 4-yr degreed) focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network. At the time of the practices immersion, the revitalization team had developed a series of planning criteria documents, including criteria for loading, route diversity, sectionalizing, and application of automation. In addition, they had developed recommended requirements for cable replacement, and conduit system design and replacement. Organizationally, the Underground Revitalization Department is part of the Underground Division.

Process

Ameren Missouri’s St. Louis service territory contains four individual secondary network grids, each sourced by separate substation. Three of the substations are sourced by overhead transmission at 138KV, and one station is fed at 35 kV. Each substation uses a ring bus design. Note that one of the substations is older and out of phase with the other three. Ameren Missouri intends to retire this station and has proposed a plan to build a new substation in a different location.

The four individual secondary network grids are 216 / 125V grids, each served from one of the four substations. Two of the network grids are fed by eight feeders at 13.8 KV, one is fed by seven feeders at 13.8 KV, and one is fed by six feeders at 13.8 K. Ameren Missouri runs only dedicated network feeders; that is, they do not mix radial primary circuits and network primary circuits.

Each of the networks is designed to N-1^[1] . However, Ameren Missouri plans for a substation bus outage and, if they lose any one bus, they may lose two feeders supplying a given network. The system is designed to handle this particular contingency – an N-2 situation. The four networks are loaded as follows: 1 at 17 MVA, one at 16 MVA, 1 at 30 MVA, and 1 at 22 MVA.

Ameren Missouri does serve customers via spot networks, most at 277/480V.

Much of the in-service primary cable is PILC. PILC cable was used as the standard up until the late 80s, when Ameren Missouri switched to EPR insulated cables as its current standard.

Ameren Missouri has considerable clay tile ducts installed. These are smaller ducts and many are crumbling. A noteworthy practice implemented by Ameren Missouri was the development of a thinner wall EPR insulated cable, which enables them to take advantage of the existing smaller ducts system (see cable design). Ameren Missouri’s current standard is PVC.

Until the recent economic downturn, St. Louis enjoyed healthy growth rate. Since the downturn, however, load growth has been stagnant, and load on the secondary network system declining. However, Ameren Missouri has seen some modest residential growth in old buildings in the downtown area that are being converted to lofts.

Ameren Missouri customers in the network are charged standard residential rates, consistent with the rates charged to radial customers. Note that a significant number of downtown customers take primary metered service from Ameren Missouri, supplied by a preferred and reserve (alternate) feeder. Ameren Missouri’s primary metered rate is, of course, different than their secondary metered rate.

Customers who request smaller 208V services will usually be connected to the secondary network grid. Customers who request 480 V service or larger 208 V services will normally receive either a pad mounted transformer installation or an indoor substation, supplied by two radial feeders. Padmounted services are usually not practical in the congested parts of downtown St. Louis. Thus, the most common design type for larger loads in downtown St. Louis is via an indoor substation.

The indoor substation (also called “Indoor Room”) typically consists of a preferred and reserve feeder with a tie switch between the two. Note that while Ameren Missouri does serve existing customers via 480V spot networks, new loads are not supplied by a spot network.

In a primary metered service to an indoor room, Ameren Missouri provides two primary supplies coming into the customer. These feed into switches, either fuses or breakers, as chosen by the customer, and can be manually or automatically (auto transfer) operated. After the breakers, the lines feed into the primary metering gear, and then onto the customer’s switchgear or transformation. Note that all equipment, except cable and meters, are owned by the customer, including the primary switches that precede the primary metering point.

In a secondary metered situation, Ameren Missouri provides the switches and transformation that precede the metering point. Ameren Missouri would provide either a preferred and reserve feeder, or a two preferred feeder design.

Customers do not pay additional fees for reserved capacity. Ameren Missouri assures there is adequate reserve capacity through its contingency planning process.

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. Network planning is based on a peak load analysis, recognizing that the peak is only representative of loading for a few days each year. In developing the load forecast, engineers will consider known projects, estimated future load additions from vacant lots to be developed, and general growth rates. Engineers will also temperature adjust their load forecast based on an algorithm developed by corporate engineering.

Engineers model the system, and perform analyses to understand anticipated requirements. For network feeders, planning engineers perform contingency studies, modeling networks with each primary feeder out of service to identify areas of needed reinforcement to supply the network in a contingency. For radial feeders, planning engineers perform contingency studies (N-1 planning) to assure they can pick up customers with reserve feeders within the emergency ratings of the transformer and cables. More specifically, they model the distribution system with one feeder out of service, simulating customers connecting to reserve feeders. From this analysis, planning engineers determine where reinforcement is necessary to be able to reliably serve customers in a contingency situation.

Technology

Ameren Missouri uses the DEW load flow product to model their network system. For networks, this model is manually populated and maintained by the planning engineers. The model includes a graphic representation of the primary, secondary, and network unit. For example, when modeling the feeder out of service, DEW will model all the protectors opening. Note that at the time of the practices immersion, Ameren Missouri has assembled a list of enhancements they desire to the DEW product.

For radial circuits, DEW imports information and attributes from Ameren Missouri’s GIS system, and imports load information from a transformer load management (TLM) system.

^[1] Note that at the time of the immersion, Ameren Missouri had drafted planning criteria that includes an N-2 design for the grid network primary feeders, and N-1 design for spot networks, and an N-1 design for radial feeders. This draft has not yet been adopted by Ameren Missouri.

7.11.3 - CEI - The Illuminating Company

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Network Planning at CEI is performed by the Planning and Protection Section of the Engineering Services Department (CEI Planning Group). The group is part of the CEI Engineering Services department, and is led by a supervisor who reports to the Engineering Manager. The group is responsible for all distribution planning and protection, from 36kV and below. The CEI Planning Group is comprised of 4 Planners and 3 Protection Engineers. All members of the group are four year degreed engineers. The Planning Supervisor noted that he prefers candidates for the CEI Planning Group to have their Professional Engineer (PE) license, but this is not a requirement.

At any one time, the CEI Planning Group may have two or three “rotational” employees working in the department for a six month period. The FirstEnergy rotational program for engineers places newer engineering employees in four different locations and assignments for six months each over a 2 year period. Rotational engineers are part of the FirstEnergy corporate organization and are placed in rotational assignments of varying types across the FirstEnergy system. At the conclusion of their rotational assignments, employees are placed in permanent positions that match their interests and aptitudes with the Company’s needs. The CEI Planning Group Supervisor noted that this program has enabled him to identify strong candidates for his group, and to expose and train all rotational employees assigned to his department in planning and protection practices.

FirstEnergy also has a corporate Distribution Planning and Protection organization responsible for providing governance and standardization to regional planning and protection groups. This group has recently produced a company wide Distribution System Planning Criteria Document.

Process

CEI’s aim is to not increase the load on the existing secondary network system; however they will add small loads to the network if conditions warrant. The addition of these loads is not a concern as the network is lightly loaded due to loss of business in the downtown Cleveland area. Their rationale for not continuing to load the network is a concern over the condition and capacity of the secondary cables. The Planning and Protection Section Supervisor noted that they have removed some “easy to remove” load from the perimeter of the network.

CEI’s standard network planning is n-1; that is, they plan the network system such that all the system components, including primary feeders, secondary cable mains and taps, and transformers are sized to be able to carry the load within “specified thermal and voltage limits” during peak conditions when any single network feeder is out of service.

Regional Engineering Services is responsible to review new service load additions of 100kW or greater to assure that secondary cable sections and network transformation are sufficient during both normal and contingency situations.

Because FirstEnergy companies operate underground systems that developed independently before they were a part of FirstEnergy, their designs reflect different planning, design and operating philosophies. FirstEnergy has recently produced a company - wide criteria Distribution System Planning Criteria document. (See Attachment 1 ). This document is applicable to CEI’s conventional distribution underground systems (13.2 and 4.3 KV), but not to their network system or their 11 kV sub-transmission system. The Criteria document presents planning topics briefly, and can be used as a handy guide for planning engineers. CEI plans to add sections to this Planning Criteria document, including a section on secondary network system planning.

One engineer speculated that were they to rebuild the service to the downtown today, they would likely not use a secondary network system, but rather, an alternative such as a primary network with auto throw-over switches to provide n-1.

Technology

For Network analysis, CEI utilizes a load flow product called PSLF – Positive Sequence Load Flow Software, by GE Energy.

For performing short circuit calculations, CEI is utilizing the CAPE software from Electrocon International.

Note that FirstEnergy is in the process if installing CYME load flow software. They ultimately intend to apply CYME to network analysis; however, its functionality in this area is still being evaluated.

7.11.4 - CenterPoint Energy

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

At CenterPoint, Distribution Planning, including network planning, is performed by the Electric Distribution Planning department (Planning group). Organizationally, this group is part of the Distribution Engineering Electric Distribution Engineering group. Note that the Planning group is not part of the Major Underground group, but assigns resources to support Major Underground.

The Planning group is not centralized. Rather, the Planning group assigns planning resources to individual regions and to support departments, such as Major Projects, or URD Design, so that the planners are physically close to the other groups they work with.

The Planning group is comprised of 21 total resources, including 2 Lead Engineers. Each of the Lead engineers has about 6 - 8 people reporting to them. These people are either 4 year degreed engineers, or technical experts. CenterPoint aims to have a balance between Engineers and Technicians. The department manager noted that the Planning group positions are often entry level engineering positions, and these engineers end up leaving the department for other opportunities.

In addition the Planning group has a Lead Engineer Specialist, who leads a computer support group comprised of 6 resources. These folks work with systems such as CymE, Microstation, LD Pro, etc.

CenterPoint estimates that about 1.5 full time equivalent resources focus on planning work for the Major Underground Group. One planning resource, an Engineering Specialist, is assigned full time to work in Major Underground. He is a “matrix” employee, with a dotted line reporting relationship to Major Underground. CenterPoint believes that positioning an individual into the Major Underground group has led to efficient communications, and strong working relationships. This individual is the “eyes and ears” for the Planning group in Major Underground. He does the bulk of the planning work in the “dedicated ^[1] ” underground system, and works closely with the Major Underground engineers to perform network system analyses.

CenterPoint encourages its engineers to obtain their PE license. The PE license is required to become a Senior Engineer.

Process

CenterPoint uses both 12kV and 35 kV as primary distribution voltages. CenterPoint began converting parts of its system to 35 kV in the early 1970’s in anticipation of significant load growth.

The decision of whether to build infrastructure at 12 or 35kV in a given area is based on economics. In general, 35kV distribution is built into areas of medium to high load growth. 12kV distribution is used in areas of stable load growth, and at locations close to the Gulf, which are more susceptible to contamination. In areas of stable load growth, CenterPoint has no plans to convert their 12kV system to 35kV.

CenterPoint is not planning to expand the 12kV system in downtown Houston area. However, they will serve smaller loads (<1500kVA) on the 12kV system where appropriate.

CenterPoint’s standard service is a radial service. In dedicated underground areas they will typically run a main feeder and an emergency feeder with either a manual or automatic throw over tie. Large loads sometimes require splitting load between two feeders.

CenterPoint avoids using 35kV distribution in Galveston and in other points close to the water because of concerns over contamination due to salt water. Contaminated 35KV distribution is more susceptible to flashover than is 12kV, without making costly design and equipment changes. (Increased distances, dead front equipment, etc) Consequently, CenterPoint had decided to standardize on 12kV distribution in these areas.

The network system (120/208 grid) is supplied at 12kV. Spot networks are also supplied at 12kV. Radial loads are supplied at either 12 or 35kV. Most new large loads are served on the 35kV system, with a main feeder and an emergency feeder.

CenterPoint has five 208V networks served by 6-9 12kV feeders each, sourced from three substations. CenterPoint also supplies spot networks in Galveston, fed from two area substations.

The protection scheme for all totally underground circuits at both 12 and 35kV is a single shot to lock out.

Technology

CenterPoint is using the CymE Power Systems Analysis Framework (PSA) software suite. CenterPoint has recently implemented the CymE network modeling module. CenterPoint engineers noted that much of the work they do involves custom modeling to analyze the economics of various options. See Circuit Modeling for more information.

^[1] The term “dedicated” underground at CenterPoint refers to three phase infrastructure is located entirely underground in their ducted manhole system. A “dedicated” network feeder does not mean that the feeder serves only a network; rather, it refers to a feeder that is entirely fed underground. In fact, at CenterPoint, feeders that supply the underground network also supply radial load along the way.

7.11.5 - Con Edison - Consolidated Edison

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

Process

Planning for Contingencies

Electric facilities in the borough of Manhattan, by law, must be underground. Also by law, the design criterion is N-2; that is, the system must be able to withstand the failure of any two components during peak periods, without resulting customer outages. Note that the Queens, Brooklyn, and the main sections of the Bronx are also designed to N-2. The rest of the Con Edison system is designed to N-1.

Load Forecasting — Ten-Year Electric Peak Load Forecast Description

Annually, the service area electric peak load forecast is developed for each of the major sectors of the economy, which includes commercial, residential, and governmental. The forecast predicts the maximum summer electric peak demand for the system.

The commercial forecast reflects three generic variables for the short- and long-term outlook: business conditions, economic conditions, and energy prices. The commercial forecast also reflects the impact of short-range construction activities within Con Edison’s service territory. The commercial sector accounts for approximately half of Con Edison’s^[1] peak load.

The residential forecast is based on projections of the number of households, number of appliances, household occupancy, and coincident use of appliances. Air conditioning load is the most important contributor to the residential load. The residential sector accounts for about one-third of the Con Edison’s^[2] peak load.

The governmental load is derived using information by customer class based on new business activities.

Key Drivers of the Electric Peak Load Forecast:

Known Construction Projects Known new projects predominantly include business activities such as planned construction projects or construction already under way. Projects are tracked to capture the effect on the electric peak load.
Economy The economic factors used in the forecasting process are the New York City private nonmanufacturing employment metric and the U.S. Gross Domestic Product (GDP). Private nonmanufacturing employment includes all employment except government and manufacturing. GDP is the broadest measure of the economy’s health.
- The economic outlook that underlies Con Edison’s forecast recognizes the service area’s place in the world economy. The forecast assumes that New York City will continue to compete for national and international business throughout the forecast period with the same degree of success that it has had in recent decades.
Consumer Behavior

Consumer response to hot weather through air conditioning usage is the main driver of the residential peak load on a hot summer afternoon. Since air conditioning load makes up 75% of the residential peak load, Con Edison captures information on air conditioning usage and number of units through various surveys.

Technology Improvements in equipment efficiency are captured for major appliances, such as air conditioners and refrigerators. These improvements are reflected in the electric peak load forecast.
Government Large infrastructure projects undertaken by the city, state, or federal governments are included in the peak load forecast.

Temperature Variable (TV) Used in Load Forecasting

What It Is

The temperature variable (TV) is a reference point that Con Edison uses in designing their electric transmission and distribution systems. The TV is used in calculating and forecasting future system loads, taking into account extreme summer weather conditions — sustained high temperatures and humidity over a three-day period — that they would expect to see in the metropolitan New York area in one of every three years.

What It Isn’t

As a reference point, the TV factor is a starting point for preparing for the effects of weather on electric loads, similar to the way in which building codes are starting points for designing and equipping homes and office buildings. It does NOT attempt to calculate or design for the worst weather Con Edison would expect to see in their region, nor does it serve as an “upper limit” design criterion for electric system components. Because Con Edison designs and builds the components of their transmission and distribution systems with significant “margin,” or conservatism, these systems have a great deal of aggregate resiliency. This means that the systems, including the distribution networks, can generally handle temperatures and consequent loads higher than those factored into the TV.

How It’s Calculated

The reference TV for Con Edison’s service area is a factor of 86° using Central Park weather. For Orange & Rockland Utilities (O&R), it is 85° using White Plains weather. In more easily understood terms, a TV factor of 86° is equivalent to a temperature and humidity Heat Index of 105° — an extremely high level at which the National Weather Service advises taking precautions against sunstroke, heat cramps, and heat exhaustion.

Specifically, the summer TV factor is calculated as a weighted average of the highest three-hour temperature (called dry-bulb) and humidity (called wet-bulb) readings each day between 9 AM and 9 PM. (Please note, dry-bulb temperature is the one familiar to most people, being the value used in all media weather pronouncements.) This temperature and humidity data helps determine the discomfort level of Con Edison’s customers, and their associated use of air conditioning.

Since heat “buildup” over a hot spell of a few days’ duration significantly increases air conditioning use and stress on Con Edison’s electric system, the formula for calculating the system TV on a daily basis incorporates three days’ worth of data. The current day’s weather is weighted at 70%, the previous day’s at 20%, and two days before at 10%. A factor of 86° for Con Edison equates to a condition that generally occurs in one of every three years.

How It Has Fared Through History

The TV reference factor has been in use as a planning tool for many years in Con Edison. A Con Edison review of data going back to 1953, when they started keeping relevant records, indicates that the TV factor of 86° or above is achieved approximately in one of every three years.

How Con Edison Compares to the Industry and the Region

Using a TV factor as a reference point is a standard planning practice throughout the utility industry. In fact, Con Edison is more conservative than most. They design to a standard that assumes “worse” and more prolonged weather than many other utilities, government agencies, and regional power pools.

Ten-Year Area Substation and Sub-transmission Feeder Load Relief Programs

Area substation transformer ratings (including breakers, bus, etc.) are calculated by Substation Equipment and Field Engineering. Transmission and Sub-transmission feeder ratings are calculated by Transmission Feeders Engineering.

Area substation transformer ratings and sub-transmission feeder ratings are calculated using appropriate first or second contingency ratings, and the capabilities of the area substations and sub-transmission feeders and load pockets are derived.

This data is then dovetailed with the ten-year independent load forecast, and the area substation load and capability tables are developed. Options are identified for needed load relief, including increased capability, transfer of load and/or peak demand reduction by DSM.

Through an iterative process with regional distribution engineering, the recommended load relief plan is developed and published as the substations and sub-transmission feeder load relief program. This program is a major feed into the five-year capital budget plan.

Network Distribution Feeder Load Relief Programs

Distribution network feeder loads and ratings are calculated in parallel with the substation and sub-transmission feeder program. The most recent historical peak distribution feeder loads are compared against the network model results (using Con Edison’s circuit modeling tool [PVL]), and any differences are reconciled. The ten-year independent load forecast is applied to the feeders – identified significant additions (i.e., specific new business projects) are injected on the feeders that will serve them, and the remaining load growth is apportioned across the remaining feeders. Feeder ratings and the driving contingency conditions are calculated, and the feeder capabilities are developed.

It is from this analysis that Con Edison conceptualizes new load relief projects. Options are identified for needed network feeder load relief, dovetailing with the area substation load relief options discussed above. Through an iterative process between the Regional Distribution Engineering organization and Transmission Planning, the options are reviewed, and a recommended plan is decided upon.

Con Edison aims to relieve all anticipated primary cable overloads (won’t go above 100% loading), as determined by their analyses. Feeder relief is almost considered nondiscretionary for network feeders, because Con Edison does not have the same flexibility to transfer load as they do in the radial (non-network) parts of the system.

Load relief projects are designed between September and December, so that they can be built between January and June, prior to the upcoming summer loading season. Upcoming summer ratings reflect this work and are published.

Network Transformer and Secondary Mains Load Relief Programs

Network transformer and secondary mains relief follows an identical process as primary feeder relief. The same ten-year independent load forecast and the same network models are run. Transformer and main ratings and the driving contingency conditions are calculated, and the capabilities are developed. In addition to this, any transformer with recorded telemetry (Con Edison’s Remote Monitoring System [RMS]) from any historic peak period indicating capability issues are studied and relieved upon confirmation. All options are reviewed by the regional engineering department and once the plan is accepted, the project is issued to and completed by both the construction and construction management groups.

Conduit Size Restriction

One challenge that Con Edison faces is trying to expand capacity given the space limitations of and damage to existing duct bank systems. In some locations, spare ducts may be crushed or blocked. In others, the size of the spares may not be adequate to pull through the necessary cable to meet loading.

For example, in a design where 750 MCM cable is called for, Con Edison may have to consider running double 500’s because the 750 cannot fit in the 4-inch spare conduit.

The Brooklyn Operation Center noted that about 10% of their ducts are crushed. In Manhattan, the number of crushed ducts is significantly higher, at 45 – 50%.

In some cases, Con Edison bifurcates the feeders; that is, breaks the feeder into two sections outside the station in order to adjust to the limited space considerations and add reliability. In this design, Con Edison installs SF ₆ switches with fault indication outside the station, protecting each leg of the bifurcated feeder. In a feeder lockout, this enables them to isolate the faulted section and pick up the rest of the load. (See the pictures below)

Technology

Load Flow System – Poly-Voltage Load Flow (PVL)

Con Edison utilizes a distribution load flow application called Poly-Voltage Load Flow (PVL). The PVL application is actually a suite of applications that was developed in house over a 20-year period of continued development. In addition to aiding engineers in performing load flow analyses, the PVL system is used to build feeder and transformer models, develop network transformer ratings, develop network feeder and cable section ratings, model area substation outages, and identify short-circuit duty at customers sites, etc.

To perform load flows, circuit models are brought into PVL from the mapping systems. The secondary system is kept in one mapping (GIS) system (different from location to location), and the primary feeders are kept in another mapping (GIS) system. Con Edison reflects all system changes on its mapping systems. Feeder maps within Manhattan are updated in 24 hours as changes occur. Secondary side maps are not updated as quickly, but are very frequently updated. These GIS systems are maintained by the mapping organization.

When the circuit information is brought into PVL, the new information overlays the existing circuit model already in the system. Once the model is brought into PVL, all users use the same model. When a circuit is brought into PVL, people responsible for model maintenance ensure that the PVL model has electrical connectivity and is in synch with the mapping system.

Load flows are conducted for a variety of reasons:

Planning engineers run base case load flows, N-1 cases, and N-2 cases. For each contingency, the PVL output tells you what is overloaded in tabular and graphical formats.
Planning engineers use PVL to assist in short-range and long-range planning. For example, the system is used to analyze conceptual projects to split existing networks into smaller networks
For new business, engineers run the existing case, and then re-run it with the new business load added to understand the loading and voltage implication of the new load.
Region Engineering runs feeder loading studies in advance of the summer to identify anticipated overload conditions.
The system is also used to understand the loading implications of different restorations scenarios in an outage.

PVL can use real-time readings from transformer vaults (gathered through Con Edison’s Network Remote Monitoring System [RMS]) for building the network load model. If needed, demands can be spotted at customer service points, using information such as customer kWh consumption and real-time transformer readings.

The PVL system can also perform cable section ratings. The system considers the impacts of soil type and temperature. The system does not automatically consider the proximity of electrical facilities to steam mains.

Operators are able to take advantage of the functionality of PVL through a real-time version known as AutoWOLF, which takes the base model and applies real-time conditions. For example, real-time transformer loading information would populate the model from RMS system. Knowledge of open feeders would populate the model from SCADA. When a circuit locks out, AutoWOLF automatically runs the system peak case, the current case, and the projected peak case, so that that information is available to an operator. The operator can look at the loading on the other feeders and try to determine which feeders to watch.

During emergency conditions, Con Edison assigns engineers assigned to the control room to monitor system loading. During normal conditions, the operators monitor the system themselves.

Con Edison has formed a PVL users group that meets bi monthly to discuss issues associated with the PVL. The PVL Users group is made up of approximately 50 people from both the regions and corporate, including network model maintenance people, designers, supervisors, engineers, engineering managers, and support personnel. Approximately 15 members attend any one meeting.

7.11.6 - Duke Energy Florida

Planning

Network Planning

People

Network Planning at Duke Energy Florida is organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I), which is led by a Director of PQR&I for Duke Energy Florida.

To perform planning work, the Network Planning group divides the Duke Energy Florida territory into four separate zones. The cities of Clearwater and St. Petersburg, part of the South Coastal Region, are included in one of the four zones. Every zone is assigned a Lead Planning Engineer and Senior Planning Engineer, who are responsible for all distribution planning activities within the zone.

Engineers/Planners in these zones work on Reliability as well as Planning. Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time planning reliability and infrastructure upgrades.

All Planners have four-year degrees in Electrical Engineering, a requirement for the position.

Duke Energy Florida has no written planning criteria specific to secondary network systems.

Process

Duke Energy Florida supplies a true low voltage meshed secondary grid system with three primary feeders in Clearwater, as well as spot network locations in both Clearwater and St. Petersburg. In both St. Petersburg and Clearwater, much urban underground infrastructure is designed in a loop scheme using non-network feeders, and automatic transfer switches (ATS) at major customer sites to provide a primary and reserve feeder supply.

Planners use specific criteria to guide enhancements to underground systems to meet anticipated load growth and additions. However, due to the different underground designs used across the service area, there are differing standards depending on location. For example, non-network primary feeders surrounding downtown St. Petersburg and Clearwater are specified to carry no more than 12 MW each, while downtown feeders that supply the networks, or are part of a primary / reserve feeder loop scheme, are designed to carry no more than 6MW. This planning criteria provides reserve capacity in urban areas of Duke Energy Florida to be able to supply N-1 reliability.

Planning Engineers plan and design both network and non-network systems. For example, in Clearwater the network load is low, and demand growth is flat. Therefore, there are no new grid or network expansion plans underway. However, the planning group is active in adding non-network load to the systems in both Clearwater and St. Pete.

Historically, in Clearwater, Duke Energy Florida had added non-network load to three network feeders, creating reliability and operational challenges. Beginning in 2013, the company embarked on a multi-year improvement project to remove non-network loads from three of the primary feeders, with the aim of having these three feeders “dedicated” to supplying the network. Much of the non-network load is being added to the fourth feeder using underground radial designs (URD transformers, for example), which will serve as a radial (non-network) feeder going forward.

In St. Pete, the company removed its downtown network grid years ago, with only spot network locations remaining. Note that in some locations, existing spot network locations are supplied with feeders that are also part of its loop scheme – these locations create some operational challenges with planned feeder outages. Most of downtown St. Petersburg is serviced with a looped feeder scheme using ATS switches. Any new loads are designed with a primary / reserve feeder supply. For St. Petersburg, load limits are 12MW, with 6MW per feeder in the downtown area. Note that downtown St. Petersburg, unlike many other areas in Duke Energy Florida ’ s service territory, is seeing new demand due to high-rise construction.

When there is a call for any new network service in the four zones, Network Planners model the impact of a proposed new load on the network using CYME®. They perform primary load flow modeling, looking at both normal conditions and contingencies.

In Clearwater, Network linemen also have access to real-time secondary load data on network transformers through Sensus® monitoring. Sensus data is checked twice a day — morning and evening. If there are anomalous changes observed at any location, a crew is dispatched to check the limiters on the suspect secondary feeder.

In the case of large load additions, and for longer-term forecasting, planning will utilize a feeder load allocation program (FLAP). Planners input anticipated annual percent load increase expectations, as well as known spot load additions, as this program will return an overall forecast.

Actions to be taken based on anticipated load growth are based on an engineering analysis and are not informed by a written planning criteria. Note that at the time of the immersion, Duke Energy was in the process of consolidating historic Duke Energy and Progress Electric planning approaches into a system planning criteria, expected to be complete mid-2017.

Technology

Network Planners use CYME Power Engineering software to perform load flow calculations on primary feeders.

Duke Energy Florida does not use software to model their network secondary. Rather, they perform real-time monitoring of secondary loading using a Sensus (Telemetrics) remote monitoring system that provides information from the vault, aggregated at the Network Protector relay. Within the Network Group, information such as secondary loading is monitored twice per day.

The FLAP (feeder load allocation program) is used when larger service loads are planned, as this system will incorporate the impact of significant anticipated load additions on the overall forecast.

7.11.7 - Duke Energy Ohio

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Distribution planning for the network underground system is performed by the Distribution Planning Organization. Distribution Planning is part of Duke Energy’s Power Delivery Engineering. Duke has one Distribution Planning organization focused on its Carolina utilities, and one focused on its Midwest utilities, including Duke Energy Ohio. Within the Distribution Planning Midwest organization, one engineer has been assigned the responsibility to focus on Duke Energy Ohio network planning.

The engineer who focuses on network planning is a four year degreed engineer. This engineer works very closely with the engineering department and the Construction & Maintenance department at Dana Avenue to plan the network.

Process

Duke Energy Ohio’s networked system is designed to n-1. That is, the system is designed to ride through the failure of any one component during a system peak, with only minor overloads to transformers, primary feeders and secondary mains during peak periods.

No scheduled outages are allowed during the summer peak load periods. Maintenance work is normally performed between September and May. If scheduled outages are required during the summer months, they are usually scheduled at night or on Saturdays and Sundays.

The downtown network in Cincinnati is fed by two substations each supplying two main street grids. Note that Duke Energy primary feeders are normally 400 MCM conductors. Substation getaway cables are either 650 CU PILC or 750 flat strap EPR cable in the first section, then 400 MCM for the rest of the feeder.

On the primary side, the planning engineer presently has information about the loading on the primary conductors. Every network feeder is monitored, providing amps, power (MW) and VARS back to the EMS system. The EMS data is saved on a PI server. The planning engineer can access the EMS information on his desktop. The planning engineer has access to good historical information on network loading saved on the PI server.

In performing planning, the planning engineer takes customer load information and adds it to a spreadsheet. The spreadsheet is used by the Planning Engineer to build connectivity between customer meters (loads) and the appropriate secondary network bus section. The spreadsheet enables the Planning Engineer to easily modify the data and perform statistical analyses. Information from the spreadsheets is manually loaded into their network planning tool.

Loading information is aggregated by manhole bus and vault for input into the network model. The planning engineer tracks large new load proposals. Information about new load additions comes to the planning engineer from various sources. Most of the time, information about new load additions comes from the customer project organization. Sometimes the planning engineer is informed about a particular project through participation in an early planning meeting, or through a fault current request.

The load on the network has been flat over the past five years. The planning engineer selects the highest peak for each grid for the last five years and adjusts the model load to meet this peak value. Through this analysis, the planning engineer will identify improvement opportunities in the system to meet anticipated loads. The planning engineer noted that he does not believe that the network and buildings within the network respond to weather the way other loads outside the network do. (Once summer conditions arrive, the load remains proportionally higher than on other areas even with changes in temperature.)

Technology

Duke Energy Ohio is using SKM Power Tools as a network planning tool. Modeling information, such as the connectivity between customer meters (loads) and the appropriate secondary network bus section are entered into the SKM tool.

The planning engineer has focused recently on bringing this model up to date. The model includes the street grid, including transformers by location, and including transformer sizing and impedance. The model has been updated to include new cables that Duke has recently changed. The model also contains updated loading information, including the loading of particular buildings.

This loading information comes from several sources. Larger commercial customers have demand meters. Load readings are housed in the Duke energy billing system and for larger customers (over 300 KW) the customer provides a phone line and loading information flows back to the company’s billing system through the phone lines. The loads of smaller customers, without demand metering, are estimated by the Planning engineer from kWH history.

The planning engineer has utilized the services of a co-op student to audit through the billing system and identify and assign customer loading served off of the street grid to the spreadsheet model (assigning customer loads to a specific secondary bus section).

Model and loading information from the spreadsheets is entered into the SKM power tools product enabling the planning engineer to model secondary load flows.

Note that the updating of the network model is a manual process. The model does not automatically import information from Duke Energy Ohio’s GIS system. Note that Duke Energy Ohio’s GIS system, while modeling primary network feeders, does not model the secondary or tie customers to the secondary network.

A longer term goal of the Planning Engineer would be to have the ability to automatically update the system model for analysis from the GIS with the push of a button. At the time of the immersion, Duke Energy Ohio was in the process of obtaining and implementing a new GIS system.

7.11.8 - Energex

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Planning is performed by the Network Capital Strategy and Planning Group, part of the Asset Management organization. The Network Capital Strategy and Planning Group is led by a group manager.

Process

The planning team works on the development plan, looking at a 10-15 year horizon. The major product of this endeavor is the Distribution Annual Planning report (DAPR), a regulatory required document (Required by the National Electricity Rules of Australia). Energex is required to produce and submit a DAPR annually.

This particular report identifies or forecasts the upcoming limitations of the system.

The planning process is highly regulated, and governed by a set of national electricity rules in Australia.

The work of developing the DAPR includes applying a set of planning criteria to the analysis of the system, and, based on forecasted loading, predicting upcoming system limitations, both thermal and voltage.

The planning process includes a five-year rolling look at the system that includes an annual analysis of anticipated demands on every circuit, substation and substation transformer. Analyses include both normal loading and contingency loading situations. Demand is calculated on every circuit, station, and substation transformer in the Energex system.

When a planning engineer identifies a deficiency, he nominates a project to correct the problem. This nomination involves a high-level description of the work to correct the problem as well as a rough indication of the costs.

7.11.9 - ESB Networks

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Distribution planning at ESB Networks is performed by planning engineers within the Network Investment groups – one responsible for planning network investments in the North, and the other for planning in the South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists” who have developed their expertise through field experience.

Planning standards and criteria are developed jointly between the Asset Investment group and the Strategy group, which is part of the Finance and Regulation group within Asset Management.

Process

ESB Networks has a carefully thought out process for reviewing their planning standards, developing investment plans, and packaging these plans for the price review process that exists within the regulatory agency in Ireland. The planning standards and company investment plans are reviewed and updated every five years. Also, necessary changes to the planning standards are brought forth at monthly management team meetings. The result of these efforts is a comprehensive five-year asset investment plan for meeting their service level targets.

Planners engineer the system to N-1, with most supplies having a “forward feed” (preferred) and a “standby feed” (reserve). The planning criteria for MV distribution requires customer voltages to remain at +/- 5% of nominal in normal situations, and +/- 10% of nominal in a standby (contingency) situations. Planning criteria also call for long-term cyclical overloads of no more than from 125-150 percent of rating for equipment, with a short-term loading of no more than 150-180 percent.

At the time of the practices immersion, ESB Networks has a program underway to convert their 10-kV distribution system to 20 kV. This conversion effort is underway outside of Dublin where the benefits of conversion are more readily realized. Note that the MV primary system serving the city of Dublin is operated at 10 kV.

Technology

For performing MV (10 and 20 kV) and for some 38-kV circuit studies, ESB Networks is using SynerGEE (GL Group). The company has tied this tool to its GIS database. For HV analyses (38 kV and 110 kV), ESB Networks is utilizing PSS® Sincal from Siemens.

7.11.10 - Georgia Power

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Resources in several groups perform distribution planning of the network at Georgia Power. The company has both Area Planning and Distribution Planning. Area Planners are responsible for different areas of the state, such as Atlanta, Savannah, Macon, Augusta, Athens, Valdosta and Columbus and are responsible for the substations in those areas to make sure they have the capacity to handle projected future loads, and contingency situations (N-1). These Area Planners are geographically based both in Atlanta and the southern part of Georgia. Those outside of Atlanta work in offices closest to the areas they are responsible for, while three Area Planners are based out of the company’s downtown Atlanta offices and are responsible for the Atlanta Metro area and a few networks in Macon and Augusta.

Projects of $2 million or less are brought before the Regional Distribution Council for approval. Any projects that require more funding are sent to upper management for review and funding approvals.

Distribution Planners are responsible for loading of both distribution and network primary feeders, and work closely with the network Area Planners. Area Planners are responsible for planning upgrades of substations on the urban networks, while the Distribution Planners are responsible for planning upgrades of the primary feeders. The two groups work closely together. Both groups – Area Planners and Distribution Planners – work with the Network Underground design engineers during the design phase.

Planning of upgrades to the secondary grid is done by principal engineers in the Network Underground department.

Process

Although Area Planners are not responsible for the network loading, they are responsible for the load on the transformers. Therefore, the Area Planners must know the configuration and cable load of the entire urban network. Area Planners evaluate contingency reserve capacity to maintain N-1 reliability of the network. For example, if Georgia Power has three transformers at a substation, and one of the transformers supplies the Network, then one of the responsibilities of an Area Planner is to insure that if the Network Bank fails, for whatever reason, the other two transformers have enough reserve capacity to pick up the full load of the failed network bank. This guarantees a high level of customer reliability. As a result of this strategy, network substations are sized accordingly, so that they have enough capacity to handle any network segment with only two transformers regardless of the peak load.

In Georgia Power’s network design, all network feeders are dedicated to the network, which is a leading practice. Feeders supplying any one network are sourced from the same substation bus. Only in a rare, emergency case would Georgia Power attempt to temporarily supply non network load from network feeders. The preferred plan is to always have dedicated network feeders for each network.

The only exception to this case is the city of Atlanta rapid transit system, MARTA. Here Georgia Power puts a distribution feeder on the network bus. The MARTA system is all in duct line, however, and is well protected, so the chance of exposure to an outage or disruption is minimized.

Georgia Power predominantly has network-only substation transformers reserved especially for the network grid, and distribution-only substation transformers for the radial or overhead distribution. There are a few that are mixed (supplying both network and non-network load) – but these are the exceptions. Network substation transformers do not tie to radial distribution anywhere else in the field. There has been some work done to install ties between network primary feeders to be used only in emergencies. These ties are manual at this time, and the network underground group is moving toward automatic ties. There is no intent to tie network sub transformers to the distribution side as it would affect planning and network operation throughout the system.

The network planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new forecasted loading. Network planning is based on a peak load analysis, recognizing that the peak is only representative of loading for a few days each year. In developing the load forecast, engineers will consider known projects, estimated future load additions from areas under development, such as downtown Savannah and Buckhead, and general growth rates. Engineers will also temperature adjust their load forecast based on previous historical data of high-peak temperatures, averaged over a number of years. Area Planners look four years ahead, forecasting the need for more capacity based on impending projects and demographic demands, such as the newly planned baseball stadium in Atlanta.

Area Planners trigger network planning changes based on the data they have, including the aforementioned load forecasts. In addition, Area Planners meet with senior engineers, marketing, and distribution engineers, every five to six months. The group examines proposed customer projects that are in the pipeline and determines whether the projects will be distribution (radial) based or network-based. The frequency of the meetings is a direct result of the number of projected projects and the likelihood they will come to completion. For example, it was projected that the Buckhead area would experience tremendous growth, and the Area Planners and Georgia Power anticipated the need for another substation in that area that would serve a new network grid; however, the economy faltered and the project was put on hold. It is only now, after an economic recovery that the substation is back on track for construction and completion. In general, when an area planner anticipates hitting 90 percent of the rating of the substation transformer in their planning outlook, they develop load relief projects. Because of the time required to get a project completed, planners start looking into solutions when the transformer is 80 percent loaded.

One of the notable practices at Georgia Power is its highly organized and consistent approach to cable and duct line placement (See Figure 1.). (See Network Design, Peachtree Racking in this report). Georgia Power’s design calls for primary feeders to be located in the bottom ducts, with secondary feeders located in the top duct lines.

Figure 1: Peachtree racking example

The Atlanta urban area has 35 networks. Some of them have secondary grids (street mains) and spot networks, while others have only spot networks.. Each is fed by three to six feeders with a primary voltage of 20kV. There is one small 12kV network in Atlanta. Georgia Power uses both ring-bus and split-bus substation designs, depending on the existing infrastructure, as both Atlanta and Savannah have older network systems in place. In other networks outside Atlanta, other voltages are supported, mostly due to legacy installations as well.

The secondary grid in Atlanta is 120/208V. While some utilities, such as SCL, run a true 480V grid, Georgia Power does not maintain any 480V grids. Georgia Power does have many 480V spot networks, however. The typical design includes multiple transformers located within a customer vault, supplied by network feeders, to supply a large customer (a high rise, for example). The Georgia Power terminology for a spot network service is a “vault service”. Note: Georgia Power may also use the term “overhead spot network” to denote locations where they supply a true spot network service from two overhead systems, typically in cases where a customer wants the reliability of a networked system, but where no network feeders are available.

A fairly common non-network design offered by Georgia Power includes supplying service with a primary feeder and alternate feeder with an automatic transfer switch between the two. A standard PMH transfer is used (not a fast transfer).

In some downtown areas, only network service is available. In other areas, only radial distribution service is available. A few areas have both network and non-network service available, and the customer can choose.

Georgia Power does not charge different rates for a network service and a non-network service, but new network customers may have to pay a capital contribution. Also they acknowledge that the upfront costs to the customer for a network service are higher due to factors such as the need for more area, higher rated service equipment, etc.

In the case of distribution customers that are supplied from two energy sources, they may or may not pay for reserve capacity. For example, in the past Georgia Power has used a “flip-flop” scheme for nursing homes, in which the backup feed is used only when needed. Now, if the feed is dedicated solely to one customer, the customer typically pays for that reserve capacity.

When pricing out the upstream reserve capacity charge, engineers must take into consideration whether it will be delivered by overhead line, underground, or a “flip-flop” configuration. Each delivery mechanism has a separate cost associated with it, and is put into the pricing calculations. If the customer is paying upfront costs, Georgia Power factors in both primary and secondary installations, mainly to cover its costs and future maintenance.

In the case of street main service, where there is little or no installation overhead but a decrease in available capacity, Georgia Power has factored in a “cost to serve” into the customers rate. This is especially true in Savannah, Georgia and other areas where downtown renovations and revitalization is placing greater demands on the grid and its maintenance.

Customers in a network area who request 208V services will usually be connected to the secondary network grid if one is present. Customers who request 480V network service may be served by a spot network in a below-grade or above-grade vault Above-grade vaults are usually not practical in the congested parts of downtown Atlanta unless the customer can provide vault space in their building. Thus, the most common design type for larger loads in downtown Atlanta is via an indoor vault with a 480V secondary spot network.

The indoor transformer vault contains two or more transformers. The vault is built by the customer based on Georgia Power guidelines. Before the transformers are mounted and energized, Georgia Power engineers inspect the customer vault to make sure it meets their functional requirements.

Georgia Power provides two or more primary supplies coming into the customer vault. One notable practice of Georgia Power is to fully insulate the secondary collector busses, which are 2000 MCM, 600 V copper, with a full EPR jacket (See Figure 2 and Figure 3.).

Figure 2: Secondary collector bus with EPR insulation

Figure 3: Secondary collector bus with EPR insulation cross section

Technology

Georgia Power has recently acquired CYMDIST to model the entire secondary and primary grid (See Figure 4.). The program is designed for planning studies and simulating the behavior of electrical distribution networks under different operating conditions and scenarios. It includes several built-in functions that are required for distribution network planning, operation and analysis. The model Georgia Power has developed is extremely accurate including cable systems, cable ratings, cable capacities and specifications. The Area Planner keeps detailed spreadsheets, continually updated, on upcoming and ongoing projects. The Georgia Power GIS system also tracks network statistics, so that if a particular network segment reaches a threshold, it is tagged for analysis by the Area Planner and Network design groups. Typically Georgia Power prefers to keep capacities in the 70 to 90 percent range, and any transformer or network segment exceeding 90 percent is prioritized and tagged for the Area Planner and engineering for more capacity.

Figure 4: CYMDIST 7 Distribution Network simulation software with Network Editor

7.11.11 - HECO - The Hawaiian Electric Company

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Network Planning at HECO is performed by Distribution Planning Division at HECO. The Distribution Planning Division is part of the System Integration Department. The Distribution Planning Division group performs all distribution planning at 46kV and below.

The group is led by a Principal Engineer and is comprised of one lead distribution engineer, and 5 Planning engineers who do all of the distribution planning work for the island of O’ahu. All of the engineers in the group are four year degreed engineers.

HECO has a documented planning criteria document. Each year, HECO planning engineers perform studies of the system using load forecasts based on historic peaks and anticipated load growth to identify places where either system loading limits are exceeded or other violations of their planning criteria are encountered. It is from this analysis that reinforcement projects are conceptualized.

Their distribution system is designed to N-1; that is, they plan their system such that all the system components, including primary feeders, secondary cable mains and taps, and transformers, are sized to be able to carry the load within specified thermal and voltage limits during peak conditions when any single component is out of service.

Process

The anticipated loading on the system is estimated by using the historic peak loading from the previous year as measured at the substation transformer, and apportioned to the feeders based on periodic loading measurements called “Tong Tests”. Historic load readings from demand meters and projected new loading information gathered from their Customer Installations Department (CID) is combined with this estimate to create a projected load profile for each feeder that is used for analysis.

HECO maintains a system power factor of 93%. They do have tariff language that requires customers to maintain an adequate power factor or incur penalties.

HECO’s Planning Criteria does not specify or limit the number of feeders that can be run in the same duct bank or conduit.

Technology

HECO historically has not used a load flow software product to aid them in distribution planning. They gather and record feeder loading and transformer loading information using an EXCEL spreadsheet. Load flows are calculated manually.

HECO is in the process of installing SynerGEE, a load flow software product from GL Industrial Services. This product will interface with HECO’s GIS system and be able to import up to date circuit models. They are targeting year end (2009) for implementation of this software.

HECO is performing secondary load flow analysis of their secondary network using the PSSE program from Siemens PTI.

HECO has limited SCADA on the distribution system, with less than 20% of the feeders having SCADA at the station. HECO has virtually no SCADA beyond the station fence.

In addition to Distribution Planning, the System Integration Department at HECO is comprised of Renewable Energy Planning, Transmission and Generation planning, a Protection group and a group that focuses on AMI.

Four times per year, HECO will perform a “Tong Test” of each feeder. The Tong Test is an amp reading taken on each phase of each feeder. One measurement is taken in the summer, one in the winter, one at night, and one during the day. These measures are used by Planning to apportion measured transformer load to each circuit.

7.11.12 - National Grid

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

At National Grid, network planning is performed by the Distribution Planning Organization, led by a Director. Organizationally, the Distribution Planning Organization is part of Distribution Asset Management, and is comprised of resources in both a central location (Waltham Massachusetts), and distributed throughout National Grid (Field Engineers).

Centrally located resources include capacity planning resources who reporting to a manager, and engineering personnel, who have broad system planning and engineering responsibilities, Regionally located resources include field engineers who report to managers of Field Engineering for both New York and New England, About two thirds of the Distribution Planning organization is centralized, with the remaining third decentralized.

In general, short term planning activity (current year) is led by the field engineers located in the regions. Longer term analyses (future years) is led by the central planners

The planning engineers who focus on the Albany network include a field engineer who works in the Albany office and focuses primarily on both radial and network underground systems for National Grid’s New York Eastern division, and an engineer situated in Waltham, who has network engineering responsibilities across the system. These engineers have responsibility for both network planning and network design.

Both of these engineers are four-year degreed engineers, and are not represented by a collective bargaining agreement (exempt).

National Grid has up-to-date standards and guidelines for the network infrastructure. In addition they have up-to-date planning criteria that address network planning.

Process

National Grid has SCADA installed to monitor loading at the substation. They are able to obtain historic 15 minute interval load data as measured at the substation.

Planning engineers use this information as well as information from National Grid’s customer information system to develop distribution feeder models. Customers / customer load are assigned to certain network busses to model the system. Engineers model the system at peak load, at 90% of peak load, and in the n-1 and n-2 contingency situations.

Distribution planning analysis includes analysis of both potential thermal overloads and voltage issues. When assessing loading impacts of devices such as transformers, National Grid uses 120% of nameplate for single contingency and 140% of nameplate for double contingency.

The network in Albany is summer peaking. Typically, planning studies for the network are performed in the spring and may project anticipated system loading multiple years in the future. In addition, the analysis may also include a fault current analysis to understand the ability of the system to properly clear faults. Note that while modeling and analysis for non network feeders occurs annually at National Grid, modeling and analysis of network feeders is not performed every year, and typically involves a multiple year projection of loading.

In the spring of 2010, planning engineers looked at the Albany network using 2009 monitored data and models as a base, and determined projected system loading for the summer of 2015. This longer-term view enabled them to develop a five-year construction plan for reinforcing the network. The analysis included thermal analysis, which looked down through the secondary as well to understand the thermal impacts on the secondary mains. Note that this analysis did not look at individual service conductor loading in the network. As part of this analysis, planning engineers also performed a fault current analysis to understand the expected performance of the system for solid faults in the secondary cable system.

National Grid’s process for reinforcing the system is that after performing the analysis planning engineers recommend capital improvements. Major capital improvements, in excess of $1 million, flow to a distribution capital investment group, an internal committee that reviews and approves funding for major investments. Capital expansions under $1 million follow an internal National Grid level of signature authorization (LOSA) procedure.

The study performed in the spring of 2010 resulted in the development of an investment proposal to the Albany network that includes the installation of network protectors, secondary cable installations, and secondary manhole mole and ring bus installations.

Technology

National Grid planning engineers use the PSSE power flow product to model and perform power flow analysis of the network system, and use a product called Aspen to perform fault analysis. (The Aspen product is also used by the System Protection group at National Grid.)

Note that the PSSE power flow product provides steady-state analysis. It cannot model network protectors (for example, back feed through the protectors).

In non-network areas, National Grid uses CymDist as a modeling tool, which has been integrated with their GIS system. National Grid has not applied this to the network system, as their GIS system does not model a meshed system.

7.11.13 - PG&E

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Network planning is performed by the Planning and Reliability Department. This department is led by Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two planning engineers are responsible for distribution planning. One of the two network engineers is relatively new to the department, and was assigned to receive training from the lead network engineer.

Both network planning engineers are four year degreed engineers. They are represented by a collective bargaining agreement (Engineers and Scientists of California).

Process

PG&E has secondary networks in both San Francisco and Oakland. They have 12 total networks, 10 being supplied by 12kV feeders and the other two, 34.5kV feeders. Each individual network system sourced at 12 kV is fed by six dedicated network feeders. Of the two 34.5kV sourced networks, one is fed by four feeders and the other, by five feeders.

Secondary network grids are 120/208V. Secondary network spots are at 120/208V and at 277/ 480V.

The downtown networks in San Francisco are fed by 4 substations, and the Oakland networks are fed by 2 substations. 12 kV primary feeders supplying the networks are typically PILC, and the 35kV are XLPE. When replacements are necessary, EPR cable is installed.

Each network is served by feeders supplied from a single substation. However, some feeders supplying a given network are fed from separate transformers at the station. In some cases, PG&E has experienced some challenges with circulating currents, such as unintended network protector operations. At the time of the immersion, PG&E was implementing changes to resolve this issue, such as redesigning the substation configuration to supply all feeders to a particular network from the same substation transformer.

PG&E customers in the network are charged standard residential rates, consistent with the rates charged to radial customers. Somewhere less than 5% of their electric revenues come from their secondary network systems.

PG&E’s network system is designed to n-1. That is, the system is designed to ride through the failure of any one component during a system peak, with only minor overloads to transformers, primary feeders and secondary mains during peak periods.

PG&E does not plan any new networks, but they will add load to the existing networks.

The planning process involves running load flows to compare system loading to the feeder ratings and to evaluate the implications to the system of anticipated new loading. Network planning is based on a peak load analysis, recognizing that the peak is only representative of loading for a few days each year. Planning engineers obtain monthly peak loads from the SCADA historian^[1] and compare this to feeder ratings. Engineers may enter the SCADA readings into the load flow model and recalculate to see if there are any overloads. Alternately, they may simply compare the monthly peak values to previous peak load readings and circuit ratings. Planning engineers will ascertain the validity of any projected new load estimates, and run load flows to understand the implications of added load.

Designing for the peak provides conservatism to the planning process. Planning engineers report that actual loading is always lower than the loading projected by their load flow models, as these models are based on peak values and do not account for load diversity.

If the calculated circuit loading exceeds 110% of the either the circuit’s normal or emergency capacity ratings, the planning engineer will consider the circuit to be overloaded and recommend design changes to ameliorate the overload condition. PG&E uses the 110% level based on the fact that their load flow model uses all peak load values and thus doesn’t account for diversity. So, rather than reacting to modeled loads over the 100% rated values of circuits, they add the additional 10% since they know their models are conservative. They do this analysis for both base case and for contingency situations. (Six different contingency models are run, one for each primary feeder supplying a network).

Cable emergency ratings are set at 110% of nominal. Transformer emergency ratings are set at 130% of nameplate. The planning criteria specify the number of hours that a device could be expected to operate at the emergency rating (varies from between 24 to 48 hours).

In San Francisco, planned feeder outages to perform maintenance are taken at night, in lower load periods, and returned to service for the day. In Oakland, planned feeder outages for maintenance are taken during the day, as the network is lightly loaded. Often, these planned feeder outages may last for one week.

Technology

PG&E uses the EasyPower load flow product from ESA to model their network system. This model is manually populated and maintained by the planning engineer. The planning engineer reports being satisfied with this planning tool.

Note that PG&E is presently implementing the CYMEDIST,(by CYME) load flow product for performing analysis of their radial system. In a subsequent phase of their project, they plan to implement the use of CYMEDIST as their network planning tool as well. A challenge for them will be the conversion of data from EasyPower to CYMEDIST.

^[1] PG&E’s SCADA provides three phase amp readings on all network feeders. Also, they have the ability to monitor loading on all network transformers through CT monitoring installed on the transformer secondary (at the NP). This information is housed in the PG&E SCADA Historian.

7.11.14 - Portland General Electric

Planning

Network Planning

People

PGE’s network system includes many facilities that customers co-design and co-own, so system planning for the network involves many departments with overlapping responsibilities. Because the process assembles experts from many areas of the company, system planning is based upon good project management and a multi-departmental approach.

Transmission and Distribution Planning: Across PGE, the Transmission and Distribution Planning (T&D) organization oversees the planning process for network and non-network systems. The Distribution Planning Department working within this organization employs five Distribution Engineers and an experienced manager with previous experience as a network distribution engineer. A planning engineer with a four-year degree in engineering covers the Portland Service Center (PSC), which includes the network.

Distribution/Network Engineers: Three Distribution Engineers have responsibilities to provide engineering services for the underground network. These engineers also work with customers to design and operate customer-owned facilities associated with network infrastructure. The Distribution Engineers are not physically based in the PSC service center or CORE group, and are overseen by the Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to perform certain design tasks associated with the civil infrastructure, including vaults, manholes, and duct banks.

Project Management Office Group: The Project Management Office (PMO) manages the larger, more complex projects. This group, which is part of the Transmission and Distribution organization, is involved in in the early stages in coordination with System Planning, and assumes responsibility for projects once the Planning Engineers have developed a shortlist of solutions. Because of an increasing number of more complex projects, PGE is expanding its Project Management Office Group.

One project manager within the PMO has responsibility for all projects in the CORE, including complex projects such as building a new network substation. The present project manager has a Project Management Professional (PMP) certification and project management experience with another utility. The PMP designation is not necessarily a requirement for T&D Project Managers.

Service & Design at PSC: Service & Design’s role is to work with new customers or existing customers that have new projects; so, they are responsible for new service connections, and upgrades to existing services. The supervisor for Service & Design’s wider responsibility includes the downtown network. The supervisor reports to the Service & Design Manager, who is a peer of the Distribution Engineering and T&D Standards manager. Both of these positions report to the General Manager of Engineering & Design.

The Supervisor of Service & Design at PSC and their group undertakes customer-initiated capital work. A “Mapper/Designer” reports to the Supervisor of Service & Design at PSC and provides the computer-aided design (CAD), geographic information system (GIS), and design service. A Field Inspector meets contractors in the field. Two inspectors work for the Service & Design organization, and one specializes in the network.

Service & Design Project Managers (SDPM): Network planning associated with customer-driven projects requires regular coordination with the customer throughout the project life. PGE has a position called a Service & Design Project Manager (SDPM), who works almost exclusively with externally-driven projects, such as customer service requests. At present, two Service & Design Project Managers cover the network and oversee customer-related projects from the first contact with the customer to the completion of the project. They coordinate with customers to assure that customer-designed facilities comply with PGE specifications.

The SDPMs can be degreed engineers, electricians, service coordinators, and/or designers. Ideally, an SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. In addition, SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC) safety codes and the ability to use or learn the relevant information technology (IT) systems. PGE prefers a selection of SDPMs with a diverse range of experience and backgrounds.

SDPMs work on both CORE and non-CORE projects. This ensures that expertise is distributed and maintained across departmental and regional boundaries.

Process

Planning Process

The T&D Planning organization identifies the need for a project and undertakes studies to assess the lowest cost solution that will resolve the issue. When planners highlight a problem, they initially identify between three and five potential solutions, before choosing the lowest cost, least risk solution and proceeding. At that point, a schedule and estimate for the project are developed before it is handed to the PMO Group. They assemble a project team that includes representatives with a range of experience, depending upon the type and scope of the project. The assembled team visits the project site, or multiple sites for a combined substation/line project, and determines the scope before submitting a project for approval.

In the future, to streamline the process, Distribution Engineering will identify the project and potential solution before involving the PMO Group, who will develop the estimate and schedule before sending the project to the Corporate Capital Review Group for funding approval. Previously, the PMO only became involved when project funding was approved. With the new process, the PMO becomes involved much earlier and provides more accurate estimates and scheduling, alongside detailed engineering studies, before a project is approved. PGE amended the process because, with the existing system, little engineering analysis was undertaken and costs often escalated after approval due to the lack of detailed information. This complicated accurate assessment of the true costs and potential risks.

One concern with the new system is that engineers will spend time performing preliminary studies and, if the project is not approved, the upfront time commitment will waste resources. Therefore, it is important to promote better synergy between engineering and the PMO to streamline the project management process leading up to approval. Once a project is approved, the PMO will escalate the process and work with the team created during the estimating and scheduling phase of the project to plan, engineer, permit, and construct the project.

For internally-driven projects, the PMO oversees the project development, while for externally-driven projects, SDPMs usually oversee the project. For external projects, the PMO is only involved for large projects with complex coordination requirements. Depending upon the makeup of the project team, the engineering group may control the entire project and only involve the PMO if problems arise, such as a risk of missing deadlines. For other projects, the PMO may be more intimately involved.

At present, the PMO focuses mainly on the transmission system, and the group is only involved with distribution projects where they connect to larger transmission projects, such as the Marquam Substation project. The PMO generally works with larger projects that require a high level of coordination between multiple groups. The PMO does not work directly with equipment and material vendors, because this is the responsibility of the Materials Coordinator. The PMO is heavily involved with scheduling and offers an opinion about the resources required.

In general, no official processes determine whether a project or task should use internal or external resources, because this depends upon the available internal resources and the preferences of senior engineers and project managers. On the distribution system, many of the tasks require local knowledge, workmanship, and expertise, so PGE is more comfortable with internal crews undertaking the work.

Overall, the CORE Planning Engineers spend 10-20% of their time planning the network system, with the remainder on the radial system. At present, written planning criteria informs network planning. PGE does not have written design criteria.

Load Reduction and New Customers: As a wider philosophy, PGE is trying to maintain the network and reduce loads where possible. If a new customer enters the system on the periphery of the network system, they are usually added to the radial system rather than the network. The reason for this approach is that networks are expensive to maintain and build, so network access is reserved for customers with connections lying well within the network.

Customers on the periphery can request an alternative service to ensure reliability, which includes a service agreement and payment for the contingency service and the reserve capacity needed. This can also depend upon the load, with the enhanced service provided free for customers requiring over 18-MW loads. Customers with loads under 4 MW pay only for the feeder, and customers with 4-18 MW demands pay for the substation capacity.

Reporting: To support network planning, the Planning Department creates bi-annual loading reports, known as the “Weak Link Report,” which covers both the radial and network systems. The report examines the system peak loading for the summer and winter, using network data sourced from the substations. At present, other monitoring data received from the network is not used for modeling or planning, and is reserved for operations.

For the Marquam project, PGE produces weekly reports that summarize aspects of the project. This periodic reporting is more aggressive because of the size of the Marquam project, and the need to monitor and coordinate many tasks. The report is sent out to the various groups involved in this project.

Standardizing: Overall, PGE is improving its processes for documenting and standardizing equipment and procedures on the network. For example, when planning the new system layout, duct banks, known as duct packages, will contain no more than two feeders per network in any duct package to reduce the chance of vault fires.

Project Scheduling SharePoint: On a monthly basis, Project Managers maintain a project schedule for their individual projects and post those to a SharePoint site. This site also includes:

Forecast cost information
Actual cost information
Brief report of monthly activities
Link to the schedule
Other commonly searched documents
This information is not commonly shared with other groups. Project Managers issue weekly reports to the PMO manager, which takes the form of a bulleted list of task updates. T&D Planning Engineers perform shorter term studies and share the results with stakeholders via SharePoint. These results are used to justify potential capital projects.

PSSE Load Modeling Software

For the network system, PGE uses the Siemens PSSE modeling software for both the primary and secondary network. Currently, operators manually enter secondary loads into the PSSE system. Planners collaborate with Distribution Engineers to obtain the most up-to-date model in PSSE, and any loading updates are entered manually. The load data is derived from the customer meters, which is presently a labor-intensive process. PGE’s network load is relatively flat, but the utility is anticipating an increase in the next few years due to an expansion of the retail sector in the downtown area.

PSSE was used to develop and model a sequence of steps when splitting the Stephens Substation secondary network into two four-feeder configurations. System planners used PSSE modeling software to perform load analyses using peak demand data drawn from metered accounts on the network. PSSE was used to assign appropriate nodes to the metered accounts, and the load was scaled to match a coincidental summer peak loading patterns.

This was used to develop a base case scenario with the loadings and voltage on lines, equipment, and buses for the Stephens network. Planners were able to ensure that no line would be loaded more than 100%, no grid transformers would be loaded more than 140%, and no spot network transformers would be loaded more than 130% during peaks. Base loadings specified that no line should be loaded more than 88% and that no transformer should be loaded more than 70%. Where outages would see equipment potentially exceed the loadings, PGE identified equipment upgrades [1].

Technology

PGE uses a number of IT systems to model the system and plan projects. PGE uses CYME/CYMDIST to assess the reliability benefits of projects on the radial system, and planners use the software to develop a base case and evaluate the system under N-0 and N-1 contingencies. For modeling the network system, engineers use Siemens PSSE software for the primary and secondary network, using data from customer meters to develop a base case and highlight where normal and peak loading exceeded recommended limits.

Because PSSE is unable to monitor single-phase loads and cannot model loops, PSC will add the secondary network to CYME, using the GIS system to model and display loops. For mapping, PGE uses ArcFM, and is presently working with the vendor, Schneider Electric, to enable ArcFM to pass information to CYME for secondary network modeling.

PGE uses an Enterprise Resource Planning (ERP) system called PowerPlan, which has an Oracle attachment named “Pace.” This system provides canned financial data about projects. Other technologies used for planning include SharePoint, Field View, the PGE Engineering Portal, PI ProcessBook, and the T&D Database.

Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.

7.11.15 - SCL - Seattle City Light

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

People

Organization

Network Planning at Seattle City Light is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A: SCL - Org Chart .The Network Design Department focuses exclusively on the planning and design of SCL’s networks.

Although SCL does have a separate planning group that performs distribution planning activities for SCL’s non-network distribution system, this group does not do the planning associated with the network. All cable ratings, load flow and voltage studies, master load flow analysis, assignment of feeders to load additions, area studies, etc. associated with the network are performed by the Network Design Department staff. (Note that SCL is currently implementing an Asset Management organization. At the time of this writing, SCL had not yet decided whether certain tasks currently performed by the Network Engineering group will be moved into the Asset Management organization.)

The Network Design Department is made up of a System Group (eight engineers) and a Services Group (eight engineers). These engineers do all of the planning and engineering for the network (the System Group), as well as interface with network customers for load additions, new loads, etc. (the Services Group). The individuals in this group are four-year degreed engineers. The senior level engineer position at SCL requires a PE license. The engineers at SCL are represented by a collective bargaining agreement (IBEW).

Culture

The Network Engineering group has a close working relationship with the Civil and Electrical construction and maintenance groups within the Area Field Operations – Network Department and the Distribution Operations Department. EPRI observed high levels of mutual respect between these groups, and high confidence by the field organizations in the planning and design decisions made by the Network Design Department.

SCL has remained committed to the network engineering department staffing levels, hiring new engineers into the network area to fill vacancies. SCL has no formal training program for network engineers. However, network engineers are sent to special classes on network equipment, etc. as part of their ongoing development.

Process

Planning Criteria

SCL has defined and documented network design criteria for Feeder Loading, Electrical System Construction, and Civil Construction (see below). SCL’s network system is designed to maintain N-1 load capability at peak load. More specifically:

Network Design Criteria for Feeder Loading

Load feeders to maintain N-1 load capability at peak load.
Limit feeder imbalance to 20% at N-0.
Keep load current within constraints determined by loadflow and ampacity studies for existing plant.
Keep load current within constraints determined by loadflow and ampacity studies for new construction.
Account for diversity factor during feeder loading analysis.

Network Design Criteria for Electrical System Construction

Allow no more than two mainstem cables from any one sub-network per MH or street vault. There may be mainstem cables from other sub-networks present (subject to the same restriction) as well as branch cables.
Allow no more than four lateral feeders from any one sub-network per MH or street vault. This may change as a result of studies for ampacity evaluations of feeder laterals with high loads or near steam lines.
Size new mainstem feeders to match substation capacity, with allowances for feeder imbalance and reliability.
Require two half-lapped layers of arc-resistant tape to each primary feeder in MHs and street vaults.
Limit DC Hi-pot testing of 15-kV class cables to a maximum of 26 kV DC and 28-kV class cables to a maximum of 47 kV DC.
Use VLF testing for newer cable testing if separable from older cable sections. Note: This particular requirement has not yet been implemented. SCL is still examining the merits of VLF testing for cable
Do not allow construction of new 480-volt secondary grid networks.
Use limiters on both ends of all secondary bus ties.

Network Design Criteria for Civil Construction (Street Facilities)

All duct banks shall be encased in concrete.
All new system duct banks shall have 5-inch diameter conduits for system cables.
Steel ducts are required for shallow construction.
Every effort shall be made to install new duct banks a minimum of 15 feet away from any steam logs. If new duct banks will be within 15 feet, a cable ampacity analysis is required to determine potential mitigation actions.
If a duct bank must cross a steam log, insulation must be applied per SCL construction guideline NDK 150.
Fluidized thermal backfill (FTB) or controlled density fill (CDF) may be used to backfill around encased service ducts.
Use only fluidized thermal backfill (FTB) around encased system ducts.

Cable Rating

SCL rates cables at 90 ˚ C; that is, they develop a cable ampacity rating that limits the conductor heating to 90 ˚ C. SCL does not develop an emergency or 24-hour rating for feeders. They plan their system to the 90 ˚ C limit.

SCL develops feeder specific ratings based on field conditions. Using software, they develop ampacity ratings for circuits that consider factors such as cable type, duct bank configuration, soil resistivity, proximity of foreign utilities, design temperature (90 ˚ C), load factor (80%), etc. SCL performs both a summer and winter analysis. The summer ratings, which are the most conservative, are typically used for planning purposes.

SCL re-rates cables any time conditions in the field change that could affect cable rating, including the addition of another parallel circuit, the addition of a foreign utility such as a steam line, a new cable in the duct bank, etc.

The specific cable ratings are entered into the load flow software for planning analysis.

Load Flow

SCL conducts a master load flow analysis twice per year using “extracts” from their monitored loading data after the summer and winter of each year. This master load flow analysis is performed on all network feeders. The analysis is performed by the Load Flow

Engineer within the Network Design Department. This process is one of the drivers of reconductoring projects.

(Note: many feeders are analyzed more than twice per year because of load increases – see feeder assignment process discussion in next paragraph.)

SCL also performs a feeder load analysis as part of their Feeder Assignment process in response to anticipated new load. The term “Feeder Assignment” means determining which feeder or feeders will serve a new network load. A Network Services engineer requests the feeder assignment based on a new or supplemental load need. The System Engineer within the Network Design department performs an analysis to determine the best scenario for serving the new load. This analysis includes ensuring that the network design criteria are met, and that any feeder imbalance is restricted to less than 20%. (Note that about 80% of new load is served as a spot network, rather than tapping the existing network secondary.) See Attachment B: Feeder assignment workflow sequence , for a flow diagram of the Feeder Assignment Process.

When SCL performs a load flow analysis, they start off with the worst case (no accounting for diversity). They then re-run the case after applying a diversity factor.

Network Secondary

SCL has existing 208 and 480 V secondary networks. SCL will not expand the 480 V network, because of the potential for having a sustained arc at 480 V.

Spot network services to new large load buildings are normally supplied at 480 V.

SCL has high fault duty in their downtown area (100000 A).

Technology

Cable Rating

SCL has been using a mid-1990s cable rating computer product called USAmp developed by USi. Within this software, SCL maintains a file containing cable specifications. The software enables planning engineers to specify the Rho (ρ – resistivity) based on the use of concrete duct bank, the diameter and wall thickness of the duct bank, pertinent dimensions such as the distance between conductors and between conductors and the wall of the duct bank, and other components such as the load factor and design temperature. The software generates cable ratings that are used for planning. SCL is currently using a cable rating product developed by CymE. SCL will also be using ETAP, which performs cable rating as well.

Load Flow and Voltage Drop

SCL uses a load flow and voltage drop analysis software package developed in house (legacy software). The software is nodal but not graphical. To perform load flows and voltage analyses, SCL engineers can call up a feeder, enter the changes, and solve the case. The output report is tabular, not graphic. The output indicates the load flow and voltage at each node.

SCL is currently evaluating third-party-vendor-developed load flow programs to replace their existing legacy program to provide graphical displays and to address ongoing enhancement, reporting, and maintenance needs.

Network Maps and Asset Records

SCL utilizes a home-developed system called NetGIS. NetGIS is their repository for network asset records, and also the product they use to produce network maps. NetGIS is not a full, graphical GIS system with electric connectivity. Rather, it enables SCL to produce CAD maps, and to maintain records associated with each network vault. Note that their load flow analysis product is not tied in with NetGIS.

More specifically, SCL personnel can obtain maps from the system, and can click onto a vault to obtain a description of the equipment contained in the vault including:

Splice type and information
Ductbank configuration
Civil information
Ground points
Busbar

When a change is made to the network, the GIS section updates the network feeder maps in NetGIS.

Remote Monitoring of the Network

SCL has installed a system developed by DigitalGrid, Inc. (formerly Hazeltine, and referred to by SCL employees as “the Hazeltine System”) to monitor their network equipment. This system uses power line carrier (PLC) technology for communication. (Communication signals are sent through existing utility power cables) SCL has been using this system for years, and has some degree of remote monitoring in all network vaults.

The DigitalGrid system is used to monitor:

current
network protector status
voltage
power factor
digital and analog sensors
vault ambient air temperature
various flags, such as:
- B - Network Protector Open
- C – Transformer Oil Temp
- E – Transformer Oil Level
- G – Smoke (currently being piloted)

The system also has alarm features for current, voltage, network protector pumping, sensors, and flags, and is tied in with the Distribution Operator consoles.

SCL utilized a pilot approach to evaluating and selecting their monitoring technology. They established pilots with products from three different vendors. In the process, SCL evaluated not only monitoring capability, but also control technology, because they are interested in implementing distribution automation in their network. (More specifically, they are seeking ways to be able to remotely operate network protectors, and to shift load from one primary feeder to another.) The result of this evaluation was that the DigitalGrid system that they have in place best suits their monitoring needs. SCL is still interested in piloting network distribution automation.

Other Planning Technologies

SCL is using the EPRI PTLoad product to assist them in rating transformers.

SCL is just beginning to use a harmonics and arc flash product from SKM.

7.11.16 - Survey Results

Survey Results

Planning

Network Planning

(Distribution Network Planning / Planning Criteria)

Survey Questions taken from 2015 survey results - Planning

Question 37 : In your typical network design, do all primary feeders sourcing a given network originate from the same substation, or do you source networks from multiple stations?

Question 38 : Are network primary feeders planned and designed as dedicated feeders?

Question 39 : Do switch points exist on your network primary feeders for the purpose of sectionalizing a network feeder?

Question 42 : Does your design limit the number of primary feeders entering a vault or a manhole?

Question 45 : Which of the following best describes your approach to loading your network?

Question 77 : Do you have any additional network “system hardening” initiatives underway?

Survey Questions taken from 2012 survey results - Planning

Question 3.3 : In your typical network design, do all primary feeders sourcing a given network originate from the same substation, or do you source networks from multiple stations?

Question 3.4 : Are network primary feeders planned and designed as dedicated feeders?

Question 3.5 : Do switch points exist on your network primary feeders for the purpose of sectionalizing a network feeder?

Question 3.9 : Does your design limit the number of primary feeders entering a vault through a given single duct bank?

Question 3.11 : Do you have any current plans to expand the size of your network? (Increase the footprint of the territory served by the network)

Question 3.12 : Which of the following best describes your approach to loading your network?

Question 3.13 : Do you have any network “system hardening” initiatives underway?

Survey Questions taken from 2009 survey results - Planning

Question 3.4 : In your typical network design, do all primary feeders sourcing a given network originate from the same substation, or do you source networks from multiple stations? (This Question is 3.3 in the 2012 survey)

Question 3.5 : Are network primary feeders planned and designed as dedicated feeders? (This Question is 3.4 in the 2012 survey)

Question 3.6 : Does your design limit the number of primary feeders entering a vault through a given single duct bank? (This Question is 3.9 in the 2012 survey)

Question 3.7 : Do you have any current plans to expand the size of your network? (Increase the footprint of the territory served by the network) (This Question is 3.11 in the 2012 survey)

Question 3.8 : Which of the following best describes your approach to loading your network? (This Question is 3.12 in the 2012 survey)

Question 3.9 : Do you have any network “system hardening” initiatives underway? (This Question is 3.13 in the 2012 survey)

7.12 - Organization

7.12.1 - AEP - Ohio

Planning

Organization

People

Planning for the areas of this urban underground network immersion study, AEP Columbus and Canton, Ohio, is performed in Columbus by the AEP Network Engineering group, which is organizationally part of the AEP parent company. Within the Network Engineering group, the company employs two Principal Engineers and one Associate Engineer to facilitate network underground planning for the Columbus and Canton urban underground networks. These planners are geographically based in downtown Columbus at its AEP Riverside offices. While the Columbus-based Network Engineers are responsible for network planning for all of Columbus and Canton, they are occasionally called upon to assist in distribution planning for areas just outside these urban areas in other parts of the AEP Ohio system, such as Gahanna. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the Director of Engineering Services who in turn reports to the AEP Vice President of Customer Services, Marketing and Distribution Services. The AEP Network Engineering Supervisor, Distribution Systems Planning Manager and AEP Vice President of Customer Services, Marketing and Distribution Services support all AEP network planning throughout its operating companies, including companies located in Texas, Indiana, Michigan, Oklahoma, and other locations.

Two Principal Network Engineers primarily oversee the planning for Columbus networks; one Associate Network Engineer primarily oversees Canton, but often helps with Columbus-based projects. The Network Engineers are responsible for all aspects of the planning, from inception through project completion, including design, work orders, material acquisition, site inspections, and implementation.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues.

Process

The Columbus and Canton Network Engineering group completes plans for urban network distribution projects in its area that are requested by the parent company based on approved system expansion and refurbishment projects. New Columbus and Canton customer service requests for network service are also routed to the Riverside-based Network Engineering group. All network underground distribution plans are based on the company’s comprehensive Network Planning Criteria guide from the AEP parent company and its 10-year capacity forecasts (See Attachment C ). At the time of the immersion, AEP was in the process of updating its network planning criteria.

7.12.2 - Ameren Missouri

Planning

Organization

People

Resources in several groups perform distribution planning of the network at Ameren Missouri.

Area planning for the distribution system is the responsibility of Distribution Planning and Asset Performance. This group, led by a manager, is staffed with four-year degreed engineers, and includes the Standards Group as well as a Planning Engineering Group. Organizationally, Distribution Planning and Asset Performance is part of Energy Delivery Technical Services, reporting to a vice president.

Local distribution planning of both the network and non-network underground infrastructure in St. Louis is the responsibility of the engineering group within the Underground Division.^[1] This division is led by manager, and consists of both engineering and construction resources responsible for the downtown infrastructure. The engineering group is led by supervising engineer, and is comprised of Engineers and Energy Services Consultants (commonly referred to as Estimators) who deal with planning, design, and service issues. The engineers are four-year degree positions. Energy Services Consultants have a combination of years of experience and formal education, including two year and four year degrees. Organizationally, the Underground Division is part of Energy Delivery Distribution Services, reporting to a VP.

Finally, Ameren Missouri has formed the “Underground Revitalization Department,” a team of engineers focused on researching, evaluating, and developing plans for performing capital improvements to and revitalizing downtown St. Louis, including the network. Part of this group’s role includes addressing issues such as the development and update of planning criteria for the network. Organizationally, the Underground Revitalization Department is part of the Underground Division.

^[1] Note that at the time of the EPRI practices immersion, June 2011, the Underground Operating Center was part of the Archview Division. In early 2012, Ameren Missouri reorganized, making the Underground Operating Center its own division, the Underground Division. In addition, the “Underground Revitalization Department” described in this document is now a responsibility of the Underground Division.

7.12.3 - CEI - The Illuminating Company

Planning

Organization

People

Network Planning at CEI is performed by the Planning and Protection Section of the Engineering Services Department (CEI Planning Group). The group is part of the CEI Engineering Services department, and is led by a supervisor who reports to the Engineering Manager. The group is responsible for all distribution planning and protection, from 36kV and below. The CEI Planning Group is comprised of 4 Planners and 3 Protection Engineers. All members of the group are four year degreed engineers. The Planning Supervisor noted that he prefers candidates for the CEI Planning Group to have their Professional Engineer (PE) license, but this is not a requirement.

At any one time, the CEI Planning Group may have two or three “rotational” employees working in the department for a six month period. The FirstEnergy rotational program for engineers places newer engineering employees in four different locations and assignments for six months each over a 2 year period. Rotational engineers are part of the FirstEnergy corporate organization and are placed in rotational assignments of varying types across the FirstEnergy system. At the conclusion of their rotational assignments, employees are placed in permanent positions that match their interests and aptitudes with the Company’s needs. The CEI Planning Group Supervisor noted that this program has enabled him to identify strong candidates for his group, and to expose and train all rotational employees assigned to his department in planning and protection practices.

FirstEnergy also has a corporate Distribution Planning and Protection organization responsible for providing governance and standardization to regional planning and protection groups. This group has recently produced a company wide Distribution System Planning Criteria Document.

7.12.4 - CenterPoint Energy

Planning

Organization

People

At CenterPoint, Distribution Planning, including network planning, is performed by the Electric Distribution Planning department (Planning group). Organizationally, this group is part of the Distribution Engineering Electric Distribution Engineering group. Note that the Planning group is not part of the Major Underground group, but assigns resources to support Major Underground.

The Planning group is not centralized. Rather, the Planning group assigns planning resources to individual regions and to support departments, such as Major Projects, or URD Design, so that the planners are physically close to the other groups they work with.

The Planning group is comprised of 21 total resources, including 2 Lead Engineers. Each of the Lead engineers has about 6 - 8 people reporting to them. These people are either 4 year degreed engineers, or technical experts. CenterPoint aims to have a balance between Engineers and Technicians. The department manager noted that the Planning group positions are often entry level engineering positions, and these engineers end up leaving the department for other opportunities.

In addition the Planning group has a Lead Engineer Specialist, who leads a computer support group comprised of 6 resources. These folks work with systems such as CymE, Microstation, LD Pro, etc.

CenterPoint estimates that about 1.5 full time equivalent resources focus on planning work for the Major Underground Group. One planning resource, an Engineering Specialist, is assigned full time to work in Major Underground. He is a “matrix” employee, with a dotted line reporting relationship to Major Underground. CenterPoint believes that positioning an individual into the Major Underground group has led to efficient communications, and strong working relationships. This individual is the “eyes and ears” for the Planning group in Major Underground. He does the bulk of the planning work in the “dedicated ^[1]” underground system, and works closely with the Major Underground engineers to perform network system analyses.

CenterPoint encourages its engineers to obtain their PE license. The PE license is required to become a Senior Engineer.

^[1] The term “dedicated” underground at CenterPoint refers to three phase infrastructure is located entirely underground in their ducted manhole system. A “dedicated” network feeder does not mean that the feeder serves only a network; rather, it refers to a feeder that is entirely fed underground. In fact, at CenterPoint, feeders that supply the underground network also supply radial load along the way.

7.12.5 - Con Edison - Consolidated Edison

Planning

Organization

People

Con Edison’s overall Network Organization includes:

Engineering and Planning Responsibilities include Energy Services, Distribution Engineering, Operations Services, Marketing and Sales, Planning and Analysis, and D.C. Elimination.
Construction

Responsibilities include Construction Management, Construction Services, Public Improvement, Substation and Transmission Construction, Administrative Services, and Environmental, Health and Safety (EHS) and Training.

Central Engineering Responsibilities include Civil / Mechanical Engineering, Control Systems Engineering, Design Engineering, Electrical Engineering, Equipment and Field Engineering, and Environmental Engineering & Program Support.
System and Transmission Operations Responsibilities include Financial Planning, Environmental and Safety Monitoring and Compliance, Transmission Planning, System Operation, and Transmission Operation.
Substation Operations

Responsibilities include Substation Planning, Environmental, Health & Safety, Protective Systems Testing, and Substation Operations.

Electric Operations Responsible for Con Edison’s Operations Centers including Manhattan, Brooklyn and Queens, and Staten Island, as well as the Transformer and Meter shops. Con Edison’s Operations Centers are responsible for Electric Construction, Electric Operations, Environmental, Health and Safety, and Financial Planning / Operations Services.
Purchasing Responsibilities include Minority Women Business Enterprise, Materials, Systems Support, Services, Technology and Strategic Initiatives, Construction, Major Projects, and Contractor Performance.
Enterprise Shared Services Responsibilities include Corporate Emergency Planning and Security, Equal Employment Opportunity Affairs, Research and Development, Facilities, Shared Services Administration, Human Resources, and Finance and Administration.

Culture

Part of the method that EPRI uses in assembling a practices summary is to visit host utilities, like Con Edison, and perform a series of interviews with personnel and conduct field site visitations. Though these visits may be brief (in Con Edison’s case, 3.5 days), in performing them, EPRI investigators often gain insights as to where utilities place importance and how employees feel about their company. Please note that the findings presented in this section (Culture) apply to all of the functions surveyed by the EPRI team: Planning, Design, Construction, Operations & Maintenance, and Safety.

EPRI investigators found Con Edison employees to be very helpful, knowledgeable, and informative. Con Edison employees showed great pride in their company, their distribution system, and their work methods. One gets the sense that everything they do has been well thought out. Con Edison has a “family” feel, with employees appearing to be focused on their work.

Con Edison has excellent documentation of work processes, guidelines, and standards. In every case where EPRI would expect to see formal documentation of a specification or procedure, Con Edison was able to produce an up-to-date document. Moreover, the standards themselves were properly aimed at their intended audience, with field guidelines including bulleted lists, tables, drawings, etc. to facilitate the use of the guideline by field employees. The EPRI investigators also noted that Con Edison has expert resources that stand behind the information in their written documentation, and revisit it to ensure its continued currency and relevance. For example, Con Edison has expert cable resources that produce their network cable specifications. These individuals stay current on cable trends and ensure that the specifications reflect the latest industry thinking.

EPRI investigators detected an environment that encourages open dialogue and exchange of ideas on issues. For example, employees offered opinions on the pros and cons of Con Edison’s practice of performing a Hi-pot test on healthy network feeders to identify weaknesses in the cable (see “ Feeder Testing ” in the Maintenance NoteBook Process section). Employees offered opinions freely on topics, even if their opinions differed from company practice.

EPRI investigators noticed a clear focus on operation of the T&D system. The tools, trucks, network equipment, training, etc. that Con Edison uses are top notch. Several Con Edison employees specifically commented on the high quality of the tools and equipment they utilize. In a visit to one of the Work Out Centers, it was evident to EPRI investigators that Con Edison gives a higher priority to investment in the distribution system, and the tools, training, and equipment to maintain and operate it, than in the Work Out Center building itself. This is not to say the building was run down; rather that Con Edison places an appropriately higher priority on investment in their distribution network than in their non-T&D facilities. One gets the sense of Con Edison being a company run by technical people who recognize it as a technical business.

EPRI investigators also noted a strong and visible focus on safety at Con Edison. In every facility that EPRI investigators visited, safety goals and performance reports were conspicuously posted. At every visited worksite, EPRI investigators noted safe work practices including traffic and pedestrian control, the use of personal protection, the wearing of safety harnesses by Con Edison workers, a lifting crane set up outside of the vaults, and continuous air quality monitoring.

EPRI investigators also noted a strong commitment to industry collaboration. The Con Edison employees interviewed showed genuine enthusiasm for participating in this practices investigation, and in sharing their work practices and expertise with others. Con Edison’s commitment to collaboration is further evidenced by their practice of making their facilities and expertise open and available to others, such as providing fault location services, and making their testing facilities and training programs available to others.

Process

Planning

Distribution System Planning is performed by the Regional Engineering departments in collaboration with the Transmission Planning group. Transmission Planning prepares a load forecast for each network and forwards this to the Regional Engineering Department. Regional Engineering then apportions the forecasted load by feeder and produces a load relief plan for each feeder.

Planning for the Future (Third Generation group (3G))

Con Edison has formed a group tasked with addressing the challenges they face in meeting their projected demand and service needs given their current system design. Con Edison refers to their current design, which is a conventional networked secondary design, as second generation, or “2-G.” The group is referred to as the “3 G” group, in that they are focused on new, third-generation system designs to meet their challenges.

Many of the challenges that Con Edison faces are similar to those faced by other network utilities. In some cases the challenges may be exacerbated at Con Edison because of their large size and physical constraints. Some of the challenges they face are the high costs of redundant systems necessary to provide N-2 levels of reliability in parts of their territory, increasing fault current, limited physical space to expand the system, low equipment utilization factors, and new load types and distributed generation.

The 3-G group is looking specifically at ways to apply technology to reduce costs by avoiding or deferring capital expansions, increase operating flexibility, and increase equipment utilization while maintaining customer reliability and service.

For example:

They have performed international benchmarking studies and participated in employee exchange programs with foreign utilities to identify practices used in utilities internationally to address some of the same challenges that they face.
They are working with the vendor community to identify new technologies, such as fast switches that can be used to transfer load between feeders beyond the substation secondary bus.
They are redesigning their approach to substation design, seeking to avoid building them, or building new stations in a way that makes more use of installed assets, eases congestion, and makes their construction cheaper while being capable of operating with the same reliability.
They are revisiting their approach to connecting new customers, seeking changes to customer connection requirements that reduce the number of customers connected from the networked secondary grid.

7.12.6 - Duke Energy Florida

Planning

Organization

People

Network Planning at Duke Energy Florida is organizationally part of the Power Quality, Reliability, and Integrity Group (PQR&I), which is led by a Director of PQR&I for Duke Energy Florida.

To perform planning work, the Network Planning group divides the Duke Energy Florida territory into four separate zones. The cities of Clearwater and St. Petersburg, part of the South Coastal Region, are included in one of the four zones. Every zone is assigned a Lead Planning Engineer and Senior Planning Engineer, who are responsible for all distribution planning activities within the zone.

Engineers/Planners in these zones work on Reliability as well as Planning. Because Duke Energy Florida has seen minimal capacity demand growth in its urban underground grid, Engineers in the PQR&I group spend much of their time planning reliability and infrastructure upgrades.

All Planners have four-year degrees in Electrical Engineering, a requirement for the position.

Duke Energy Florida has no written planning criteria specific to secondary network systems.

7.12.7 - Duke Energy Ohio

Planning

Organization

People

Distribution planning for the network underground system is performed by the Distribution Planning Organization. Distribution Planning is part of Duke Energy’s Power Delivery Engineering Organization. Duke has one Distribution Planning organization focused on its Carolina utilities, and one focused on its Midwest utilities, including Duke Energy Ohio.

Within the Distribution Planning Midwest organization, one engineer has been assigned the responsibility to focus on Duke Energy Ohio network planning. This Engineer has other duties as well, but is the point person within the Planning department for the Cincinnati network.

This Network Planning Engineer is a four year degreed engineer.

This engineer works very closely with the Distribution Design Department and the Construction & Maintenance department at Dana Avenue to plan the network.

EPRI noted a very strong working relationship between:

the Network Planning Engineer, part of Distribution Planning Midwest, within the Asset Management organization,
the Project Engineer within the Distribution Design department who focuses on Cincinnati network design issues,
the Supervisor, Construction and Maintenance, Dana Avenue, who focuses on C & M issues in the network and leads the field resources, and
the Asset Manager, part of the Duke Reliability and Integrity Group, within Asset Management, and located in Charlotte.

These four individuals work closely as a team to manage all aspects of the Cincinnati network.

7.12.8 - Energex

Planning

Organization

People

The Australian Energy Management Commission (AEMC) is a federal body that manages all aspects of rules within the electric power industry. The body proposes rule changes, handles rule negotiations with owners such as Energex, mandates market reforms, and publishes final rules. Utility owners must consult with AEMC on major projects greater than $5M.

The Australia Energy Regulator office enforces rules on behalf of the AEMC. As practitioners find problems with the rules, they can propose changes. To that end, owners have founded associations for representation to the AEMC on their behalf, such as Energy Networks Australia and Grid Australia.

Process

Utilities in Australia, as practitioners, have the ability to identify problems and petition for changes to rules developed by the AEMC. An example cited by Energex management was the application of the “regulatory test.” In Australia, any major project (greater than $5M) must be presented to market participants, who have the ability to identify potential solutions. So, for example, an aggregator of generation supply may vie for the opportunity to service a new load. Energex was successfully able to assure that the rules require that the level of security of any supply solution offered by a market participant be commensurate with the level of security offered by the network solution. In other words, the ability of a market aggregator to supply a potential new load must be as secure as a solution put forth by Energex that leverages the Energex network.

As a part of its regulatory requirements, each utility owner, including Energex, must prepare a Distribution Annual Planning Report (DAPR) in accordance with the requirements of Section 5.13.2 of the National Electricity Rules (NER). The information contained within the DAPR complies with the requirements of Schedule 5.8 of the NER and describes the following:

The power network.
Planning procedures and policies.
Summary of network reliability for the previous financial year.
Forecast loads and emerging system limitations.
Proposed solutions to system limitations.
Major construction activities completed or committed to in the last 12 months.

The DAPR is an essential document for Energex and any other utility on the eastern seaboard of Australia as it affects funding, approval of major projects, and forecasting both network underground and distribution projects. It is essentially a government-approved roadmap for utilities when considering projects, refurbishment, performance, and maintenance.

7.12.9 - ESB Networks

Planning

Organization

People

Organizationally, system planning is performed by planners within the Network Investment groups, part of Asset Investment, within the Asset Management organization at ESB Networks. In addition to Asset Investment, the Asset Management organization consists of Program Management, Infrastructure Stakeholder Management, Assets & Procurement, Finance & Regulation, and Operations Management. These groups work closely together to manage the asset infrastructure at ESB Networks.

More specifically, distribution planning is performed within two Network Investment groups – one responsible for planning network investments in the northern part of Ireland, and the other for planning in the south. Planning is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists” who have developed their expertise through field experience.

Planning standards and criteria are developed jointly between the Asset Investment group and the Strategy group, which is part of the Finance and Regulation group within Asset Management.

7.12.10 - Georgia Power

Planning

Organization

People

Resources in several groups perform distribution planning of the network at Georgia Power. The company has both Area Planning and Distribution Planning. Area Planners are responsible for different areas of the state, such as Atlanta, Savannah, Macon, Augusta, Athens, and Columbus and are responsible for the substations in those areas to make sure the transformers have the capacity to handle projected future loads, contingencies, etc. These Area Planners are geographically based both in Atlanta and the southern part of Georgia. Those outside of Atlanta work in offices closest to the areas they are responsible for, while three Area Planners are based out of the company’s downtown Atlanta offices and are responsible for the Atlanta Metro area and a few networks in Macon and Augusta. Organizationally, Area Planners sit outside the network Underground group, but have a dotted line reporting to senior engineers in the Network Underground group. Note that Georgia Power’s Network Underground group is semi-autonomous and acts as a division within the organizational structure of Georgia Power.

Distribution Planners, are responsible for feeder loading to the networks and work closely with the Area Planners. Basically, Area Planners are responsible for all planning operations “inside the fence” of the urban networks, while the Distribution Planners are responsible for planning operations that fall “outside the fence” of the urban network(s). The two groups work closely together.

Process

Both groups – Area Planners and Distribution Planners – work with the network engineers during the design phase of projects. Projects of $2 million or less are brought before the Regional Distribution Council for approval. Any projects that require more funding are sent to the upper management for review and funding approvals.

7.12.11 - HECO - The Hawaiian Electric Company

Planning

Organization

People

Network Planning at HECO is performed by Distribution Planning Division at HECO. The Distribution Planning Division is part of the System Integration Department. The Distribution Planning Division group performs all distribution planning at 46kV and below.

The group is led by a Principal Engineer and is comprised of one lead distribution engineer, and 5 Planning engineers who do all of the distribution planning work for the island of O’ahu. All of the engineers in the group are four year degreed engineers.

HECO has a documented planning criteria document. Each year, HECO planning engineers perform studies of the system using load forecasts based on historic peaks and anticipated load growth to identify places where either system loading limits are exceeded or other violations of their planning criteria are encountered. It is from this analysis that reinforcement projects are conceptualized.

Their distribution system is designed to N-1; that is, they plan their system such that all the system components, including primary feeders, secondary cable mains and taps, and transformers, are sized to be able to carry the load within specified thermal and voltage limits during peak conditions when any single component is out of service.

7.12.12 - National Grid

Planning

Organization

People

The Distribution Planning organization, led by a Director, performs network planning at the National Grid. Organizationally, the Distribution Planning Organization is part of Distribution Asset Management, and is comprised of resources in both a central location (Waltham Massachusetts), and distributed throughout National Grid. About two thirds of the organization is centralized, with the remaining third decentralized.

Centrally located resources include capacity planning resources who reporting to a manager, and engineering personnel, who have broad system planning and engineering responsibilities, Regionally located resources include field engineers who report to managers of field engineering for both New York and New England

The planning engineers who focus on the Albany network include a field engineer who works in the Albany office and focuses primarily on both radial and network underground systems for National Grid’s New York Eastern division, and an engineer situated in Waltham, who has network engineering responsibilities across the system. These engineers have responsibility for both network planning and network design.

Both of these engineers are four-year degreed engineers, and are not represented by a collective bargaining agreement (exempt).

National Grid has up-to-date standards and guidelines for the network infrastructure. In addition they have up-to-date planning criteria that addresses network planning.

7.12.13 - PG&E

Planning

Organization

People

At PG&E, network planning is performed by the Planning and Reliability department. This department is led by Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems. There are eight engineers that comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two Planning engineers are responsible for both network planning and network design.

One of the two network engineers is relatively new to the department, and was assigned to receive training from the lead network engineer.

The lead planning engineer noted that PG&E does not have a design manual for the network system. There are some construction standards that have been developed for network designs, but no design standards. At the time of the practices immersion, PG&E was working on retaining the services of a retired engineer to write the design manual for networks.

Both network planning engineers are four year degreed engineers. They are represented by a collective bargaining agreement (Engineers and Scientists of California).

7.12.14 - Portland General Electric

Planning

Organization

People

At PGE, system planning for the network involves many departments with overlapping responsibilities and includes the consideration of facilities that customers design and own. Because the process draws together experts from many areas of the company, system planning is based upon good project management and a multi-departmental approach.

Transmission and Distribution Planning: Across PGE, the Transmission and Distribution (T&D) Planning organization oversees the planning process for network and non-network systems. The Distribution Planning Department working within this organization employs five Distribution Engineers and an experienced manager with previous experience as a network distribution engineer. A planning engineer with a four-year degree in engineering covers the Portland Service Center (PSC), which includes the network.

Distribution/Network Engineers: Three Distribution Engineers have responsibilities to provide engineering services for the underground network. These engineers also work with customers to design and operate customer-owned facilities associated with network infrastructure. The Distribution Engineers are not physically based in the PSC service center or CORE group, and are overseen by the Eastern District Central Supervisor, who reports to the Manager of Distribution and T&D Standards. The underground Distribution Engineers are qualified electrical engineers. When needed, PGE hires civil engineers to perform certain design tasks associated with the civil infrastructure, including vaults, manholes, and duct banks.

Project Management Office Group: The Project Management Office (PMO) manages the larger, more complex projects. This group, which is part of the Transmission and Distribution organization, is involved in in the early stages in coordination with System Planning, and assumes responsibility for projects once the Planning Engineers have developed a shortlist of solutions. Because of an increasing number of more complex projects, PGE is expanding its Project Management Office Group.

One project manager within the PMO has responsibility for all projects in the CORE, including complex projects such as building a new network substation. The present project manager has a Project Management Professional (PMP) certification and project management experience with another utility. The PMP designation is not necessarily a requirement for T&D project managers.

Service & Design Project Managers (SDPM): Network planning associated with customer-driven projects requires regular coordination with the customer throughout the project life. PGE has a position called a Service & Design Project Manager (SDPM), who works almost exclusively with externally-driven projects, such as customer service requests. At present, two Service & Design Project Managers cover the network and oversee customer-related projects from the first contact with the customer to the completion of the project. They coordinate with customers to assure that customer-designed facilities comply with PGE specifications.

The SDPMs can be degreed engineers, electricians, service coordinators, and/or designers. Ideally, an SDPM has an associate degree or a combination of electrical engineering experience and appropriate education. In addition, SDPMs should have proven project management skills and understand PGE and industry standards and practices. They should also have knowledge of the National Electrical Safety Code (NESC) and National Electrical Code (NEC) safety codes and the ability to use or learn the relevant information technology (IT) systems. PGE prefers a selection of SDPMs with a diverse range of experience and backgrounds.

SDPMs work on both CORE and non-CORE projects. This ensures that expertise is distributed and maintained across departmental and regional boundaries.

Process

Across its service territory, PGE operates three regions, with each further subdivided into areas. One of the areas, the Portland Service Center (PSC), services central downtown Portland, which is the location of the company’s network infrastructure. The infrastructure that the PSC manages includes a mixture of overhead and underground facilities.

The PSC territory also includes five network systems. One substation supplies three network systems, and a second substation supplies the other two network systems. Each of these substations backs up the other. The system is designed to provide N-1 contingency reliability, meaning that reliability is maintained even with the any single piece of equipment removed from service.

The network uses a delta-wye configuration, with dedicated network primary feeders. Many of the buildings in the downtown Portland area are becoming more energy efficient, and this means that PGE operates the network with lighter loads.The PGE network has had few problems with protectors pumping and challenging, although older buildings have had some issues with the lighter loading, which can cause protectors to open.

Overall, due to the multiple redundancies in the network, the system is considered very reliable.

Substation Configurations: One of the two substations, which supplies three networks, is sourced by three 115-kV primary feeders, which supply four power transformers. The substation serves both network and radial feeders. Each of the three networks is supplied by four dedicated network feeders, at 12.4 kV, with each emanating from a different bus section. Voltage regulation is performed at the bus level. One of the networks consists of only spot network loads. PGE prefers to serve spot networks with four feeders, where possible, although some spot network locations are supplied by two or three feeders. The other two networks that this substation sources contain both grid network and spot network loads

The other substation that supplies two networks is located on the other side of the Willamette River, and its feeders cross the waterway to supply downtown Portland. This is the older of the two substations. Each of the networks is supplied by four dedicated network feeders, at 11 kV, with each emanating from different bus sections. However, this substation also supplies radial load through radial feeders that emanate from the same bus sections as do the network feeders. Each feeder has its own regulator (in contrast to the other station, where regulation is at the bus level) to prevent pumping and cycling of network protectors because of voltage differences at the station. This provides PGE finer control, but limits capacity.

In the future, all loads that the second substation supplies will transfer to a new substation, which is under construction at the time of this immersion process. 12.4-kV feeders from this new station will supply networks.

Marquam Substation: PGE is constructing the new Marquam Substation, which will address a number of issues with the older substation:

The new substation will eliminate the river crossing that the older substation used
The new substation will have added capacity in anticipation of future load growth
The substation solves the existing co-mingling of the radial and network feeders on the same bus
The new facility will be able to cope with the load that the newer substation supplies when that substation is rebuilt in the future
The new substation can serve as a backup for quickly restoring network load

The Marquam Substation will serve five separate network systems, with two of the network systems transferred from the existing older station. A third will be transferred from the newer station within 10 years. The fourth and fifth network systems are earmarked for future load growth.

Marquam getaway duct banks will consist of four 48-in. (122-cm) diameter steel casings for crossing underneath a major roadway, with the conduit emanating from the casings tied into new vaults. Each of the casings will contain fourteen 6-in. (15-cm) diameter conduits, and PGE performed studies to assure that this configuration would not lead to overheating (and thus affect cable ampacity).

The substation will supply networks with a total network load of 75 MVA for each of the five network systems. Each of the feeders supplying the network is designed to carry up to 15 MVA. Load balancing will balance primary feeders within a ± 10% tolerance. In future, additional transformers, switchgear, and other equipment will be installed at Marquam with the ability to serve up to three radial feeders, rated at 600 amps [1].

Overall, Marquam will remove some of the reliability issues associated with the 1-1 kV system supplied out of the older station. During the construction of the new substation, PGE split the existing eight feeder network system to two four-feeder systems, which will help minimize outage times during the transfer. The new design also conforms to a more-standardized four-feeder system, and will provide future back-up capability for existing substations [2].

Technology

PSS®E

PGE’s Planning Engineers use the Siemens PSS®E application, which supports electric transmission system analysis and planning, and is used for modeling and simulations. PSSE can model networks with up to 200,000 buses, and users can perform steady-state contingency analyses and test corrective actions and remedial schemes. Users can analyze balanced and unbalanced faults, as well as perform deterministic and probabilistic contingency analyses. PGE can use the system to model substation topology, and users can anticipate potential network issues and model alternatives. PSSE includes a comprehensive library.

PSSE supports a number of analyses, including:

Power flow
System dynamics
Short circuits
Contingency analyses
Optimal power flows
Voltage stability

The system is compatible with other systems, and add-ons support bidirectional flows and the modeling of distributed generation installations.

PSSE is presently only able to model three-phase loads, not single-phase loads. PSSE is also unable to show loops graphically and creates errors when modeling the secondary network, which has prevented development of accurate models. PGE is transitioning to CYME software, which is presently used for the radial system. To do this, PGE will use ArcGIS to model and display loops.

Geographic Information System (GIS) – ESRI ArcGIS

To support planning, engineers use ArcFM, which is built upon ESRI’s ArcGIS system. Users can access ArcGIS mapping software via a browser, desktop application, or mobile device, and organizations can share maps and data. ESRI’s system allows users to capture, analyze, and display geographical information, enabling display of maps, reports, and charts.

GIS is used to map assets and circuits, and can be linked to the customer information system and other enterprise applications. The maps provided with ArcGIS include facility maps, circuit maps, main line switching diagrams, and a service territory map [3]. Operators can use ArcGIS to schedule work and dispatch crews, and they can also locate crews and view work status and progress [4].

With ArcGIS, operators and crews can locate assets and infrastructure, as well as determine how they are connected. The view of the electrical system includes connectivity, service points, and underground assets. Crews can follow how current flows through the interconnected network and determine upstream and downstream protective devices. The GIS allows users to overlay external data, including images, county maps, and computer-aided design (CAD) files onto the map view.

The GIS includes the ArcMap and ArcFM viewer, which allows designers to use compatible work units and send these to the Maximo system. In 2017/2018, PGE will investigate processes for transferring Arc GIS information into CYME, which will require a software development from the vendor, Schneider Electric. ArcFM is built on top of ArcGIS, and the system will allow engineers to use CYME, which is presently used on the radial system, for the network.

ArcFM GIS software helps engineers design network layouts and create a package with details for relevant personnel. Schneider’s software is a map-focused GIS solution that allows users to model, design, maintain, and manage systems, displayed graphically alongside geographical information. ArcFM uses open-source and component object model (COM) architecture to support scalability, user-configurability, and a geographical database.

PGE uses an Enterprise Resource Planning (ERP) system called PowerPlan, which has an Oracle attachment named “Pace.” This system provides financial data about projects. Other technologies used for planning include SharePoint, Field View, the PGE Engineering Portal, PI ProcessBook, and the T&D Database.

Portland General Electric, Marquam Substation Network Distribution Ductbank Casings, internal document.
Derek Harris. 2014. PGE Stephens Network System Split Report, internal document.
Smart Grid Report. Portland General Electric, Portland, OR: 2017. http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq16327.pdf (accessed November 28, 2017).
GIS for Electric Distribution. ESRI, Redlands, CA: 2010. http://www.esri.com/library/brochures/pdfs/gis-for-electric-distribution.pdf (accessed November 28, 2017).

7.12.15 - SCL - Seattle City Light

Planning

Organization

People

Organization

Network Planning at Seattle City Light is performed by the Network Design Department, which is part of Energy Delivery Engineering. See Attachment A . The Network Design Department focuses exclusively on the planning and design of SCL’s networks.

Although SCL does have a separate planning group that performs distribution planning activities for SCL’s non-network distribution system, this group does not do the planning associated with the network. All cable ratings, load flow and voltage studies, master load flow analysis, assignment of feeders to load additions, area studies, etc. associated with the network are performed by the Network Design Department staff. (Note that at the time of the EPRI practices immersion, SCL was implementing an Asset Management organization. At the time of this writing, SCL had not yet decided whether certain tasks currently performed by the Network Engineering group will be moved into the Asset Management organization.)

The Network Design Department is made up of a System Group (eight engineers) and a Services Group (eight engineers). These engineers do all of the planning and engineering for the network (the System Group), as well as interface with network customers for load additions, new loads, etc. (the Services Group). The individuals in this group are four-year degreed engineers. The senior level engineer position at SCL requires a PE license. The engineers at SCL are represented by a collective bargaining agreement (IBEW).

Culture

The Network Engineering group has a close working relationship with the Civil and Electrical construction and maintenance groups within the Area Field Operations – Network Department and the Distribution Operations Department. EPRI observed high levels of mutual respect between these groups, and high confidence by the field organizations in the planning and design decisions made by the Network Design Department.

SCL has remained committed to the network engineering department staffing levels, hiring new engineers into the network area to fill vacancies. SCL has no formal training program for network engineers. However, network engineers are sent to special classes on network equipment, etc. as part of their ongoing development.

Process

Planning Criteria

SCL has defined and documented network design criteria for Feeder Loading, Electrical System Construction, and Civil Construction (see below). SCL’s network system is designed to maintain N-1 load capability at peak load. More specifically:

Network Design Criteria for Feeder Loading

Load feeders to maintain N-1 load capability at peak load.
Limit feeder imbalance to 20% at N-0.
Keep load current within constraints determined by loadflow and ampacity studies for existing plant.
Keep load current within constraints determined by loadflow and ampacity studies for new construction.
Account for diversity factor during feeder loading analysis.

Network Design Criteria for Electrical System Construction

Allow no more than two mainstem cables from any one sub-network per MH or street vault. There may be mainstem cables from other sub-networks present (subject to the same restriction) as well as branch cables.
Allow no more than four lateral feeders from any one sub-network per MH or street vault. This may change as a result of studies for ampacity evaluations of feeder laterals with high loads or near steam lines.
Size new mainstem feeders to match substation capacity, with allowances for feeder imbalance and reliability.
Require two half-lapped layers of arc-resistant tape to each primary feeder in MHs and street vaults.
Limit DC Hi-pot testing of 15-kV class cables to a maximum of 26 kV DC and 28-kV class cables to a maximum of 47 kV DC.
Use VLF testing for newer cable testing if separable from older cable sections. Note: This particular requirement has not yet been implemented. SCL is still examining the merits of VLF testing for cable
Do not allow construction of new 480-volt secondary grid networks.
Use limiters on both ends of all secondary bus ties.

Network Design Criteria for Civil Construction (Street Facilities)

All duct banks shall be encased in concrete.
All new system duct banks shall have 5-inch diameter conduits for system cables.
Steel ducts are required for shallow construction.
Every effort shall be made to install new duct banks a minimum of 15 feet away from any steam logs. If new duct banks will be within 15 feet, a cable ampacity analysis is required to determine potential mitigation actions.
If a duct bank must cross a steam log, insulation must be applied per SCL construction guideline NDK 150.
Fluidized thermal backfill (FTB) or controlled density fill (CDF) may be used to backfill around encased service ducts.
Use only fluidized thermal backfill (FTB) around encased system ducts.

7.12.16 - Survey Results

Survey Results

Planning

Organization

Survey Questions taken from 2015 survey results - Summary Overview

Question 9 : Within your organization, do you have a distinct Network Engineering and Network Planning groups?

Question 10 : Which of the following functions does your Network Engineering/Planning group(s) perform? (check all that apply)

Question 11 : Within your company, how many Full Time Equivalent resources (FTE’s) make up the following functions? (Provide total FTE’s, including work performed by contractors)

Survey Questions taken from 2012 survey results - Planning

Question 3.1 : Do you have a distinct Network Planning group, or is network planning performed by a general planning organization?

Survey Questions taken from 2009 survey results - Planning

Question 3.1 : Do you have a distinct Network Planning group, or is network planning performed by a general planning organization?

Question 3.2 : How many people perform network planning at your company?

7.13 - Program Management

7.13.1 - Duke Energy Florida

Planning

Program Management

People

At Duke Energy Florida, there is a Resource Management group responsible for planning and resource support for construction, civil construction maintenance, and large project construction. The Resource Management group has an active role in larger network construction projects such as cable replacement and targeted program work.

Resource Management includes a Project Logistics and Support group that consists of two planners who oversee twelve schedulers to provide project logistics and support. The resource planners and schedulers in this group determine the resources, budget, and schedule of construction projects throughout Duke Energy Florida. The Resource Management group is a centrally located organization that supports all of the Construction and Maintenance groups throughout Duke Energy Florida.

A majority of the projects involving the network system are not handled by the resource management group. The group becomes involved in network system projects when contractors are needed or the projects are large in scope. Network supervisors will work with the schedulers to maintain work crew schedules and forecast upcoming projects and plans. The supervisor meets once a week with the Scheduler, more often if necessary.

Schedulers will help to “work the plan” for large projects, and work closely with department supervisors to determine required skill sets and ensure enough resources are assigned to a project. In addition, the Resource Management group will make sure to match the skill set of employees with work being performed. For example, historically, Network Specialist crews had been assigned to perform annual structural integrity inspections of vault infrastructure – a task which was time consuming and one that did not require the qualifications of a Network Specialist. The Network Group enlisted the services of the Resource Management group to obtain appropriately skilled alternative resources to perform those inspections, enabling the crews with electrical network experience to focus on work more suited to their skillset.

Process

All daily construction and maintenance work falls outside of the realm of the Resource Management group’s responsibility. Assignment and oversight of daily construction and maintenance work is the responsibility of the Network Group supervisor, who will also manage time sheets and projects worked for network crews.

The Network Group supervisor will meet weekly with schedulers in the Resource Management group to discuss planned work to be performed. In addition, the weekly meetings serve as an opportunity for to share schedules and ask for additional people and resources if necessary.

Larger programmatic work, such as cable replacement efforts underway in St. Petersburg, will involve Resource Management.

Technology

Most of the project planning and tracking for network work is handled with Microsoft Excel. Schedulers will use a software package called iScheduler for assignment of work. iScheduler is part of WMIS, made by Logica.

At the time of this immersion, the network system group was in the Process of incorporating its scheduling with the main operating company’s Work Management Information System (WMIS) software, in conjunction with the Resource Management organization. WMIS is developed by Logica and is designed to maintain accounting and time reporting information in one software package. The WMIS electronic workflow management software is able to assign work orders and create schedules for the network field crews.

7.13.2 - Energex

Planning

Program Management

People

The Program Management group at Energex is organizationally aligned with the Service Delivery group, and is led by a group manager. The Service Delivery Group is responsible for all elements of service delivery, including design, construction and operations. Program Management also works closely with Asset Management.

Members of the Program Management team include senior project managers, individuals with extensive experience who handle more complex projects. Project complexity is driven by the use of multiple work groups, difficult customer interactions, or key accounts. Most project managers have experience in the field but also have some project management qualifications.

The Program Management group also has project coordinators who manage smaller jobs. These people often come from a clerical background with project management expertise. Their expertise is more about managing personnel than solving technical problems.

Energex is looking into requiring a PMP certification for project management positions and is actively encouraging employees who have not done so to receive formal project management training.

It is the responsibility of the Program Management group to “bundle up” related projects that come from the design group and assign resources and timing for projects before handing them over to a project manager. The project manager works with the Program Management group to make certain the time, resources, and on-site work are completed according to schedule.

Process

Program Management monitors the overall work plan. As forecasted dates approach, the program management group assigns resources, and matches specific projects to the expected work in the plan.

Much work is driven by DAPR, which covers a five-year timeline. The Program Management group builds its program of work out of the DAPR. Typically funding is already approved when Program Management becomes involved. If it is a large project, like a large project within the CBD, Program Management becomes involved fairly early, as soon as the Planners begin work.

The Program Management team lines up construction resources. The group typically looks at 12-month and five-year views based on estimates of work load throughout Energex. The team constructs Gantt charts for each of the anticipated projects. Each project Gantt chart displays, based on timing, the kinds of resources that are needed, skillsets required, and the cost associated with every major activity of the project. The team can then roll all projects forward and look at resource requirements month by month and by the year for the entire company, creating an aggregate resource requirement. The Program Management office can then assess any conflicts or resource constraints and move assets and resources around and adjust timelines accordingly, based on priority.

The head of Project Management schedules work groups from day zero (present) to up to six months out. These schedules are at a very detailed level. For example, the construction for a CBD project requires specific resources, and Energex crews need to achieve specific goals at scheduled dates (milestones). Energex uses Ellipse to conduct the scheduling, logistics, and all aspects of project. Project Management also works with work group leaders when things go wrong. This tight coordination is critical because most of the CBD projects are coming out of the same pool of personnel. Unlike the Distribution group, the CBD Network groups have highly specialized people who must be accurately scheduled for maximum effectiveness.

Most of the CBD work is associated with small medium voltage transformers. These sites have a three feeder meshed supply to the customer and may include switchgear, remote control relays, or a ring main unit, depending on what the planner wants. Where the CBD is concerned, the design approach is fairly standard, but as Energex service extends to the edge of the underground network, the approach varies depending on customer requirements.

At the edge of the CBD, the service design is more customer-driven by the project timing, how much room customers are willing to allot Energex equipment, etc. The planners set up the agreement with the customer on what Energex will do, and then pass the agreed to approach to the Design group. After leaving Design, the Program Management group bundles the project and assigns it to a project manager.

The Program Management team internally monitors the performance of the project as it progresses through each step in the project life cycle. In CBD projects, because of complexity, Program Management also assigns a project manager who works with the designers. Program Management has about 35 project managers available to them who handle projects that range from normal infrastructure to CBD projects. Program Management assigns a senior project manager when multiple workgroups are involved, such as a project requiring installation of switchgear and SCADA controls, and thus, involving multiple specialized workers.

If overtime or contractor resources must be brought in to meet deadlines, the Program Management office indicates this at a macro level, but the Project Management group works out specifically what extra resources are needed, especially in the near term (0 to 6 month range). The two teams, Program Management and Project Management, then work cooperatively.

Program Management is evaluated at Energex on the basis of on-time delivery of projects, value, and cost control. When a project moves into construction phase and is behind schedule, it is the project manager’s job to request additional resources. The project manager must then meet with Asset Management and go over options for resolving the project schedule and justify additional resources, either internally or through contractors. Multiple options are discussed, and the costs for each option are outlined, both in terms of capital and personnel.

These situations are often avoided by monitoring projects at each phase. Therefore, communication between Program Management, Design, project managers, and Asset Management is essential to stay on schedule and at cost. Regardless, de-scoping of projects is sometimes necessary, especially if plans are old, if features originally planned are not needed, etc. This saves both time and money and is tracked by the Program Management group when de-scoping frees up capital and human resources that can then be allocated to other projects.

Technology

The Program Management group uses Primavera EPPM to schedule and forecast jobs well into the future. Ellipse provides the team a macro-level view of all ongoing and planned Energex projects, as well as drill down to any project’s details. Gantt charts are used by project managers, supplied by Program Managers, with two-way communication and updates to these charts as the project is under way.

7.13.3 - ESB Networks

Planning

Program Management

People

As part of their Asset Management organization, ESB Networks has a group focused on Program Management. This group, led by a manager, consists of a Project Owner – Asset Management, an Integrations management group for distribution and for transmission, a Unit Cost performance group, and a Business Process and Data Management group.

The Program Management group provides project oversight, management services and tracking of the network investment project portfolio. Individual projects are managed by the delivery organization, but the portfolio is managed by the Program Management group.

Project portfolio managers do not require engineering degrees, but an engineering background is advantageous in that the manager can speak the language of the engineer.

Process

The Program Management provides project portfolio management services for ESB Networks. Their work includes the following activities:

Monitor the project portfolio
Assure structures are set up
Assure approvals are set up
Ensure that projects are released/shaped and packaged in the right way
Report on the progress of major efforts
Work closely with the Finance and Regulation group on developing communication strategies, and delivering results against goals to the regulatory agency
Maintain an integrated standard approach across ESB Networks

The Program Management group maintains a cooperative relationship with others in the organization, as they work closely with many internal groups in managing the project portfolio.

The Program Management provides oversight of the company’s maintenance programs. In general, they develop an overall asset strategy, and define that into maintenance plans.

The group establishes maintenance approaches for equipment of a particular type. For example, for HV assets, ESB Networks has established seven different maintenance/testing approaches, depending on the particular assets characteristics. Therefore, not all HV assets are subjected to the full suite of maintenance – it depends on the asset’s characteristics.

For distribution assets, however, ESB Networks’ maintenance approach is generally to perform consistent and routine maintenance across all of the assets of a particular type. ESB Networks did cite some examples of intended targeted approaches for distribution assets, such as implementing routine cable diagnostic testing of worst performing MV feeders. In this case, however, the regulator did not endorse this approach for distribution assets.

For capital projects, ESB Networks develops and seeks to obtain regulatory approval of an overall capital investment plan that includes various categories of capital spend, including system refurbishment projects developed by Asset Managers, loading driven reinforcement projects identified by Network Investment managers, line diversion projects (relocations) and undergrounding of facilities, renewable connections, reactive work, new customer connections, etc. Often the plan includes bundled projects that require capital from different spending categories.

Technology

ESB Networks uses an SAP enterprise resource planning (ERP) system, including the Maintenance Management module, and SAP Business Warehouse. ESB Networks notes that while not best-of-breed, this system has broad integrated functionality.

For maintenance, ESB Networks uses this system to initiate maintenance orders based on certain parameters. For certain HV assets, the company has established measurement points, with threshold levels that, when exceeded, initiative high priority orders to perform maintenance.

ESB Networks uses a distribution facilities information system (DFIS), which is their distribution asset register. This system is updated nightly. Note that at the time of the practices immersion, ESB Networks was planning and upgrade to their GIS system, which would tie in with the DFIS.

7.13.4 - Georgia Power

Planning

Program Management

See Construction: Project Management

7.14 - System Protection

7.14.1 - AEP - Ohio

Planning

System Protection

People

System protection for AEP Ohio is performed by the AEP Network Engineering group in tight collaboration with its parent company. The company employs two Principal Engineers and one Associate Engineer to facilitate network design, including system protection, for the Columbus and Canton urban underground networks. These engineers are geographically based in downtown Columbus at its AEP Riverside offices. Organizationally, the Network Engineering group is part of the AEP parent company and performs planning for AEP Ohio as well as provides support services to the other AEP operating companies. Columbus-based Network Engineers provide system protection in collaboration with AEP Distribution and the Network Engineering Supervisor. The Network Engineering group reports to the AEP Network Engineering Supervisor, who in turn reports Distribution Systems Planning Manager. Distribution Systems Planning reports to the Director of Engineering Services who in turn reports to the AEP Vice President of Customer Services, Marketing and Distribution Services.

AEP also has a Network Standards Committee, headed by the lead Network Engineering Supervisor in its downtown Columbus offices, and comprised of representatives from all AEP operating companies. This group works closely with the parent company’s Distribution Services organizations, and holds regular teleconference sessions on network findings, “lessons learned” in the field, and discusses potential network engineering solutions to common network planning and implementation issues. This committee can and does test and recommend system protection alternatives, such as recommending an approach for cable limiter placement or standardizing on a certain style of network protectors for the AEP networks.

The AEP Ohio underground networks are monitored at the AEP Ohio Network Operations Center at a location in downtown Columbus. Using a remote monitoring system, Network Technicians collect and monitor data from network protectors, transformers, and other vault sensors (see Remote Monitoring System ). If the network experiences any problems, service personnel are dispatched from this Operations Center to the field.

Process

Protection issues on the network system, including sizing and coordination of protective devices such as cable limiters and network protector fuses is the responsibility of the Network Engineering group.

AEP Ohio has standardized on Eaton CM52 network protectors, though it has various in-service styles of both Eaton and Richards protectors. The company utilizes cable limiters and sizes them to coordinate with the Network protector fuses.

The entire AEP Ohio network monitoring system is under refurbishment, most notably with a dual looped, redundant fiber-optic communications network that will relay information to AEP Ohio monitoring stations (See Remote Monitoring System ). Optical cabling is being installed as the CM52 network protectors and other microprocessor controls and sensors offer a wider range of information than was available on protectors the company used in the past.

AEP Ohio uses cable limiters on all its 480 secondary networks, at both ends of the mains (see Figure 1). The company also uses limiters in 216 V networks on cables sizes 250 MCM and above (though faults at 216 V will self-clear). Cable limiter application approach is documented in the AEP article, Guide to the Installation of Cable Limiters on Network Secondary and Service Cables . AEP uses the “Bussman” type cable limiters.

Figure 1: 600-V cable limiter used by AEP Ohio

For network protector relay settings, AEP Ohio uses standard settings on file, established based on recommendations by the network protector relay manufacturer for different sizes and voltages of network transformers, and whether or not it is a spot network. Protectors are routinely tested in the field and before installation.

One notable practice at AEP Ohio is its fire protection safeguards in vaults. Using the High Thermal Event System from Eaton, if the system detects a fire, it automatically trips and shuts down service to prevent fire from spreading beyond the vault. The fire guard system is installed on the high voltage primary switches.

Technology

Switches and protectors can be tripped remotely through the Network Operations room through its SCADA system. Most AEP Ohio network protectors now have electronic relays for connecting the communication wire coming out of the protector to the SCADA system. Other protectors are being actively upgraded to these microprocessor relays as the fiber-optic upgrade continues throughout the Columbus network.

Protectors are inspected and maintained on a regular basis (see Maintenance ).

AEP has issued an overcurrent protection guide that outlines general coordination issues.

AEP also uses the CYME TCC module to perform coordination studies. AEP used this technology to perform arc flash studies and to developing its network protector fuse requirements to conform to arc flash requirements.

7.14.2 - Ameren Missouri

Planning

System Protection

People

System protection for both the network and non-network infrastructure serving Ameren Missouri, such as sizing fuses and establishing relay settings, is performed by engineers within the System Protection group. The System Protection Group is part of Substation and Relay Maintenance, a group within Energy Delivery Technical Services at Ameren Missouri. This group provides protection for the entire company, including power plant protection, transmission and distribution.

The System Protection Group, led by a Supervisory Engineer, is comprised of 4- year degreed electrical engineers. System Protection engineers are non-union employees at Ameren Missouri.

For the urban underground infrastructure supplying St. Louis, System Protection engineers perform feeder device coordination for all 13.8kV feeders, size the fuses that protect the transformer in the indoor rooms used to service large customers radially, and establish network protector relay settings.

For network protector relay settings, Ameren Missouri uses standard settings on file, established based on recommendations by their network protector relay manufacturer for different sizes and voltages of network transformers, and whether or not it is a spot network. System Protection engineers establish the settings. Distribution Service Testers within the Reliability Support Services group perform the fieldwork.

The System Protection Group actively supports the downtown revitalization effort as needed. For example, one of the changes being considered by the revitalization group is the addition of primary sectionalizing switches (such as Vista switches) on network feeders. The group is evaluating the implications of such an addition to a protection scheme for network feeders.

Process

For network feeders, protective devices include the feeder breaker, network protectors and cable limiters installed on the secondary. Network feeders are designed without automatic reclosing. Feeders are protected with phase, overcurrent and instantaneous relaying. Ameren Missouri network feeders are fed straight off the substation bus, while radial feeders are fed through reactors to limit the fault levels for Ameren Missouri’s numerous primary metered customers. Ameren Missouri does not use primary sectionalizing switches as part of their network feeder design.

Ameren Missouri installs standard link type limiters between transformers and ring buses, and between ring buses on both ends of secondary mains. They use high capacity “sand type” limiters where they serve customers from the ring bus, and between protectors and the collector bus in a 480V spot.

For radially fed downtown customers, Ameren Missouri typically supplies either a preferred and reserve feeder scheme or a two preferred feeder scheme with a manually or automatically operated tie switch. In these designs, Ameren Missouri will specify a high side fuse in the indoor room to protect the transformer (For example, a 125 A fuse supplying 2500kVA transformer). The System Protection Group will then size these fuses.

For network protector relay settings, Ameren Missouri uses standard settings on file, established based on recommendations by their network protector relay manufacturer for different sizes and voltages of network transformers, and whether or not it is a spot network. System protection engineers report that the system is working well. Ameren Missouri does not experience problems with false trips or with protectors hanging up.

Technology

Distribution feeders are modeled in DEW. The System Protection Group will periodically (about every other year) provide source impedances to the group that maintains the feeder models. The DEW feeder models provide fault levels to the system protection group for analysis.

Ameren Missouri uses Aspen software to perform coordination. Aspen contains relay curves, time-current characteristics for primaries fusing, etc.

A the time of the practices immersion Ameren Missouri was analyzing the implications of changing standards around arc flash on protection, particularly in spot networks.

7.14.3 - CEI - The Illuminating Company

Planning

System Protection

People

System protection at CEI is performed by 3 Protection Engineers in the Planning and Protection Section of the Engineering Services Department (CEI Planning Group). All members of the group are four year degreed engineers.

FirstEnergy also has a corporate Distribution Planning and Protection organization responsible for providing governance and standardization to regional planning and protection groups. This group is currently working on developing company wide Distribution System Protection Philosophy document.

Process

The CEI Planning group is responsible for performing the analyses to determine appropriate protection. For example, it is this group that will determine and provide the settings for new, electronic relays being installed in network protectors.

Technology

Network Feeders are protected with phase and ground overcurrent relays with instantaneous and time delay. ( Non-directional time and instantaneous phase overcurrent relays (50/51); Time and instantaneous ground overcurrent relays (50N/51N).

CEI has decided to install electronic relays in their network protectors. These relays will modernize the infrastructure, add reliability to the network protective scheme and prepare the system for possible future SCADA interaction. These relays have been ordered, and are scheduled to be installed in 2009.

7.14.4 - CenterPoint Energy

Planning

System Protection

People

System protection of major underground facilities at CenterPoint is performed by the Major Underground Engineering department. Note that while CenterPoint has protective relaying employees in other parts of the company, resources to design, construct and maintain system protection for the underground are wholly contained within Major Underground.

Protection design is the primary responsibility of an engineer within the Vaults group of Major Underground Engineering. At the time of this EPRI visit, the position was vacant and the duties were being filled by the department Consulting Engineer.

Protection construction and maintenance is the responsibility of the Relay sub group of Major Underground, led by an Operations Manager. This group is comprised of a two Crew Leaders, and Network Testers, the field position at CenterPoint that constructs, maintains and tests network equipment, including implementing protection settings.

Process

The Vaults group engineer within the Major Underground Engineering department is responsible for performing the analyses to determine appropriate protection settings. The engineer works closely with the Relay Crews to develop procedures to ensure that the settings are tested thoroughly in Major Underground’s relay shop before field implementation. There is also continuous collaboration between the engineer and the relay crews whenever protective schemes are modified. The modifications are tested jointly in the relay shop by the engineers and the relay crews.

Technology

CenterPoint uses communication enabled microprocessor relaying in most locations. This includes microprocessor relays with communications within their network protectors. A network rehabilitation project began in 1999 to replace all network protectors with CMD type network protectors with communications enabled microprocessor relays.

One of CenterPoint’s ongoing concerns is that the expected shorter life of the new, battery powered devices, as compared to older electromechanical devices.

All underground feeders at CenterPoint, including Network Feeders, are set single shot to lockout. They are protected with phase and ground overcurrent relays with instantaneous tripping.

For situations where a substation transformer is highly loaded, CenterPoint has implemented programming at certain substations that will swap loads to alternate sources in the case of the loss of a substation transformer, helping them to defer the investment to increase transformer capacity. This programming, using substation relays in combination with remotely controlled devices in the field, moves loads among transformers within a station and from station to station to provide service continuity in a contingency situation during peak periods by optimizing the distribution of load among transformers. See Distribution Automation Control in Contingencies . (Note: this methodology is not used in substations feeding dedicated underground circuits.)

7.14.5 - Duke Energy Florida

Planning

System Protection

People

Planning does participate in establishing protection settings, but works closely with a separate Distribution Protection, Automation, and Control group that develops standard protection settings for distribution systems, including a standard protection scheme for the network. (Example, the “one shot to lockout” requirement for a network feeder). Both Planning and the Protection group are part of the Power Quality, Reliability, and Integrity Group (PQR&I).

Both the Planning and Protection groups work closely with Network Group, as much of the institutional knowledge of network protector settings is maintained by Network Specialists within the Network Group.

An Engineer within the Duke Energy Florida Standards group has developed a Secondary Networks section of the Engineering Guidelines that contains good information on network protection, and on coordination between cable limiters and the network protector relays. See Attachment C .

Process

In general, for network protector relay settings, Duke Energy Florida follows IEEE guidelines, and will work with the NP manufacturer, Eaton, to develop altered settings (such as building in a delay) when necessary to meet specific situations. The settings (overvoltage and the reverse current) of the St Petersburg NP relays are a bit different than the settings of the NP relays in Clearwater, as the two systems differ. For example, the St. Petersburg infrastructure consists of only spot networks supplied by non-dedicated feeders. Clearwater consists of spots and a grid network supplied by dedicated feeders.

As Duke Energy Florida has comingled network and non-network loads on portions of their systems in Clearwater and St. Petersburg, they have experienced issues such as protector cycling and pumping. In many cases, they have worked with the manufacturer to alter the settings to aid in these situations.

For network protectors, Duke Energy Florida uses the Eaton CM22 at 208V and the CM52 at 480V operation. All protectors are equipped with the electronic (MCPV) relays (see Figure 1). Duke Energy specifies internal network protector fuses, and sizes limiters to coordinate with the network protector.

Figure 1: Network Protector (CM22 with MPCV relay)

Cable Limiters are installed at each secondary junction on the secondary mains on the outgoing secondary cable. In addition, cable limiters are installed at all service connections. Duke Energy Florida uses full section limiters on the street main secondary grid. Half section limiters are used on service connection junction points and are sized to match the conductor size. This is to ensure a service conductor fault will be isolated before damaging the secondary main and associated limiters. Limiters are sized such that when a primary fault occurs, the primary protection should clear before any limiters blow. For a secondary fault, the limiters should clear the fault before the network protector fuse opens.

Technology

All network vaults contain Qualitrol monitoring (see Figure 2), which includes the network transformer oil level and oil temp as well as monitoring of the sump pump oil minder system to detect, alarm, and cease pumping of water in the presence of oil in the water. This information is aggregated using the Qualitrol sensor module and fed to the Eaton VaultGard system.

Figure 2: VaultGard and Qualitrol collection boxes mounted on vault wall

Vault information is remotely monitored using the Sensus system, which aggregates information gathered in the NP relay and in the Qualtrol sensor module through the Eaton VaultGard system, and transmits this data via cellular communications (see Figure 3), using a third party application (See Remote Monitoring).

Figure 3: Wall mounted Antenna for communication with Sensus System

7.14.6 - Duke Energy Ohio

Planning

System Protection

People

Duke Energy has a System Protection group that performs protective device coordination on the network. This work includes supporting the Network Planning engineer and the Network Project engineer in sizing fuses and establishing settings for network protector relays. (Note that most network protector locations utilize standard relay settings. )

The System Protection group that supports the Cincinnati network is part of the Protection Engineering, within the Asset Management organization. The System Protection group works closely with the Network Project Engineer within Distribution Design and the Network Planning Engineer within Distribution Planning Midwest.

Network Service Persons, a field classification within the Dana Avenue Underground group, are responsible for setting the network protector relays.

Process

When load is added to the system or the feeder needs to be recorded for any other reason, the network engineer will mark up a one line drawing of the feeder with the changes and send it to the System Protection group, who is responsible to look at the implications of the changes on the protection scheme and recommend any changes.

The system protection group is also responsible for sizing current limiting fuses, usually requested by customer based on the fault current. Note that Duke Energy Ohio does not require a current limiting fuse for a customer service.

7.14.7 - Energex

Planning

System Protection

See Design: Network Design

7.14.8 - ESB Networks

Planning

System Protection

People

System protection at ESB Networks is designed by planning engineers within the Network Investment groups – two groups responsible for planning network investments in the North and South. Organizationally, the Network Investment groups, both north and south, are part of the Asset Investment organization. In addition to the Network Investment groups, the Asset Investment organization is also comprised of a Generation Investment group and a Specifications group, each led by a manager. The Asset Investment group is part of Asset Management.

Planning and system protection is performed by one HV planner and four MV planners. Most of these individuals are degreed engineers, but some are “Technologists,” who have developed their expertise through field experience.

Planning standards and criteria are developed jointly between the Asset Investment group and the Strategy Manager, which is part of the Finance and Regulation group within Asset Management.

Process

ESB Networks has documented guidelines that restrict short circuit levels and also guidelines that affect neutral treatment. The ESB Networks underground network designs specify primary and backup protection against phase and ground faults. ESB Networks provides duplicate protection at network feeder supply points to eliminate pushing faults up to the next level. Therefore, the most critical circuits have more critical protection. ESB Networks uses secure radio communication between supply points and has both distance and differential relaying. If one protection fails, the other serves as backup protection. The designs include the following:

All 110-kV transformers have differential, distance relaying with back-tripping
38-kV uses distance relaying as well as a permissive over-reach transfer tripping
MV systems use overcurrent protection at the feeder source, where single-phase spurs are fused from the mainline.
LV systems rely on multiple protected earth grounding

ESB Networks maintains strict civil standards for underground network cable burial and protection.

LV and MV cabling is installed in red, high-impact underground PVC ducts with a 150-200 Joules rating. HV cabling is installed in red, high-impact cement-bonded high-density polyethylene (HDPE) ducts with a minimum 200 Joules rating.

To prevent accidental dig-ins, ESB Networks has begun deploying a notable two-tier marking system for its LV/MV duct-lines. At 75 mm directly above the duct-line workers lay a 2.5 mm wide tape marker. Above that, at approximately 300 mm below the surface above the duct-line, there is a 250 mm wide marker. For HV duct-lines, the company lays a 2.5 mm thick marker strip along the entire width of the trench 75 mm above the duct.

It is notable that all duct-line markers are yellow. ESB Networks has found that yellow tape markers are the most visible to any work crews that may be digging in the area of buried duct-lines.

Technology

ESB Networks uses secured radio communications between supply points.

ESB Networks is piloting the use of fiber-optic phase conductor (OPPC) cabling on the LV system. This cable can act as a phase conductor and provide an optical path for communications.

All procedures for cable duct-line burial and marking are contained in the company’s online repository for use by internal personnel and outside contractors.

7.14.9 - Georgia Power

Planning

System Protection

People

System protection of the network infrastructure serving Georgia Power, such as sizing fuses and determining network protector settings, is performed by engineers within the Network Underground engineering group, part of the Network Underground organization. This group provides protection engineering services for only the network underground system. Led by a Manager, the network UG Engineering group is comprised of four-year degreed electrical engineers, as well as Technicians (some, with a two year technical degree). These engineers are non-union employees.

Within the Network Underground organization, there is also a Network Operations and Reliability organization, led by a manager, and comprised of resources, such as maintenance crews, Test Technicians, who perform the fieldwork associated with network protector settings, maintenance and installation, and Test Engineers, who operate and troubleshoot the network system. Maintenance crews are staffed with bargaining unit positions. The Test Technician classification is a non-bargaining, non-exempt position. The Test Engineer is a non-bargaining position.

The network is monitored by the Network Operations staff, comprised of Test Engineers, and is comprised of four-year and two-year degreed engineers.

Process

For network protectors, Georgia Power uses both Richards and Eaton protectors. Engineers have standardized on submersible dual voltage protectors (can be set for either 208V or 480V operation.

Figure 1: Lee Welch, GA Power, describing a network protector

Georgia Power deploys mainly Eaton CM 22 and Richards 313 and 314s, and is happy with all three products. Engineering has bought and installed a few CM 52s for trial, but are concerned with the implications of stored energy in the unit spring. Once the trial is complete and identified issues are resolved, Georgia Power may move to this model or some other similar. Electronic relays are used on all types of protectors. Some older protectors have internal fuses, but Georgia Power is moving to protectors with outside fuse boxes mounted on the top of the protectors. Current-limiting fuses are installed outside all protectors. All new 480 volt protectors have the external fuse boxes, which allow one fuse to be uncovered at a time – a precaution against phase-to-phase flash.

Figure 2: 3000 A silver sand CLF

All network protectors are connected to the Network Operations center by a SCADA system that runs on DSL, radio frequency using the Southern Link system, or fiber network connection to the center where protectors are monitored by the Network Operations staff. Remote monitoring has been in place at Georgia Power for 15 years (See Figure 3 and Figure 4.).

Figure 3 and 4: Image from GA Power Network Control Room

For network feeders, protective devices include the feeder breaker, network protectors, and fuses installed on the secondary between the network and the customer. Current-limiting fuses are used between the collector bus and the customer’s facilities (See Figure 2). The limiters are in place mainly to protect the Georgia Power bus from customer faults, and the company does not want customers to depend on that limiter.

Georgia Power network feeders are fed by circuit breakers straight off the substation bus. Network feeders are designed without automatic reclosing, normal for an underground network design.

For network protector relay settings, Georgia Power uses standard settings on file, established based on recommendations by the network protector relay manufacturer for different sizes and voltages of network transformers, and whether or not it is a spot network. Protectors are routinely tested in the field and before installation. Georgia Power engineers report that the system is working well, and ascribe this to standardization and remote monitoring. Georgia Power experiences very few problems with false trips or with protectors hanging up.

Technology

Breakers and protectors can be tripped remotely through the Network Operations room through its SCADA system. Many protectors now have electronic MPCV relays for connecting the communication wire coming out of the protector to the SCADA system. Protectors are inspected and maintained on a regular basis, tracked by in-house maintenance software.

7.14.10 - National Grid

Planning

System Protection

People

System protection for the network, such as sizing fuses and establishing relay settings, is performed by planning engineers within distribution planning. This includes all protection settings including the distribution feeder breaker settings. Note that National Grid does have a protection engineering group, whose responsibility stops at the substation bus.

Process

For network feeders, protective devices include the feeder breaker, network protectors and cable limiters installed on the secondary.

Historically, National Grid Albany used cable limiters on network protector leads and on services. More recently. National Grid has been applying cable limiters to street mains in selected locations to assure that the secondary cable system can adequately clear solid faults.

National Grid’s network standards call for all new conductor installations to have limiters installed at each end of cable runs and at junction points. The cable limiters used are standard, non-replaceable type. Sand type current limiters are not used in the street grids.

Technology

A National Grid underground engineer has performed a study of the Albany network to identify locations where the secondary cable system cannot adequately clear solid faults. From this study, he has identified specific locations where corrective measures such as changing conductor size, installing cable limiters or changing transformers to increase the available fault duty can be applied.

Figure 1: Note cable limiters on network protector leads.

7.14.11 - PG&E

Planning

System Protection

People

System protection for the network, such as sizing fuses and establishing relay settings, is performed by the network planning engineers. For network protector relay settings, PG&E uses standard settings (established over 30 years ago) for different sizes and voltages of network protectors. Assuming that the network protector’s breaker mechanism is working properly, if a network protector has problems closing or opening, then a distribution engineer would review the settings and ask the Maintenance and Operations Department to implement any changes.

The network planning engineers are part of the Planning and Reliability Department. This department is led by Principal Engineer, who is also the department supervisor. This group does distribution planning for both the network and non-network systems. Eight engineers comprise this department. Six focus on the radial system, and two focus on the network system.

For network systems, the two Planning engineers are responsible for distribution planning and network protection. Both network planning engineers are four year degreed engineers.

The planning engineers are represented by a collective bargaining agreement (Engineers and Scientists of California).

Process

For network feeders, protective devices include the feeder breaker, network protectors and cable limiters installed on the secondary. PG&E uses cable limiters where the secondary feeds out the street grid (limiters applied on both ends). Limiters are sized by the network planning engineer.

Network feeders in San Francisco are designed with primary sectionalizing switches^[1] (manually operated, not fault sensing devices). One of the drivers for the decision to design these switches into their network feeders was have a place to sectionalize.

Figure 1: Oil filled network primary sectionalizing switch (model used at training facility)

For example, when opening a network feeder, they may have network protectors that are “hung up”; that is, failed to open. The primary sectionalizing switches provide them an opportunity to isolate the section of the feeder where the hung up protector is located so that they can move ahead with their work assignment in the de-energized section.

The switches provide an isolation point for troubleshooting and repairing a failed cable section. In addition, the sectionalizing point minimizes the steps associated with feeder clearances as they provide the ability to take a clearance on a feeder section rather than the entire feeder.

The sectionalizing switches have historically been oil filled devices. PG&E has embarked on a program to replace these devices with solid dielectric vacuum switches in order to reduce environmental and other possible hazards associated with the gear.

Figure 2: Solid dielectric network primary sectionalizing switch (model used at training facility)

As part of PG&E’s planned SCADA upgrade project, which will increase the level of remote monitoring and control in the network (See Remote Monitoring and Control), network protector relays are being replaced with communication enabled relays (Eaton MPCV relays).

PG&E may use a “load capacitor” on the network protector to be able to close the protector in the event of an unloaded secondary. For example, if a customer breaker opens, and the network protector (NP) is set on the automatic setting, it won’t detect any load on the secondary. PG&E will use the load capacitor to provide a “phantom load” to confirm the NP’s ability to close when set to auto, and when the customer’s load is restored.

Figure 3: “Load capacitor” mounted on secondary used to test the auto close ability of the NP

A challenge for PG&E is that they frequently have NP’s that will not close when the circuit is reenergized. In some cases, this is caused by very light loading, but in many cases, PG&E engineers suspect a relay settings issue. One area of increased focus cited by PG&E is the proper application of the NP test kit and establishment of the settings in the proper range during protector maintenance.

^[1] Note that in Oakland, network feeders are not designed with primary sectionalizing switches. This difference is due to historical differences in design and maintenance philosophies between Oakland and San Francisco. PG&E has recently assigned responsibility for planning of both networks to the network planning engineers, within the Planning and Reliability group.

7.14.12 - Portland General Electric

Planning

System Protection

People

Several groups are involved with system protection on the network. On the PGE system, the Substation Group and Distribution Group are different organizations with different areas of concern. The Substation Protection Department handles feeder breaker protection, and Distribution Engineers handle protector settings on the distribution system, and the coordination of settings with the feeder breaker.

Service & Design Project Managers (SDPMs) are also involved with system protection. They have a clearly defined role and work almost exclusively on external projects. Two SDPMs cover the network and oversee customer projects from start to finish, ensuring that protective systems comply with regulations and PGE specifications.

Another important role is the Special Tester, which is a journeyman lineman who has additional training and technical skills, making them an expert on network protectors and relay settings. One Special Tester that is embedded in the network CORE group checks any protective equipment before it enters service on the network.

Process

System protection begins at the network substations, where network feeders emanate from separate bus sections. In this way, the loss of a bus section causes an outage on only one feeder supplying any one network. At one of the two stations that supply the networks, PGE regulates voltage with bus regulation. At the other station, the company uses line regulation, as this station supplies both network and radial feeders from the same bus sections, and line regulation offers finer control. PGE does not experience many problems with network protectors pumping and cycling, which is symptomatic of voltage and angle differences among network feeders.

PGE supplies its networks from 12.4-kV primary feeders from one station, and from 11-kV primary feeders from another station. Its networks are delta-wye, with all network feeders dedicated to network supply. Primary network feeders are protected with instantaneous relaying. PGE uses a faster acting setting when workers are working on a feeder.

In most of its spot network vaults, PGE has installed a ground fault relay scheme that measures the neutral and ground current through a current transformer (CT). If the current exceeds a threshold, it trips all of the network protectors supplying the spot and locks them into the open position. Once this system activates, the protectors can only be closed with manual intervention. PGE installed this scheme because the primary protection scheme will not see through to a fault on the downstream side of the protector prior to the collector bus. PGE has experienced incidents in which the customer bus in front of (upstream of) the switchgear faulted, and the ground fault protection scheme worked as intended.

For the protective system to function correctly, PGE requires that the customer-side ground and neutral not be grounded on the customer side, but instead be isolated, and that it be tied in with the ground fault scheme on the vault secondary side.

In addition, most vaults also have a trip scheme tied in with thermal sensors located above the collector bus and above the transformers. This scheme also trips all of the protectors supplying the spot.

Overall, PGE’s network rarely has problems with protectors pumping and cycling. However, in older buildings, lightly loaded systems may cause the protectors to open.

On the CM52 network protectors that PGE uses, fuses are mounted externally and do not include a “visual open.” The CM52 is a dead-front protector. At the time of the immersion, PGE was considering utilizing the arc flash reduction module (ARMS) system in future spot network locations. PGE does not use remote racking as a standard.

Crews bring new protectors to the warehouse, where a Special Tester tests them. This initial quality assurance check ensures that there will be no issues when the unit is installed. In addition, the Special Tester checks the equipment before it enters service. In some vaults, network protectors are wall mounted rather than fitted to the transformer, because the facilities are older and the vault is not big enough to fit a network unit. In some of these vaults, because of space limitations, the network unit is built by banking three single-phase transformers together, and using a separate wall-mounted primary switch and wall-mounted network protector.

Technology

All PGE network protectors are either CMD or CM52 units from Eaton. Standard sizes that PGE uses are 1875 A and 2825 A units. Eaton systems have high interrupting and fault close ratings, and the components are modular and standard across the different ratings. By using the same units, PGE reduces the need for a large part inventory and additional training for technicians and crews^[1].

PGE uses CM52 network protectors in 125-kV/216-kV and 277-kV/480-kV volt-Y connected secondary network systems. The systems include an air circuit breaker with an operation mechanism, network relays, and control equipment. The units are available as submersible variants, and can stand alone or be mounted on the transformer throat. Submersible units are made of welded steel, which is bonderized and painted. The network protectors include an internal window that allows crews to see the internal hardware, and the door can be hinged on either side^[2].

CM52 units include externally-mounted, silver-sand fuses to interrupt fault currents if the networker fails to trip. Additional internal copper-link or lead alloy fuses can be installed inside the enclosure.

Protector Remote Monitor: The PGE network is fitted with a remote monitoring system, which is used only for monitoring and not for control. The remote monitoring system is fiber based, using the Eaton Mint II system with a PowerNet server platform interface. A fiber conversion system from H&L Instruments converts the fiber communications to the protocol used on the NPs, and vice versa.

At present, PGE uses the system only for monitoring and not for control. When clearing a feeder, crews open the feeder breaker and double check, through the remote monitoring, that the protectors are open. They also test at the substation to assure that there is no back-feed. PGE is assessing the Eaton VaultGard monitoring system to harden the system, using the looped fiber optic communications already installed throughout the downtown area. The reason for assessing VaultGard is that it is a web-based protocol with integrated software that allows a higher degree of control.

Eaton. “CM52.” Eaton.com. http://www.eaton.com/Eaton/ProductsServices/Electrical/ProductsandServices/ElectricalDistribution/SpecialtyPowerDistributionSystems/SecondaryNetworkSolutions/CM52Protectors/CM52/index.htm (accessed November 28, 2017).
Instructions for the Eaton Type CM52 Network Protectors 800 to 4500 Amperes. Eaton, Moon Township, PA: 2010. http://www.eaton.com/ecm/groups/public/@pub/@electrical/documents/content/ib52-01-te.pdf (accessed November 28, 2017).

7.14.13 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 4.5 - Primary Feeder Protection

EPRI Low-Voltage Training Material

Fuse and Cable Limiter Coordination

7.14.14 - Survey Results

Survey Results

Planning

System Protection

Survey Questions taken from 2018 survey results - Manhole Event Preparedness and Response

Question 17 : Do you use cable limiters in your network secondary system(s)?

Survey Questions taken from 2015 survey results - Design

Question 65 : Do you use cable limiters in your network secondary system(s)?

Question 66 : If you use cable limiters please indicate where you install them (check all that apply)

Question 67 : If you use cable limiters, do you perform a protection coordination study between the Network Protector fuse, cable limiters, and the station’s feeder relay?

Question 68 : If you use cable limiters, do you rely on the conductor to burn clear as part of your secondary network protection scheme?

Question 69 : If you use limiters, do you perform studies of anticipated bolted fault currents in the secondary to assure that faulted sections burn clear or are isolated by appropriately sized cable limiters?

Question 70 : By your estimation, what percentage of the time are cable limiters effective?

8 - Safety

8.1 - 2020 Vision Program

8.1.1 - Portland General Electric

Safety

2020 Vision Program

Process

Recently, PGE accepted that many of its business processes were siloed, making it difficult to view operations across the entire enterprise. The fact that the company used over 300 different software applications exacerbates this challenge. In addition, the computer solutions used were fragmented, relied on patches and workarounds, offered little consistency and flexibility, and relied upon a number of key personnel. Accordingly, PGE recently initiated a number of programs to update the information technology (IT) systems, and use technology rather than employees to perform certain key functions.

One of PGE’s programs to address the IT gap is the “2020 Vision” program, which is intended to improve the overall efficiency of the business (see Figure 1). The 2020 Program began in 2008-2009, with the intention of delivering a modern, integrated IT system able to handle increasingly complex demands. The program uses technology to streamline and facilitate core business processes by enhancing the technology infrastructure and introducing flexibility to the workforce. The program will also improve the protocols for retaining knowledge and experience within the organization. Finally, it will improve the visibility of data across the company and support better use of data and metrics for reporting and accountability.

Figure 1: 2020 Vision Program

The 2020 Vision Program is a ten-year strategy that will modernize and consolidate the technology used at PGE. Legacy systems will be replaced by enterprise applications that maximize efficiency, streamline processes, and create flexibility. The new, integrated technology platform will reduce the number of vendors and underpin future smart grid developments.

The core technologies used in the program system include:

Maximo Mobile and Scheduling
Geospatial Information System and Graphic Work Design (GIS/GWD) replacement
Outage Management System replacement (OMS).
Although PGE has reduced the number of different programs, the new systems are more complex and have additional functions, as well as a need for interfaces between systems and common data management. Cybersecurity is also an issue, with IT support required to protect sensitive data.
Maximo: Maximo replaces the previous work management system, supports metric-based service management processes, and provides a common asset database across PGE.
Geographic Information System (GIS) and Graphic Work Design (GWD): This system is intended to improve the access of field employees to important asset location information. It also allows PGE to share critical information with emergency services during an incident. The system reduces the amount of manual, paper-based work and reduces the design time for customer-requested tasks.
MyTime: This web-based time collection system handles time and labor data, as well as automates working rules, regulations, and union contract provisions.
Customer Engagement Transformation: This project is intended to replace the older customer information system and meter data management system.

T&D Transformation

T&D Transformation is a subset of the 2020 Vision Program. PGE performed an in-depth review of the best way to capture efficiencies with new software systems and improve effectiveness. The program seeks improvement in five areas:

Employee Safety: Maximo Mobile & Scheduling supports safety, because it is possible to track and log work processes when a worker completes inspection or maintenance work, locate employees, and provide communications.
Accountability: Teams are provided with comprehensive information, and supervisors can monitor current crew status and track work progress. This provides data about how work is performed and helps assess how it can be completed more efficiently.
Standardization of Processes: All departments will use the same systems.
Productivity: Streamlining work orders and sending information remotely will improve productivity by reducing travel time, allowing dynamic re-optimization of work schedules, updating work status, and updating asset information and details of work performed.
O&M Efficiency: Maximo will allow PGE to track inventory use and find the optimum stock levels, and maximize the availability of stock for upcoming work while lowering the amount of unnecessary stock held in inventory.

Overall, the program relies upon centralization, standardization, and technological solutions to streamline workflow processes. The first phase, completed in 2012, implemented Maximo and Mobile technologies, and now supports substation operations, field employees, and back-office workers. The system uses Maximo to track work and assets, and supports Enterprise Resource Management with Logica’s Asset and Resource Management Scheduler and Field Manager. This system integrates with Maximo and other systems to support scheduling, dispatch, and updating field work progress. In 2015, PGE installed the Geospatial Information System and Graphic Work Design Applications (GIS/GWD) system, after a process of analyzing, building, and testing the system. The utility also installed the new OMS.

Next Wave Project

The Next Wave project is a subset of the 2020 Vision Project and involves Maximo 7.5, CGI Asset Resource Management (ARM) Scheduler, and CGI ARM Field Manager. The new systems will replace and enhance existing work process and asset management systems. Alongside the IT implementation, PGE has initiated a number of organizational and process changes that will improve productivity, make assets more visible, enhance workflow and monitoring, and deliver a more robust and consistent data collection process. The Next Wave Project focuses on T&D.

8.2 - Accident - Incident Investigation

8.2.1 - Ameren Missouri

Safety

Accident / Incident Investigation

People

When Ameren Missouri experiences an incident, such as a failure of a piece of network equipment, or a safety accident or near miss, they will form a post incident response team to conduct an investigation. The composition of the team performing the post incident investigation depends on the nature of the incident.

Process

After a significant safety incident, Ameren Missouri may implement a Safety Stand Down, a period of work shut down where company resources are focused on investigation and understanding what happened and implementing processes to avoid repeat incidents. Ameren Missouri successfully used the Safety Stand Down after a significant incident in early 2011 involving an electrical contact where, fortunately, no one was hurt. Following the incident, they shut down work, and implemented a two-week “safety blitz” that included a review of company safety manuals with employees, employee testing, and a review of procedures for working with energized equipment.

Post incident investigations of a failed piece of equipment may lead to changes in equipment specifications or design standards. As an example, a post incident investigation of a network transformer failure led Ameren Missouri to change their transformer specification to call for a rupture proof tank design.

Technology

Ameren Missouri publishes a monthly Incident Summary, a bulletin that describes the incident, indicates the primary and contributing causes of the incident, and summarizes the recommendations to prevent the incident from occurring in the future. The Incident Summary bulletin is posted on the Safety Bulletin board within each department.

8.2.2 - CEI - The Illuminating Company

Safety

Accident / Incident Investigation

People

For an OSHA recordable incident or and accident / incident where medical attention is given, CEI has a formal investigation process. This process calls for the formation of an investigation team that includes the Region Director of the region involved, the regional Safety department, the Union steward, and, sometimes, Corporate Safety.

CEI does not have a formal written process for incident investigations that are not OSHA recordable.

Process

Every incident at CEI is followed up with an investigation. The leader of the investigation team depends on the incident. The team is usually led by the department manager. Team members include individuals on the crew, supervisors, and the union steward. If the incident is OSHA recordable, the Regional Director will be involved. If someone got hurt or may have been hurt, a safety coordinator is included.

The role of the investigation team is to:

determine what happened; that is, ascertain the facts,
verify that procedures were followed,
view the incident as a learning situation with a focus on prevention,
recommend revisions to existing procedures,
produce a report that summarizes findings and conclusions.

8.2.3 - CenterPoint Energy

Safety

Accident / Incident Investigation

People

CenterPoint has a formal process for investigating an OSHA recordable accident or vehicular accident. Within five days of the accident’s occurrence, an investigation committee is formed consisting of:

Director
Manager
Crew Leader
Member of the Safety Department
HERO Committee Member
Person(s) involved
Peer employee

Process

Every OSHA recordable and vehicular accident at CenterPoint is followed up with a formal investigation. The investigation committee will look at the incident, ascertain the facts and summarize what happened, perform an analysis to determine whether or not procedures were followed, and develop recommendations to prevent a similar occurrence in the future.

Note that the administering of formal discipline associated with an incident is not part of the team’s role. Determining if discipline will be administered is the responsibility of management in partnership with the Human Resources department.

Technology

CenterPoint publishes and distributes a safety facts bulletin summarizing every injury and incident.

8.2.4 - Con Edison - Consolidated Edison

Safety

Accident / Incident Investigation

People

Environmental, Health, and Safety (EHS)

Con Edison has a centralized group Environmental, Health, and Safety group (EHS), as well as EHS personnel imbedded throughout the field organizations. Con Edison has an extensive set of procedures as well as intensive training around EHS issues.

The EHS department responsibilities include providing internal oversight and guidance on environmental, health, and safety issues; policy and procedure development; performance reporting; compliance; incident investigation; and review and approval of safety equipment.

Process

Con Edison Accident/Incident Reporting Process

Con Edison has well-documented procedures for investigating and reporting serious accidents, incidents, and other occurrences. At Con Edison, serious accidents, incidents, and occurrences are those situations that affect Company operations, threaten degradation of service to a significant number of customers, might result in media interest, or affect the Company’s image to customers, regulators, elected officials, or the public. Con Edison’s procedures define actions that must be taken and define responsibilities for executing those actions.

When a serious accident, incident, or occurrence takes place, the department involved with the event notifies a group called the Central Information Group (CIG), located at Con Edison’s Energy Control Center. The CIG, which is manned around the clock, is responsible for acquiring, and disseminating information on reportable incidents to all appropriate company organizations. The distribution of the communication depends on the type of incident. For example, if someone is injured, there would be rapid notification to a broad array of people, including senior management. For other types of incidents, the email distribution may be limited to local management.

Con Edison’s procedures define the types of incidents to be reported, including:

Incidents related to Transmission Capability on the Electric System are reported by the System Operator.
Incidents that affect the Gas, Electric, and Steam Distribution Systems are reported by the appropriate Emergency Supervisor or Responsible Party.
Incidents that are classified as Personal Injuries or Property Damage relating to or caused by Company Employees and/or Company Equipment are reported by the Appropriate Emergency Supervisor or Responsible Party.
- For an accident involving a serious injury or death, the CIG issues an Accident Facts Bulletin via email as soon as practical after the event.
Incidents classified as Civic Obligations are reported by the appropriate Emergency Supervisor or Other Responsible Parties — e.g., Fire and/or Police Department.
Incidents affecting the Gas or Steam Transmission System are reported by the appropriate Gas System Operator or Steam Dispatcher.
Incidents involving Contingencies, Low Voltage, or Customer Outages are reported by the Electric Operations Emergency Supervisor.
Incidents involving Steam Operations are reported by Generating Station Operations Shift Supervisors.
Incidents involving Oil Spills, Fires, and Hazardous Substances are reported by Substation Operations.

After a serious accident, incident, or occurrence takes place, an Incident Investigation Team is promptly formed to investigate and prepare a confidential report detailing the events that led to the incident, and providing any recommendations that emerge from the investigation. The team members, including a chairperson, are selected from multiple organizations in the Company, with at least one member who is knowledgeable of the particular operation(s) involved in the incident, one member from the Law department, one member from Auditing, and one member from the Environment, Health, and Safety department.

8.2.5 - Duke Energy Florida

Safety

Accident - Incident Investigation

People

When Duke Energy Florida experiences a safety related incident, such as a failure of a piece of equipment, or a safety accident or near miss, they will conduct an investigation. The first responder to incident is the Lead Professional Health and Safety Professional for the division where the incident occurred.

Process

After a significant safety incident, the Lead Professional Health and Safety Professional will begin the investigation to determine the facts of what happened, why it happened, and how to prevent a future incident similar in nature. Over time, incident investigations have become more successful as employees have seen improvements as a result of findings from prior incident investigations. The learnings from prior investigations have resulted in new procedures or engineered safeguards to protect workers in the field.

Having seen successful results from prior investigations, employees are more engaged in the incident investigation to improve overall safety for the entire company. Employees are engaged in reporting near misses as the focus is not on disciplinary action, but rather prevention of future incidents.

One example of an incident requiring investigation and resulting follow up was one where a worker who had completed performing a DC hi- pot test, shut the DC hi-pot tester off, and attempted to remove the test probe from the de-energized feedthrough with a leather gloved hand, rather than with an insulated rubber glove. He received a shock even after the machine was turned off. Unknown to the worker, there was still charge left on the cable. In response to this incident, all hi-pot test units were “red tagged” and taken out of service until updated firmware from the manufacture could be installed on the testers, which prevents shock due inadvertent bare handed contact after the machine is shut down by grounding the cable under test and bleeding off any charge.

Technology

After a safety incident has occurred, the Lead Health and Safety Professional is sent immediately to the site, documents what happened by directly interviewing crew members and supervisors, takes pictures, and files a Preliminary Investigation Report (PIR). The PIR will provide recommendations to prevent an incident in the future and is forwarded to the corporate Vice President of Safety.

8.2.6 - Duke Energy Ohio

Safety

Accident / Incident Investigation

People

Duke Energy Ohio performs an accident investigation to ascertain the facts associated with an accident and to identify follow-up learnings.

An accident investigation team is formed consisting of the supervisor, a union representative, the crew involved in the accident, and corporate Environmental Health and Safety (EHS).

The team is charged with developing a preliminary report within 24 hours of the accident.

Process

Duke Energy Ohio has an accident investigation form that describes the steps to take in performing the accident investigation.

8.2.7 - Energex

Safety

Accident / Incident Investigation

People

Improving safety is a key focus area for Energex, which is driven by the company CEO. The company has embarked upon a system wide effort to change their safety culture. In the recent past, Energex had experienced three safety incidents, resulting in worker injuries. The company is hoping to leverage the emotion from those events as a driver for changing the safety culture.

Energex has established a safety management system, which is a comprehensive framework that guides their safety approach, and addresses strategies for managing the hazards and risk associated with the design, construction, operation and maintenance of the system. Strategies such as the approach to safety training, incident investigation and response, and emergency preparedness and response, are guided by this framework.

Energex has recently reorganized their safety organization, consolidating a corporate safety group, a Service Delivery safety group, and a Power Plant Safety group to form one safety organization.

Process

In response to a safety incident, Energex conducts an incident investigation. After severe incidents, such as an electrical contact, the company suspends all live line activities until the incident is fully understood. The response to an incident depends upon the severity of the incident. Each incident is classified and the level of classification defines the response. An investigation is performed using an investigation framework referred to as the incident causation analysis method (ICAM), which is a framework for documenting incident findings. In response to employee feedback requesting more information about safety incidents in their aftermath, Energex produces an incident summary. The incident summary is communicated back to employees through an incident learning document

(See Attachment B: Share Our Learnings Sample)

Technology

Energex has an incident database, called the eSafe system, which houses summations of all safety incidents and near misses. Each day, before the field crews are dispatched to conduct the day’s work, the work leader performs a “safety catch-up,” which is a review of any previous day incidents identified through the eSafe system with the work crews. Employees sign a document, indicating that they participated in this meeting.

(See Attachment C: Daily Safety Catch-up for Field Services)

8.2.8 - ESB Networks

Safety

Incident Investigation

People

ESB Networks maintains a Chief Executive Safety Committee that oversees and thoroughly documents safety procedures and practices. Representatives from throughout the company rotate onto the committee to get a more complete overview of current and evolving safety practices. Incidents are investigated by the safety committee, staff members, and network safety trainers.

Process

ESB Networks has a strict code of practices of safety behavior agreed upon by all the trade unions. Staff members participate in safety incident investigations, including approaches for doing work differently throughout the network to prevent another incident of the type investigated. Near miss reports can be reported anonymously – a way in which ESB Networks believes it can capture more data – and there is no punitive action taken for reporting near misses.

8.2.9 - Georgia Power

Safety

Incident Investigation

People

Crew supervisors are required to document any and all accidents, incidents or injuries at the job site with forms that are kept on the crew truck(s). The injury report is then forwarded to the Safety and Health group within Georgia Power. If the incident involves failed equipment or a “near miss,” a report is filed with engineering as well, and a Test Engineer must inspect the site before work continues. Failed equipment is then systematically and safely removed and taken to the Georgia Power TestLab for analysis.

Process

In the event of an accident, even a minor one, such as a crew member pulling a muscle, a member of the Safety group fills out a first aid form which includes all information about the accident including witnesses. The crew supervisor signs the form. The injured employee, the Safety group, and the supervisor each receive copies of the signed report. The employee can then take the report to a clinic, doctor, etc. to receive treatment, and to determine if the accident is considered an OSHA-recordable event.

For OSHA recordable events, the Safety supervisor will issue a First Notification report which is distributed state-wide over the company intranet to all managers, supervisors, and crew supervisors. The managers and supervisors use this report to inform their crews and raise awareness about the incident and how it can be prevented in the future. The First Notification report then is entered into the Georgia Power electronic OSHA log. Hard copies of the form are also kept. The same procedure is followed whether the accident is preventable or non-preventable.

Georgia Power is especially vigilant about arc flash prevention. If a crew member works on an energized conductor, for example, and does not follow safety procedures, the non-compliance must be reported. All incidents that involve a flash must be reported. Not reporting a flash incident is cause for dismissal.

Managers at Georgia Power report that as a result of these stringent safety guidelines and focus on reporting, they believe that employees do report every incident, however minor, including dents to equipment, windshield cracks, etc.

Technology

Georgia Power uses a computer program called “SHIPS” to documents training and safety records of all employees. Records are kept concerning accidents, incidents and OSHA recordable events. The system serves as the permanent record of the safety and training history throughout an employee’s career.

Incidents and accidents are classified as “charged” for incidents in which an employee is responsible for the incident. The record of the incident is “charged” to the employee’s business unit, or “uncharged” if the employee is not responsible. In this way, safety becomes behavioral-based, and the Health and Safety group can analyze these incident statistics for any number of variables that might be useful in modifying safety training and/or awareness.

8.2.10 - HECO - The Hawaiian Electric Company

Safety

Accident / Incident Investigation

People

At HECO, Accident - Incident Investigation is administered by the Safety department.

HECO has implemented a Near Miss program that investigates serious near miss situations that could have resulted in injury or death to someone, equipment damage, or a widespread outage. The Safety department administers the Near Miss program.

Process

The crew involved in the near miss situation would notify the safety department who would work with the department involved to investigate the situation. The outcome of the investigation can result in changes in work procedures to prevent or at least minimize the potential for a similar future occurrence.

The program is non – punitive, unless there is a serious violation of the safety rules.

HECO is also focusing on changing their approach to accident and incident investigation to be more focused on prevention. This includes the development of a Near Miss program that includes investigation of “near misses” that could have resulted in either damage to equipment, outages, or injury.

8.2.11 - National Grid

Safety

Accident / Incident Investigation

People

Supervisors and safety professionals of National Grid perform periodic compliance assessments, which are audits to assure that company safety practices are being adhered to. The results of these audits are reviewed and trended so that the company understands what the large issues are. Smaller or less significant incidents are typically reviewed informally.

National Grid has a formal incident analysis process to be implemented following a significant incident, or a near miss with the potential of being significant. National Grid uses an incident management system (IMS) that informs supervisors of the level of severity of various incidents. For example, a supervisor may use the IMS to determine whether or not a particular near miss event requires a formal incident analysis or not.

Process

In a formal incident involving safety, the Safety Department will assign team leader to an incident review team. The team is required to complete an analysis within two weeks.

Technology

National Grid has established a telephone number for employees to use to report incidents that are significant, or near miss events that had the potential to be significant,

National Grid provides near miss cards, which employees can fill out and turn into Corporate Safety reporting near miss events. These cards are not anonymous (See Attachment I).

National Grid uses an incident management system (IMS) managed by the Corporate Safety Department.

8.2.12 - PG&E

Safety

Accident / Incident Investigation

People

When PG&E experiences an incident as a result of failure of a piece of network equipment, such as a transformer or network protector, they will conduct a post-failure incident investigation. This investigation is normally led by the manager of networks, the asset manager for network equipment. The manager of networks is responsible for writing the failure investigation report.

Process

PG&E documents the results of its post incident investigation in a failure investigation report. This report includes a discussion of the background, the sequence of events that led to the failure, the findings of the investigation, and specific recommendations resulting from the investigation.

PG&E has an accident investigation form and procedure that describes the steps to take in performing the accident investigation.

PG&E has developed and implemented a form to enable employees to report “near misses” or “close calls”. This is an informal program at PG&E. PG&E management acknowledged that near misses are likely underreported by the work force for fear of repercussions, and that an area of opportunity for the company would be to increase the reporting of near misses to better identify risks and implement countermeasures.

8.2.13 - SCL - Seattle City Light

Safety

Accident / Incident Investigation

Process

Safety Accident Investigation

SCL has a process for convening a fact-finding investigation meeting after an accident within a certain time frame. These post-accident investigations sometimes result in work practice / process changes based on lessons learned from the investigation.

8.3 - Arc Suppression Blankets

8.3.1 - CenterPoint Energy

Safety

Arc Suppression Blankets

Process

CenterPoint performs heat gun checks to identify hot spots before entering a hole, as part of their manhole - vault entry process. They may use blast blankets in areas where the heat gun checks they perform as part of their manhole entry reveal hot spots.

8.3.2 - Duke Energy Florida

Safety

Arc Suppression Blankets

People

Duke Energy Florida uses blast blankets in areas where they are concerned about inadvertent contact with conductors or equipment. They will hang the blankets on portable stanchions, developed by Duke Energy Florida and dielectrically certified by a third party testing company (Kinetrics). Due to the success Duke Energy Florida had with the stanchions, an article was written in Incident Prevention Magazine [1] on the development of the stanchions.

Process

Instead of wrapping rubber blankets around or on top of areas of concern, Duke Energy Florida has set up stanchions with D rings where they can hang the blast blankets to provide separation between the equipment and workers in the hole.

New work procedures require the stanchion blast blanket system be used any time a crew is working on one circuit and there is another circuit in the hole.

Technology

The stanchions are threaded tension bars designed for use in the manholes and vaults. While newer manholes are designed with the clips in the ceiling for hanging blast blankets, older manhole do not have clips, because there is uncertainty about the strength of the material behind the ceiling in which the D ring will be mounted. The advantage of the threaded stanchion system is that it can expand within the manhole or vault and it is free standing without the requirement of additional drilling.

Figure 1: Blast blanket on stanchions

^[1]incident-prevention

8.3.3 - HECO - The Hawaiian Electric Company

Safety

Arc Suppression Blankets

People

Arc Suppression Blankets are used by the Cable Splicers within the C& M Underground Group.

Figure 1: Arc Suppression Blankets

Figure 2: Arc Suppression Blankets

Process

Cable Splicers utilize arc flash suppression blankets to cover facilities when perform work activities that increase the potential for an arc flash, such as moving cables and splices on energized facilities.

8.3.4 - Survey Results

Survey Results

Safety

Arc Suppression Blankets

Survey Questions taken from 2015 survey results - Safety

Question 129 : Please indicate which of the following design, operational or work procedure changes you have implemented to address network arc flash issues

Survey Questions taken from 2012 survey results - Safety

Question 8.11 : Please indicate which of the following design, operational or work procedure changes you have implemented to address network arc flash issues

8.4 - Career Development Program

8.4.1 - Con Edison - Consolidated Edison

Safety

Career Development Program

Process

Career Development Programs

Con Edison has three distinct programs focused on career development.

The GOLD program (Growth Opportunities for Leadership Development) is the company’s main college recruitment program. The GOLD program develops high-caliber college graduates for positions of increasing responsibility and leadership within the company during the course of an 18-month period. Through a series of practical, rotational job assignments, mentoring, and senior-management guidance, GOLD program participants tackle challenging supervisory and project-based jobs that provide valuable work experience and insight into Con Edison’s practices and operations. Upon successful completion of the program, participants are poised to advance into Con Edison’s management ranks.

The Management Mentoring Program is a career development program focused on present management employees. Con Edison’s Talent Management organization facilitated the establishment of 60 one-to-one mentoring partnerships in 2007-2008. Partners were committed to positively engage in a mentoring experience from April 2007 through April 2008. Potential participants (protégés to be mentored) must be management employees in band levels 1, 2, or 3, have at least one year of service in the company, maintain performance in good standing, and obtain their manager’s approval to participate. Potential participants should be goal oriented, receptive to feedback, and willing to assume responsibility for their personal growth. Mentors are management employees in band levels 3 or 4 who have cross-functional experience and a desire to be a mentor. This program is not available to employees in the TEAM, GOLD, or summer intern programs, because these programs currently have mentors assigned within the program structure.

Con Edison’s TEAM program (Tools for Employees Advancing into Management) is a career development program designed to provide recently promoted, former weekly employees with the tools necessary to make a successful transition into a management role. The program is administered by the Employee Programs & Services section of Talent Management and has as its goal the development of candidates into skilled supervisors or individual contributors. The program helps candidates fine tune their technical and job-related skills through their daily work activities. Candidates are provided with tools and training targeted at developing their leadership skills. The program seeks to build a solid leadership strategy upon the foundation of experience and hands-on expertise that candidates have acquired in their time as members of the bargaining unit. This fusion of technical and leadership expertise is designed to create a core of skilled management professionals who will help lead Con Edison into the future.

8.4.2 - Survey Results

Survey Results

Safety

Career Development Program

Survey Questions taken from 2015 survey results - Safety

Question 130 : Do you require your network engineers to obtain their professional engineering (pe) license before they can move to more senior engineering positions?

Question 131 : Do you have a formalized training program for cable splicers, network mechanics and other individuals working on the network system?

Question 132 : Is advancement from apprentice to the journey worker level in a given period of time required as part of the job function (i.e. – automatic progression job)?

Question 133 : If you have an automatic progression, what is the amount of time required to achieve the journey worker level?

Question 134 : Can you briefly describe your training program for network workers?

8.5 - Contractor Safety Orientation and Certification

8.5.1 - Duke Energy Florida

Safety

Contractor Safety Orientation and Certification

People

Contractor work at Duke Energy Florida is awarded through the Resource Management group.

Process

Contractors, especially for larger projects, must go through an on-boarding process, including agreements to strictly adhere to Duke Energy Florida standards, safety practices, reporting procedures, and scheduling.

Smaller civil project contractors, on an ad hoc basis, are hired based on expertise in specialties, such as manhole covers, construction repairs, and are not subject to an extensive on-boarding process.

8.5.2 - HECO - The Hawaiian Electric Company

Safety

Contractor Safety Orientation and Certification

People

HECO requires all contractors to receive basic safety orientation and to be certified as having completed this training. The training is conducted by the HECO safety department.

Process

When a new contractor enters HECO, they are required to participate in a safety orientation training session. This training consists of videos that familiarize the contractor with the characteristics of HECO’s electrical system, review HECO safety rules, and remind the contractor of the devastating effects of electrical contacts and burns.

At the conclusion of the training, the contractor receives a sticker on his hardhat certifying that he has completed the safety orientation.

Contractors must comply with all HECO safety rules.

Figure 1: Contractor Safety Orientation Sticker

8.5.3 - PG&E

Safety

Contractor Safety Orientation and Certification

People

PG&E normally does not supplement their native workforce with contractors to perform routine work (construction and maintenance) in the network. However they do utilize external contractors to perform certain targeted work types. For example, PG&E uses an external contractor to perform environmental cleanups of vaults and manholes.

8.6 - Field Safety Person

8.6.1 - Ameren Missouri

Safety

Field Safety Person

(Blue Hat Program)

People

Ameren Missouri has implemented a program called the Blue Hat program. In this program a union employee is given a temporary assignment to act as a liaison between the field force and senior management on issues related to safety. It is named Blue Hat, because resources assigned to this position wear a blue hard hat – a different color hat than the regular Ameren Missouri employee.

People selected for this assignment are usually employees who have demonstrated a commitment to safety. Assignments can last for one to two years.

See Organization

Process

The goal of the Blue Hat resources is to liaise with the field force on issues of safety, tools and work methods. Their first objective is to try to resolve any identified issues themselves acting as an agent for the employee within the company. Issues that cannot be resolved by the Blue Hats are elevated to management.

Technology

The Blue Hats issue periodic reports that cover topics related to tools, methods, and safety. As an example, the May 2011 issue included articles on minimizing backing accidents, on the downtown network revitalization effort, and inspecting tools. These Blue Hat reports are posted on the Underground Construction department Safety bulletin board.

Figure 1: Blue Hat Report

8.6.2 - Duke Energy Ohio

Safety

Field Safety Person

(Technical Skills Specialist)

People

Duke Energy Ohio has created a position called a Technical Skills Specialist (TSS). In place at Duke about 10 years, the TSS is a position designed to work closely with the field force, familiarizing them with new equipment and tools, solving problems, addressing safety issues, and performing training, including compliance training.

There is one TSS who is focused on the network. This individual works closely with the Cable Splicers and Network Service personnel in the Dana underground group.

The TSS is an exempt employee, with the networked TSS position often being filled by a former Cable Splicer.

The TSS position is also used as a developmental opportunity for someone who is being groomed for supervision.

Process

The TSS works closely with field resources, and is typically the first person alerted of a problem or a training issue.

The TSS participates in job tailgate sessions, and spends much of his time in the field.

The TSS works closely with field resources to introduce them to new equipment types. He will often arrange for a manufacturer to come out and train employees on the use of a new tool.

Duke’s experience with this position has been positive in that this individual builds rapport with the field force and can act as a liaison between the employees and supervision.

8.6.3 - Georgia Power

Safety

Field Safety Person

People

The Network Underground group has a dedicated Health and Safety Advisor assigned to them, who functionally reports to the Health and Safety department at Georgia Power. The Advisor meets regularly with the larger Georgia Power Safety and Health group. The Advisor also works closely with the Storm Center and with the Cable Locating group.

In all, the Safety and Health Advisor is responsible for the training and safety management of approximately 180 people within the organization. The Network UG Manager works closely with the Safety and Health Advisor on safety and health issues related to the operation and maintenance of the network underground system throughout Georgia.

The person presently assigned to the position of advisor for the Network UG group came up from the ranks of the underground organization, serving as a Cable Splicer, so he is familiar with the unique needs and requirements for safely working in a network. The Advisor shadowed safety personnel to gain on the job training, and eventually co-chaired and chaired the safety committee while he was a Cable Splicer crew leader.

The Advisor has received formal OSHA training at Georgia Tech as well as formal training in excavating, soil analysis, and scaffolding.

See Organization/Culture

8.6.4 - HECO - The Hawaiian Electric Company

Safety

Field Safety Person

(Work Environment Specialist (WES))

People

The Work Environmental Specialist (WES) is a position within the C&M Underground department that focuses on construction and maintenance issues, tools and equipment issues, and safety issues.

The WES position is a temporary one, with employees from field positions rotating into the department for one year terms. After one year as a WES, an employee will return to his normal, permanent field job, and another employee will assume the role as a WES. This rotational approach also enables the individual who is assigned as a WES, to take the “learnings” from that experience back into the field when he returns.

The WES position was developed in 2008 to focus on issues that affect employees. Because the position is filled with employees who come from field positions and have established relationships with co-workers, department employees feel more comfortable talking with the WES about issues of safety, tool and equipment issues, etc.

The WES acts as a liaison between the C&M Underground group and the Safety department. The WES participates on company safety teams, such as the Construction and Maintenance Safety Team, a cross functional group that focuses on safety issues at HECO.

Process

According the HECO, the WES position has had a positive impact in creating dialogue between the field force and management around safety issues. They cited several examples where changes in tools or methods were made based on feedback from employees provided to the WES. The WES will liaise with safety, equipment vendors, the Technical Services group, etc, as required to bring about change in the department.

One example of a tool change that was brought about by the WES, was the implementation of battery operated cable cutters for use by Cable Splicers. The WES helped build the business case to justify the increased cost of this tool based on an improvement in safety.

8.6.5 - National Grid

Safety

Field Safety Person

(Work Methods Group)

People

National Grid has group called Work Methods, part of Distribution Engineering Services. Within this group are resources assigned to various parts of the company, with one resource having responsibility for supporting Underground East.

Work Methods resources act as an interface between the field resources and the Standards and Safety organizations. The group serves as the eyes and the ears of the field force, working closely with the field, performing job audits, and writing underground operating procedures. They have built a good rapport with the field force, and thus are able to identify issues from the field and liaise between the field and office organizations.

Individuals who work in work methods normally come from the field force, and are thus familiar with construction, and its associated practices, tools, and equipment.

Work Methods resources typically spend one to two days in the office and three to four days in the field per week. They work closely with standards engineers, the safety department, field crews, and field crew supervision.

Work Methods resources contribute content to the Electric Operating Procedures (EOP), a well thought out guideline used by National Grid that describes, in detail, procedures for performing certain tasks. The EOP book is up to date, with new processes issued quarterly, and all of the contents revisited on a three-year cycle. Copies of electric operating procedures can be found on National Grid trucks.

Figure 1: EOP Book on Truck

Figure 2: EOP Book on Truck

Safety audits - Work Methods people perform four SUSA’s per year.

Process

This group serves as the eyes and ears of the field force, and works as an interface between the field and Standards on issues of equipment, standards, tools and practices. Work Methods plays a key role in communicating changes to the standards to field. As an example, Work Methods individuals participate in annual standards presentations that are made to the field to explain significant changes in the construction standards. Work Methods also issues utility bulletins describing changes in work practice, describing new materials or tools, or addressing safety issues. (See Safety – Utility Bulletins)

National Grid’s Work Methods group also performs periodic random post construction field audits to identify and resolve any issues with the construction standards and how they are being built in the field. They will select jobs at random, review the job design, and the “as built” construction to identify opportunities for improvement. (See Post Construction Audits for more information.)

Work Methods resources will also perform SUSA safety audits, responsible for performing four per year.

Technology

Work Methods issues utility bulletins describing changes in work practice, describing new materials or tools, or addressing safety issues. (See Safety – Utility Bulletins.)

Work Methods resources contribute content to the Electric Operating Procedures (EOP), a well thought out guideline used by National Grid that describes, in detail, procedures for performing certain tasks. Example EOP’s include:

Infrared Non contact Thermometer inspection requirement for UG equipment.
Electric training procedure for Infrared Heat Inspections.
Cable Installation and Removal
Distribution Cable dielectric testing
Repairing PILC 2.4- 35kv
Fault Locating
UG Inspection And Maintenance
Proving Cables to be De-energized

8.6.6 - PG&E

Safety

Field Safety Person

People

(Senior Distribution Specialist)

PG&E has a position called Senior Distribution Specialist, part of the Electric Distribution Standards Strategy group. There are five specialists in total, with one assigned to the underground. Three are assigned to specific geographic areas, and one focuses on tools and equipment.

This specialist is a subject matter expert, and acts as an interface between the Standards Department and field resources. Specialists act as the “eyes and ears” of the Standards Department, and meet with standards engineers every two months to address issues.

A senior distribution specialist is a management position. As subject matter experts, senior distribution specialist positions are filled by experienced field resources - usually individuals who have been linemen, foreman and supervisors.

Senior distribution specialists meet every other month with each other and the standards engineers to discuss and resolve underground issues.

Process

The senior distribution specialists are often the first stop for underground issues raised by the field resources. An important role is to serve as an advocate for field resources, assuring that changes are made with visibility of their impact to field resources. In this capacity, they also serve as a safety liaison, bringing safety concerns back to the organization for resolution.

Another important role is to communicate changes in materials and standards back to the field forces. As an example, PG&E field resources identified a problem with stress cone covers, used to cover cables parked on a standoff bracket within pad-mounted equipment. The covers were too large, preventing the equipment doors from being closed. In this example, the specialist worked with the manufacturer to redesign and test the redesigned stress cone cover. The specialist worked with the field force to pilot and evaluate the covers and communicated to use of the new material to the organization.

Figure 1: Prototype Stress Cone Cover being evaluated under the leadership of the Senior Distribution Specialist

8.6.7 - Survey Results

Survey Results

Safety

Field Safety Person

Survey Questions taken from 2018 survey results - safety survey

Question 7 : Do you have a “safety person”, (either a fulltime safety professional or other employee assigned to a safety role) focused on the network?

Question 8 : If you have a safety person focusing on the network, is the person a full time safety professional, or another employee assigned to a safety role?

Survey Questions taken from 2012 survey results - Safety

Question 8.1 : Do you have a “safety person”, (either a fulltime safety professional, or other employee assigned to a safety role) focused on the network?

Question 8.2 : If you have a safety person focusing on the network, is this person a full time safety professional, or another employee assigned to a safety role?

Survey Questions taken from 2009 survey results - Safety

Question 8.3 : Do you have a “safety person”, (either a fulltime safety professional, or other employee assigned to a safety role) focused on the network? (This question is 8.1 in the 2012 survey)

Question 8.4 : If you have a safety person focusing on the network, is this person a full time safety professional, or another employee assigned to a safety role? (This question is 8.2 in the 2012 survey)

8.7 - Lead Cable Safety

8.7.1 - AEP - Ohio

Safety

Lead Cable Safety

People

AEP has a strong culture of safety, which is evident in its attention to safety in the work place, in its work practices, and in its approach to network design.

Process

All Network Mechanics and Network Crew Supervisors receive extensive safety training, including annual lead awareness training.

8.7.2 - Ameren Missouri

Safety

Lead Cable Safety

People

The Underground Construction Department consists of Cable Splicers, Construction Mechanics, and System Utility Workers. Cable Splicers and Construction Mechanics are journeymen positions.

Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices.

Note that at the time of the practices immersion, Ameren Missouri was implementing a new position, called the System Journeyman, which combines the duties of Cable Splicer and Construction Mechanic. System Journeyman are responsible for performing minor civil work such as installing cable, switching and tagging, and performing cable testing and cable splicing activities.

Ameren has in-service lead cables in their underground network system. The current standard for new cable installations is EPR insulated cables for both primary and secondary.

Process

Ameren Missouri has a 30 month mandatory progression for Cable Splicers whereby employees must move through a program of formal training, on the job training (OJT) and testing and achieve the journeyman level within this period.

Working with lead and lead splices is part of the formal training received by Cable Splicers.

8.7.3 - Energex

Safety

Lead Cable Safety

People

See Training / Safety Training

Process

Safety training includes practices for dealing with lead conductors. While Energex is shifting to XLPE cabling, it still works routinely with lead (PILC cables within Brisbane). The company has established work practices to minimize employee exposure to lead. Example practices include wearing gloves, not smoking at the work site, and not heating the lead to a point where it becomes a dangerous vapor. Energex believes that as long as workers work within the confines of its required practices, they are safe from lead exposure. Employees (jointers) who work with lead receive annual blood tests for lead exposure.

Technology

See Training / Safety Training

8.7.4 - Georgia Power

Safety

Lead Cable Safety

Georgia Power does deliver periodic lead awareness training.

See Organization/Culture

8.7.5 - National Grid

Safety

Lead Cable Safety

People

National Grid Albany has in-service lead cables in their underground network system, both primary and secondary. In their primary system, the current standard for new cable installations is EPR insulated cables. For secondary, the current standard is rubber cable with the Hypalon jacket.

Working with lead and lead splices is part of the formal training received by Cable Splicers. Training programs for Cable Splicers include a specific course on lead awareness.

8.7.6 - PG&E

Safety

Lead Cable Safety

People

The bulk of PG&E’s underground system, both network and non network uses lead cables. For network primary feeders at 12kV, PG&E continues to use lead cables as their standard because of their reliability. However for the radial system, they are attempting to remove lead cables from the system as they fail, and replace them with XLPE insulated cables.

Training programs for cable splicers include specific courses on working with lead cable and on the safe handling of lead materials. This includes training offered as part of the Cable Splicer job progression as well as the Safety Health and Claims group.

Process

PG&E has long-standing work practices for dealing with and working around lead; however, these practices have not been formalized.

PG&E requires the use of leather gloves when working with lead but has no requirement for chemical gloves.

Technology

PG&E’s Safety Health and Claims website contains information on the safe handling of lead materials.

8.8 - Manhole - Vault Entry

8.8.1 - AEP - Ohio

Safety

Manhole / Vault Entry

People

Network Mechanics and Network Crew Supervisors are responsible for following safe manhole and vault entry procedures, as outlined in the AEP Safety Manual. AEP performs confined space entry and rescue training as part of its formal training for Network Mechanics and provides refresher training in manhole rescue annually.

Process

All AEP Ohio Service Trucks are equipped with the necessary protective gear and tools for safe entry into manholes and vaults. Prior to entering a manhole or vault, crews test the atmospheric quality in the hole by dropping a gas monitor hose into the hole. AEP uses continuous gas monitoring and may ventilate the hole if necessary (see Figures 1 and 2).

Figure 1: Continuous air monitor (1 of 2)

Figure 2: Continuous air monitor (2 of 2)

AEP is not performing stray voltage tests of the manhole lid. To facilitate vault entrance, AEP utilizes an extendable post technology (LadderUP) attached to the permanently mounted vault ladder (see Figures 3 and 4).

Figure 3: LadderUP safety post (1 of 2)

Figure 4: LadderUP safety post (2 of 2)

AEP does not tether employees or require workers to wear lifting harnesses. Rescue apparatus is available on each truck. One practice of note is the use of hand-held Infrared (IR) cameras to identify hot spots as a manhole entry procedure (see Figures 5 and 6). Workers (both AEP and Contractors) will capture cable and bus temperatures. While an entire overview of temperature conditions is tested, particular attention is focused on cable joints, where the possibility of arcing from failed joints is the greatest. The company has mandated that if there is a 40 degree differential or greater on either side of a joint, the crew is to leave the manhole or vault and call in the condition.

Figure 5: Obtaining cable joint temperatures readings using IR camera

Figure 6: FLIR Systems IR camera used by AEP Ohio

AEP Ohio has been using this technique for over five years, and as a result, many distribution splices have been repaired. As a result of these on-going repairs, the crews are finding fewer instances of potentially dangerous cable joints. Most of the trouble spots have been cleaned up in the last three to four years.

Technology

First aid kits and AEDs are available on all crew trucks. AEP has purchased newer IR cameras that are less likely to provide false readings than the older versions. Trucks also contain Stat X aerosol fire suppressant kits (see Figure 7).

Figure 7: IR Camera and Stat X Fire Suppressant kit mounted on truck door panel

8.8.2 - Ameren Missouri

Safety

Manhole / Vault Entry

People

Ameren Missouri performs confined space entry and rescue training as part of its formal required training for Underground Construction, Distribution Service Test, and Distribution Operating workers. Refresher training in manhole rescue is offered annually.

The Underground Construction department consists of Cable Splicers, Construction Mechanics, and System Utility Workers. Cable Splicers and Construction Mechanics are journeymen positions. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Construction Mechanics perform the civil aspects of the work. System Utility Workers serve as helpers to the other two positions, and perform duties such as cable pulling and manhole cleaning. Note that at the time of the practices immersion, Ameren Missouri was implementing a new position, called the System Journeyman, which combines the duties of Cable Splicers and Construction Mechanics. System Journeyman are responsible for performing cable work, civil construction, and operating network equipment.

Maintenance and operations of network equipment such as network transformers and network protectors are performed by resources within the Service Test group and Distribution Operating group.

The Service Test group is made up of Service Testers and Distribution Service Testers. Service Testers perform low-voltage work only. They focus on things such as voltage complaints, RF interference complaints, and testing and maintaining batteries. Distribution Service Testers perform network protector maintenance, transformer maintenance including oil testing, and perform fault location. It is the Distribution Service Tester position who works routinely with network infrastructure.

The Distribution Operating group is made up of Traveling Operators, who perform switching on the system, including placing tags and obtaining clearances, and act as first responders and troubleshooters.

Process

Ameren Missouri performs a series of inspections when entering a manhole. After removing the lid, crews tests the atmospheric quality in the hole by dropping a gas monitor into it. Ameren Missouri field crews test air quality every time a man enters a hole, and use continuous air monitoring while men are working in a hole. Ameren Missouri may use ventilators to flush the vault with fresh air. An example situation where forced ventilation is utilized is when working in a hole where the manhole temperature is very high, impacted by adjacent steam lines.

Figure 1: Gas monitor

Figure 2: Vault Ventilation (Heat Shrink Splicing)

Figure 3: Vault Ventilation (Heat Shrink Splicing)

On entering the manhole or vault, the crew will do a quick visual inspection of the interior, including the electrical components within the vault. Crews will complete a Network / Radial Vault Entrance & Condition form, documenting their visual inspection findings.

Ameren Missouri uses a manhole rescue apparatus set up over manholes, and requires employees to wear harnesses and be tethered (rope tethers) to the lifting apparatus when working in manholes. If an employee has to move to an area in the manhole where he feels he is unsafe, he can disconnect from the tether - but in general employees stay tethered. The tether is connected to the lifting apparatus with a piece of electrical tape that is designed to separate in the unlikely event of a vehicle striking the lifting apparatus, thus protecting the worker from injury in such an event.

Ameren Missouri uses either a 10 ft or 14 ft fiberglass ladder to enter the manhole. They allow the ladder to remain in the hole while working unless the hole is too small to accommodate both the ladder and the worker(s).

Figure 4: Lifting Apparatus

Figure 5: Lifting Apparatus (note use of electrical tape to affix the tether (rope) to the apparatus)

For vault entry, Ameren Missouri has developed a novel lifting tool for lifting the vault hatch that minimizes the loading on the worker’s lower back. This device has an ergonomically shaped handle and rotating hooks for attaching to various grate configurations.

Figure 6: Lifting Tool for Vault Grate

Figure 7: Lifting Tool for Vault Grate

Figure 8: Lifting Tool for Vault Grate

Figure 9: Lifting Tool for Vault Grate

Figure 10: Lifting Tool for Vault Grate

Ameren Missouri is not requiring tethering or lifting harnesses for workers who enter vaults. This is, in part, due to the vault entrance design which includes a pull – out access and protection apparatus referred to as either the “safety basket” or the “cage”. The “cage” is a device that is raised above the vault entrance, and is used to ease vault ingress and egress by providing a hand rail for moving on or off the vault ladder, and for work area protection, by preventing either pedestrians or workers from accidentally falling into the hole.

Figure 11: Ameren Missouri worker lifting the cage

Figure 12: Ameren Missouri worker lifting the cage

Figure 13: Typical vault entrance - Ameren Missouri

Figure 14: Typical vault entrance Note permanently mounted ladder

Vault ladders are permanently mounted to the vault wall.

Technology

Ameren Missouri trucks are equipped with first aid kits.

8.8.3 - CEI - The Illuminating Company

Safety

Manhole / Vault Entry

People

Underground Electricians are responsible for establishing a safe work zone, and performing all required safety steps associated with manhole / vault entry. EPRI observed strong attention to work zone safety at all site visits.

Process

CEI tests air quality every time a man enters a hole, and uses continuous air monitoring while men are working in a hole. EPRI observed that these monitoring devices are positioned in the hole as opposed to just outside the hole.

CEI requires all workers to wear harnesses. A lifting crane is set up outside the hole to perform manhole rescue in case of an emergency. Workers are not tethered while working.

Note: The lifting crane is not required for short-duration tasks.

Technology

CEI has recently purchased new Air Quality monitoring devices. Industrial Scientific Model Number ITX. These are battery powered units and are connected to a docking station every evening to charge and calibrate.

8.8.4 - CenterPoint Energy

Safety

Manhole / Vault Entry

People

Major Underground crews are responsible for establishing a safe work zone, and performing all required safety steps associated with manhole / vault entry.

Process

CenterPoint tests air quality every time a man enters a hole. They utilize monitors that test for oxygen levels as well as the presence of three different gases. CenterPoint does not use continuous monitoring; rather, they will ventilate a hole during the performance of any work, including inspections.

CenterPoint also performs heat gun checks to identify hot spots before entering a hole. They may use blast blankets in areas where the heat gun checks they perform as part of their manhole entry reveal hot spots.

CenterPoint requires a lifting device and harnesses for manhole rescue to be present at each work location. CenterPoint does not require workers to wear a harness while working. All crew members are required to have annual training in manhole rescue.

Technology

CenterPoint is using Multi-Gas Detectors with Data Logging Software. These monitors perform a “pretest” evaluation that notifies the user if the unit needs to be recalibrated and recertified.

Figure 1: 3M 740 Multi Gas Detector

8.8.5 - Con Edison - Consolidated Edison

Safety

Manhole / Vault Entry

Process

Network Protector Vault Entry

When Con Edison employees enter a network protector vault in a building, it is their practice to first open the doors connecting multiple vaults so that they have access to multiple paths for exit in the event of an emergency.

Manhole Entry

Con Edison crews take a stray voltage reading whenever they enter or leave an underground structure. They use a proximity tester; then if there is a problem, they use a fluke meter to further diagnose. Often, to remedy stray voltage, they cut cable.

Con Edison is using continuous air quality monitoring. In the past, crews tested air quality upon entry, exit, and every two hours. Their current practice is to monitor continuously.

The units used to monitor air quality are self-diagnosing, meaning that they alarm if they malfunction. The units are recalibrated every two months.

One challenge that they face is the battery life of the units for longer jobs.

Con Edison requires all workers to wear harnesses. A lifting crane is set up outside the hole to perform manhole rescue in case of an emergency. (The lifting crane is not required for short-duration tasks.)

8.8.6 - Duke Energy Florida

Safety

Manhole - Vault Entry

People

Organizationally, Duke Energy Florida field resources that construct, maintain, and operate the urban underground and network infrastructure fall within a specific Network Group which is part of the Construction and Maintenance Organization. The Network Group is led by a supervisor who reports to the Region General Manager. The group consists of ten craft workers, five Electric Apprentices and five Network Specialists (the journey worker position), all part of the Network Specialist job family.

The Network Specialist is a jack-of-all-trades, responsible for all facets of UG work, including cable pulling, splicing, and maintaining and operating equipment such as cables, joints, network switches, transformers and network protectors. Network Specialists also work with the installation and maintenance of automation associated with the equipment they manage.

Electrician Apprentices are the entry level position in the Network Group. Electrician Apprentices provide assistance to Network Specialists while receiving on the job training. In addition, Electrician Apprentices with proper training are able to prepare cable splices excluding splices on lead and submarine cable.

Manhole Safety and Rescue Standards at Duke Energy Florida are established and monitored by the Lead Health and Safety Professional for the South Coastal Zone.

Process

Duke Energy Florida crew leaders perform thorough job briefings (tailboards) at the beginning of each work day or new job (see Figure 1). Every time a job site briefing is conducted, topics discussed are checked off and notes are recorded on a Tailboard Sheet see Figure 2). Elements of the tailboard session include:

Identification of the crew leader for the tailboard and job
Job location and address are reviewed
Crew qualifications and familiarity with tools are confirmed
Work and safety procedures are reviewed (including manhole entry procedures)
Crew members sign the tailboard sheet documenting their participation

In addition to the tailboard topics listed above, crews will review what to do if a medical emergency occurs. The location of the nearest hospital is provided and a crew member is designated as the person to call 911 if there is an emergency. Duke Energy Florida’s protocol is to call 911 first and then call the dispatcher. All company radios have an emergency call button with a direct radio connection to the dispatcher.

At the end of the day, a post job tailboard is held with the crew to make sure all switching is complete, grounds removed, and clearance tags have been removed. During the post job tailboard, lessons learned are discussed and the crew discusses the safest route to exit while addressing any obstructions or stationary objects that might impede a safe exit. The crew leader performs a full inspection of the job site to make sure conditions were restored to normal, no tools were left behind, and all equipment/cables are in safe configuration with proper tagging if work was not completed.

Figure 1: Job site tailboard discussion

Figure 2: Job site tailboard sheet

Personal Protective Equipment (PPE)

All work crews are equipped with the following PPE:

Fire retardant (FR) clothing (8-12 Cal, 65 Cal for 480V spot networks)
FR high visibility safety vest
Harnesses
Steel toed boots
Rubber gloves
Leather work gloves
Safety glasses
Hard hats

All PPE equipment is thoroughly inspected every six months, and is inspected daily at all job sites. As a safety precaution, all employees at the job site are not allowed to wear jewelry.

Before entry into the manhole/vault, a continuous gas monitor is placed into the hole to constantly monitor the air quality and gas levels inside the hole as crews are working. Alternatively, crew members may wear personal gas detection monitors. The continuous gas monitors are calibrated every day (see Figure 3). If necessary, under direction of the crew leader, the hole will be ventilated with forced air during certain situations (see Figure 4). In addition, new work procedures require an infrared (IR) inspection prior to commencing work in the hole.

Figure 3: Continuous gas monitor - Altair 4X Multigas Detector

Figure 4: Manhole ventilation

At Duke Energy Florida, all employees entering a submersible manhole or vault wear a harness and are tethered. Workers are tethered to a tripod mounted rescue apparatus (Sentry RS3 by Gemtor [1], Figures 5 and 6) that is tested and recalibrated annually, or anytime load is placed on the rescue device. A calibration sticker is affixed to the tripod to indicate the last calibration date. In the event that a rescue is performed, the harness used is replaced.

An acceptable alternative at Duke Energy to using tethering is to utilize a SCUBA system with an oxygen pack to perform manhole rescue. Use of the SCUBA system requires workers to remove facial hair.

Figure 5: Rescue apparatus including tripod

Figure 6: Sentry RS3 Personal Fall Arrest Device by Gemtor

Manhole/Vault Rescue

As previously stated, all entry personnel are fully tethered at Duke Energy Florida. There is a crew member observer at the top, outside of the hole. If the outside observer is required to retrieve equipment or a part from the truck for crew members in the hole (and thus called away from his duties as an observer), the crew will perform an “all stop” in the hole. Once an “all stop” is called, the worker in the hole stops all activities and moves to the ladder in preparation to exit in the event of an emergency. Once the material is lowered down to the crew member below, work can resume.

If an emergency occurs, crews are trained to call 911 immediately. Because crew cell phones are equipped with GPS, the 911 call is the fastest way to receive outside assistance to a location.

In the event of a flash or fire, observation crew members:

Do not enter the hole under any circumstances
Call 911
Make a call to Dispatch
The tethered employee(s) inside the hole is pulled out

Annually, all crew members receive refresher training in manhole rescue procedures at a vacant manhole. During this full day training session, crew members are also trained in arc flash, manhole fire, and other emergency rescue procedures.

Switching and Tagging

Switching is performed by crew members (Network Specialists of Electrician Apprentices) with field direction from the Network Specialists who will hold the clearances. Crew members carry a switch book where all switching orders are written down. The switching orders will identify all of the switching steps including:

Who performs the switching
What device is operated
Where the location of the device to operate is located
When will the device will be operated (in operational order)

While performing a switching order, crew members use three-way communication with dispatch. The crew member will record what the dispatcher tells him verbatim in his switch book and then he will read the information back to the dispatcher. After the crew member has read the switching step to the dispatcher, the dispatcher will confirm that it matches what is on his switching order. Only after confirmation, the dispatcher will issue the clearance number and allow the crew member to operate the device.

All switchers must be on the approved switching and tagging list. Every two years, all Network Specialists and Electrician Assistants take a switching and tagging procedure training course.

Another standard safety procedure prior to entry into a manhole/vault is to establish a protection “hotline”. The “hotline” is a safety related protection setting for the substation feeder breaker to reduce the duration of the instantaneous trip from the normal setting of 30 cycles to 6 cycles, so that if a fault occurs while a man is in the hole, the fault will clear more quickly. The “hotline” clearance is tagged to the crew leader, who designates the person working in the hole as an alternate clearance holder. The hotline clearance is obtained for every energized primary network feeder in the manhole.

Technology

Blast Blanket Stanchions

Duke Energy Florida uses blast blanket stanchions (shown in Figure 7) in areas where they are concerned about inadvertent contact with conductors or equipment. Instead of wrapping rubber blankets around or on top of areas of concern, Duke Energy Florida has set up stanchions with D rings where they can hang the blast blankets to provide separation between the equipment and workers in the hole. The stanchions were developed by Duke Energy Florida and dielectrically certified by a third party testing company (Kinetrics). Due to the success Duke Energy Florida had with the stanchions, an article was written in Incident Prevention Magazine [2] on the development of the stanchions.

The stanchions are threaded tension bars designed for use in the manholes and vaults. While newer manholes are designed with the clips in the ceiling for hanging blast blankets, older manhole do not have clips, because there is uncertainty about the strength of the material behind the ceiling in which the D ring will be mounted. The advantage of the threaded stanchion system is that it can expand within the manhole or vault and it is free standing without the requirement of additional drilling.

New work procedures require the stanchion blast blanket system be used any time a crew is working on one circuit and there is another circuit in the hole.

Figure 7: Blast blanket on stanchions

Manhole Prints and Information Sheets

Duke Energy Florida maintains thorough manhole prints. The manhole prints are printed in color with the primary feeders shown in color while secondaries are shown in black ink. (See Attachment E ).

The manhole prints show the facilities that are placed on each wall. The manhole prints provide detailed and accurate dimensions including manhole depth, the position of the racks on the wall, and cable position. Each wall is laid flat on the drawing itself. If you were to take a scissors, cut the walls, and fold the walls up towards you, you would have an accurate depiction of being inside the manhole. Manhole prints can be printed on request for field projects. The manhole prints are also accessible via the corporate GIS system and can be saved as PDF files.

In addition to the manhole prints, “Information Sheets” initially created in Microsoft Excel are available and provide detailed information about the cable in the manhole. “Information Sheets” are also available for download from the corporate GIS system and can be saved as PDF files. The “Information Sheets” provide details about the cable including:

Cable Size
Voltage Class
Insulation Type
Manufacturer
Duct Position
Year Installed (with Work Order Number)

See Attachment E for sample of the information sheet.

[1] Gemtor

[2] incident prevention

8.8.7 - Duke Energy Ohio

Safety

Manhole / Vault Entry

People

Duke Energy Ohio performs confined space training annually. The training is conducted by a safety expert within the Work Methods and Procedures Department. This training is classroom training.

Process

Duke Energy Ohio field crews test air quality every time a man enters a hole, and use continuous air monitoring while men are working in a hole. EPRI observed that these monitoring devices are positioned in the hole as opposed to just outside the hole.

Figure 1: Continuous air monitoring device

Duke Energy Ohio requires all workers to wear harnesses. The harnesses are equipped with retrieval hooks. Workers are not tethered while working.

Historically, the underground group in Cincinnati had an arrangement with the Cincinnati Fire Department, in which the fire department would be called upon to perform manhole rescue. The fire department would use the rescue winch system mounted on each truck to rescue a worker.

At the time of the EPRI immersion, Duke Energy Ohio was in the process of changing their approach. For example, they are equipping each of their trucks with equipment to be able to perform a confined space rescue, including rescue lifting apparatus. They are also analyzing the implications of this change on crew makeup.

8.8.8 - Energex

Safety

Manhole Vault Entry

Manhole (Pit) Entry

People

Energex performs confined space training and rescue training (such as switchboard rescue and pit rescue training) as part of its statutory required training for field workers. Refresher training for safety training is conducted semi-annually. Jointers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation.

Process

Energex establishes a safety work area using traffic cones and barriers to isolate vehicular and pedestrian traffic from the job site (see Figures 1 and 2).

Figure 1: Energex job site - underground pit

Figure 2: Energex job site - underground pit

Energex performs a series of pre-entry inspections when entering a pit. Crews test for atmospheric quality by dropping a four gas monitor (oxygen, carbon monoxide, percent lower explosive limit [LEL] and hydrogen sulfide) into the hole. Energex requires continuous monitoring. If crews obtain a bad reading, they may ventilate the hole (see Figures 1 and 2).

Upon entering the pit, the worker performs a quick visual inspection of the interior of the pit, to identify any swollen joints, leaking oil, or other indications of a problem. Energex is not performing any stray voltage testing on the pit cover.

Energex does not require workers to wear harnesses or to be tethered, and workers do not setup rescue apparatus at the mouth of the pit. A rescue apparatus is available on the truck.

A first aid rescue kit is available on the truck and placed next to the manhole opening at the surface, or next to the mini pillar in which the worker is working (see Figure 3). These rescue kits do not contain breathing apparatus. In a flash situation, employees would dial 000 (the Australian equivalent of 911 in the U.S.), and request the fire department to respond.

Figure 3: Energex truck used by underground crews

Low-voltage switchboard or mini -pillar

Employees working in a mini-pillar or low-voltage switchboard wear low-voltage gloves, and stand on an insulated mat (see Figures 4 and 5). A first aid kit is placed next to the worker, and contains an insulated hook that would allow an employee to pull an employee away from the switchboard who accidently makes contact (see Figures 6 and 7).

Figure 4: Insulated mat placed in from of low-voltage switchboard

Figure 5: Insulated mat placed in front of mini pillar

Figure 6: Safety kit placed next to mini-pillar (the orange bag)

Figure 7: Energex employee holding insulated hook for switchboard rescue

Technology

Energex required personal protective equipment (PPE) includes a hardhat, safety glasses, steel-toed boots, and all natural fiber clothing. At the time of the immersion, Energex was transitioning to the use of fire resistant (FR) protective clothing. Energex uses continuous gas monitoring, with portable four-gas detectors. Energex trucks are equipped with global positioning systems, and first aid kits.

8.8.9 - Georgia Power

Safety

Manhole / Vault Entry

People

Georgia Power has various employee classifications that must enter manholes and vaults to perform their jobs including Cable Splicers, Test Engineers, Test Technicians, and Duct Line Mechanics. Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Duct Line Mechanics perform the civil aspects of the work. Test Engineers perform transformer testing, troubleshooting and maintenance. Test Technicians perform network protector testing and maintenance.

The Health and Safety group at Georgia Power performs safety training for employees who may work in manholes and/or vaults, including annual refresher training in working in enclosed spaces and manhole rescue. There is a Safety Advisor assigned specifically to the Underground Network group at Georgia Power who leads this training.

Georgia Power’s Network Underground Safety and Work Procedures contain guidelines for performing manhole and vault entry, and a checklist that must be completed by the crew leader. (See Attachment J )

Process

Prior to entering a manhole or vault, Georgia Power requires that all crew members know the exact location of the enclosed space, the requirements for tagging if applicable, which circuits are present, the scope of work to be performed, how to respond in case of an emergency, and the results from the pre-entry test of atmospheric quality.

Georgia Power personnel perform a series of inspections when entering a manhole. After removing the lid, crews test the atmospheric quality in the hole by dropping a gas monitor into it. The crews test air quality every time a man enters a hole. Georgia Power may use ventilators to flush the vault with fresh air. An example situation where forced ventilation is utilized is when working in a hole where the manhole temperature is very high (See Figure 1).

Figure 1: Georgia Power worksite, note ventilation

Crews use fiberglass ladders to enter manholes or permanently mounted ladders on vault walls. On entering the manhole or vault, the crew will do a quick visual inspection of the interior, including the electrical components within the vault (See Figure 2).

Figure 2: Georgia Power worksite

Georgia Power has rescue apparatus located on the trucks, but does not normally set up the apparatus. Georgia Power does not require employees to wear harnesses or be tethered.

Georgia Power relies on fire departments to do any rescue and extraction and call 911 for assistance. The crew makes certain it is safe for fire department rescue personnel to enter the vault or manhole.

Technology

First Aid kits and AEDs are on all crew trucks. Crews also have internal communications through its SouthernLINC radio system to call for additional assistance from any other Georgia Power crew.

8.8.10 - HECO - The Hawaiian Electric Company

Safety

Manhole / Vault Entry

People

HECO Underground Cable Splicers are responsible for establishing a safe work zone, and performing all required safety steps associated with manhole / vault entry.

Process

HECO tests air quality every time a man enters a hole. HECO is not using continuous monitoring. They use active ventilation of the hole.

HECO is not requiring lifting harnesses, or utilizing a lifting crane is set up outside the hole to perform manhole rescue in case of an emergency.

8.8.11 - National Grid

Safety

Manhole / Vault Entry

People

National Grid performs confined space entry and rescue training as part of its formal required training for workers in the Electrical group. Refresher training in manhole rescue is offered annually

The Electrical Group is comprised of Cable Splicers, Maintenance Mechanics and Mechanics. Cable Splicers work with cable and cable accessory installation and maintenance, including cable pulling and splice preparation. Maintenance Mechanics perform network switching, fault location, minor vault maintenance, and inspection and maintenance of network equipment such as transformers and network protectors. Mechanics perform minor civil work.

Process

National Grid performs a series of pre-entry and post-entry inspections when entering a manhole. Prior to removing the manhole lid, the lid is tested for potential using a stray voltage detector. After removing the lid, crews tests the atmospheric quality in the hole by dropping a gas monitor into it. Note that National Grid requires continuous air monitoring and requires at least one person in a vault or manhole to wear a four-gas monitor (oxygen, carbon monoxide, %LEL and hydrogen sulfide) at all times. National Grid also checks for elevated temperatures in the manholes before entry.

On entering the manhole or vault, the crew will do a quick visual inspection of the interior, including the electrical components within the vault. All separable connectors are checked with an infrared gun to detect overheating from electrical faults.

Crews complete an enclosed space evaluation form for every manhole entry to document the conditions and indicate what workers must be aware of. Gas levels from the monitor are recorded on this form (See Attachment J .)

Continuous ventilation is not used unless chemicals are being used, or there are bad readings on the air monitors. In this case ventilators are used to flush the vault with fresh air, and entry is not allowed until the air monitor indicates that levels are safe. The underground department does not use SCUBA gear.

National Grid Albany uses a manhole rescue apparatus set up over manholes, and requiring employees to wear harnesses and be tethered (rope tethers) to the lifting apparatus. The tether is connected to the lifting apparatus with a breakaway pin that is designed to separate in the unlikely event of a vehicle striking the lifting apparatus, thus protecting the worker from injury in such an event. The wearing of tethers is an established practice at National Grid Albany, as National Grid has required employees to be tethered for over eight years. If the circumstances within the vault make the wearing of the tether impossible or unsafe, employees may elect not to wear the tether, but must document this decision on the pre-job briefing An alternate method is then used and documented on the job brief form. In this method, the entrants still wear the harness. An extendable pole is set up at the entry, which allows the attendant to reach into the manhole or vault without entering, to clip a tether onto the harness, and rescue the entrants.

National Grid trucks are equipped with a code blue button, which can be used in an emergency. This button, part of the radio system within the truck, gives the emergency call top priority, All trucks are equipped with an automatic vehicle location system, such that when the blue button is depressed, the operations area will know what truck issued the call and where the truck is located from the on board GPS system.

Technology

National Grid required Personal Protective Equipment (PPE) includes a hardhat, ANSI safety glasses with side shields, steel toed, EH-rated boots, outer layer FR protective wear with an Arc Thermal Protective Value rating of 8 cal per square centimeter (Level 2), and all natural-fiber clothing underneath.

National Grid may differentiate the clothing required based on tasks.

National Grid uses continuous gas monitoring, with portable four gas detectors worn by employees.

National Grid workers wear lifting harnesses with tethers. A rescue lifting apparatus is set up at the manhole entrance.

National Grid trucks are equipped with global positioning systems, first aid kits, and burn kits.

Figure 1: Stray Voltage detector

Figure 2: Four gas monitor

Figure 3: Lifting apparatus

Figure 4: Employee tethered to the lifting apparatus

Figure 5: Breakaway pin between the tether and lifting apparatus

Figure 6: Lifting apparatus

Figure 7: Code blue button

Figure 8: Truck-mounted First Aid kit

8.8.12 - PG&E

Safety

Manhole / Vault Entry

People

PG&E performs confined space entry training as part of its formal required training to become a cable splicer. Refresher training is offered annually.

Process

PG&E field crews test air quality every time a man enters a hole, and use continuous air monitoring while men are working in a hole.

Crews entering will perform other safety checks depending on the work assignment. For example, crew members entering a vault to perform transformer oil testing will perform a few checks to confirm the transformer is de-energized, such as checking the network protector status, feeling the transformer unit to see if it is humming, and comparing the oil temperature to the recorded high temperature.

PG&E does not use a manhole rescue apparatus set up over the manholes or require employees to wear harnesses and tethers.

The M&C Network Electric group has an arrangement with fire departments in San Francisco and Oakland, in which the fire department would be called upon to perform manhole rescue. In an accident, PG&E’s procedure is to call the distribution operator, who would then call 911 to engage the fire department to perform first response.

Figure 1: Continuous air monitoring device

Figure 2: Job Site

Technology

PG&E trucks are equipped with first aid kits.

Ultimately, enabled by the remote monitoring system, PG&E would like the crews to have the ability to determine the status of the network protectors from the truck through a lap top. (See Remote Monitoring)

PG&E is piloting a small tripod that can be used for lifting equipment out of the hole. This could facilitate lifting light equipment out of the hole, but is not a manhole rescue apparatus.

8.8.13 - SCL - Seattle City Light

Safety

Manhole / Vault Entry

Process

During the the Manhole Drill crews perform heat gun readings in each manhole to identify any problems. Crews also look for problems on adjacent feeders in the same hole, and may postpone performing the feeder maintenance until addressing any identified problems on the adjacent feeders (in other words, address problems on adjacent feeders before moving to an N-0 the crews perform heat gun readings in each manhole to identify any problems. Crews also look for problems on adjacent feeders in the same hole, and may postpone performing the feeder maintenance until addressing any identified problems on the adjacent feeders (in other words, address problems on adjacent feeders before moving to an N-0 condition).

Heat gun checks are performed both at the front end, before the maintenance is accomplished, and at the back end, after maintenance is complete

Technology

SCL uses continuous air monitoring.

SCL does not routinely require workers to wear a harness, or the positioning of a lifting apparatus outside the hole.

8.8.14 - Practices Comparison

Practices Comparison

Safety

Manhole - Vault Entry

2015 Survey Results

8.8.15 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 9.2.3: Enclosed Spaces Entry

8.8.16 - Survey Results

Survey Results

Safety

Manhole - Vault Entry

Survey Questions taken from 2018 survey results - safety survey

Question 9 : Do you perform routine training on how to conduct a tailboard meeting?

Question 10 : How to you determine / assess the quality of your tailboard meetings?

Question 22 : Please indicate which of these manhole / vault entry procedures you utilize:

Survey Questions taken from 2015 survey results - Safety

Question 128 : Please indicate which of these manhole/vault entry procedures you utilize:

Survey Questions taken from 2012 survey results - Safety

Question 8.7 : Is a first aid kit on hand when a crew is working in a vault?

Question 8.10 : Please indicate which of these manhole / vault entry procedures you utilize

Survey Questions taken from 2009 survey results - Safety

Question 8.8 : Is a first aid kit on hand when a crew is working in a vault? (This question is 8.7 in the 2012 survey)

Question 8.10 : Do you use continuous air quality monitoring when working in a Manhole? Vault?

Question 8.11 : Do you require the use of a lifting crane and worker harnesses when working in an Underground Manhole? Underground Vault?

8.9 - Morning Stretch

8.9.1 - AEP - Ohio

Safety

Morning Meeting / Stretch

People

At AEP Ohio, Network Crew Supervisors lead daily morning safety briefings that include a morning stretch.

Process

In addition to stretching, Network Crew Supervisors use the daily morning safety meeting to report out from both the District Safety Council and the State Safety Council.

Technology

Crews utilize a video to guide them through their daily stretching exercise routine.

8.9.2 - Ameren Missouri

Safety

Morning Meeting / Stretch

People

The Construction Supervisor responsible for Underground Construction conducts a daily morning meeting with the entire department to review safety and health issues and to prepare for the day. This morning meeting also includes a morning stretch.

Process

The morning meeting / stretch is led by the Construction Supervisor. It includes the discussion of safety issues, such as reminding employees to stay hydrated in hot weather conditions, and administrative issues, such as replacing expired contents of a first aid kit.

The meeting also includes a morning stretch. Employees are not mandated to participate in the stretch but must be present at the meeting. Virtually all participate in the stretching.

One day per week, the stretching is led by a physical therapist. On the days of the week when the physical therapist is not present, the morning stretch is led by an employee.

Ameren Missouri contracted with a company called Apex to develop an injury prevention program for Ameren Missouri aimed at reducing employee injury. This program includes the daily performance of stretching exercises, and a weekly visit to the morning meeting by a physical therapist. On the day of the visit, the physical therapist leads group in the performance of the stretching exercises. This physical therapist is also available after the meeting to provide individual counseling to employees on prevention and on treating minor strains (such as recommending the use of ice or heat, etc.)

Ameren Missouri reports a significant reduction in soft tissue injuries in their Illinois company attributable in part to the implementation of a similar program there.

Technology

Ameren Missouri has posted a description of the various morning warm-ups and stretching exercises on their Safety Bulletin Board.

8.9.3 - Duke Energy Florida

Safety

Morning Meeting / Stretch

(30 for 30)

Process

Duke Energy Florida has implemented a practice called “30 for 30,” where every thirty minutes, participants of a meeting stand and stretch for 30 seconds. The meeting discussion does not cease, but continues as participants engage in this stretch. A timekeeper is assigned at the start of the meeting to remind participants to stretch at 30 minute intervals.

8.9.4 - Georgia Power

Safety

Morning Meeting / Stretch

People

Each morning, crews start the day with a safety discussion and a morning stretch to prepare them for the day physically and mentally.

Technology

Georgia Power utilizes bulletin boards throughout the company to re-enforce safety programs and safety and health messaging.

Figure 1: Examples of safety related displays; Note that Georgia Power encourages daily stretching

8.9.5 - HECO - The Hawaiian Electric Company

Safety

Morning Stretch - Walk about

People

All personnel in the C&M Underground group participate in performing daily morning light stretching exercises and in a brief walk around the HECO office facility. This includes supervisors and any visitors who will participate in the morning safety / tailboard meeting.

Process

The HECO C&M Underground group begins each work day with a morning stretch and a brief walk around the office facility. This process was implemented to encourage the group to loosen up each morning to help prevent injury

This process has also assisted with mental focus too, with workers casually chatting about the upcoming workday. This morning “walk about” is immediately followed by the morning safety Tailboard meeting.

8.9.6 - National Grid

Safety

Morning Meeting / Stretch

People

Job briefings are conducted at the start of the each job, and are led by the person in charge of the work (either the supervisor, or a crew leader or similar position). Additional job briefings are held whenever there is a significant change in the working conditions that might impact the safety of employees. The job briefing is documented and signed by the designated employee in charge of the job.

Process

The briefing covers hazards associated with the job site and its surroundings. During the briefing, the crew identifies all hazards, both electrical and non-electrical, in the work environment. Difficult physical work, including strain, awkward positions, and difficult lifting is discussed. The briefings cover all of the hazards associated with the job, work procedures, special precautions, energy source controls, personal protective equipment requirements, and a warm-up / stretch period.

The scope of the discussion depends on the job and how it relates to employee experience and training. Brief discussion is allowed for routine work, where it is expected that employees have the experience to recognize and avoid the hazards of the job. Extended briefings are required where employees are unfamiliar with the hazards, or the work is particularly complicated or hazardous.

Employees working alone do not need to conduct formal job briefings but are expected to plan tasks and perform them as though a job briefing were being done.

8.9.7 - PG&E

Safety

Morning Meeting / Stretch

People

Prior to each shift, the distribution supervisors conduct a pre-shift tail board meeting with the field crews. The meeting is conducted in the cable splicer day room, known as the “bull room”. The content of the tail board meeting varies from meeting to meeting, addressing safety concerns specific to the projects scheduled for that shift and including a reading from the safety manual. This meeting is also used to review any pertinent utility bulletins (see Utility Bulletin).

Process

The pre-shift tailboard meeting also includes stretching by field crews, including a brief upper body stretch of the arms, elbows and shoulders.

8.9.8 - Survey Results

Survey Results

Safety

Morning Stretch & Walk About

Survey Questions taken from 2009 survey results - Safety

Question 8.2 : Please indicate the type(s) of safety meetings you conduct. Check all that apply.

8.10 - Near Miss Program

8.10.1 - AEP - Ohio

Safety

Near Miss Program

People

Network Mechanics and Network Crew Supervisors are required to document any “near miss.”

Process

In the event of a “near miss,” any crew member must fill out a written form and submit it to the supervisor. This report is recorded in the AEP Ohio database system and likely will become the topic of the next day’s morning meeting.

Technology

“Near miss” reports are recorded in the AEP Ohio database.

8.10.2 - Ameren Missouri

Safety

Near Miss Program

People

Ameren Missouri has implemented a Near Miss program, where employees are encouraged to report near misses through an anonymous reporting system. Ameren Missouri managers acknowledged that while the program is gaining momentum, there still exists some skepticism among the bargaining unit employees about this program and that employees have been slow to report near misses.

Technology

Ameren Missouri issues a number of safety related publications, including near miss reports. These reports and other safety- related publications are posted on a safety bulletin board within each department.

8.10.3 - CEI - The Illuminating Company

Safety

Near Miss Program

Note: Refer to Safety Stop Program.

8.10.4 - CenterPoint Energy

Safety

Near Miss Program

People

CenterPoint Energy has implemented a “Near Miss” safety suggestion box for identifying methods to address issues identified through near misses.

8.10.5 - Con Edison - Consolidated Edison

Safety

Near Miss Program

(Close-Call Reporting)

People

Close Call Coordinator and/or local Close Call Committee communicate the status of Close Call(s)/Lessons Learned to their organization.

Con Edison’s Corporate EH&S department routinely publishes Close Calls or Lessons Learned that apply to a broader base.

Process

Close-Call Reporting

Con Edison has implemented a close-call program to enable employees to report hazards, unsafe conditions, and/or unsafe behavior that have the potential to result in injuries or property damage, without disciplinary action.

Con Edison employees are encouraged to recognize, report, and share situations that they believe may lead to a potential injury, or that represent conditions that need to be corrected. Employees can report close calls through an on-line form located on the Con Edison intranet. (See Attachment H , Con Edison Specification CSP 26.00 — Close Call Procedure.)

When a Close Call is submitted, an individual for that department, called the “Close Call Coordinator,” reviews the submittal for completeness and to categorize it as either a Close Call or a Lessons Learned. A “Close Call” is an event where no physical injury or property damage has occurred, but had the potential to result in injury or property damage. A “Lessons Learned” is an event where property damage or a minor injury (no medical treatment or first aid needed) occurred.

On a monthly basis, the Close Call Coordinator and/or local Close Call Committee communicate the status of Close Call(s)/Lessons Learned to their organization.

Con Edison’s Corporate EH&S department routinely publishes Close Calls or Lessons Learned that apply to a broader base.

8.10.6 - Duke Energy Florida

Safety

Near Miss Program

People

Duke Energy Florida has two formal programs in place aimed at improving safety practices by learning from experience.

One is a “Near Miss” program designed to document information about events where a safety hazard occurred, but no one was hurt. For example, an employee accidently dropping a tool into an area that creates a flash with no one getting injured is an example of a “Near Miss.” The other program is a “Good Catch” program designed to document information about potential safety hazards identified before the occurrence of an event. For example, an employee proactively reporting cracked and raised cement on a walkway that poses a trip hazard before anyone trips.

All employees are encouraged to document and report both Near Misses and Good Catches. Supervisors are responsible for reporting both as they identify them. The reporting associated with these programs is supervised by the Lead Health and Safety Professional for the South Coastal Zone.

Duke Energy Florida enjoys good participation in these programs. In a recent eighteen-month survey of Duke Energy Florida, there were 54 Near Misses reported state-wide, including both native and contractor resources. Employees noted that both programs gained momentum as employees saw the value of the information being distributed in near miss and good catch reports. Employees began to see the reporting of this information as a way of increasing learning and an opportunity to improve safety, rather than something that would result in punitive action.

Through programs like this, Underground department experts believe they have achieved a “culture of safety,” where employees take personal accountability for their own well-being and the well-being of their coworkers.

Process

Near Miss reports and Good Catch reports are submitted through the network system’s PlantView online software, and issued in the form of Safety Alerts. An example of a Near Miss report is included in Attachment N.

After a Near Miss is reported, the Lead Health and Safety Professional is sent immediately to the site to document what happened by directly interviewing crew members and supervisors. The safety professional will also take pictures of the event site and prepare and submit a Preliminary Investigation Report (PIR) which includes recommendations to prevent an incident in the future. This PIR is forwarded to the corporate Vice President of Safety. A Near Miss report, a one or two-page description of the near miss incident, is published and shared throughout the company. (See Attachment N .)

Technology

Network system employees fill out Near Miss and Good Catch reports in the company’s online PlantView system. Electronic PIR reports are filed with Duke Energy Corporate.

8.10.7 - Energex

Safety

Near Miss Program

People

Improving safety is a key focus area for Energex, which is driven by the company CEO. The company has embarked upon a system wide effort to change their safety culture. In the recent past, Energex had experienced three safety incidents, resulting in worker injuries. The company is hoping to leverage the emotion from those events as a driver for changing the safety culture.

Energex has established a safety management system, which is a comprehensive framework that guides their safety approach, and addresses strategies for managing the hazards and risk associated with the design, construction, operation and maintenance of the system. Strategies such as their approach to safety training, incident investigation and response, and emergency preparedness and response, are guided by this framework, including near miss reporting.

Energex has recently reorganized their safety organization, consolidating a corporate safety group, a Service Delivery safety group, and a Power Plant Safety group to form one safety organization.

Process

Energex has piloted a program for reporting near misses, hazards, and incidents in four of its locations. Their initial experience is that the number of near misses reported is low, but that employees do report incidents and hazards. Energex is actively pursuing methods to increase near miss reporting. Energex promotes the reporting of near misses and hazards. The company has noticed a proportional decrease in lost-time accidents to the increase in the reporting of these metrics.

8.10.8 - ESB Networks

Safety

Near Miss Program

People

ESB Networks employs a Manager of Safety, Quality, and Environment within its ESB Networks group. ESB Networks also maintains a Chief Executive Safety Committee that oversees and thoroughly documents safety procedures and practices. Representatives from throughout the company rotate onto the committee to get a more complete overview of current and evolving safety practices.

Process

Safety is engrained at every level within ESB Networks, with complete senior management support, including periodic, mandatory safety audits conducted on a regular basis. The organization has recently embarked on a four-year continuous safety improvement campaign that includes behavioral approaches, meetings, and on-the-job coaching. As a result of this and earlier initiatives, it is notable that ESB Networks has earned an OH SAS (Occupational Health and Safety Auditing System) accreditation, which is a significant industry accomplishment.

Among the “safety tenets” that ESB Networks ascribes to are the following:

“If it’s not safe, don’t do it.” (their most important tenet)
“A near-miss today could be an accident tomorrow.”
“We are proud of what we do.”
“We get it right the first time.”
“We look out for each other.”

As a part of its positive re-enforcement of safety policies, reporting of near-misses is not penalized, and ESB Networks finds that field personnel and Network Technicians proactively report and make recommendations for further improving safety practices.

8.10.9 - Georgia Power

Safety

Near Miss Program

People

Crew supervisors are required to document any and all accidents, incidents or injuries at the job site with forms that are kept on the crew truck(s). The injury report is then forwarded to the Safety and Health group within Georgia Power. If the incident involves failed equipment or a “near miss,” a report is filed with engineering as well, and a Test Engineer must inspect the site before work continues.

Technology

Georgia Power uses a computer program called “SHIPS” to documents training and safety records of all employees. Records are kept concerning accidents, incidents and OSHA recordable events. The system serves as the permanent record of the safety and training history throughout an employee’s career.

Incidents and accidents are classified as “charged” for incidents in which an employee is responsible for the incident. The record of the incident is “charged” to the employee’s business unit, or “uncharged” if the employee is not responsible. In this way, safety becomes behavioral-based, and the Health and Safety group can analyze these incident statistics for any number of variables that might be useful in modifying safety training and/or awareness.

8.10.10 - HECO - The Hawaiian Electric Company

Safety

Near Miss Program

People

HECO has implemented a Near Miss program that investigates serious near miss situations that could have resulted in injury or death to someone, equipment damage, or a widespread outage. The Safety department administers the Near Miss program.

Process

The crew involved in the near miss situation would notify the safety department who would work with the department involved to investigate the situation. The outcome of the investigation can result in changes in work procedures to prevent or at least minimize the potential for a similar future occurrence.

The program is non – punitive, unless there is a serious violation of the safety rules.

HECO acknowledges that there are likely near miss situations that go unreported.

8.10.11 - National Grid

Safety

Near Miss Program

People

National Grid has a formal incident analysis process to be implemented following a significant incident, or a near miss with the potential of being significant. National Grid uses an incident management system (IMS) that informs supervisors of the level of severity of various incidents. For example, a supervisor may use the IMS to determine whether or not a particular near miss event requires a formal incident analysis or not.

Process

In a formal incident involving safety, the Safety Department will assign team leader to an incident review team. The team is required to complete an analysis within two weeks.

Technology

National Grid has established a telephone number for employees to use to report incidents that are significant, or near miss events that had the potential to be significant,

National Grid provides near miss cards, which employees can fill out and turn into Corporate Safety reporting near miss events. These cards are not anonymous (See Attachment I).

National Grid uses an incident management system (IMS) managed by the Corporate Safety Department.

8.10.12 - PG&E

Safety

Near Miss Program

People

PG&E has developed and implemented a form to enable employees to report “near misses” or “close calls”.

Process

This is an informal program at PG&E. PG&E management acknowledged that near misses are likely underreported by the work force for fear of repercussions, and that an area of opportunity for the company would be to increase the reporting of near misses to better identify risks and implement countermeasures.

8.10.13 - Portland General Electric

Safety

Near Miss Program

People

To ensure a conduit between management and field workers, PGE employs safety coaches who volunteer to represent their department. They discuss safety issues and events, including reported near misses, with management and the safety team to ensure that any concerns are dealt with and escalated if needed. Safety coaches sit on the Safety Committee, which meets monthly.

The CORE group has one safety coach, and the position is rotated every 2-3 years. The CORE safety coach is a journeyman with normal duties and acts as a point of contact if crew members have a safety concern or experienced a near miss.

Safety coaches discuss concerns and incidents amongst themselves during monthly meetings and determine what actions should be taken. In addition, prior to the monthly meeting, the safety coach spends time talking with crews to find out any issues that can be raised at the meeting.

Process

Overall, PGE adopts a mantra of “see something, say something” for any safety concerns. PGE uses a formalized program called My Safety which documents near miss situations online. Employees can enter information about a near miss, and the safety coach can fill in the details. Alternatively, near miss incidents can be submitted anonymously.

Safety professionals throughout the company view any items entered into the My Safety program, and a selection of important topics is picked out every week for discussion at the weekly meeting.

If a near miss incident did not violate any safety rules or result in a direct injury, there will be no disciplinary consequences. Where rules were violated or an injury or damage occurred, the supervisor pursues the matter and determines an appropriate response.

PGE does not have a formal “good catch” program. However, the My Safety program provides the ability for an employee to recognize a peer for good safety performance.

Technology

My Safety Application: On the My Safety Application used by crews to log incidents, users can view a summary of safety incidents grouped by location, as well as summaries of safety performance. This system is used to record near misses and recognize peers for good performance.

8.11 - Operating a 5KV Underground Oil Switch

8.11.1 - CEI - The Illuminating Company

Safety

Operating a 5kV Underground Oil Switch

People

Underground Electricians perform sectionalizing of the 4kV underground distribution system. This system consists of older, oil filled switches. Many of these devices have deteriorated and are prone to failure.

Process

CEI 5kV oil switches are only operated in a no load condition. They will use these devices to parallel and break parallel feeders.

Because of the age of these devices, CEI had a long standing practice to only operate these devices remotely from outside the hole using a rope attached to the switch handle.

They had an event that demonstrated that operating the device from top at the mouth of the hole was still potentially hazardous to employees, as a fire ball could shoot out the top of the hole.

More specifically, they had a fault that they thought was caused by the failure of a pole top termination. They opened oil the switch to de-energize the line section. When they repaired the problem with the termination, they went back to the hole to close the switch. They did this by affixing a rope to the switch handle. They ran the rope under a ladder to get the proper angle when pulling the switch. One man stood next to the hole to hold the ladder down, while the other guy pulled up on the rope. It turned out that when they closed the switch, they closed into another fault that existed on the line section that they were unaware of. This resulted in a flash that injured the man at the top of the hole.

They have made two significant changes as a result:

Changed their work procedures to require that after they repair a fault they do a cable test before attempting to reenergize a circuit or circuit section. They use either a 5kV megger test (DC test) or a VLF test.
They implemented a device for remotely operating the switch handle, while being able to stand away from the manhole opening – see Technology section below.

Technology

Because of the risks associated with operating older 5kV oil switches, CEI has developed a device for remotely operating the switch handle, while being able to stand away from the manhole opening. The device consists of a base which attaches to the switch body itself, an operating handle that fits over the switch handle, and a slide mechanism and cable device that can used to operate the switch from a safe distance from the manhole opening.

Figure 1: Base

Figure 2: Base + Switch body

Figure 3: Operating handle that fits over the switch handle

Figure 4: Slide mechanism and cable device than can be used to operate the switch from a safe distance from the manhole opening

See Attachment - V

8.11.2 - PG&E

Safety

Operating a 5kV Underground Oil Switch

Process

PG&E has been moving from using oil switches as network feeder sectionalizing switches to a solid dielectric switch. One driver for this change is a concern over the failure of the switch and the environmental and other hazards associated with oilfield gear.

8.12 - Operating Errors Investigations

8.12.1 - CEI - The Illuminating Company

Safety

Operating Errors Investigations

People

The investigation of an operating error is similar to the incident investigation process at CEI. The people involved in the investigation team depend on the nature of the operating error. If there are safety related issues to the error, the safety coordinator and director may be involved.

In a case where the operating error affects customer reliability, the operating error investigation may be performed as part of an outage investigation analysis that includes people from asset management. This outage investigation team, called a REAP team, performs analysis of outages causes to develop procedures to prevent these circumstances from recurring.

CEI may or may not administer formal discipline depending upon the circumstances associated with the operating error.

Process

The process for conducting operating error investigations is not documented, and is administered informally by the department manager. The investigation team is formed and meets to discuss the incident and to make recommendations based on the incident findings. For example, CEI had an incident where an employee erroneously marked and cut a live 33kV cable (The employee thought it was de-energized), resulting in a lengthy outage to customers. After this incident, a team was formed to investigate what happened and to make recommendations to avoid repeat incidents of this type.

As a result of this particular incident, CEI modified its procedure to require a second employee to verify what the first employee determined to be the de-energized feeder before cutting the cable. Only when this dual check is complete, will CEI commence with the cable cut.

Technology

The results of operating incident investigations are documented.

8.12.2 - Con Edison - Consolidated Edison

Safety

Operating Errors Investigations

Process

Operation Error Procedure

Con Edison’s Manhattan Electric Operations department has developed a procedure for investigating and documenting operating errors that occur in the Manhattan Customer Service Area.

An operating error is defined as a violation of a safety, environmental, maintenance, or operating procedure that did or could have resulted in an unsafe working condition, an environmental incident, personal injury, equipment damage, customer or equipment outages, or operation of equipment not consistent with its design.

The procedure requires that when an operating error occurs and is recognized, all further operations are to cease immediately, until the incident is investigated and report written. No attempt shall be made to undo the action that resulted in the error until precise orders are issued to safely remedy the situation.

A responsible person assigned by the Manhattan Electric Control Center Manager prepares and issues a report describing the error.

The report is to be clearly and concisely written and contain, but not be limited to the following:

Description of the system/equipment conditions before the error
Detailed description of the error
Sequence of events (chronology), if required
Initial critique of the error
Recommendations to prevent another error
All applicable maps, feeder prints, layouts, Before and After project drawings (B&A’s), wiring diagrams, hold-offs, and b-tickets shall be included in the report.

(See Attachment I Sample Operating Error Report 02-25M51 6 29 02, for a sample of a completed operating error report.)

8.12.3 - HECO - The Hawaiian Electric Company

Safety

Operating Errors Investigations

( Near Miss Program)

People

HECO has implemented a Near Miss program that investigates serious near miss situations that could have resulted in injury or death to someone, equipment damage, or a widespread outage. The Safety department administers the Near Miss program.

Process

The crew involved in the near miss situation would notify the safety department who would work with the department involved to investigate the situation. The outcome of the investigation can result in changes in work procedures to prevent or at least minimize the potential for a similar future occurrence.

The program is non – punitive, unless there is a serious violation of the safety rules.

HECO acknowledges that there are likely near miss situations that go unreported.

8.12.4 - SCL - Seattle City Light

Safety

Operating Errors Investigations

Process

Safety Accident Investigation

SCL has a process for convening a fact-finding investigation meeting after an accident within a certain time frame. These post-accident investigations sometimes result in work practice / process changes based on lessons learned from the investigation.

8.13 - Organization

8.13.1 - AEP - Ohio

Safety

Organization/Culture

People

AEP has a strong culture of safety, which is evident in its attention to safety in the work place, in its work practices, and in its approach to network design. EPRI researchers observed a wide variety of good safety practices:

Excellent housekeeping at work facilities
Inclusion of safety features in equipment specs and design standards
Effective use of job work site protections
Innovative designs such as a service center design without a raised dock, which is more appropriate to the type of truck used by the underground department as it avoids the need to step down into the truck (as one would from a raised dock.)

AEP utilizes various committees/teams at all levels of the organization to coordinate safety activities. At the overall company level, AEP has a Safety Committee, comprised of representatives from throughout all its operating companies. AEP also utilizes committees at the individual operating company level. AEP Ohio conducts monthly state-wide safety meetings (Ohio Safety Council), as well as area-specific meetings, such as meetings of the Columbus Safety Council. At AEP Ohio, safety initiatives are coordinated and implemented through the Ohio Distribution Safety Supervisor.

At the work level, Network Crew Supervisors and Network Mechanic crew leaders are responsible for performing onsite and morning safety briefings. An AEP Ohio Safety Department Representative performs periodic onsite safety inspections.

Process

Monthly state-wide meetings and local Columbus Safety Council meetings are held with the AEP Ohio Safety Coordinator in attendance. These meetings focus on topical issues, including new technology, equipment, procedures, and safety recommendations. These councils also serve as a forum for members to address safety concerns. Relevant information from these meetings is then shared with employees in AEP Ohio’s daily morning meeting with employees.

Morning Meetings for the field crews focus on topical safety practices and are led by one of five Network Crew Supervisors. The Morning Meeting duty is rotated among the five Network Crew Supervisors.

Formal Safety Training

All Network Mechanics and Network Crew Supervisors have undergone extensive safety training, including lead awareness, de-energization of cables, network protectors, safe manhole entry, and many other safety procedures and practices that are contained in the AEP Safety Manual. Annual safety training for Network Mechanics is also held on topics such as safe handling of new equipment and lead awareness.

Company-wide yearly Safety Stand Downs are also conducted, which focus on specific safety practices in depth. In these “Stand Downs,” workers spend allotted time, usually several hours, focusing on a safety topic.

Safety Checklists

Safety Checklists are used to document conditions as well as the performance of a safety discussion at job sites. These checklists can be filled out using a smart phone application (app). The checklist is tied to AEP Ohio’s Human Performance Improvement program, which uses the SAFER acronym for approaching all jobs.

“S” for summarizing all procedures and safety precautions that will be needed at the job.
“A” for anticipating any potential dangers, problems, or complications.
“F” for foreseeing what all the steps that are required in the job.
“E” for evaluating all the protections and safety procedures that should be used.
“R” for reviewing just-in-time-documents online, past experiences on similar jobs, and online best practices for the specific job they are performing.

Safety checklists are recorded online.

Safety Audits

The AEP Safety Department Representative performs 15 safety audits per year in AEP Ohio. Information is recorded and reported to AEP Ohio management as well as to the parent company.

Cooperation with Local Fire Department

AEP Ohio has recently held meetings with the local Columbus fire department to coordinate rescue and emergency response procedures. In cooperation with the fire chief and his staff, the Columbus Fire Department and AEP Ohio will put together a manhole rescue and fire response video and training course. The focus of the training is how network crews and the fire department must work together, and clearly delineate procedures and roles in in emergency situations. The finished video will be made available to all AEP operating companies.

Cooperation with Local Fire Department

It is notable that the AEP Ohio network group has not had one personal injury in the last 10 years. (Only minor vehicle accidents have occurred.) AEP Ohio ascribes this safety track-record to its philosophy of always putting safety first – before productivity and customer service.

Technology

AEP Ohio uses job safety checklists that can be filled out using a smartphone app. Safety information is recorded and available online for the entire company. The AEP Safety Manual, safety forms, guidelines, and safety best practices documents are available online to all company employees.

8.13.2 - Ameren Missouri

Safety

Organization

People

Safety is a key area of focus for Ameren. EPRI researchers noted visible attention to safety at Ameren Missouri, both in terms of observed work practices, work area protection and personal protection, and in the company’s proactive efforts to influence the corporate culture associated with safety.

Ameren Missouri has formed safety culture teams comprised of employees who focus on understanding the “pulse” of the organization, and on developing and implementing strategies to build trust and positively influence the culture.

In the past few years, Ameren Missouri has implemented multiple strategies to influence the company culture to focus on safety and to shift accountability for safety to the individual. These strategies range from changes in job classifications and job training requirements, to the implementation of safety related programs such as the implementation of a morning stretch period in field worker departments. Part of Ameren Missouri’s safety focus is entitled “Target Zero". Target Zero is a vision or goal for the company for zero unsafe acts. Ameren Missouri knows that unsafe acts ultimately lead to accidents and injuries. Consequently, the mindset they are striving for is one that tries to achieve zero unsafe acts. This focus on safety is elevated to the highest level of the organization, with safety being part of Ameren Corporation’s vision statement.

Ameren Missouri has a safety department that is organizationally aligned with Energy Delivery Distribution Services. There are six supervisors within this group, aligned functionally, who are responsible to develop and implement strategies to influence safety. One of these positions, a Senior Safety Supervisor, is assigned to focus on the safety of underground resources. Safety Supervisor positions are filled by people with varied backgrounds.

Ameren Missouri managers within the Underground organization are taking actions to develop new attitudes. These actions include things such as adding tools and equipment that facilitate safe work practices, and providing supplemental training to employees based on their feedback of where they lack confidence in performing a particular task. Managers report that new attitudes have taken hold, with employees holding one another accountable on issues of safety. Front line supervisors report that they feel like they have management backing to respond to issues associated with safety.

Ameren Missouri has a safety program called the Blue Hat program, designed to increase worker safety awareness and problem resolution. In this program an employee from the union is temporarily assigned to a position within the department that liaises with the field force on issues with tools, equipment and work practices. (See Safety - (Blue Hat Program) ) )

The change in culture is having a positive effect on safety performance. As an example, the Underground Construction group has seen a quantifiable improvement in department safety performance that company management attributes to a change in the department culture.

Ameren Missouri tracks industry-standard safety measures such as OSHA recordable incidents, lost workdays, and days away restricted and transfer (DARTS), a measure that includes resources who are back at the work place, but remain on restricted duty.

Ameren Missouri’s safety approach includes programs that reward successful performance, and punitive action for disregard of safety rules. These programs were implemented in an attempt to raise the bar and hold employees and crew leaders responsible. For example, Ameren Missouri offers an Eagle Leadership award, a financial award given to the employees in a work group for achieving certain safety goals. As another example, Ameren Missouri has developed certain “rules to live by”, such as the wearing of seat belts. If an employee breaks one of these rules, Ameren Missouri will take a punitive action, such as giving an employee who violated the rule time off without pay.

Process

Ameren Missouri conducts a number of periodic safety related meetings and practices including:

Regular tail board meetings
Morning “5 minute” briefings
Monthly safety meeting
Tool committee meetings
Safety committee meetings
Culture committee meetings

An example of safety practice implemented as part of Ameren Missouri’s focus on safety is kicking off meetings with a safety message. The meeting host will select a topic of interest for the group and start the meeting by sharing information on that topic. The topic does not necessarily have to be related to the meeting purpose, but rather a topic that would be of interest and generally apply to the meeting participants. An example topic would be a reminder to a meeting of field resources to identify all potential energy sources, including non conventional (non electric) sources such as water, steam, work equipment, etc.

Another program that Ameren Missouri has implemented that influences the safety culture is the performance of safety assessments. Ameren Missouri will assemble a small group of employees, typically between two and five, and visit either an operations center or workgroup and perform an assessment or review of everything they do from a safety perspective. Assessment teams will review both downstream and upstream activities. Downstream activities are things that are the consequences of performance, such as performance metrics, recordable incident rates, lost time accidents, etc. Upstream activities are things that work groups are doing to prevent accidents, such as job briefings, and performing quality safety meetings. Assessment teams will try to understand the linkages between upstream and downstream activities. Part of the assessment process is to talk with employees, understand their perspectives, and gather internal best practices that can be shared with others.

Another practice is the performance of job briefings (tailboards). At Ameren Missouri there are six elements to a job briefing. They include a review of:

hazards of the job
safe procedures and practices
discussions of any special precautions
identification of energy sources
discussion of clearances
personal protective equipment

An element of the job briefings is a requirement to regroup and re-brief when the work environment changes.

Ameren Missouri conducts a daily morning safety meeting (also called a “5 minute briefing”). This meeting is lead by a supervisor who prepares a safety related topic. The morning meeting includes stretching exercises. Once a week, Ameren Missouri invites in a physical therapist to lead the morning stretching exercises and to provide personal counsel to employees.

The construction supervisors within the Underground Construction group perform routine safety observations, called Job Behavior Observations (JBOs). Supervisors and managers are required to perform a certain number of JBO’s each month. Information from these observations is recorded on a form.

An example of a good safety practice in place at Ameren Missouri is the formal conversation that takes place during a shift change, when one employee is ready to leave his shift and the other employee comes on shift. Ameren Missouri requires a specific discussion of any operational issues and unusual conditions that may exist.

Ameren Missouri has implemented a Near Miss program, where employees are encouraged to report near misses through an anonymous reporting system. Ameren Missouri managers acknowledged that while the program is gaining momentum, there still exists some skepticism among the bargaining unit employees about this program and that employees have been slow to report near misses for fear of punitive action.

Technology

Ameren Missouri issues a number of safety related publications, including safety sampling results, safety alerts, near miss reports, Blue Hat reports, standards reports, incident summaries, and tool committee summaries. These safety-related publications are posted on a bulletin board within each department focused on safety.

Figure 1: UG Construction Safety Bulletin Board

8.13.3 - CEI - The Illuminating Company

Safety

Organization

(Culture)

People

EPRI investigators noted a strong focus on safety at CEI. Safety goals and performance reports were conspicuously posted at the UG Network Service operating center. Various safety initiatives and meetings are conducted, including a daily “Safety Standup” meeting, involving the entire department.

EPRI investigators noted safe work practices including adequate traffic and pedestrian control, the use of personal protective equipment, the wearing of safety harnesses by workers, a lifting crane set up above the vault or manhole opening, and continuous air quality monitoring.

CEI has tied safety performance to incentive compensation, with non bargaining compensation being tied to overall safety performance, and bargain unit incentive compensation tied in with attendance at safety meetings, training, and not having an accident.

Culturally, one CEI employee noted that they have changed the attitude about safety from a “victim mentality” to one of “accountability”. They have accomplished this by driving responsibility for safe work practices down to the individual, and getting front line supervision involved.

Process

CEI has multiple practices in place to maintain a focus on safety. These include:

Safety training – each man receives from 16 – 24 hours per year.
Advanced Safety Coordinators – CEI employs two people who are focused in safety
Daily Safety Standup Meeting
Daily Safety Communication
Safety Stop program
Safety topic of the month
Monthly Safety Stand down meeting
Monthly supervisor safety meeting
Quarterly corporate meeting with union representation

8.13.4 - CenterPoint Energy

Safety

Organization

(Culture)

People

EPRI investigators noted a strong focus on safety at CenterPoint. Safety goals and performance reports were conspicuously posted at the Major Underground operating center. Various safety initiatives and meetings are conducted, including the “HERO” value based safety program, a peer to peer safety observation program described more fully later in this report.

EPRI investigators noted safe work practices during site visits, including adequate traffic and pedestrian control, the use of personal protective equipment, atmospheric testing and ventilation, and the use of a heat gun to test for hot spots when entering a manhole.

CenterPoint has company level safety goals, and breaks these down into departmental safety goals. Major Underground’s safety performance is tied into the corporate goals. Safety performance is incorporated into performance reviews.

Culturally, CenterPoint has programs in place that help to increase employee focus on safety. They have several safety observation initiatives underway and set goals for the number of observations performed to get employees thinking and talking about safety. They have implemented a suggestion box as part of the HERO program to gather ideas about safety improvement.

Process

CenterPoint has multiple practices in place to maintain a focus on safety. These include:

Safety training – each man receives about 20 hours per year including training in manhole rescue, asbestos awareness, excavation safety, and ladder safety.
HERO Program
Crew Inspections (Safety Site Inspections)
Safety Action Committee
Monthly Safety Meeting
Safety Council Meeting
Accident Review Process
Tailboard meetings at start of each day and at project sites
Daily safety message distributed to employee pagers
“Near Miss” safety suggestion box

8.13.5 - Con Edison - Consolidated Edison

Safety

Organization

(Culture)

People

Safety Culture

EPRI investigators noted a strong and visible focus on safety at Con Edison. In every facility that EPRI investigators visited, safety goals and performance reports were conspicuously posted. At every visited worksite, EPRI investigators noted safe work practices including traffic and pedestrian control, the use of personal protection, the wearing of safety harnesses by Con Edison’s workers, a lifting crane set up outside of the vaults, and continuous air quality monitoring.

Environmental, Health, and Safety (EHS)

Con Edison has a centralized group Environmental, Health, and Safety group (EHS), as well as EHS personnel imbedded throughout the field organizations. Con Edison has an extensive set of procedures as well as intensive training around EHS issues.

The EHS department responsibilities include providing internal oversight and guidance on environmental, health, and safety issues; policy and procedure development; performance reporting; compliance; incident investigation; and review and approval of safety equipment.

Technology

Sump Pump Installations with Oil Minder System

For vaults equipped with sump pumps, Con Edison installs an Oil-Minder control system (by Stancor). This system allows water to be automatically pumped from vaults without ejecting oil. The Con Edison installation includes a high water alarm, which is tied in with Con Edison’s RMS system, where applicable.

The Oil-Minder system uses a sensor probe that can distinguish oil from water. When the probe detects water, the sump pump operates. When the probe detects oil, the system prevents the sump pump from operating, containing the oil in the sump hole. The system relies on the fact that oil is lighter than water and rises to the top of the sump hole. If, for example, the sump hole contains water with a layer of oil on the top, the sensor probe (which reaches down to within 3 inches of the bottom of the sump hole), sensing water, pumps water out of the hole until the probe detects the oil. When the oil is detected, the pump stops.

See Attachment K .

Con Edison has sump pump installations that predate its use of the Oil Minder system. The utility is installing about 100 Oil Minder System units annually in their existing vaults with sump pumps.

Cable Design

Con Edison is working with cable manufactures to remove potentially hazardous substances from their distribution cables. These substances include the fire-retardant bromides used in the Dual-Layer Ethylene Alkene Rubber (EAM) cable insulation and the lead in the primary Ethylene Propylene Rubber (EPR) cable insulation.

8.13.6 - Duke Energy Florida

Safety

Organization

(Culture)

People

Safety is a key area of focus for Duke Energy Florida. EPRI researchers noted visible attention to safety, both in terms of observed work practices, such as work area protection and personal protection, and in the company’s proactive efforts to influence the corporate culture associated with safety.

The view at Duke Energy Florida is that all employees must be involved in fostering a culture of safety. Their approach to safety improvement is to create an environment that engages employees in the process, rather than focus on only disciplinarian measures. Employees cited examples of how the environment of employee engagement has improved safety through application of learnings from prior incidents and “near miss” events to operational processes and to engineering designs.

Duke Energy Florida has a corporate safety department that includes Health and Safety Professionals. One lead Safety and Health Professional focuses on safety in the South Coastal Region, which includes Clearwater and St. Petersburg. This person is responsible to develop and implement strategies to influence safety in the region, including the safety of the network underground organization.

Lead Health and Safety Professional positions are filled by people with well-rounded experience in field work, training, and safety. The Lead Health and Safety Professional for the South Coastal Region has 38 years of total experience at Duke Energy Florida, including 17 years of experience in the field as a lineman, and 9 years of experience as a trainer.

Each Operating Center in Duke Energy Florida has formed a local safety committee, comprised of representatives from each work group, and led by an employee designated as the operating center safety chairperson. As Clearwater and St. Petersburg are part of separate operating centers, network employees may be represented on either local safety committee. Participation is voluntary, and there is no forced rotation of members on the committee. The local safety committees hold monthly safety meetings. The local ops center chairperson and committee report (via a dotted line) to the Lead Health and Safety Professional.

Process

The Lead Health and Safety Professional communicates directly with network system supervisors in the Clearwater/St. Petersburg area on an as-needed basis, whenever an issue needs to be addressed. The Lead Health and Safety Professional also participates in safety meetings, and is responsible for performing routine safety observations, performing a minimum of eight observations each month.

Duke Energy Florida conducts a number of periodic safety related meetings including:

Job site tail board meetings
“Take 10” Meetings
Weekly meetings
Monthly safety meeting
Zone Safety Committee Meeting

(See the Safety Meetings section of this report for more information.)

Job briefings (tailboards) are conducted prior to every job at Duke Energy Florida and include the following topics.

Hazards of the job
Safe procedures and practices
Discussions of any special precautions
Identification of energy sources
Discussion of clearances
Personal protective equipment

An element of the job briefings is a requirement to regroup and re-brief when the work environment changes. This practice is call an “all-stop,” which as the name entails, stops all work at the time initiated. In addition, Duke Energy Florida also performs a post job briefing.

Duke Energy conducts a daily morning safety meeting, also called a “Take 10” meeting. This meeting is led by a supervisor who prepares a safety related topic. In addition to the safety topic, the discussion includes job and site specific safety issues as part of the planning for the work of the day.

Once a month, a safety meeting is held in each of the operating centers in the South Coastal Zone; Clearwater meetings are held the first Wednesday of every month, while St. Petersburg meetings are held the second Wednesday of each month. All employees, including the network Group, attend this meeting unless unavailable because of an outage or emergency. While the Safety and Health professional participates in these meetings, they are led by the local safety committee, comprised of representation from each work group and led by an employee designated as safety chairperson. The content for the meeting includes corporate safety and training content, as well as content developed by the local safety committee.

In turn, each Operating Center Safety Chairperson and co-Chair attend a monthly Zone Safety Meeting. This separate monthly meeting includes all the safety chairs from the operating centers that comprise a Zone. Once a quarter, all Zones meet for a Florida-wide Safety coordination meeting.

An example of a practice implemented as part of Duke Energy Florida’s focus on safety is kicking off meetings with a safety message, and assigning responsibility for safety related duties in the event of an emergency, such as calling 911, or retrieving the AED. The meeting host will select a topic of interest for the group and start the meeting by sharing information on that topic. The topic does not necessarily have to be related to the meeting purpose, but rather a topic that would be of interest and generally apply to the meeting participants. An example topic would be a reminder to a meeting of field resources to identify all potential energy sources, including non-conventional (non-electric) sources such as water, steam, work equipment, etc.

Another practice of note is the “30 for 30,” a practice where every thirty minutes, participants of a meeting stand and stretch for 30 seconds. The meeting discussion does not cease, but continues as participants engage in this stretch. A timekeeper is assigned at the start of the meeting to remind participants to stretch at 30 minute intervals.

Duke Energy Florida has implemented a “Near Miss” program, where employees are encouraged to report near misses. In addition, there is a “Good Catch” program to identify situations were an employee noticed a potential safety hazard and reported it before an event occurred.

Technology

Duke Energy Florida issues a number of safety related publications, including “Connection” which is safety communication packet distributed electronically weekly to the supervisors as one document with links to other documents that include safety related topics. The other documents may include Safety Alerts describing incidents or near misses, Health and Safety Awareness bulletins, updates on safety performance, and other safety related communications. “Connection” ensures a single source is providing a unified and consistent safety message broadcast to all company employees. See Attachment K for a sample of the connections bulletin – note the links to the other safety related documents. See Attachments L , M and N for samples of a Health and Safety Awareness Bulletin, a Safety Alert Incident summary and a Safety Alert “ Near Miss ” summary.

8.13.7 - Duke Energy Ohio

Safety

Organization

(Culture)

People

EPRI researchers noted specific attention to safety in their visits at Duke Energy Ohio. Safe working practices were observed during field visitations, including work area protection, such as the use of traffic cones and warning tape, and personal protection, such as wearing FR rated clothing, and using continuous air monitoring.

Duke Energy recently had a leadership change, with the new leader taking a very close look at the company’s approach to safety. As a consequence of this company wide focus on safety, at the time of the EPRI immersion, Duke Energy Ohio was in the process of reviewing their safety practices, and was in the process of implementing activities to change the safety culture.

Duke’s new focus is on promoting safe behaviors. They recognized the need to move from a punitive approach to one that focuses on changing behaviors.

Sample actions underway at Duke Energy Ohio to increase safety awareness include:

Providing increased safety training for both management and the union. This training involves bringing people in from the field as opposed to conducting the training on a rain day. (One employee cited the fact that management brought employees in to receive this training on a nice day as evidence of their commitment to safety),
Requiring management employees to read a particular book on safety / performance by Aubrey Daniels,
Implementing a safety behaviors program,
Manning jobs differently. For example if a field crew calls into the office and says that they need additional resources to do the job safely, management would capitulate.
“Walking the talk”. Duke employees cited a specific example of an ice storm where an employee suffered a near miss. Management shut down the restoration effort to understand what had happened. The fact that management agreed to take a “time out” from the restoration during a major event meant a lot to the employees and demonstrated that management was serious about safety.
Another significant change in Duke’s management philosophy was getting front-line supervisors back in the field.

Duke Field supervisors have noticed a change in their safety culture as a result of these efforts. They noted that a few years back, when a supervisor would visit a crew, it used to be like “pulling teeth" to get people to adhere to the company safety rules. “Now”, they noted, “you seldom find any infractions in PPE.” Over the past two years, they have gone from “lax to careful”.

The Dana Avenue underground department had no designated safety person. However, each work group within the underground department has their own safety chairperson – en employee who represents that group at safety meetings. A question asked by EPRI investigators was “Who is responsible for safety?” The response at Duke Energy Ohio was “All of us”.

Process

Duke Energy Ohio convenes regular safety meetings at various levels in the organization, ranging from quarterly Safety Oversight Committee meetings to job specific tailboard meetings.

Duke Energy Ohio has tied company bonuses to the achievement of Total Case Incident rate targets. Incentives apply to both bargaining and non bargaining employees.

Technology

Duke Energy recently updated their safety manual. The manual is written generally, covering all areas of T & D. However, because this manual is written generally, it doesn’t cover safety issues specific to network operations.

Supervisors at Dana Avenue believe that the company should invest in a safety manual that describes safety procedures for the network. For example, “what should employees do when detectors reveal gas in manholes?” The field force knows that when the alarm goes off, they need to get out of the hole. But specific guidelines for responding safety situations in the network are not well documented.

8.13.8 - Energex

Safety

Organization

(Culture)

People

Improving safety is a key focus area for Energex, which is driven by the company CEO. Energex has embarked on a system-wide effort to change their safety culture. In the recent past, Energex had experienced three safety incidents, resulting in worker injuries. Energex is hoping to leverage the emotion from those events as a driver for changing the safety culture.

Energex has established a safety management system, which is a comprehensive framework that guides their safety approach, and addresses strategies for managing the hazards and risk associated with the design, construction, operation, and maintenance of the system. Strategies such as the approach to safety training, incident investigation and response, and emergency preparedness and response, are guided by this framework.

Energex has recently reorganized its safety organization, consolidating a corporate safety group, a service delivery safety group, and a people and procurement safety group to form one safety organization.

The safety organization is comprised of four departments:

Governance, community and assurance
Incident investigation and analysis, comprised of six full-time incident investigators
Operational safety and risk department, comprised of safety advisors (9) , and project team (4), and focused on issues such as personal protective equipment (PPE), and asbestos management,
Strategy, capability and performance, focused on establishing and executing a safety strategy on behalf of the company.

Process

Energex recognizes that positively influencing safety performance involves changing behaviors, and that it is a change management issue that must be addressed over time. The company has implemented a number of strategies to influence their safety culture (see Figure 1).

Figure 1: Energex sample poster promoting safety

The company recently conducted a safety culture diagnostic, hiring a contractor to review their practices and make recommendations for change. A leading safety program is one outcome from the effort.

Safety is a company key result area. The company, through their normal business process, produces a company scorecard of KPIs, and safety is a key component. Scorecard performance is used to determine performance bonuses for all employees. The bonus pool for employees is up to six percent of salary.

Historically, Energex used lagging indicators, such as lost-time incidents frequencies, as safety KPIs. The company has elected to move away from the use of lagging indicators as KPIs used to calculate performance bonuses, and instead shifted to leading indicators, which measure preventive behaviors.

Energex’s current safety KPI is an aggregated metric comprised of the following three leading indicators:

Percentage of leadership safety visits conducted within expected time frames. Multiple employee types, including every level of management, have targets for performing field safely visits. The number of visits to be performed varies by job type.
Percent of eSafe actions closed out on time. When Energex has a safety incident, they perform a post incident investigation. Out of this investigation, they will produce specific recommendations (referred to as eSafe actions) with an expected time frame for completion. This metric is based on adherence to the recommendation implementation schedule.
Near Miss and Hazard Reporting Target Energex promotes the reporting of near misses and hazards. The company has noticed a proportional decrease in lost-time accidents to the increase in the reporting of these metrics.

In addition to a performance bonus system based on safety performance as measured by the leading indicators, Energex also provides cash incentives to employees who work in a particular work group who achieve certain safety milestones based on lagging indicators, such as time without a lost-time incident.

Note that lagging indicators, such as lost time, are not part of any incentive pool for front line supervisors, as Energex does not want to incent personnel in these front line jobs to cover up incidents. The company wants to create an environment where people report incidents. At the time of the practices immersion, Energex was considering shifting these payments to leading indicators.

8.13.9 - ESB Networks

Safety

Organization/Culture

People

ESB Networks employs a Manager of Safety, Quality, and Environment within its ESB Networks group. ESB Networks also maintains a Chief Executive Safety Committee that oversees and thoroughly documents safety procedures and practices. Representatives from throughout the company rotate onto the committee to get a more complete overview of current and evolving safety practices.

Process

Safety is engrained at every level within ESB Networks, with complete senior management support, including periodic, mandatory safety audits conducted on a regular basis. The organization has recently embarked on a four-year continuous safety improvement campaign that includes behavioral approaches, meetings, and on-the-job coaching. As a result of this and earlier initiatives, it is notable that ESB Networks has earned an OH SAS (Occupational Health and Safety Auditing System) accreditation, which is a significant industry accomplishment.

Among the “safety tenets” that ESB Networks ascribes to are the following:

“If it’s not safe, don’t do it.” (their most important tenet)
“A near-miss today could be an accident tomorrow.”
“We are proud of what we do.”
“We get it right the first time.”
“We look out for each other.”

As a part of its positive re-enforcement of safety policies, reporting of near-misses is not penalized, and ESB Networks finds that field personnel and Network Technicians proactively report and make recommendations for further improving safety practices.

ESB Networks spends about €4M per year on public safety advertising. Builders and contractors as well as ESB Networks personnel are proactively informed about safe digging operations near buried cable (see Attachment C: Safe Digging Procedures).

Technology

ESB Networks has recently published a new “Live Line” policies and procedures manual that thoroughly details safety issues and practices of working on live lines.

ESB Networks’ Safety Rules colloquially referred to as the “Bible”, is prepared and periodically updated by the Operations Policy group, and is available in hard copy and online. All Network Technicians receive a copy, which they must sign after receiving and reviewing it. The “Safety Rules” book contains the following:

Sets out how work should be organized
Sets out how personnel communicate with the control room operator
Sets out the different roles for personnel when operating on the system
Describes processes for grounding the system
Details safety clearance zones, such as working distances, etc.

These documents are available in hard copy and through the ESB Networks intranet. The company web site also posts and keeps updated documents on safety procedures on safe digging and avoiding electrical hazards through a public, online link at their web site (see Figure 1).

Figure 1: Publically posted safety documents on ESB Networks web site.

8.13.10 - Georgia Power

Safety

Organization/Culture

People

The Network Underground group has a dedicated Health and Safety Advisor assigned to them, who functionally reports to the Health and Safety department at Georgia Power. The Advisor meets regularly with the larger Georgia Power Safety and Health group. The Advisor also works closely with the Storm Center and with the Cable Locating group.

In all, the Safety and Health Advisor is responsible for the training and safety management of approximately 180 people within the organization. The Network UG Manager works closely with the Safety and Health Advisor on safety and health issues related to the operation and maintenance of the network underground system throughout Georgia.

The person presently assigned to the position of advisor for the Network UG group came up from the ranks of the underground organization, serving as a Cable Splicer, so he is familiar with the unique needs and requirements for safely working in a network. The Advisor shadowed safety personnel to gain on the job training, and eventually co-chaired and chaired the safety committee while he was a Cable Splicer crew leader.

The Advisor has received formal OSHA training at Georgia Tech as well as formal training in excavating, soil analysis, and scaffolding.

Safety is a key area of focus for Georgia Power. EPRI researchers noted visible attention to safety throughout the Underground Network group, both in terms of observed work practices, work area protection and personal protection, and in the company’s proactive efforts to influence the corporate culture associated with safety.

Each morning, crews start the day with a safety discussion and a morning stretch to prepare them for the day physically and mentally.

Each work group has a weekly safety meeting to discuss incidents and near-misses, as well as a safety topic where a rule or policy is discussed.

Each group within Georgia Power has a safety committee in which every department is represented. The Network UG safety committee is comprised of volunteer representatives from Engineering, Maintenance, Cable Construction, Duct Line Construction, and Operations & Reliability. The committee meets once a month. The minutes of the meeting are recorded and distributed. The meeting addresses open issues, any recent incidents, or new ideas for improving the safety and well-being of employees.

The Georgia Power Network Underground group develops an annual safety plan which describes the various safety committees, and communicates the department safety strategy including expectations of employees, and accident reporting procedures.

(See Attachment H )

Process

Network Underground employees attend quarterly safety meetings, run and managed by the Safety and Health group, which address issues specific to the group. The group often invites guest speakers to these meetings who are experts on specific network underground safety issues.

In addition to these quarterly meetings, employees must attend yearly safety training in the following areas:

OSHA regulations
CPR
First Aid
Smith System Safe Driving refresher
Fire extinguishers
Use of AED

If any employee has a driving accident, the employee must take the full Smith System Safe Driving course (not the refresher course), as do any new employees. The Safety and Health group also brings in an expert from Industrial Hygiene and Environmental Safety to talk about the following:

Industrial hygiene
Hearing and sight protection
Lead awareness
Environmental safety, including safe handling of spills and storm water regulation
Battery storage
PCB storage
Safe hauling of flammable liquid

Other topics are covered as determined by the Safety and Health group within Georgia Power.

Once every two years, Georgia Power requires flagging training through the vehicle training specialists. Even though contractors are usually used for flagging, Georgia Power wants its field personnel trained as well.

Depending on crew members’ job classifications, they must also complete the following training:

Forklift training every three years.
Competent Person class on trenching, as needed
Enclosed space training, as needed

Local management decides what training is need for each location and when.

Competent Person Training is essential not just for safety reasons, but also in the event of an OSHA inspection at a trenching site. Each job crew must have a crew leader with the appropriate Competent Person training for the work the crew is performing. This crew leader is given a Competent Person card, which they can show to any OSHA or Georgia Power inspector.

Job briefings, led by a member of the crew, are held before each job. Crews are reminded of key safety measures that must be taken according to the tasks at hand on the site, such as protective gear required, confined spaces measures, etc. The crew member responsible for filling out the job briefing report sends it to the crew supervisor who keeps it on file for one year in a Job Briefing book. This is an OSHA requirement strictly followed by Georgia Power employees. Any qualified crew member can perform the job briefing, and the responsibility is routinely rotated to give all crew members greater familiarity of safety and job procedures.

(See Attachment I for a copy of the job briefing form.)

Since 2005, Georgia Power has instituted a safety program called “Target Zero” to emphasize that no accident is acceptable. There have been no serious injuries at Network Underground since the goal has been in place. If an accident should occur, the company resets the clock, so to speak, back to zero. It would have negative connotations, it believes, to focus on any accidents. There is a consistent focus on zero accidents, regardless. Safety is a key goal in the company’s overall performance plan.

Georgia Power also has a safety program called “100 Days of Summer” as most accidents happen in the hottest weather. It is notable that Georgia Power has an extensive safety training and compliance program, but it also emphasizes many health and safety issues off the job. One example is its “Take 5 @ the 5’s” initiative, which reminds employees to take five minutes at five before each hour to hydrate.

Georgia Power uses a number of positive motivators to re-enforce safety practices. One example is departmental awards for achieving its “Target Zero” program with the goal of zero safety incidents in one calendar year. Another positive motivator is a safety competition with a neighboring utility, Duke Power. The winners receive luggage, a cooler, or some other personal gifts. Georgia Power also has intra-company safety competitions with awards and prizes as well.

Technology

Georgia Power issues safety reports to all departments; documents safety training schedules; and issues Web site blurbs on the company intranet about safety tips, safety competitions, and safety reminders. Bulletin boards are also used throughout the company to re-enforce safety programs and safety and health messaging. Bulletin boards also display recorded deaths at the company (See Figure 1 and Figures 2 and 3) to remind everyone of the seriousness of the hazards they face every day. The Safety and Health group feels this has had a positive effect because there have been no fatalities at Georgia Power Network Underground since 1988.

Much of the Georgia Power’s communication about safety is designed to appeal to the employee’s sense of responsibility to family.

Figure 1: Examples of safety related displays; Note that Georgia Power encourages daily stretching

Figure 2 and 3: Examples of safety related displays

Georgia Power has what it calls the Section Zero book, which contains all mandatory safety and work procedures. The book was negotiated between company and union and covers all areas of safety including PPE specifications, housekeeping, and safety and work procedures for distribution.

8.13.11 - HECO - The Hawaiian Electric Company

Safety

Organization

(Culture)

People

EPRI investigators noted a strong focus on increasing safety awareness at HECO, driven from the CEO level of the organization.

HECO has recently established a new safety approach, including a new high level vision for safety, the establishment of new safety metrics, the establishment of safety goals over a three year period, and reporting of safety performance. For example they have shifted their metrics from one based on lost time accidents to one based on the EEI standard Total Recordable Cases Incident rate. This will expand their focus to all recordable incidents and enable them to better benchmark with others. Their three year safety performance targets are aggressive, aiming for first quartile safety performance^[1] . They are conducting quarterly reviews to monitor progress against these goals, and make course corrections as required.

Process

HECO recognizes the change management challenges of improving safety performance. They are actively working to change a historic culture that at times found it acceptable to take risks in order to get the lights back on. They are focused on establishing a culture that recognizes that all accidents are preventable, and that employees must look out for their own safety and the safety of their co-workers. One example of an action HECO took to help change the safety culture was to include lineman from other companies (through the Northwest Lineman’s college) to supplement their safety training. These lineman brought ideas about how others do things that directly resulted in changes at HECO, such as a focus on wellness and the implementation of a morning stretching program.

HECO is also focusing on changing their approach to accident and incident investigation to be more focused on prevention. This includes the development of a Near Miss program that includes investigation of “near misses” that could have resulted in either damage to equipment, outages, or injury.

HECO has also implemented a Job Hazards Safety Process.

HECO has taken steps to increase safety dialogue among employees, including conducting frequent safety meetings, requiring worker tailboard meetings, and implementing the Work Environment Specialist position, to identify and address safety issues without employees fearing any punitive reprisal ( See Work Environment Specialist). HECO wants to change a historic perception that some hold that company safety professionals are focused on placing blame, rather than determining root causes to prevent future similar incidents.

Technology

HECO has made recent changes to their personal protective equipment approach, requiring a Level 2 clothing system, including 8 Cal FR rated clothing and the use of face shields. (See Personal Protective Equipment)

^[1] Based on EEI Benchmarking comparisons

8.13.12 - National Grid

Safety

Organization

(Culture)

People

EPRI researchers noted visible attention to safety at National Grid, both in terms of observed work practices, work area protection and personal protection, and in the implementation of safety strategies to develop a safety culture. This was evidenced by practices such as beginning every employee meeting with a “safety moment”, conducting both formal and informal safety meetings and inspections, and in using the impact on safety as a key factor in evaluating project priority.

National Grid appears to have been successful in inculcating safety into its culture. EPRI researchers participated in several meetings where employees, as part of the “safety moment” volunteered and transformed a description of a personal experience associated with safety into an impromptu safety message for the benefit of all meeting participants.

Internal surveys conducted by National Grid reveals that employees believe the company to be serious about safety.

National Grid employs safety professionals who work to develop and implement strategies to influence the safety culture. Organizationally, safety professionals are grouped functionally, with individuals focused on electric safety in a separate group from those that focused on gas, shared services, etc. Within New York East, there are two safety professionals focused on electric operations – one for overhead lines, and one for underground lines and substations. The safety professional responsible for underground lines and substations has a four year degree in Safety, is a Certified Safety Professional, and has experience working for a number of large companies in a safety area. National Grid employs safety professionals with a variety of backgrounds and experience.

National Grid has an investment management group which is responsible for overseeing the justification and risk analysis of specific projects. In particular, it is responsible for prioritizing project based on risk analysis, and thus plays a crucial role in directing resources to mitigating safety risks.

Site visits to assess work crew safety are undertaken both formally and informally. Formal compliance assessments are conducted so that each employee is observed and reported on at least once per year. Informal assessments are conducted using the Safe and Unsafe Acts (SUSA) visits model, where a work group is observed without their knowledge (most often by their direct supervisor) and then engaged in a discussion centered on how their activities may have been safe or unsafe, and how to resolve the unsafe acts in the future.

Pre-job briefings are an integral part of day-to-day safety. These outline the site-specific safety hazards, equipment, and techniques that will be encountered or used on the job. The employee in charge of the work delivers these briefings. If the supervisor is on site, he/she is considered in charge of the work and the job briefing. If not, the crew chief, crew leader, working leader, working foreman, or similar person is in charge of the work and the briefing. During the briefing, the crew assesses the job site and surroundings and discusses the types of hazards present.

The entire crew, including the supervisor, is expected to be focused on safety in all work. A copy of the electric operating procedures (EOP) book is required to be in the service van and available to the work leader. A committee of field workers and supervisors, engineers, and the Safety Department revisits all EOPs on a three-year schedule.

There is mandatory first aid training for crews, which covers both first aid and rescue procedures. Yearly manhole rescue training is conducted. Other training includes air monitoring procedures and personal protective equipment training.

Overall safety is assessed across lines of business with the use of a calculation tool called the Safety Pyramid.

Process

National Grid has a number of safety management practices in place designed to achieve their vision of being a world-class safety organization. These include on-site safety assessments, pre-job briefings, electric operating procedures (and review cycles), and general safety measures. Some of these practices will be discussed in more detail in this report.

On-Site Safety Assessments

National Grid conducts two types of on site safety assessments – the Safe and Un Safe Acts visits and Compliance Assessments.

Safe and Unsafe Acts (SUSA) visits or observations are done by supervisors six times per month and by work methods people four times per year. These are informal assessments designed to give employees feedback, and engage them in the process of thinking about safety in their work.

A more formal Compliance Assessment is conducted for every employee at least annually. This Compliance Assessment is a formal observation that connects an employee to the work that he/she is doing, holding them accountable for their activities and the state of equipment they are responsible for. Department supervisors are responsible for performing two compliance assessments per month. Operating departments conduct surveys of the field conditions periodically to ensure there is full awareness of configurations in the field. Additional incident analyses may follow significant findings of concern.

Pre-job briefings

Job briefings are conducted at the start of the each job, and are led by the person in charge of the work (either the supervisor, or a crew leader or similar position). Additional job briefings are held whenever there is a significant change in the working conditions that might impact the safety of employees. The job briefing is documented and signed by the designated employee in charge of the job. (See Attachment K )

The briefing covers hazards associated with the job site and its surroundings. During the briefing, the crew identifies all hazards, both electrical and non-electrical, in the work environment. Difficult physical work, including strain, awkward positions, and difficult lifting is discussed. The briefings cover all of the hazards associated with the job, work procedures, special precautions, energy source controls, personal protective equipment requirements, and a warm-up / stretch period.

The scope of the discussion depends on the job and how it relates to employee experience and training. Brief discussion is allowed for routine work, where it is expected that employees have the experience to recognize and avoid the hazards of the job. Extended briefings are required where employees are unfamiliar with the hazards, or the work is particularly complicated or hazardous.

Employees working alone do not need to conduct formal job briefings but are expected to plan tasks and perform them as though a job briefing were being done.

Electric Operating Procedures (EOP)

Correct operating procedures are an important safety consideration. National Grid has developed an Electric Operating Procedure manual that covers safety aspects such as the type of personal protective equipment to be used, grounding methods, and other working methods. These procedures were developed by committees with representatives from engineering, construction and operations, and safety, and are re-visited every three years to ensure they are up to date and correct. A variety of conditions may be assessed in their preparation. For example, a study of all the potential hazards a cable splicer might be exposed to would be conducted to determine the types of personal protective equipment to be used and the procedures that are most appropriate.

National Grid has a number of other notable general safety practices in place to ensure the highest standards of safety are adhered to. These include:

PPE Requirements

Personal Protective Equipment (PPE) includes hardhat, ANSI safety glasses with side shields, steel toed EH-rated boots, and outer layer protective wear with an Arc Thermal Protective Value rating of 8 cal per square centimeter, and with all natural-fiber clothing underneath.

National Grid requires hearing protection for anybody working on an activity with suspected or measured noise exceeding safe levels, and posts warning signs in high noise areas. If noise levels interfere with understanding normal conversational speech, hearing protection is required. Note that National Grid has implemented a Hearing Conservation Program that includes implementing administrative and engineering controls to reduce noise exposure and offering targeted training on hearing protection to employees.

Tethering

Crews in vaults are tethered at all times, except if it is unsafe or impossible. In this case, it is documented in the pre-job briefing, and crew leaders must authorize the acceptable conditions for untethering. National Grid has had this policy in place for approximately ten years.

Continuous Air Monitoring

Crews use continuous monitoring for combustible and other dangerous gases. Crew members wear portable four gas monitors, with at least one person on the crew in the hole wearing an air monitor at all times. A full time attendant must remain outside the vault at all times and cannot enter the vault.

Equipment

All trucks have an automatic vehicle location system, and a Code Blue button. In the case of an emergency, the Code Blue button is pressed, and the truck’s system notifies the Operations Center. The Operations Center then calls 911 and directs services to the truck’s location based on the GPS coordinates. Every truck is also equipped with a first aid kit.

Technology

National Grid’s safety monitoring practices allow it to compare safety between different lines of business within the organization. The tool used for this is the Safety Pyramid. This conceptual tool gives a safety score that is a composite measurement of various types of incidents, weighted by their severity. It includes Lost Time Incidents, Restricted Work Day Cases, OSHA Recordable Incidents, Switching Errors, Motor Vehicle Accidents, SUSA and Compliance Assessments, Significant Hazard Reports, and Near Miss Incidents.

8.13.13 - PG&E

Safety

Organization

(Culture)

People

EPRI researchers noted visible attention to safety at PG&E, both in terms of observed work practices, work area protection and personal protection, as well as in the implementation of safety strategies such as the conducting of safety meetings and inspections and design changes to reduce potential exposure to employees and the public.

PG&E has effectively implemented an asset management process for network equipment, assigning a specific person as the “Manager of Networks,” part of the Distribution Engineering and Mapping organization. This asset manager is responsible for determining the investment, maintenance and replacement strategies for network assets including network transformers, network switches, and network protectors. The manager of networks noted that much of the investment in the network is really focused on maintaining and improving safety rather than reliability, as network secondary systems are inherently reliable by virtue of their design. PG&E has made space specific design changes to improve worker and public safety.

EPRI observed strong working relationships between the manager of networks, and other key PG&E resources focused on network management. The manager of networks was visible and known to the field force, periodically meeting with field crews to review topics of interest, often safety related topics.

Safe working practices were observed during field visitations, including work area protection, such as the use of traffic cones and warning tape, and personal protection, such as wearing FR rated clothing, and using continuous air monitoring.

Safety related training is incorporated into the formal training provided to cable splicers. Each course offered to splicers through their job progression includes safety related issues such as manhole safety.

PG&E has established safety goals set at the division level and are not broken down to the M&C Electric Network group. However, the Group’s safety performance contributes to the divisional goal.

Process

PG&E has incorporated safety processes, such as safety meetings, safety training, safety observations, and the routine conducting of tail board meetings into their work processes. For example, the Superintendent, Vice President of the M&C Electric Network group conducts two safety observations per week. One PG&E employee noted that the company’s emphasis on safety is such that “anyone can bring up a safety issue or stop a job because of the potential safety issue”.

PG&E uses a document called a “Utility Bulletin”, which is a document that notifies the crews of key issues, including safety related issues.

PG&E has implemented design changes to improve the overall reliability and safety of the system.

One such safety-driven design strategy is PG&E’s implementation of a program to replace oil filled transformers located in high rise buildings with dry type transformers to mitigate the potential effects of a catastrophic failure of an oil filled transformer.
Another is their decision to change the network unit design from one with a transformer mounted primary switch compartment to one with a remotely located solid dielectric switch as a primary sectionalizing point. This decision eliminates a potential failure point, preventing a failure of the primary switch compartment from migrating to the transformer tank itself, and thus expanding the potential severity of the event.
Another is the installation of a new manhole cover system designed to improve safety by reducing the risk of collateral component and infrastructure damage.

Technology

PG&E maintains a Safety Health and Claims Website that provides employees to safety and health related materials.

Safety and health related placards and notices were evident at all PG&E facilities visited by EPRI researchers.

Figure 1: Safety Placard at San Ramon Training Center

8.13.14 - Portland General Electric

Safety

Organization

(Culture)

People

Safety is a core value at PGE, and the company has developed a comprehensive program to protect workers, customers, and the public. Many programs are implemented company-wide and also cover the network system, while the CORE also has its own safety programs to cover the unique operating conditions of the underground system.

Executive Safety Council (ESC): PGE has created an ESC to oversee safety across the company. The safety officers and senior management representatives on the ESC regularly meet with employee groups to listen to any concerns about safety and share information about PGE safety initiatives 15 [1].

Safety Coordinator for Eastern Region: Every region in PGE’s service territory has a safety coordinator. The present coordinator for the Eastern Region, which includes the CORE, has over 30 years of experience and began working for PGE as a journeyman.

Safety Coaches: To ensure that there is a conduit between management and field workers, PGE employs safety coaches who work with the safety team. Safety coaches are members of the union who volunteer to represent their department.

They discuss safety issues and events with management and the safety team to ensure that any concerns are dealt with and escalated if needed. Safety coaches sit on the Safety Committee, which meets monthly. The CORE group has one safety coach, and the position is rotated every 2-3 years. The CORE safety coach is a journeyman with normal duties who acts as a point of contact if crew members have a safety concern or experienced a near miss. Safety coaches discuss concerns and incidents amongst themselves during monthly meetings and determine what actions should be taken. In addition, prior to the monthly meeting, the safety coach spends time talking with crews to find out any issues that can be raised at the meeting.

The safety coaches complete a Safety Committee training program provided by the training department, which includes the following:

Occupational Safety and Health Administration (OSHA) training
“Why You Are a Safety Coach”

Ergonomic Specialist: PGE employs an ergonomic specialist who oversees a number of training programs to enhance safety, including compliance training. The main goal of the specialist is to prevent injuries, and the specialist undertakes regular field visits to discuss safety with employees across PGE.

The ergonomic specialist also works with the safety coordinator to mitigate injuries. One example is an effort underway to prevent worker injuries when removing heavy manhole covers, a priority issue within PGE. Another example is a tool initiative being implemented across the company, using battery-operated tools to minimize injuries such as repetitive motion injuries from using hand tools.

The ergonomic specialist is involved in the workers’ compensation program and liaises with an external vendor to provide the MoveSmart program. MoveSmart shows employees how to move their bodies in ways that minimize strains and other injuries. PGE has implemented a one-day “Train the Trainer” course for the MoveSmart program.

Process

Safety Meetings

To maintain the focus on safety and its priority across the entire company, PGE holds regular meetings to address concerns and ensure implementation of programs across the company.

Weekly Safety Coaches Meeting: On Mondays, the safety coach organizes the weekly safety coaches meeting, which is open to all and includes members of all groups, including engineering and design. This helps engineers gather any concerns raised by line crews. The meeting agenda includes a review of the action register, running list of open action items, discussion of near misses, and round table discussions of safety-related topics.

Weekly Conference Call: Every Thursday, the company holds a weekly conference call that includes supervisors from the various line units, management, and safety coaches from across PGE. This wider conference call may include the senior management of the company and is intended to share information between regions. A rotating facilitator manages the call.

To ensure that information is shared across the company that important information is passed to the line crews, any issues raised during the weekly conference call are discussed during the local safety calls held every Monday morning. Action items from the Thursday conference calls are logged on the Action Register alongside the expected completion dates. During the Monday morning safety meeting, time is always allotted for reviewing these actions.

Safety Committee: The Safety Committee, which meets monthly to discuss safety across the region, includes all safety coaches, safety coordinators, and the regional management team. At this meeting, the Regional Safety Coordinator raises a particular topic of local interest for discussion in the weekly meetings.

On a quarterly basis, all regions (Eastern, Southern, Western) hold a larger quarterly safety meeting. A chairman oversees quarterly meetings and union representatives initiate them.

Weekly Meeting: Every Monday morning, PGE line crews hold a Monday morning safety meeting, which for lasts about an hour. The meeting begins with an update about events occurring in the city and a discussion covering whether any of these will affect scheduled work. The meeting also includes a list of issues and near misses encountered in the field and in the yard during the previous week, as reported by crews. The meeting always begins with a safety moment, in which an item from the safety manual, such as foot protection, is reviewed. The meeting also includes the Action Register Review with points discussed during the Thursday conference call. Meetings are never rushed and line workers are free to raise any issues. The meetings also discuss action plans from previous meetings.

For example, one meeting saw crews raise the issue of sewer gases in vaults. The foreman leading the discussion explained the procedure that crews should follow if they suspect that sewer gases are present in a manhole/vault. They were informed that they should not enter the vault and instead report it to the repair organization, which calls out a contractor to clean the vault. Workers should never expose themselves to any airborne pollutants.

Some other examples of issues discussed at meetings include the following:

Crews noted that a number of vaults had a new collector bus installed, but the spacing between the conductors was extremely tight. This could present a safety issue during future work. In order to mitigate the safety risk, crews installed insulation blankets over the secondary cable and posted notices in the vault stating that before any work is performed in the vault, the feeders should be de-energized.
One worker raised the issue of shared vaults with a neighboring utility, noting that there should be a better notification system to ensure that the other company does not perform switching or other tasks that could pose a hazard to workers ensconced in enclosures. Tailboards: At every job site before the work begins, the crew holds a tailboard meeting. A tailboard sheet informs and records the contents of this meeting. The dashboard displays the sheet, which all employees must sign to show that they understand it. Completed tailboard sheets are filed to maintain a record of the job discussion. The safety coordinator periodically reviews them. See Appendix C.

Safety Initiatives

Near Miss Program: PGE uses a formalized program in which a program called My Safety documents near miss situations online. All employees have access and the safety coach may assist in filling in details. Near miss incidents can be submitted anonymously.

Safety professionals across the system view any items entered into the My Safety program, and important topics are selected each week for discussion at the weekly meeting.

If a near miss incident did not violate the safety rules or result in a direct injury, there will be no disciplinary consequences. Where rules were violated or an injury or damage occurred, the supervisor pursues the matter, and consequences depend on the results of the supervisor’s investigation.

Safety Coordinator Crew Visits: One of the main roles of the safety coordinator is to conduct field visits, and each coordinator must log at least 200 crew visits every year. During a site visit, the coordinator looks for any safety violations. The coordinator records each visit, noting what was found, the date of the visit, the name of the foreman, the job address, and the crew number.

The CORE supervisor tries to make at least five crew visits per week and fills out a safety observation form. These forms are used across the company, so some of the items on the form are not applicable to CORE work. Relevant items include the following:

Vault entry
Traffic control
Personal protective equipment
A general comments section

Focus on Safety: PGE has a companywide focus on safety, including using numerous safety related key performance indicators (KPIs) to track performance for all supervisors. Overall, PGE’s safety performance is very good, and the corporate goal is to achieve zero injuries. In the past four years, PGE has cut the number of injuries annually from 160 to 80 across the company.

PGE believes that the main reasons for this improvement are the following:

Improving communication and discussions about safety
Convincing employees that it is possible to work without injuries by rigorously adhering to safety practices, not compromising safety to get the job done, and consistent management attention and support of safety
Focusing on training
Becoming more diligent with the stretching program to reduce the number of soft tissue injuries. This stretching program was a grass roots initiative in one of the PGE regions and resulted in a dramatic reduction in number of strains and sprains. It was adopted company-wide, with employees leading it.

Figure 1: PGE Stretch Program One poster

Within the CORE group, the biggest cause of injuries is lifting manhole covers. The overall incident rate fell by 38% between 2015 and 2016 for the Eastern Region.

Grassroots Safety: The grassroots safety programs in place at various PGE sites actively seek feedback from employees and rely on the experience of field workers to identify any safety issues, and work to rectify them. PGE believes that these grassroots programs can help workers completely eliminate hazards, improve practices, and assure compliance with regulations [1].

Tool Program: One company-wide initiative saw the standardization of the power tools used by crews, sourcing them from a single manufacturer and shifting away from hand tools to battery-operated units. In terms of safety, this ensures fewer repetitive injuries, reduced incidences of carpel tunnel syndrome, and better ergonomics.

Confined Space Entry: If a crew notices any evidence of sewer gases in manholes/vaults, it does not enter the space. Instead, it calls the repair organization, which arranges a contractor to clean the vault.

Personal Safety: PGE has a documented lead safety procedure that contains requirements for working with lead, including respiratory requirements. At present, PGE uses an onboarding process for employees, which includes taking a base level lead blood count. PGE has a periodic lead blood testing program and intends to place additional emphasis on lead working practices and lead testing.

PGE has also reviewed its mandatory drug and alcohol testing program. Previously, a drug test was mandatory when an employee injury occurred. However, this practice led to criticisms by employees who felt that the company cared more about drug compliance than occupational health. PGE redefined the procedure to reassure employees that properly addressing the health issues was the top priority.

Accident Response: During an accident, PGE procedures dictate that the crew should call the System Control Center (SCC) with the relevant information. In addition, either the crews or SCC contacts emergency services. The SCC completes an online form that is distributed to approximately 150 people automatically and calls out the safety coordinator responsible for the network. In addition, PGE has a Crisis Response Team that responds to situations of employee injury. Representatives of this team travel to the hospital with the injured employee and notify the family. Using this team removes the burden from the SCC. This protocol was implemented approximately 10 years ago.

Automatic Vehicle Location (AVL)systems are standard in PGE vehicles and help dispatchers monitor the location of crews, as well as match crew skills with the emergency [2].

Technology

My Safety Application: To record safety incidents, every employee has access to the web-based My Safety application, which includes basic identification information, dropdowns, and checkboxes to complete, as well as a comments section to elaborate on the incident/issue in question. Alternatively, a paper form that mirrors the application input form can be completed and passed on to an administrative person within the safety organization who will enter the details into the system.

Figure 2: My Safety" submission of a near miss screen shot

The My Safety application can be used to report safety incidents, near misses, and to provide recognition to a peer for good safety performance. The system is also used to record contractor-reported incidents/issues.

Portland General Electric 2015 Service Quality Measure Report. Portland General Electric, Portland, OR: 2015. http://edocs.puc.state.or.us/efdocs/HAQ/re61haq161241.pdf (accessed November 28, 2017).
R. Lewis II. “Mobile Tools Maximize Productivity at PGE.” Transmission and Distribution World, January 27, 2015. http://www.tdworld.com/features/mobile-tools-maximize-productivity-pge(accessed November 28, 2017).

8.13.15 - SCL - Seattle City Light

Safety

Organization

(Culture)

People

SCL Network crews do not feel pressure to sacrifice safety for productivity. They believe the network system is very safe. Network crews have high confidence in the system design, in the way the system is maintained, and in the way the network enclosures are constructed.

SCL’s approach to safety violations is non-punitive. Any punishment associated with safety is tied to breaking the work rules, not the accident itself.

Documentation

SCL’s safety manual is the Washington State Department of Labor and Industries Safety Standards for Electrical Workers, Chapter 296-45 WAV.

Training

Each year, every network employee attends 3.5-5 days of training that includes mandatory training such as confined space, manhole rescue, first aid, etc., as well as nonmandated training on pertinent topics.

SCL conducts various meetings to ensure a good flow of information relative to safety. Network employees attend:

Monthly safety meetings
Weekly crew chief meetings
Monthly “all network” meetings, where they bring everyone together to talk about training, safety, report out from conference findings, etc.
Bi-weekly Crew Coordination meetings, where safety issues related to specific jobs are discussed
Tailgates at the start of day, and after lunch each day

Process

Field Safety Coordinator Position

SCL has a program where they rotate a Cable Splicer into a Field Safety Coordinator position for a period of one to two years. This person is responsible for performing safety crew inspections and communicating safety issues.

Safety Accident Investigation

SCL has a process for convening a fact-finding investigation meeting after an accident within a certain time frame. These post-accident investigations sometimes result in work practice / process changes based on lessons learned from the investigation.

Visible Break Requirement

SCL requires a “visible break” as part of their clearance procedures. They contend that this requirement – being able to observe the visible break on the transformer primary switch through the site window, and also pulling the fuses when opening the network protector – has led to their strong safety record.

Safety Apparel

At the time of the EPRI immersion, SCL did not require flame-retardant clothing for its field workers.

Technology

Cable Testing and Grounding

In order to test that a cable is dead, SCL uses a Husky guillotine cutter with a ground for the purpose of spearing and grounding cable at the same time. They developed this tool, in partnership with Husky, because of concern with spearing their cable given the three-conductor cable they are using. The tool cuts and grounds the cable remotely after the crewman has left the vault.

Wrench with Captive Bolt Feature

SCL has developed a tool for keeping the nuts that are removed when removing network protector fuses captive. This eliminates the risk of a nut falling to the energized portion of the network protector.

8.13.16 - Survey Results

Survey Results

Safety

Organization

Survey Questions taken from 2018 survey results - safety survey

Question 7 : Do you have a “safety person”, (either a fulltime safety professional or other employee assigned to a safety role) focused on the network?

Question 8 : If you have a safety person focusing on the network, is the person a full time safety professional, or another employee assigned to a safety role?

Survey Questions taken from 2012 survey results - Safety

Question 8.1 : Do you have a “safety person”, (either a fulltime safety professional, or other employee assigned to a safety role) focused on the network?

Question 8.2 : If you have a safety person focusing on the network, is this person a full time safety professional, or another employee assigned to a safety role?

Survey Questions taken from 2009 survey results - Safety

Question 8.1 : How many days per year of safety training do your network field personnel receive per person?

Question 8.3 : Do you have a “safety person”, (either a fulltime safety professional, or other employee assigned to a safety role) focused on the network? (This question is 8.1 in the 2012 survey)

Question 8.4 : If you have a safety person focusing on the network, is this person a full time safety professional, or another employee assigned to a safety role? (This question is 8.2 in the 2012 survey)

8.14 - Personal Protective Equipment

8.14.1 - AEP - Ohio

Safety

Personal Protective Equipment

People

EPRI researchers observed strict and consistent adherence to the use of personal protective equipment (PPE) by AEP Ohio network resources. AEP network employees are required to wear a hardhat, safety glasses, and outer layer flame resistant (FR) clothing (level 2 standard). Reflective vests are required in traffic areas. AEP may differentiate PPE requirements based on task. For example, in 480-V vaults where potential arc energies are high, workers will supplement PPE with a higher rated outer garment to perform some activities.

Technology

AEP is very focused on safety for its network workers. The Network Engineering Supervisor seeks “engineered solutions” rather than “administrative solutions” wherever possible in order to add another level of safety, in case someone inadvertently forgets or omits an administrative step. This focus on engineered solutions is evident in AEP Ohio’s network unit standard, and in particular its selection of safety features associated with it network protectors.

Safety features associated with the protector include:

Dead front unit
“Stack light” annunciator system indicating protector status
Remote rackout feature
ARMS module – arc reduction system – ordered on all 480-V protectors.
For 480-V NPs, use external disconnects on top of the protector
External disconnect keys cannot be retrieved unless protector is opened to prevent attempting to disconnect the protector from the secondary under load.

8.14.2 - Ameren Missouri

Safety

Personal Protective Equipment

People

EPRI researchers observed strict and consistent adherence to the use of personal protective equipment by Ameren Missouri resources, including hard hat, safety glasses, FR rated clothing, and rubber goods protection when required.

Technology

Ameren Missouri requires flame resistant (FR rated) clothing for its employees in accordance with the IEEE standards. They have a documented protective apparel policy that defines the protective apparel requirements for employees of different classifications. In general, underground employees are required to wear Ameren Missouri approved FR apparel above the waist as their outermost garment. Below the waist, they require clothing that is either FR rated, or 100% natural fiber that is 11oz or more.

Ameren Missouri may differentiate the clothing required based on tasks. For example, a Traveling Operator will don a lab coat style 40 calorie flash suit when testing for potential on a test breaker or racking out a network protector.

Figure 1: Ameren Missouri Worker PPE

Figure 2: Ameren Missouri Worker PPE

Ameren Missouri is not requiring tethering or lifting harnesses for workers who enter vaults. This is, in part, due to the vault entrance design which includes a pull – out access and protection apparatus referred to as either the “safety basket” or the “cage”. The “cage does not provide room for the lifting apparatus to be set up over the vault mouth, and would prevent a worker from being lifted vertically out of the vault.

Figure 3: Work Area Protection – Manhole

Figure 4: Work Area Protection - Vault

Ameren Missouri uses a manhole rescue apparatus set up over manholes, and requires employees to wear harnesses and be tethered (rope tethers) to the lifting apparatus when working in manholes. If an employee has to move to an area in the manhole where he feels he is unsafe, he can disconnect from the tether - but in general employees stay tethered.

8.14.3 - CEI - The Illuminating Company

Safety

Personal Protective Equipment

People

At FirstEnergy, all layers of clothing must be FR rated (Flame Resistant), except underwear.

First Energy provides employees with a $250/ year per person clothing allowance. In addition, employees are provided an allowance for the purchase of safety shoes.

The level of protective equipment required and the vendors from which clothing is purchased are chosen by the Corporate Safety department.

The wearing of ear rings by Underground Electricians is prohibited.

Process

FirstEnergy is in the process of moving to a 12 cal^[1] clothing system for all line workers, including Underground Electricians. This change was driven, in part, by changing NEC and OSHA guidelines surround arc flash hazards and personal protective equipment.

All employees will be issued an FR T shirt and will be required to wear layers of FR clothing as required to meet the 12 cal requirement.

Face protection in addition to a hardhat and safety glasses (such as a face shield or balaclava) will be required in certain applications.

Technology

FirstEnergy is in the process of moving to a 12 cal clothing system for all line workers, including Underground Electricians.

^[1] Clothing system with an Arc Thermal Performance Value of 12 cal / cm²

8.14.4 - CenterPoint Energy

Safety

Personal Protective Equipment

People

CenterPoint resources noted that PPE infractions were the most often reported observations made by the HERO employee based safety program (See HERO Program ).

Process

In light of the changes on PPE required due to arc flash rule changes, CenterPoint recently changed its standard clothing level for underground workers from heavy cotton to an 8.7 FR shirt, worn on top of a T shirt.

Technology

CenterPoint’s standard PPE is comprised of a hard hat, safety glasses, long sleeve FR Level 2 shirt, cotton pants, shoes with puncture resistant soles (steel toes not required), and a traffic vest if working on the street.

CenterPoint does vary the PPE requirements, depending on the work type. For example, when working on 480V systems in the network, an FR jacket and face shield are required in addition to the standard PPE.

8.14.5 - Con Edison - Consolidated Edison

Safety

Personal Protective Equipment

People

Safety Culture

EPRI investigators noted a strong and visible focus on safety at Con Edison. In every facility that EPRI investigators visited, safety goals and performance reports were conspicuously posted. At every visited worksite, EPRI investigators noted safe work practices including traffic and pedestrian control, the use of personal protection, the wearing of safety harnesses by Con Edison’s workers, a lifting crane set up outside of the vaults, and continuous air quality monitoring.

8.14.6 - Duke Energy Florida

Safety

Personal Protective Equipment

People

Safety is a key area of focus for Duke Energy Florida. EPRI researchers noted visible attention to safety, including good work area protection and the use of personal protective equipment (PPE).

Duke Energy Florida network safety standards and equipment are supervised by the Lead Health and Safety Professional for the South Coastal Zone.

All Duke Energy Florida Electrician Apprentices and Network Specialists are certified in CPR, First Aid, and trained to reduce/prevent the risk of spreading blood borne pathogens.

The use of personal protective equipment is one of Duke Energy Florida’s “Keys to Life”, a practice which is essential to maintaining personal safety and is thus, non-negotiable. See Special Safety Programs - “Keys to Life”.

Process

All PPE is thoroughly inspected every six months at the DCC, and is inspected daily at all job sites. As a safety precaution, all employees at the job site are not allowed to wear jewelry.

Duke Energy Florida may differentiate PPE requirements based on task.

Duke Energy Florida believes that in order for employees to respond to an emergency quickly and effectively, they must have the necessary tools readily available. To that end, the company is in the process of consolidating field crew truck safety equipment. Unlike many operating companies, where First Aid and Automated External Defibrillator (AED) equipment are kept in separate bins, the company is standardizing on Safety Backpacks, containing both first aid kits and AEDs. Duke Energy Florida will complete the deployment of standardized backpack kits with AEDs and first aid supplies on all company vehicles this year.

Technology

All work crews are equipped with the following PPE:

Fire retardant (FR) clothing (8-12 Cal, 65 Cal for 480V spot networks)
FR high visibility safety vest
Harnesses
Steel toed boots
Rubber gloves
Leather work gloves
Safety glasses
Hard hats

Duke Energy Florida is implementing standardized backpack kits, containing both first aid kits and AED’s, to ensure that both the equipment and the training on the use of that equipment are uniform throughout the company. In addition, since the kits are standardized, field workers will know all what first aid supplies are available and be ready in the event of a medical emergency if they are working with different vehicles.

8.14.7 - Duke Energy Ohio

Safety

Personal Protective Equipment

Technology

Duke Energy Ohio requires flame resistant (FR rated) clothing for its employees. Duke does not differentiate the clothing required based on tasks.

Duke requires head protection, glasses, a sturdy work boot with a defined heel, FR rated shirt and pants, and vests for traffic control when applicable. At the time of the immersion, Duke was not yet requiring a jacket or a hood.

Duke does not require steel toed boots indicating that the weight of the equipment is such that the steel toe wouldn’t really protect the foot anyway and could potentially do more damage.

Duke Energy Ohio requires a 4.2 calorie FR clothing system with 100% natural fiber underneath. Duke provides an allowance to the employee for purchasing the clothing.

Duke recently implemented the wearing of harnesses by field employees when working in a submersible manhole or vault. At the time of the EPRI immersion, Duke Energy Ohio was not utilizing a lifting crane or tethering workers.

8.14.8 - Energex

Safety

Personal Protective Equipment

People

Energy Networks Australia (ENA), an organization that represents the interests of distribution utilities in Australia, and somewhat analogous to the role of EEI for U.S. utilities, has developed a guideline for PPE, which establishes minimum requirements, based on clothing system testing.

Process

At the time of the immersion, Energex was shifting from an all-cotton clothing requirement, to a fire resistant (FR) clothing requirement. Energex is conducting clothing tests on various clothing types to establish a final clothing system / system level. Energex anticipates a shift to all FR-rated clothing within the next 12 months.

8.14.9 - ESB Networks

Safety

Personal Protective Equipment

Technology

ESB Networks Issues personal protective equipment to all field technicians, including arc-protective jackets with a flash shield used for switching. Gear is regularly inspected for flaws, and replacement equipment is issued if needed.

8.14.10 - Georgia Power

Safety

Personal Protective Equipment

People

The use and specifications of PPE by Georgia Power follows strict OSHA rules and IEEE guidelines with additional specifications developed and implemented by Georgia Power’s Safety and Health group. EPRI researchers observed strict and consistent adherence to the use of personal protective equipment by Georgia Power personnel during its immersion visit to job sites, including hard hat, safety glasses, FR rated clothing (Level 2), and rubber goods protection when required.

Process

According to tasks, as detailed in the Section Zero book and through training, employees are expected to wear the appropriate gear for the job they are performing. For example, Cable Splicers must be in FR clothing, hard hat, eye and ear protection, steel toed boots with a defined heel, and rated gloves when appropriate.

Employees receive a three hundred dollar per-year safety clothing allowance for their basic FR pants, shirt, and coveralls. Management orders the coveralls with a company to make certain that standard clothing is used by all personnel. Any additional protective gear such as rubber or Kevlar gloves, face shields, switching smocks, etc. are provided by the company and stored on crew trucks.

Georgia Power has washers and dryers on the premises for employees to properly launder and inspect their equipment on a regular basis. Employees are expected to turn in worn or defective PPE and replace it. Georgia Power Safety Inspectors can search trucks and inspect PPE equipment; if defective PPE is found, the Safety Inspector will confiscate it.

Technology

Georgia Power has rubber goods exchange areas for recycling and replacing worn rubber goods. Uniform condition guides are prominently posted in work crew areas (See Figure 1 through Figure 3.).

Figure 1: Rubber goods exchange area

Figure 2: Rubber goods exchange area

Figure 3: Uniform condition guide

8.14.11 - HECO - The Hawaiian Electric Company

Safety

Personal Protective Equipment

People

HECO requires that employees wear FR (Flame Resistant) clothing, and is using an 8 Cal clothing system. HECO C&M underground employees wear HECO coveralls.

HECO also requires steel toed shoes, hard hats and safety glasses

HECO has recently implemented the use of face shields for UG C&M employees anytime they are grounding, switching, or working within five feet of energized equipment. Early issues associated with this change are increased difficulty in communications and fogging of the face shields.

Figure 1 and 2: HECO employees wearing face shields

Process

HECO provides an allowance to C&M field employees for the purchase of flame retardant clothing. Employees have access to an account through which they can order flame retardant clothing up to the allowance amount. Most of the Underground C&M employees observed by EPRI wear FR rated coveralls provided by HECO.

C&M Underground employees are responsible for washing their own FR clothing with the exception of the coveralls, which are washed by HECO through an arrangement with a cleaning service.

8.14.12 - National Grid

Safety

Personal Protective Equipment

People

EPRI researchers observed strict and consistent adherence to the use of personal protective equipment by National Grid resources.

Technology

National Grid required Personal Protective Equipment (PPE) includes a hardhat, ANSI safety glasses with side shields, steel toed EH-rated boots, outer layer FR protective wear with an Arc Thermal Protective Value rating of 8 cal per square centimeter (Level 2), and all natural-fiber clothing underneath. Reflective vests or outer garments are also required in traffic areas.

National Grid may differentiate the clothing required based on tasks. For example, a higher arc flash rated outer garment is required to perform switching in some applications.

National Grid has a hearing conservation program. Hearing protection is required for anybody working on an activity with suspected or measured noise exceeding safe levels, and warning signs are posted in high noise areas. If noise levels interfere with understanding normal conversational speech, hearing protection is required. Administrative and engineering controls to reduce noise exposure are being implemented where possible. Specific training for employees is also being offered.

National Grid uses continuous gas monitoring, with portable four gas detectors worn by employees.

National Grid workers wear lifting harnesses with tethers. A breakaway rescue lifting apparatus is set up at the manhole entrance.

Figure 1: PPE

Figure 2: Breakaway rescue lifting apparatus is setup at manhole entrance

Figure 3: National Grid workers wear lifting harnesses with tethers

8.14.13 - PG&E

Safety

Personal Protective Equipment

People

EPRI researchers observed strict and consistent adherence to the use of personal protective equipment by PG&E resources.

Technology

PG&E requires flame resistant (FR rated) clothing for its employees. PG&E may differentiate the clothing required based on tasks. For example, cable splicers will don a 100 calorie flash suit when racking out a 480 V network protector, or when operating a primary oil switch from inside the hole. (The normal process is to rig the switch handle and operate the oil switch from outside the hole.)

PG&E requires head protection, safety glasses, a sturdy work boot with a defined heel, FR rated shirt and pants, and vests for traffic control when applicable.

PG&E uses a level 2 clothing system. PG&E provides an allowance to employees for purchasing the clothing. The allowance differs by classification.

At the time of the EPRI immersion, PG&E was not utilizing a manhole rescue apparatus set up over the hole, such as lifting crane, or requiring employees to wear harnesses and to be tethered.

PG&E relies on the Fire Company to perform manhole rescue.

8.14.14 - SCL - Seattle City Light

Safety

Personal Protective Equipment

Technology

At the time of the EPRI immersion, SCL was not requiring Flame retardant (FR rated) clothing. SCL has since adopted a category 2 clothing system.

8.14.15 - References

EPRI Underground Distribution Systems Reference Book (Bronze Book)

Chapter Section 9.2.4: Arc Flash Protection

8.14.16 - Survey Results

Survey Results

Safety

Personal Protective Equipment

Survey Questions taken from 2018 survey results - safety survey

Question 13 : What clothing system level is required to work in the network (routine work)?

Question 14 : For 480V network protectors, does your company require crews to wear flash suits (i.e. higher than cat four PPE) or other incremental protection when they open or work in an energized NP?

Question 15 : Does your utility test the heat rating or arc flash rating of your tools and clothing?

Question 16 : Does your utility buy clothing or tools that are arc flash certified / heat certified?

Question 17 : What other types of work in the network, if any, require incremental PPE or other tools? Please describe.

Survey Questions taken from 2015 survey results - Safety

Question 126 : Do you require your network crews to wear flame retardant (FR rated) clothing?

Question 127 : If so, what clothing system level is required to work in the network (routine work)?

Survey Questions taken from 2012 survey results - Safety

Question 8.3 : Do you require your network crews to wear flame retardant (FR rated) clothing?

Question 8.4 : If so, what clothing system level is required to work in the network (routine work)?

Question 8.5 : Do you require incremental face protection, such as a face shield, or goggles and balaclava when working in the network?

Question 8.6 : For 480 V NP’s, does your company require NP crews to wear Flash Suits when they open an energized NP?

Question 8.7 : Is a first aid kit on hand when a crew is working in a vault?

Question 8.8 : Do your crews have an AED (Automated External Defibrillator

Question 8.11 : Please indicate which of the following design, operational or work procedure changes you have implemented to address network arc flash issues

Survey Questions taken from 2009 survey results - Safety

Question 8.5 : Do you require your network crews to wear flame retardant (FR rated) clothing? (This question is 8.3 in the 2012 survey)

Question 8.6 : If so, what clothing system level is required to work in the network (routine work)? (This question is 8.4 in the 2012 survey)

Question 8.7 : Do you require incremental face protection, such as a face shield, or goggles and balaclava when working in the network? (This question is 8.5 in the 2012 survey)

Question 8.8 : Is a first aid kit on hand when a crew is working in a vault? (This question is 8.7 in the 2012 survey)

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8.15 - Safety Communication

8.15.1 - Ameren Missouri

Safety

Safety Communication

( Safety Alert)

People

The Ameren Missouri Safety department prepares a document called a Safety Alert to communicate significant safety issues internally. Issues could be a review of a significant incident, with recommendations for change. Safety Alerts are often produced as a result of incident investigations to communicate findings and changes in procedures stemming from the investigation.

Technology

The Safety Alert is used to communicate significant safety issues, and is posted on the Safety Bulletin board. (See Attachment L for sample Safety Alert.)

8.15.2 - CEI - The Illuminating Company

Safety

Safety Communication

(Daily Safety Communication)

People

First Energy has implemented a safety process where by a summary of any significant safety issue that occurs across their system is reported and recorded to a company wide voice mail box. Each day, the recordings of these incidents are sent to all the Director level personnel across the company. The Directors are responsible for rolling this information to their managers and their teams, and to safety personnel. These individuals are responsible for rolling the information out to their teams.

Process

All operating areas are responsible to contact this message box and report any safety related issue that occurs. Incidents can range from accident summaries, to bee stings, to contractor incidents. Each day, the recordings of these incidents are sent to all the Director level personnel across the company. The Directors are responsible for rolling this information to their managers and their teams, and to safety personnel.

Technology

A standard voice mail box was established at First Energy for this purpose.

8.15.3 - Con Edison - Consolidated Edison

Safety

Safety Communication

Process

Morning Call

Con Edison conducts a “morning call” in each region, and in their System Operations group. The morning call is a telephone conference call where important operating issues are discussed. The morning call typically takes about ten minutes to complete.

The call includes a discussion of:

first contingencies; that is, situations where a piece of equipment is out of service and the system is operating in an N-1 condition,
activities and outages scheduled on primary feeders
secondary activity anticipated for the day
outages/incidents experienced on the systems
work reporting; that is, a review of the work scheduled for the day
shunts and bridges; that is, places where temporary cables are installed, usually above ground, bypassing a section of the distribution system
street light work scheduled for the day
environmental issues
feeder issues

The handout used during the call consists of:

Display of the Feeder Board, listing the primary feeders that are out of service
Display of the Critical Transmission and Substations Equipment Outage Status
Table of the current feeder outages, indication of the reason for the outages, anticipated duration, work to be performed, other pertinent comments, etc.
HIPOT Summary (high potential feeder test summary), listing feeders that were tested the previous day
Banks dropped
Customer Service – Distribution Equipment report, indicating the defective banks off the system, both customer and company owned
Lists of other systems statuses, such as Banks Made Auto, Banks on Outage, Open Mains Received, Open Mains Tied Permanent
Customer Outages
Shunts and Bridges Summary Report
Customer Outages
Outstanding Job Summary by Responsibility
Age Distribution Summary by Responsibility, showing the number of projects of different types, sorted by how long the job has taken (the age of the job)
Daily Open Mains summary Report
Summary of Primary C and D Faults
Daily Incident Report, highlighting safety incidents

8.15.4 - Duke Energy Florida

Safety

Safety Communication

(Safety Updates/Bulletins)

People

“Connection” is an electronic safety summary communication sent via email from the Duke VP of Operations. This universal, company-wide communication is distributed to all Supervisors on Friday so that employees receive the latest information at the same time. These summaries are reviewed Monday mornings in team meetings. Many Supervisors forward the communication to their team members in addition to conducting the briefing. The Connection communication includes summaries of recent events, including Incidents, Near Misses, “Good Catches” (problems averted due to timely intervention), and embedded links to important information.

See Attachment K for a sample of the connections bulletin – note the links to the other safety related documents. See Attachments L , M and N for samples of a Health and Safety Awareness Bulletin, a Safety Alert Incident summary and a Safety Alert “ Near Miss ” summary.

Process

“Connection” serves an important role in the company because it provides a single, consistent method of communication to all employees about safety at Duke Energy. This digest enables supervisors to go to one source to find information that is relevant to their operations that week, such as the conditions in specific manholes, duct lines, etc. “Connection” gives employees have a weekly “one-stop” overview of pertinent events on the system, with links attached to other documents with more detailed information. It prevents employees from having to access numerous systems to get the information.

As a part of its on-going commitment to Safety, Duke Energy Florida’s “Connections” also contains safety performance reports, including company key performance indicators such as the total incident case rate (TICR), and the preventable vehicle accident rate (PVA), both industry standard measures.

“Connection” allows users to click on specific event categories, such as Significant Injury or Fatality (SIF). Within this group, individual event details are visible through the system, such as type of injury, and the full injury report, including date, time, and cause. Good Catches and Near Misses are captured in the electronic PlantView system and communicated to all employees through “Connections.”

“Connection” includes information from throughout the Duke Energy operating companies, and crew supervisors can filter information that they believe could be of use to their own crew sites. Given Duke Energy’s large footprint throughout the United States, this allows different regions to share experiences throughout the company. For example, a Near Miss in Ohio due to unusual site conditions was recently reviewed by the Florida crews.

“Connection” also includes time-sensitive information, such as the deadline requirements to complete certain training courses. The communication includes links to course schedules and resources. After training is complete, the trainee’s supervisor signs a Record of Training (ROT), which are also stored online (see Safety Training).

Technology

Duke Energy Florida has an extensive electronic system for recording and reporting incidents, Near Misses, Good Catches and other events through its PlantView system. PlantView is a tool developed by EPRI that can be used to automate the entry, storage, management, and reporting of information in an integrated database that is accessible through web portals.

“Connections” is sent out to the field and its contents are reviewed weekly, during Monday briefings.

8.15.5 - Duke Energy Ohio

Safety

Safety Communication

People

Each morning, Duke Energy Ohio convenes a safety meeting. The content of the meeting varies from day to day but includes things such as: reading of minutes from safety meetings, reviewing safety bulletins that are produced by Corporate, review any changes in specifications, reviewing any Power Delivery (PD) letters (see below).

Each workgroup within the underground department has its own safety chairperson.

Process

At the time of the immersion, the morning safety meeting involved all the employees in that department. Dana Avenue management revealed that they are considering breaking the larger group into smaller meetings to talk more specifically about safety issues. If they implement this, they would start as one group to discuss department wide issues, and then break into smaller groups.

Technology

The PD Letter (Power Delivery Letter) is a bulletin used to communicate a safety issue, safety changes or work practices change. The content of a PD Letter can range from highlighting an issue with a particular piece of equipment, to providing work practice guidelines. See Attachment K for a sample PD Letter.

PD Letters can be read at the morning safety meeting. PD letters that are issued relative to information normally found in company manuals need to be incorporated into those manuals by whoever initiated the letter.

8.15.6 - Energex

Safety

Safety Communication

People

Energex has established a safety management system, which is a comprehensive framework that guides their safety approach, and addresses strategies for managing the hazards and risk associated with the design, construction, operation and maintenance of the system. Strategies such as the approach to safety training, incident investigation and response, and emergency preparedness and response, are guided by this framework.

Energex has recently reorganized their safety organization, consolidating a corporate safety group, a Service Delivery safety group, and a Power Plant Safety group to form one safety organization.

Process

In response to employee feedback requesting more information about safety incidents in their aftermath, Energex produces an incident summary. The incident summary is communicated back to employees through an incident learning document

(See Attachment B: Share Our Learnings sample )

Technology

Energex has an incident database, called the eSafe system, which houses summations of all safety incidents and near misses. Each day, before the field crews are dispatched to conduct the day’s work, the work leader performs a “safety catch-up,” which is a review of any previous day incidents identified through the eSafe system with the work crews. Employees sign a document, indicating that they participated in this meeting.

(See Attachment C: Daily Safety Catch-up for Field Services sample)

8.15.7 - Georgia Power

Safety

Safety Communication

( Safety Alert)

People

The Safety Advisor for the Network Underground group sends out a safety alert to all managers and supervisors throughout Georgia Power whenever an OSHA-recordable incident occurs. The alert includes a copy of the First Notification report which is prepared for all OSHA recordable accidents, preventable or non-preventable. The managers and supervisors use this report to inform their crews and raise awareness about the incident and how it can be prevented or avoided in the future.

Process

The First Notification report then entered into the Georgia Power electronic OSHA log. Hard copies of the form are also kept. (See Incident Investigation )

The Georgia Power risk management group and the company’s insurance carrier also receive copies of the First Notification report.

Technology

First Notification Reports are sent company-wide over the Georgia Power intranet to all managers and supervisors. Incidents are kept electronically in the company’s SHIPS computer program, and hard copies are also filed.

8.15.8 - National Grid

Safety

Safety Communication

(Utility Bulletin and Safety Briefing)

People

Utility Bulletin

National Grid utilizes a utility bulletin (also called a Distribution Engineering Service bulletin, or DES bulletin) to communicate significant issues internally, which pertain to safety, standards, or work methods. The bulletin itself is a brief write-up of the issue to be communicated.

Safety Briefing

National Grid’s Safety, Health, and Environment Department (SHE) distributes general weekly Safety Briefing newsletters. These Safety Briefings encompass a variety of topics, from general safety programs and initiatives to specific safety concerns and incident analyses. The editor for these briefings accepts weekly submissions for newsletter content from all employees..

Every Monday afternoon, National Grid sends out information for a Tuesday morning safety briefing conducted by supervisors. Tuesday morning safety briefings are held every week, and the content can include information published in the Safety Briefings provided by Safety, or a review of utility bulletins issued by Work Methods, Standards, Or Safety.

Process

Utility Bulletin

DES bulletins are used as a way to communicate information about new tools, methods or equipment to the field force, engineering, and supervision. DES bulletins are often issued as an interim step before the implementation of a formal change to a practice or standard at National Grid.

For example, the Standards Department may issue a bulletin that describes a change in material or in a construction standard in advance of those changes being published in the company’s Standards book or Material Specifications. For example, see Attachment F for a Bulletin issued by Standards describing the use of fire stop sealants at duct openings in manholes.

Similarly, the Work Methods group may issue a bulletin to describe a change in an electric operating procedure, or to introduce new or changed tools and equipment. (See Attachment G for a sample bulletin describing a new gas detector introduced at National Grid.)

Also, the safety group may issue a bulletin to reinforce a safety concept or to notify the field force of a safety concern with a particular tool, practice, or piece of equipment.

Bulletins may be reviewed as part of a pre shift tailboard meeting.

Safety Briefing

Safety Briefings contain information on a variety of topics related to health and safety, including:

Policies
Procedures
Regulations
Laws
Study findings
New initiatives
Best practices
Incident analyses
General health and well-being tips (e.g. stress reduction, safe driving)
General news items

A representative sampling of headlines from recent newsletters is presented here to give an idea of the general flavor of the newsletter.

Follow the Rules - Not Just for Compliance, But For Your Safety!

This article explains that safety rules are not arbitrary, but are designed based on previous injuries, and represent an opportunity to learn from the misfortunes of others. It then describes recent incidents that had the potential to be very serious but which only resulted in minor injury, and directly compares them to actual fatalities in similar circumstances from the OSHA fatality database, showing that had the circumstances been only slightly different, those seemingly minor incidents could have resulted in fatalities.

Vehicle Housekeeping

A description of vehicle housekeeping practices and how they may lead to unsafe working conditions is provided, including injuries from using improper tools because the proper ones can’t be found, tripping hazards, strain injuries from reaching around other objects because of general disorganization, and other scenarios. It then discusses general housekeeping rules that will keep the vehicle organized and safer.

Injury Reporting Basics

Here, the responsibilities of supervisors for reporting injuries and ensuring employees receive the correct medical attention are outlined. It includes procedures and phone numbers for reporting injuries to the appropriate Health and Safety management department.

Hearing Conservation Program

Some changes to a hearing conservation program are outlined, including employee responsibilities, noise monitoring methods, hearing studies, and general high noise environment regulations.

National Work Zone Awareness Week

A national campaign to promote awareness of motorist and worker safety issues in work zones along roadways is described, along with some events and media coverage meant to promote the campaign.

Personal Security Drill Findings

A drill was conducted to assess the response of a field worker, and appropriate supervisory staff, to a scenario involving a dangerous conflict with an upset customer. Results of the drill, with recommendations for staff, are presented.

Anti-Idling Laws

Laws in many states and local jurisdictions concerning vehicle idling are discussed. A discussion of the costs of engine idling across the fleet of vehicles, in terms of diesel and engine maintenance costs, is presented, along with a link to National Grid’s policy on idling.

Technology

Utility Bulletin

The Bulletin is used to communicate significant issues internally, including safety issues, operational issues or work practice changes

Safety Briefing

Submissions for the newsletter can be submitted to the editor via email. The newsletter is distributed in PDF format and may be printed for posting.

8.15.9 - PG&E

Safety

Safety Communication

(Utility Bulletin)

People

PG&E prepares a document called a Utility Bulletin to communicate significant issues internally. Issues could be operating issues, safety issues, the proper use of a tool, etc.

PG&E has a defined process for issuing a utility bulletin and requires a level of signature authorization.

Process

Utility bulletins are often issued as an interim step before the implementation of a formal change to a practice or standard at PG&E. Utility bulletins may be reviewed as part of a pre shift tailboard meeting.

As an example, EPRI observed the manager of networks reviewing with the M&C Electric Network night shift maintenance crews a particular utility bulletin describing procedures for manually operating a network protector, including steps for operating a protector that is “hung up” either remotely using a rope sling, or directly, wearing a 100 calorie flash suit. A key message of the bulletin was that when operating a protector using a rope sling, the protector lever must be activated in a quick and continuous motion to prevent arcing of the contacts, especially on the GE protectors.

Figure 1: Picture of network protector contacts with evidence of arcing. (From PG\&E NP repair shop)

Technology

The PD Utility Bulletin is used to communicate significant issues internally, including safety issues, operational issues or work practice changes (See Attachment M for sample utility bulletin.)

8.15.10 - Portland General Electric

Safety

Safety Communication

People

PGE utilizes safety updates and bulletins to communicate safety related information at all levels of the company. At the executive level, the Executive Safety Council (ESC) regularly meets with employee groups to listen to safety concerns and share information about PGE safety initiatives [1].

Figure 1: Safety notices prominently displayed

Safety coaches provide the main link between management and field workers. Safety coaches discuss concerns with management and the safety team, and act as a point of contact for field workers wishing to discuss issues. They regularly discuss issues among themselves and determine what actions are needed. The CORE group has one safety coach, a volunteer position taken by a journeyman on a 2-3 year cycle. Safety coaches also talk to crews before the monthly meetings to determine what issues should be shared.

Process

PGE has produced a number of laminated safe work practices sheets and notes for certain tasks. At present, they only apply to overhead work rather than CORE underground practices. Overall, the company is in the process of documenting work practices to memorialize knowledge that has historically been passed only verbally (“tribal knowledge”).

The way in which PGE delivers safety updates and bulletins is through the various weekly and monthly meetings held across the company. In addition, job-related safety information and updates are reviewed during jobsite tailboard meetings.

Technology

My Safety Application: On the My Safety Application used by crews to log incidents, users can view a summary of safety incidents grouped by location, as well as summaries of safety performance.

Portland General Electric 2015 Service Quality Measure Report. Portland General Electric, Portland, OR: 2015. http://edocs.puc.state.or.us/efdocs/HAQ/re61haq161241.pdf (accessed November 28, 2017).

8.15.11 - Survey Results

Survey Results

Safety

Safety Communication

Survey Questions taken from 2009 survey results - Safety

Question 8.2 : Please indicate the type(s) of safety meetings you conduct. Check all that apply.

8.16 - Safety Meetings

8.16.1 - AEP - Ohio

Safety

Safety Meetings

People

AEP utilizes various committees/teams at all levels of the organization to coordinate safety activities. At the overall company level, AEP coordinates safety through its Safety Committee, comprised of representatives from throughout its operating companies.

AEP also utilizes committees at the individual operating company level. AEP Ohio conducts monthly state-wide safety meetings (Ohio Safety Council), as well as district specific meetings, such as meeting of the Columbus Safety Council. The underground network organization has representation on both the State and District (Columbus) safety councils. These councils respond to safety issues brought forth by representatives. Issues may also be directed towards the safety department.

At AEP Ohio, safety initiatives are coordinated and implemented by safety department representatives. One safety department rep has responsibility for the network organization (among others). Network Crew Supervisors perform daily morning safety briefings. Information from the safety councils is normally disseminated to the workforce through the daily morning safety briefings. Network Mechanic crew leaders are responsible for performing onsite (tailboard) safety briefings. These meetings are documented, with crew members required to sign the form.

An AEP Ohio Safety Department Representative performs periodic onsite safety inspections. In addition, Network Crew Supervisors perform periodic onsite safety inspections, with the required number varying from year to year (typically about 15 inspections per year).

Process

The safety council meetings (both the State and District Safety Councils) are focused on safety issues, including new technology, equipment, procedures, and safety recommendations. The meetings provide a forum for addressing safety issues. These councils are comprised of representatives from various functional groups including the underground network group. These councils will, for example, discuss and seek resolution to safety concerns associated with both tools and processes, with the District Council addressing more local issues specific to Columbus.

Network Crew Supervisors use the daily morning safety meeting to report out from both the District Safety Council and the State Safety Council. Each morning meeting is led by one of the Network Crew supervisors, with the responsibility for leading the meeting rotated among the crew leaders.

Technology

Safety checklists are used to document conditions as well as the performance of a safety discussion at job sites. These checklists can be filled out using a smartphone application (app).

Safety information is recorded and available online for the entire company. Forms, guidelines, and safety best practices documents are available online for all company employees, including the AEP Safety Manual.

8.16.2 - Ameren Missouri

Safety

Safety Meetings

People

Ameren Missouri holds various safety meetings, ranging from job site tailboard meetings to large company safety meetings. Meetings can be led by a crew foreman, supervisor, manager or safety professional, depending on the type of meeting.

In addition, Ameren Missouri has implemented the practice of kicking off all company meetings with a brief safety message delivered by the meeting host. The meeting host will select a topic of interest for the group and share information on that topic. The topic does not necessarily have to be related to the meeting purpose, but rather a topic that would be of interest and generally apply to the meeting participants.

Process

Ameren Missouri holds various safety meetings, including:

Job site tail board meetings
Morning “5 minute” briefings
Monthly safety meeting
Quarterly Safety meetings
Tool committee meetings
Safety committee meetings
Safety Culture Team meetings

Job Site Tail Board Meetings

Ameren Missouri crew leaders perform job briefings (tailboards) at the beginning of each work day or new job. An element of the job briefings is a requirement to regroup and re-brief when the work environment changes.

Ameren Missouri records the job briefing on a Job Briefing Sheet, including the employees who participated in the briefing.

Morning “5 minute” briefings

Ameren Missouri conducts a daily morning safety meeting (also called a “5 minute briefing”). This meeting is led by a supervisor who prepares a safety related topic. The morning meeting includes time for employee warm-up and stretching exercises. Once a week, Ameren Missouri invites a physical therapist to lead the morning stretching exercises and provide council to employees.

Monthly Safety Meeting

Ameren Missouri conducts monthly safety meetings within each department. For example, the Underground Construction group and Service Test group each convene a monthly safety meeting, with all members of the department represented. A safety professional may or may not be present.

A meeting summary is posted on the Safety bulletin board.

Note than in the Service Test department, union employees also meet quarterly to discuss safety issues. This meeting is evidence of a cultural transition at Ameren Missouri, with individuals taking accountability for their safety.

Quarterly Safety Meetings

Ameren Missouri conducts quarterly safety meetings with all employees. These meetings are administered by Ameren Missouri safety professionals.

Tool Committee

The Ameren Missouri underground group has formed a tool committee comprised of one supervisor, and three field representatives to discuss issues and develop recommendations for worker tools. The Blue Hat representative also participates on this committee.

The tool committee meets monthly. A meeting summary is posted on the Safety bulletin board.

Safety Committee

The Ameren Missouri Underground Construction group has formed a safety committee led by a supervisor and comprised of in house people, including a safety professional from Ameren Missouri’s safety group. This committee discusses departmental safety issues and makes recommendations for change locally. Information from this committee is distributed via the monthly safety meetings, or daily morning 5 minute meetings.

The safety committee meets monthly. A meeting summary is posted on the Safety bulletin board.

Safety Culture Team

Ameren Missouri has formed a Safety Culture Team to focus on understanding cultural barriers to improving safety locally, and to make recommendations for changes to build trust and positively influence the company culture. The committee is comprised of managers and supervisors, including the UG Construction manager. A safety professional is also part of this team.

The safety culture team meets monthly. A meeting summary is posted on the Safety bulletin board.

(Tailboard Meetings)

People

Ameren Missouri crew leaders perform job briefings (tailboards) at the beginning of each work day or new job.

Process

At Ameren Missouri, there are six elements to a job briefing. They include a review of:

hazards of the job
safe procedures and practices
discussions of any special precautions
identification of energy sources
discussion of clearances (called work practices authorization or WPA Ameren Missouri)
personal protective equipment

An element of the job briefings is a requirement to regroup and re-brief when the work environment changes.

Technology

Ameren Missouri records the job briefing on a Job Briefing sheet, which includes the employees who participated in the briefing. For example, in the Distribution Service Test department, the record of the job briefing is part of the time reporting process, with employees required to record both the start of day job briefing, and any subsequent briefing required as field conditions may change. This includes a recording of the elements of the briefing that include the following, known by the acronym “PAUSE”: PPE, Awareness of hazards, Unusual or special precautions, Safe work rules, and Energy source control.

8.16.3 - CEI - The Illuminating Company

Safety

Safety Meetings

(Daily Safety “Stand Up” Meeting)

People

All personnel in the Underground department participate in the daily safety “Stand Up” meeting. The meeting is led by the Underground Department Manager and his supervisory team and involves all department employees. Company safety personnel may or may not be present.

Process

Every workday begins with brief safety meeting led by the Underground Department Manager, and involving the entire department. This meeting is referred to as the daily safety stand up meeting. The content of the meeting varies and is based on areas of need or relevance. For example, with icy weather conditions, a focus might be on slips, falls and other hazards associated with this weather. The meeting would also cover safety issues associated with specific projects being worked on, or on specific incidents that may have occurred in other parts of the company (Available through the Daily Safety Communication). The meeting also provides an opportunity for employees to voice any safety related concerns they may have.

This process has been highly effective in maintaining a focus on safety and giving employees a forum to voice both safety related and non safety related concerns.

CEI has other safety meetings in place to maintain a focus on safety, including the following:

Monthly Safety Standdown meeting
Monthly supervisor safety meeting
Quarterly corporate meeting with union representation

Technology

The daily safety “Stand Up” meeting is primarily a discussion, although visual aids, such as Power Point presentations may be used.

8.16.4 - CenterPoint Energy

Safety

Safety Meetings

People

Daily Safety Tailboard Meeting

CenterPoint Crew Leaders conduct a daily safety tailboard with their crews where safety issues associated with the days work are discussed.

Also, CenterPoint requires that Major Underground crews conduct a jobsite tailboard meeting at every job location. This meeting is conducted by either a Crew Leader or the crew chief.

Monthly Safety Meeting

Monthly, CenterPoint conducts a series one hour safety meeting with all Major Underground employees. Each Major Underground manager prepares and hosts his own meeting, typically held at the start of the shift.

Over the past five years, CenterPoint has overtly moved the responsibility for these meetings from the Safety department to the Major Underground department managers themselves.

Bi-Monthly Safety Council Meeting

Every other month, CenterPoint holds a meeting comprised of the department director, managers and crew leaders (all supervision) of the Major Underground department, called the Safety Council Meeting. The purpose of this meeting is to discuss pressing safety issues, review safety trends identified through observations and other inputs, and develop strategies for improving department safety.

Safety Action Committee

Monthly, CenterPoint conducts a meeting of the Safety Action Committee, hosted by a Major Underground Crew Leader who is assigned to a safety role. This is the same Crew Leader who liaises with the HERO team as a representative of Major Underground. Each Major Underground Crew Leader has a group representative (crew member) who attends the meeting.

CenterPoint schedules this meeting monthly, usually back to back with the monthly Safety meeting.

Process

Daily Safety Tailboard Meeting

The jobsite tailboard meetings include a discussion of the safety issues associated with each project. Information about the job discussed at the jobsite tailboard meeting, such as atmospheric testing or water issues, is recorded on a tailboard conference sheet See Attachment N . Every member of the crew signs the conference sheet. The results of the conference are kept on the truck dash so that they are accessible during the project.

Figure 1: Tailboard Conference Sheet

Information from the tailboard is filed and saved for a period of three years.

Monthly Safety Meeting

In advance of the meetings, the Major Underground management team meets to determine the topics to be presented and the approach for the meeting. Managers will often invite people from their departments to present topics as this can add more credibility to the information being presented.

CenterPoint safety professionals will sometimes participate in this meeting, particularly if there is a specific company wide message or program to disseminate.

Safety Action Committee

The purpose of the meeting is to bring safety issues to the group for discussion and resolution. Issues can be associated with any aspect of the work, including materials, engineering, work practices, tools, etc. The meeting format is a round table, with each person given an opportunity to contribute. Management guests are sometimes invited.

8.16.5 - Con Edison - Consolidated Edison

Safety

Safety Meetings

Process

Safety Meetings

A job briefing is held each morning for every crew led by either a supervisor or lead mechanic.

Con Edison supervisors perform daily safety inspections, inputting the information on a four-page form. See Attachment J. The results of this form are entered into a computer system.

Con Edison also holds a larger safety meeting monthly with all field employees. Safety discussions are incorporated into other meetings as well, such as the underground network equipment standards committee meetings.

Con Edison gives safety performance high visibility. Safety performance reports are conspicuously posted in the utility’s buildings.

8.16.6 - Duke Energy Florida

Safety

Safety Meetings

People

Duke Energy Florida holds various safety meetings, ranging from job site tailboard meetings to large company safety meetings. Meetings can be led by a crew foreman, supervisor, manager or safety professional, depending on the type of meeting.

One Lead Health and Safety Professional is responsible for the Clearwater and St. Petersburg network system safety standards and oversight. This person is responsible to develop and implement strategies to influence safety in the South Coastal Region, including the safety of the network underground organization.

Each Operating Center in Duke Energy Florida has formed a local safety committee, comprised of representatives from each work group, and led by an employee designated as the operating center safety chairperson. As Clearwater and St. Petersburg are part of separate operating centers, network employees may be represented on either local safety committee. Participation is voluntary, and there is no forced rotation of members on the committee. The local safety committees hold monthly safety meetings. The local ops center chairperson and committee report (via a dotted line) to the Lead Health and Safety Professional.

Duke Energy Florida has implemented the practice of kicking off all company meetings with a brief safety message delivered by the meeting host. The meeting host will select a topic of interest for the group and share information on that topic. The topic does not necessarily have to be related to the meeting purpose, but rather a topic that would be of interest and generally apply to the meeting participants. In addition, at meeting starts, Duke Energy Florida’s practices is to assign responsibility for safety related duties in the event of an emergency, such as calling 911, or retrieving the AED. A practice of note is the “30 for 30,” a practice where every thirty minutes, participants of a meeting stand and stretch for 30 seconds. The meeting discussion does not cease, but continues as participants engage in this stretch. A timekeeper is assigned at the start of the meeting to remind participants to stretch at 30 minute intervals.

Process

Duke Energy Florida holds various safety meetings, including:

Job site tailboard meetings
“Take 10” Meetings
Weekly Meetings
Monthly safety meeting
Zone Safety Committee Meeting

Job Site Tailboard Meetings

Duke Energy Florida crew leaders perform thorough job site briefings (tailboards) at the beginning of each work day or new job. Every time a job site tailboard is conducted, topics are checked discussed are checked off and notes are recorded on a Tailboard Sheet. Elements of the tailboard session include:

Identification of the crew leader for the tailboard and job
Job location and address are reviewed
Crew qualifications and familiarity with tools are confirmed
Plans for hydration breaks
Work plans and safety procedures are reviewed (including manhole entry procedures)
Workers sign the tailboard sheet documenting their participation

At the end of the day (or project), the crew leader does full inspection around the job site to make sure conditions were restored to normal, that no tools were left behind, and that all equipment/cables are in a safe configuration with proper tagging if work was not completed. In addition, a post job tailboard meeting is held with the crew to make sure all switching is complete, grounds removed, and clearance tags have been removed. During the post job tailboard, lessons learned are discussed and the crew discusses the safest route to exit while addressing any obstructions or stationary objects that might impede a safe exit.

“Take 10” Meetings

Network crew supervisors lead a “Take 10” briefing every morning for each of their crews. The “Take 10” meeting was initially instituted as a pre – work day tailboard sessions, as practiced at many utilities, where the job plan is discussed by the team and supervisors review site and job-specific safety issues. Over the years, the discussion has evolved to include communication of periodic safety information/messages to augment the job preplanning prior to leaving for the job site.

Weekly Meetings

Weekly, department supervisors, including the Network Group supervisor, conducts a brief safety meeting to review the contents of a company issued safety communication packet entitled “The Connection”. This company safety communication packet is issued to all supervisors on Friday afternoon, so that they can prepare to communicate information relevant to their department during Monday morning meetings. “Connection” is a safety packet prepared for Delivery Operations, Transmission Grid Solutions, Gas Operations and Customer Operations, and issued by the Vice President of Distribution Maintenance and Construction with input from all departments. Included in the packet are event reports, near misses, and good catches. A sample weekly connections summary is attached to this report in Attachment K. “Connection” ensures a single source is providing a unified and consistent message broadcast to all company employees.

Monthly Safety Meeting

On a monthly basis, Duke Energy Florida will conduct a monthly safety meeting within each operating center within the South Coastal Zone. Each Operating Center holds the meeting on a selected Wednesday within the month, so no two operations centers hold meetings at the same time. All employees, including the network Group, attend this meeting unless unavailable because of an outage or emergency. While the Safety and Health professional normally participates in these meetings, their presence is not mandatory, as these meetings led by the local safety committee, comprised of representation from each work group and led by an employee designated as safety chairperson. The content for the meeting includes corporate safety and training content, as well as content developed by the local safety committee.

In turn, each Operating Center Safety Chairperson and co-Chair attend a monthly Zone Safety Meeting. This separate monthly meeting includes all the safety chairs from the operating centers that comprise a Zone.

Zone Safety Committee Meeting

Quarterly, Duke Energy Florida holds Zone Safety Committee Meetings for all of Florida. Each division in Duke Energy Florida will appoint a lead, chair, and co-chair to attend the Zone Safety Committee Meeting. At this meeting, safety topics are developed to be reviewed at the next Monthly Safety Meeting with all employees. The Safety and Health professional normally leads the discussion of the topics developed at the Zone Safety Committee meeting at the next Monthly Safety Meeting.

Technology

The “Connections” safety communications is distributed electronically to the supervisors as one summary document with links to other documents that include safety related topics. This includes safety topics, and includes a review of safety events that may have occurred. The department supervisor will cull through the available data and look for information that is relevant for his team.

This review may also include a review of “Near Misses” and “Good Catches.” “Good Catches” are situations were an employee noticed a potential safety hazard before an event occurred. For instance, an employee proactively reporting cracked and raised cement on a walkway that poses a trip hazard before anyone trips is an example of a “Good Catch”. A “Near Miss” is an event where a safety hazard occurred, but no one was hurt. For example, an employee accidently dropping a tool into an area that creates a flash with no one getting injured is an example of a “Near Miss.”

8.16.7 - Duke Energy Ohio

Safety

Safety Meetings

People

Morning Safety Meeting

Each morning, Duke Energy Ohio convenes a safety meeting. The content of the meeting varies from day to day but includes things such as: reading of minutes from safety meetings, reviewing safety bulletins that are produced by corporate EH and S, review any changes in specifications; reviewing any PD letters (see Technology below).

Each work-group within the underground department has their own safety chairperson.

Monthly Safety Committee Meeting

Duke Energy Ohio holds a monthly safety committee meeting. This meeting consists of resources from the entire region, including Dana Avenue and other districts.

Dana Avenue has two representatives to the monthly committee - one from management, and one from the union. The union representative to the meeting is a volunteer. Duke tries to rotate the involvement of the union, giving a person two or three times to attend.

Safety Week

Safety week is a week where Duke Energy sets aside time to focus on safety related topics.

Tailboard Meetings

Every crew is responsible for performing a jobsite safety tailboard.

These meetings are used to discuss issues with the jobs, point out potential safety hazards, review operating protocol and clearances, etc.

Process

Morning Safety Meeting

At the time of the immersion at Duke, the morning safety meeting involved all the employees in that department. Dana Avenue management revealed that they are considering breaking the larger group into smaller meetings to talk more specifically about safety issues. If they implement this, they would start as one group to discuss department wide issues, and then break into smaller groups.

Monthly Safety Committee Meeting

The purpose of the meeting is to discuss safety issues relative to the Region. An example of a topic discussed at this meeting is the challenge that Duke Energy Ohio experienced when they moved to dead front switchgear (elbows) as a standard. For this issue they developed a training session on operating dead front switch gear, and participated in the delivery of the training to the districts in the new equipment.

Safety Week

Safety week is a week where Duke Energy sets aside time to focus on safety related topics. The content covered can be any safety related topic, such as dog bites, sun exposure awareness, and safety demonstrations.

Often, during this week, Duke Energy management will hold special events, such as a cookout, to bring employees together to focus on safety.

Tailboard Meetings

Tailboard meetings are used to discuss issues with the jobs, point out potential safety hazards, review operating protocol and clearances, etc.

Duke Energy Ohio has recently implemented documentation of tailboard meetings.

Technology

Morning Safety Meeting

The PD letter (Power Delivery Letter) is a bulletin used to communicate a safety issue, safety changes or work practices change. The content of a PD letter can range from highlighting an issue with a particular piece of equipment, to providing work practice guidelines. See Attachment K for a sample PD Letter.

PD Letters can be read at the morning safety meeting. PD letters that are issued relative to information normally found in company manuals need to be incorporated into those manuals by whomever initiated the letter.

8.16.8 - Energex

Safety

Safety Meetings

People

Energex Crew leaders perform a job site risk assessment, called a “tool box talk” (see Figure 1). This is a documented safety meeting, with a form that is signed by all crew members and job site visitors who receive the briefing. Any visitors who arrive at the site must participate in a safety briefing as well. The performance of the job site tool box talk is a legislative requirement in Queensland.

Process

The briefing reviews the scope of the job and illuminates hazards specific to the job. The form used in the past was multiple pages and involved many check boxes. Energex worked with employees to produce a streamlined form that is used to document the safety meeting, to simplify its use, and to encourage discussion of job site safety hazards.

Figure 1: Energex crew leader conducting a tool box talk (job site safety briefing)

8.16.9 - ESB Networks

Safety

Safety Meetings

(Tailboard Meetings)

People

ESB Networks maintains a Chief Executive Safety Committee that oversees and thoroughly documents safety procedures and practices. Representatives from throughout the company rotate onto the committee to get a more complete overview of current and evolving safety practices. A group of 30 people representing 178 teams across ESB Networks attend the committee meetings with an emphasis on improving safety procedures in any way possible.

Process

ESB Networks holds regular monthly meetings for all personnel, and safety issues are one of the key topics of discussion and review. ESB Networks believes in a positive re-enforcement of safety behavior (see “Safety – Culture ” in this report.)

In addition, ESB Networks has periodic safety forums with its contractors to address issues of safety, and it encourages the various contractor companies to cooperatively work on improving safety procedures. ESB Networks was able to obtain common learning across all contractors and to identify best practices. If a contractor or ESB Networks personnel are found to be operating unsafely, inspectors and/or supervisors have the authority to stop work on a project until corrective measures are made.

Tailboard Meetings

People

Job site meetings are mandatory for all personnel before a project begins, whether it is a minor repair or major commissioning of service, etc. The meeting is led by the field supervisor.

Process

ESB Networks has a specific job site safety plan (JSSP) which is a risk assessment of the job site. The plan is reviewed by all crew members prior to work. Each crew member then signs the job site safety plan. ESB Networks feels this has had a significant impact on reducing incidents.

Related to the job site safety plan, ESB Networks has implemented “climb safe” procedures, which entail performing specific pre climbing tests, such as tapping poles to identify rot, and proper fall and catch techniques.

ESB Networks believes that the implementation of these two pre job techniques has resulted in a significant reduction in incidents. (ESB Networks has seen a dramatic reduction in safety incidents in recent years with their increased focus on safety.

Technology

Monthly job site safety briefing reports are entered into the ESB Networks internal system each month.

8.16.10 - Georgia Power

Safety

Safety Meetings

People

The Network Underground group has a dedicated Health and Safety Advisor assigned to them, who functionally reports to the Health and Safety department at Georgia Power. The Advisor meets regularly with the larger Georgia Power Safety and Health group.

In all, the Safety and Health Advisor is responsible for the training and safety management of approximately 180 people within the organization. The Safety and Health Advisor works closely with the Network UG Manager on safety and health issues related to the operation and maintenance of the network underground system throughout Georgia.

The person presently assigned to the position of advisor for the Network UG group came up from the ranks of the underground organization, serving as a Cable Splice, so he is familiar with the unique needs and requirements for safely working in a network. The Advisor shadowed safety personnel to gain on the job training, and eventually co-chaired and chaired the safety committee while he was a Cable Splicer crew leader.

Process

The Network UG group holds several different types of safety meetings including weekly safety meetings within each work group, monthly meetings of the Network UG Safety committee, and quarterly meetings of the entire department.

The Network UG safety committee is comprised of volunteer representatives from Engineering, Maintenance, Cable Construction, Duct Line Construction, and Operations and Reliability. The committee meets once a month, and is focused on improving safety and work practices and providing a forum for employees to have input. Work of the committee includes developing topics and programs for monthly departmental safety meetings, developing and approving revisions to the Network Underground Safety and Work Procedures manual, informal review of accidents, both medical and vehicular, and a review of all safety concerns brought forth by employees to their safety representatives.

The entire Network Underground group of Georgia Power convenes quarterly for a safety meeting led by Safety and Health advisor. The group often invites guest speakers to these meetings who are experts on specific network underground safety issues.

Employees also attend yearly safety training, including compliance training such as enclosed space training, trenching, and CPR. In addition, Network UG employees receive annual training on using a bucket truck, as UG resources are called upon to work as service repair crews during storms. Note that Georgia Power has built a small overhead training yard at the Network UG location to accommodate this training.

8.16.11 - HECO - The Hawaiian Electric Company

Safety

Safety Meetings

People

All personnel in the C&M Underground group participate in a daily morning Safety / Tailboard meeting. The meeting is led by the C&M Underground supervisors and involves all department employees. Company safety personnel and Engineering department personnel may or may not be present.

Process

The meeting is held each morning after the morning stretch / walkabout to discuss the days work, safety issues, as well as Company and department business. Typically the meeting will begin with general safety Company and department issues that involve everyone. The meeting will then break into smaller tailboard discussions of the days work.

EPRI observed very open lines of communication between employees at these meetings. The meetings have a “family feel”, with workers readily voicing issues and concerns, and individuals showing respect for each other’s opinions. EPRI further noted a strong working relationship between the UG group and the Engineering staff that were present at these meetings.

Technology

The meeting is primarily a discussion, although visual aids, such as job sketches or tools demonstrations may be used.

8.16.12 - National Grid

Safety

Safety Meetings

People

National Grid holds various safety meetings, ranging from job site tailboard meetings to large company safety meetings. .

Meetings can be led by a crew foreman, supervisor, manager or safety professional depending on the type of meeting,

National Grid’s Safety, Health, and Environment Department (SHE) distributes general weekly Safety Briefing newsletters. These Safety Briefings encompass a variety of topics, from general safety programs and initiatives to specific safety concerns and incident analyses. The editor for these briefings accepts weekly submissions for newsletter content from all employees..

National Grid has a certified safety professional who acts as the point contact for general health and safety issues that arise.

Process

National Grid holds various safety meetings, ranging from job site tailboard meetings to large company safety meetings. Examples of safety meetings include:

Division Safety Meeting
- This meeting, run by the Manager – UG Lines East, includes both union and management personnel, and a safety professional.
Mid-Level Safety Meeting
- This meeting includes the Manager – UG Lines East and his counterparts across the system (other UG management), and includes management and union representatives, and Work Methods.
EO Safety Committee
- This is a month safety meeting comprised of vice presidents, who establish safety strategies for the company,
Tuesday Morning Safety Briefing
- The entire underground electric group meets each Tuesday morning to review issues associated with safety. The content for these meetings is often based on published Safety Briefings provided by the Safety Department (See Safety Communication: Safety Briefing), and distributed every Monday afternoon. The content of these meetings can also include a review of utility bulletins issued by Work Methods, Standards, Or Safety (See Safety Communication: Utility Bulletin). These meetings are run by department supervisors.

Technology

Submissions for the newsletter can be submitted to the editor via email. The newsletter is distributed in PDF format and may be printed for posting.

8.16.13 - PG&E

Safety

Safety Meetings

People

PG&E holds various safety meetings, ranging from job site tailboard meetings (see below) to large company safety meetings. In general, PG&E uses a grass roots approach to safety, involving employees in discussion of safety issues and establishment of safety practices.

Meetings can be led by a crew foreman, supervisor, manager or safety professional (Safety Coordinator), depending on the type of meeting,

The Safety Coordinator is a Safety Health and Claims Department employee responsible for implementation of the company’s safety programs, and is a point contact for general health and safety issues that arise.

Process

PG&E holds various safety meetings, ranging from job site tailboard meetings to large company safety meetings. Examples of safety meetings include:

Monthly Safety Meeting

The safety coordinator convenes a monthly safety meeting with representatives from the M&C Electric Network group. The meeting objective is to develop a “grass roots” safety approach specific to needs of the M&C Electric Network Group. The safety coordinator acts as a facilitator, and meeting attendees include the Superintendent, VP of the M&C Electric Network group, and a front line supervisor who is designated a safety “coach”.

Monthly Crew Foreman / Supervisors Meeting

The Superintendent, VP of the M&C Electric Networks holds a monthly crew foreman / supervisors meeting that includes a specific focus on any safety related issues.

Weekly Safety Meeting (also referred to as a Standup Meeting)

The Supervisors conduct a weekly meeting with the field force to discuss and resolve issues facing the group. Safety is a central focus, although the meeting is used to discuss issues of any type.

Bi-Monthly Regional Phone Conference

PG&E holds a bi monthly conference call that includes a discussion of key safety related issues.

Tailboard Meetings

Prior to each shift, the distribution supervisors conduct a pre-shift tail board meeting with the field crews. The meeting is conducted in the cable splicer day room, known as the “bull room”. The content of the tail board meeting varies from meeting to meeting, addressing safety concerns specific to the projects scheduled for that shift and including a reading from the safety manual. This meeting is also used to review any pertinent utility bulletins (see Utility Bulletin).

The pre-shift tailboard meeting also includes stretching by field crews, including a brief upper body stretch of the arms, elbows and shoulders.

In addition, each crew leader is responsible for performing a jobsite safety tailboard meeting. These meetings are used to discuss specific issues with the jobs, point out potential safety hazards, review operating protocol and clearances, etc.

8.16.14 - Portland General Electric

Safety

Safety Meetings

People

Safety is a core value at PGE, and the company allocates time for frequent meetings at every level of the organization. This ensures that safety concerns and directives are discussed throughout the company.

Executive Safety Council (ESC): PGE has created an ESC to oversee safety across the company. The safety officers and senior management representatives on the ESC regularly meet with employee groups to listen to any concerns about safety and share information about PGE safety initiatives [55].

Safety Coordinator for Eastern Region: Every region in PGE’s service territory has a safety coordinator. The present coordinator for the Eastern Region, which includes the CORE, has over 30 years of experience and began working for PGE as a journeyman.

Safety Coaches: To ensure that a conduit between management and field workers, PGE employs safety coaches who work with the safety team. Safety coaches are members of the union who volunteer to represent their department.

They discuss safety issues and events with management and the safety team to ensure that any concerns are dealt with and escalated if needed. Safety coaches sit on the Safety Committee, which meets monthly. The CORE group has one safety coach, and the position is rotated every 2-3 years. The CORE safety coach is a journeyman with normal duties and acts as a point of contact if crew members have a safety concern or experienced a near miss. Safety coaches discuss concerns and incidents amongst themselves during monthly meetings and determine what actions should be taken. In addition, prior to the monthly meeting, the safety coach spends time talking with crews to find out any issues that can be raised at the meeting.

Process

Safety Meetings

To maintain the focus on safety and its priority across the entire company, PGE holds regular meetings to address concerns and ensure that programs are implemented across the company.

Weekly Safety Coaches Meeting: On Mondays, the safety coach organizes the weekly safety coaches meeting, which is open to all and includes members of all groups, including engineering and design. This helps engineers gather any concerns raised by line crews. The meeting agenda includes a review of the action register, running list of open action items, discussion of near misses, and round table discussions of safety-related topics.

Weekly Conference Call: Every Thursday, the company holds a weekly conference call that includes supervisors from the various line units, management, and safety coaches from across PGE. This wider conference call may include the senior management of the company and is intended to share information between regions. A rotating facilitator manages the call.

To ensure that important information is shared across the company and passed to the line crews, any issues raised during the weekly conference call are discussed during the local safety calls held every Monday morning. Action items from the Thursday conference calls are logged on the Action Register alongside the expected completion dates. During the Monday morning safety meeting, time is always allotted for reviewing these actions.

Safety Committee: The Safety Committee, which meets monthly to discuss safety across the region, includes all safety coaches, safety coordinators, and the regional management team. At this meeting, the Regional Safety Coordinator raises a particular topic of local interest for discussion in the weekly meetings.

On a quarterly basis, all regions (Eastern, Southern, Western) hold a larger quarterly safety meeting. A chairman oversees quarterly meetings and union representatives them.

Weekly Meeting: Every Monday morning, PGE line crews hold a Monday morning safety meeting, which for lasts about an hour. The meeting begins with an update about events occurring in the city and a discussion covering whether any of these will affect scheduled work. The meeting also includes a list of issues and near misses encountered in the field and yard during the previous week, as reported by crews. The meeting always begins with a safety moment, in which an item from the safety manual, such as foot protection, is reviewed. The meeting also includes the Action Register Review with points discussed during the Thursday conference call. Meetings are never rushed and line workers are free to raise any issues. The meetings also discuss action plans from previous meetings.

For example, one meeting saw crews raise the issue of sewer gases in vaults. The foreman leading the discussion explained the procedure that crews should follow if they suspect that sewer gases are present in a manhole/vault. They were informed that they should not enter the vault and instead report it to the repair organization, which calls out a contractor to clean the vault. Workers should never expose themselves to any airborne pollutants.

Some other examples of issues discussed at meetings include the following:

Crews noted that a number of vaults had a new collector bus installed, but the spacing between the conductors was extremely tight. This could present a safety issue during future work. In order to mitigate the safety risk, crews installed insulation blankets over the secondary cable and posted notices in the vault stating that before any work is performed in the vault, the feeders should be de-energized.
One worker raised the issue of shared vaults with a neighboring utility, noting that there should be a better notification system to ensure that the other company does not perform switching or other tasks that could pose a hazard to workers ensconced in enclosures.

Tailboards: At every job site before the work begins, the crew holds a tailboard meeting. A tailboard sheet informs and records the contents of this meeting. The dashboard displays the sheet, which all employees must sign to show that they understand it. Completed tailboard sheets are filed to maintain a record of the job discussion, and the safety coordinator periodically reviews them. See Appendix C.

Focus on Safety: PGE has a company-wide focus on safety. Every meeting, whether it is a line meeting or management meeting, opens with a “safety focus.” PGE uses numerous safety key performance indicators (KPIs) to track safety performance for all supervisors. Overall, PGE’s safety performance is very good, and the corporate goal is to achieve zero injuries. In the past four years, PGE has cut the number of injuries annually from 160 to 80 across the company.

PGE believes that the main reasons for this improvement are the following:

Improving communication and discussions about safety
Assuring employees that it is possible to work without injuries by rigorously adhering to safety practices, not compromising safety to get the job done, and consistent management attention and support of safety
Focusing on training
Becoming more diligent with the stretching program to reduce the number of soft tissue injuries. This stretching program was a grass roots initiative in one of the PGE regions and resulted in a dramatic reduction in number of strains and sprains. It was adopted company-wide, with employees leading it.

Safety Coordinator Crew Visits: One of the main roles of the safety coordinator is to conduct field visits, and each coordinator must log at least 200 crew visits every year. During a site visit, the coordinator looks for any safety violations. The coordinator records each visit, including what was found, the date of the visit, the name of the foreman, the job address, and the crew number.

The CORE supervisor tries to make at least five crew visits per week and fills out a company form.

8.16.15 - SCL - Seattle City Light

Safety

Safety Meetings

People

Training

Each year, every network employee attends 3.5-5 days of training that includes mandatory training such as confined space, manhole rescue, first aid, etc., as well as non-mandated training on pertinent topics.

SCL conducts various meetings to ensure a good flow of information relative to safety. Network employees attend:

Monthly safety meetings
Weekly crew chief meetings
Monthly “all network” meetings, where they bring everyone together to talk about training, safety, report out from conference findings, etc.
Bi-weekly Crew Coordination meetings, where safety issues related to specific jobs are discussed
Tailgates at the start of day, and after lunch each day

8.16.16 - Survey Results

Survey Results

Safety

Safety Meeting

Survey Questions taken from 2009 survey results - Safety

Question 8.2 : Please indicate the type(s) of safety meetings you conduct. Check all that apply.

8.17 - Safety Observations

8.17.1 - AEP - Ohio

Safety

Safety Observations

(Safety Auditing)

People

Periodic safety observations are performed by both the AEP Ohio Safety department representative and by Network Crew Supervisors.

Process

Safety checklists are used to guide the performance of the job site observations and to record findings. These checklists can be filled out using a smartphone application (app). The checklist is tied to AEP Ohio’s Human Performance Improvement program, which uses the SAFER acronym for approaching all jobs.

“S” for summarizing all procedures and safety precautions that will be needed at the job.
“A” for anticipating any potential dangers, problems, or complications.
“F” for foreseeing all the steps that are required in the job.
“E” for evaluating all the layers of protections and safety procedures that should be used.
“R” for reviewing just-in-time-documents online, past experiences on similar jobs, and online best practices for the specific job they are performing.

Safety checklists are recorded online. The AEP Safety Department Representative performs 15 safety audits per year in AEP Ohio. Information is recorded and reported to AEP Ohio management as well as to the parent company.

Technology

AEP Ohio uses job safety checklists that can be filled out through a smartphone app. Safety information is recorded and available online for the entire company. Forms, guidelines, and safety best practices documents are available online for all company employees, including the AEP Safety Manual.

8.17.2 - Ameren Missouri

Safety

Safety Observations

(Job Behavior Observations)

People

All management employees in Energy Delivery, including supervisors, managers, superintendents and vice presidents, perform periodic safety observations called Job Behavior Observations (JBOs). Per their process, each supervisor is required to perform a certain number of JBO’s per month, depending on their job classification. For example, supervisors are required to perform at least four work site JBO’s per month.

Process

As the title indicates, JBO’s are aimed at reinforcing positive job behaviors, such as the wearing of proper personal protective equipment, and adhering to company policies and procedures. The JBO inspector will review the job site and work being performed, looking for and recording observations of safe practices related to:

Personal protective equipment (broken into detail)
Body use, movement and position
Housekeeping
Vehicle equipment and use
Policy and procedures

The inspector will conduct a short tailboard meeting with the field crew, noting the positive observed behaviors, and pointing out any noted deficiencies.

Figure 1: Ameren Missouri Superintendent performing JBO

Technology

Information from the JBO is recorded on a form, and entered into a computer system used to generate reports. Findings are aggregated at the division level, and published in reports that indicate the total number of observations, and the percentage of observed safe behaviors. These reports are issued monthly by the safety department and posted on the safety bulletin boards in each work center.

8.17.3 - CenterPoint Energy

Safety

Safety Observations

People

At CenterPoint, supervisors, managers and crew leaders are responsible for performing periodic site visits to perform safety observations. Observations are recorded on a Site Inspection checklist (See Attachment M).

Process

When supervisors perform safety observations, they are required to record these observations on a site inspection checklist.

Crew Leaders are responsible for performing at least four observations per month and for recording observations on the checklist. Operations Managers perform two observations per month, and the department Director performs one observation per month.

Technology

Information recorded on the checklists is kept in a three ring binder. Once per year, Major Underground management meets with the safety group to audit the observation findings, identify trend, and if appropriate, recommend safety improvement initiatives.

8.17.4 - Con Edison - Consolidated Edison

Safety

Safety Observations

Process

Safety Meetings

A job briefing is held each morning for every crew led by either a supervisor or lead mechanic.

Con Edison supervisors perform daily safety inspections, inputting the information on a four-page form. See Attachment J: Safety Inspection Form . The results of this form are entered into a computer system.

Con Edison also holds a larger safety meeting monthly with all field employees. Safety discussions are incorporated into other meetings as well, such as the underground network equipment standards committee meetings.

Con Edison gives safety performance high visibility. Safety performance reports are conspicuously posted in the utility’s buildings.

8.17.5 - Duke Energy Florida

Safety

Safety Observations

People

Regular occurring safety observations at Duke Energy Florida are performed by both the lead Health and Safety Professional for the South Coastal Zone, and by supervisor(s) within the Network Group.

The Lead Health and Safety Professional for the area will perform crew safety observations throughout the year, performing a minimum of eight observations each month. The purpose of the observations is to reinforce positive job behaviors.

Network department supervisors perform periodic job site observations and driving observations. Supervisors must perform and submit documentation of 15 job site observations per quarter.

Note that employees are expected to update their driving records (citations, tickets, insurance, etc.) in the Duke Energy Florida’s PlantView management system.

Process

The safety observation performed by the Health and Safety professional focuses on both the operations of the crew members including adherence to company standards, and how the supervisor interacts with his crew. While on site, the Health and Safety Professional may focus on a particular crew member for a detailed observation. This crew member will be asked questions about job scope, safety procedures, safety precautions taken while working, and safe practices at the site. In addition to asking questions, the observer will look for and document the use of safety and work practices.

Similarly, the safety and driver observations performed by department supervisors are focused on the use of safe work practices and adherence to company safety standards.

Observations of safe practices include:

Utilization of human performance concepts, tools and techniques, such as conducting or participating in the pre-job briefing
Use of personal protective equipment and other safety precautions
Body use, movement and position, and craftsmanship
Housekeeping and work area protection
Vehicle and equipment
Policy and procedures
Communications

Observers utilize a detailed Field Observation Form as a guideline, indicating whether or not observed behaviors are being performed in accordance with safety related practices or the Duke Energy Florida standard. In support of these observations, the company has developed subdocument that defines the “Range of Tolerance” associated with observed practices.

The safety inspector will conduct a short tailboard meeting with the field crew after the observation, noting the positive observed behaviors, and pointing out any noted deficiencies.

Technology

Job Site safety observations are documented on a paper Field Observation Form after during each visit (See Attachment O). Similarly, driver observations are also recorded on a paper form (See Attachment Q). These observations are then electronically recorded in PlantView, and can then be sorted for reporting by many fields including supervisor, employee, team, and time/date of observation.

8.17.6 - Duke Energy Ohio

Safety

Safety Observations

(Jobsite Inspections)

People

Supervisors perform monthly crew audits, visiting each crew once per month.

EHS employees will also perform random safety audits.

Process

Supervisors record their observations on an audit form. The information later gets entered into a computer system, for reporting and analysis.

The job site inspection summaries are reviewed by the department’s Vice President.

Technology

The job site inspection information is recorded on a form (See Attachment L) and then entered in a computer system. The EHS group analysis the summary data to identify safety / work practice trends.

8.17.7 - Energex

Safety

Safety Observations

People

Energex Crew leaders perform a job site risk assessment, called a “tool box talk” (see Figure 1). This is a documented safety meeting, with a form that is signed by all crew members and job site visitors who receive the briefing. Any visitors who arrive at the site must participate in a safety briefing as well. The performance of the job site tool box talk is a legislative requirement in Queensland.

Process

The briefing reviews the scope of the job and illuminates hazards specific to the job. The form used in the past was multiple pages and involved many check boxes. Energex worked with employees to produce a streamlined form that is used to document the safety meeting, to simplify its use, and to encourage discussion of job site safety hazards.

Figure 1: Energex crew leader conducting a tool box talk (job site safety briefing)

8.17.8 - ESB Networks

Safety

Safety Observations

(Safety Auditing)

People

A Safety Services team gathers information and statistics on incidents and near-misses. This information is incorporated into ESB Networks’ extensive documentation system.

Process

Safety quality and environment are sampled through on-site visits by supervisors. There are two mandatory safety audits required of each supervisor per month. The results of these on-site safety samples may entail coaching, and it is not punitive unless the safety infraction is very serious.

ESB Networks measures success by less lost time due to injuries; no employee first-time injuries; fewer near-miss reports; less contractor injuries; and actions taken on safety improvement plans when adopted.

At the time of this immersion report there were only 12 minor incidents in the year – all were investigated. ESB Networks ’ goal for the year was no more than 20 incidents.

8.17.9 - Georgia Power

Safety

Safety Observations

(Safety Auditing)

People

The Georgia Power Network Underground group has a dedicated Health and Safety Advisor who reports to the Health and Safety Distribution supervisor within Georgia Power. The Advisor meets regularly with the larger Georgia Power Safety and Health group.

The Network Underground group has a dedicated Health and Safety Advisor assigned to them, who reports to the Health and Safety department at Georgia Power. The Advisor meets regularly with the larger Georgia Power Safety and Health group.

The Advisor, as well as Network Underground leadership, such as distribution supervisors (crew foremen), perform regular job site inspections, called safe work observations, to reinforce safe work practices.

Process

The Safety Advisor and Distribution Supervisors each make approximately 25 observations a month. For a Distribution Supervisor, this works out to about one visit per crew per month. Observations from the visitation are recorded on a form. The form contains a checklist of items for inspection, including work methods, equipment condition, working conditions, etc. Any defective safety equipment, such as torn gloves or worn boots, are confiscated and noted. The focus of the observations is to identify and call out those practices that are being done well, to reinforce positive behaviors.

Paper forms completed by Distribution Supervisors are forwarded to the Safety Advisor for entry into a Georgia Power computer system using Microsoft Word documents. Job observations can be pulled up on the computer system by crew leader, foreman, date, etc., though Georgia Power does not routinely run reports against this system.

(See Attachment K )

Technology

Job behavior and inspection forms are kept in Word documents for review and retrieval. OSHA-recordable accidents are stored in the company SHIPS safety management system.

8.17.10 - National Grid

Safety

Safety Observations

(Crew Observations)

Safety Compliance Assessment

People

The safety compliance assessment is a formal process in which a supervisor visits a job site and audits the safety practices in place. This type of assessment connects an employee to his/her work and formally records the results. Formal assessments are conducted so that each employee is observed and reported on at least once per year. Unlike the Safe and Unsafe Acts (SUSA) visits, which are intended to inform workers and assist them with making safe choices on an ongoing but anonymous basis, this is a formal compliance assessment that holds employees accountable for their working methods and equipment.

Process

Supervisors within UG Electric East are required to perform at least two Safety Compliance audits per month. Each employee is to be observed at least once per year.

Each department (for example the underground group) has its own compliance assessment procedure based on the work undertaken. Compliance reports indicate who was audited and where, unlike the SUSA visits which are more anonymous. Incidents are reviewed to see what the biggest issues are. A major focus with compliance assessments is ensuring that a complete, well-written job brief was performed and signed, identifying hazards and risks for that job, and that steps were identified and taken to reduce those risks.

The compliance assessment form (See Attachment E) includes basic information on the assessment, including the site name and location, crew task, observation date, personnel observed, whether they are employees or contractors, the number of people observed, and the observer(s).

Many items in various categories are assessed and recorded on the checklist. These include the following:

Focused Observations for Electric
- Are hazards understood?
- Are proper steps taken to avoid those hazards?
Manual Handling - Soft Tissue Injury Prevention
- Are repetitive or strenuous tasks done correctly?
Communication & Risk Assessment
- Are the job brief and related duties done correctly?
Work Area Safety
- How secure is the work area?
- Are hazards marked?
- Is the work area kept tidy?
Personal Protection
- Is the protective equipment in good condition?
- Is it properly used?
Using Tools and Equipment
- Are appropriate tools used?
- Are they in good condition?
Vehicles / Mobile Equipment
- Are vehicles being operated properly?
- Are they in good condition?
- Is all the required safety equipment on board and inspected?
Work Methods and Procedures
- Are proper procedures being followed at all times?
Work Place Environment
- Is the environment safe and comfortable?
- Is water and first aid equipment available?
Work Practices
- How is the body positioned during tasks?
- What sorts of precautions are taken while maneuvering and working?
Environmental
- How is waste managed?
- Are proper procedures being followed to protect the environment?

These categories all have a number of very detailed checklist items, which can be rated Safe or Unsafe, or on a scale from Poor to Very Good, depending on the question.

For checklist items that score as “poor” or “unsafe”, specific observation detail are recorded, including the people involved, the details of the problem, and the immediate action taken to remedy it. Follow-up items are listed and assigned to the appropriate party, including the due date and a complete date to be filled out once completed.

Technology

A checklist for Compliance Assessment form is used for performing these assessments. (See Attachment E)

The Corporate Safety department records information from the compliance assessments into a computer system for generating reports to monitor safety trends.

8.17.11 - PG&E

Safety

Safety Observations

(Crew Observations)

People

Supervisors perform a minimum of four work site crew observations per week.

The VP, Superintendent M&C Electric Networks performs two crew observations per week.

PG&E also has a group within Maintenance and Construction (M&C) called the Quality Control (QC) group. This group performs periodic safety audits. Note that at the time of the EPRI practices immersion, this group was being trained on network systems in preparation for implementing QC audits of the network.

Process

The crew observations include a look at work procedures and safety procedures.. Supervisors log their observations on form. The information later gets entered into a computer system, for reporting.

Technology

The crew observation information is recorded on a form and then entered in a computer system. Certain items may be flagged by the system based on “scores” reported by the observer, though it is not being used for performance trending.

8.17.12 - Portland General Electric

Safety

Safety Observations

People

Safety observations are the responsibility of the safety coordinator for Eastern Region, who covers the CORE in addition to other locations. The present coordinator has over 30 years of experience and began his career with PGE as a journeyman.

The CORE supervisor also routinely performs safety observations and tries to make at least five safety visits per week.

Process

Safety Coordinator Crew Visits: One of the main roles of the safety coordinator is to conduct field visits, and each coordinator must log at least 200 crew visits every year. During a site visit, the coordinator looks for safe work practices and any safety violations. The coordinator records each visit on a crew visit form, noting what was found, the date of the visit, the name of the foreman, the job address, and the crew number.

The CORE supervisor also tries to make at least five crew visits per week and records findings on a similar crew visit form.

Figure 1: T&D safety coordinator crew visit form

8.17.13 - Survey Results

Survey Results

Safety

Safety Observation

Survey Questions taken from 2018 survey results - safety survey

Question 9 : Do you perform routine training on how to conduct a tailboard meeting?

Question 10 : How to you determine / assess the quality of your tailboard meetings?

8.18 - Special Safety Programs

8.18.1 - Ameren Missouri

Safety

Special Safety Programs

(Safety Sampling)

People

Ameren Missouri has implemented a peer to peer safety observation process called Safety Sampling. In this program, employees perform periodic safety observations with peers to reinforce positive job behaviors. The program is similar to the Job Behavior Observation (JBO) program, performed by managers (See Safety – Job Behavior Observation ). ).

Process

An example of the process used to perform safety sampling is the one used in the Distribution Service Test department. This department has a safety committee that includes four Distribution Service Testers. Each member of the committee spends one day per month visiting with crews, and performing a safety sampling. They will review the job site and work being performed, looking for and recording observations of safe practices related to:

Personal protective equipment (broken into detail)
Body use, movement and position
Housekeeping
Vehicle equipment and use
Policy and procedures

The safety sampling inspector will conduct a short tailboard meeting with the field crew, noting the positive observed behaviors, and pointing out any noted deficiencies.

Technology

Information from the safety sampling is recorded on a form (See Attachment M ).

Statistical summary information from the safety sampling program is reported monthly and published on the Ameren Missouri safety bulletin boards in each work center.

8.18.2 - CEI The Illuminating Company

Safety

Special Safety Programs

(Safety Stop Program)

People

CEI has two full time safety professionals called Advanced Safety Coordinators, who focus on implementing safety programs for the entire Illuminating Company. The Advanced Safety Coordinators report organizationally to the Director of Human Resources for CEI. One of the programs they administer is the Safety Stop Program, focused on observation and reporting of safety behavior.

Process

CEI is utilizing a program produced by DuPont Corporation called the Safety Stop Program (Safety Training Observation Program). The program is focused on guiding people (leaders, supervisors, safety professionals, etc) in observing workers performing routine work activities with a focus on safe behaviors. The program includes training of employees in performing safety observations, and the use of a “stop” card that is used to observe and record safe acts and to correct unsafe acts. (See Attachment U). ).

The program includes five criteria: Decide, Stop, Observe, Act, and Report. Supervisors will perform safety observations that include noting the reactions of people, the use of personal protective equipment, the positions of people, the use of tools and equipment, and procedures and orderliness. They will record both safe acts and unsafe acts observed. If an unsafe act is observed, they will take immediate corrective action and record same.

Supervisors complete the observation forms and send them to the Advanced Safety Coordinators who tabulate the information and use the information to monitor trends. Once per quarter the trend summary is distributed and aids management in determining what safety elements to focus on.

CEI has had high participation in the programs, with over 2000 safety observations turned into their Safety Coordinators in 2008.

CEI noted that most reported observation of unsafe practices was in the procedures and orderliness category.

Technology

The Safety Stop Cards are filled out manually. The information collected is tabulated and reported using a Microsoft Excel spreadsheet.

8.18.3 - CenterPoint Energy

Safety

Special Safety Programs

(HERO Program)

People

CenterPoint has implemented a Value Based Safety Program in each major operating group. Within Distribution Operations, of which Major Underground is a part, the program is called the HERO (“Having Employees Record Observations”) program.

The HERO program, now in its third year, is a peer to peer observation program led in full by employees, and including all employees (other than Managers). The program supplements CenterPoint’s other safety meetings, and is focused on getting employees to look out for each other.

Each division has a HERO team, with representatives for each group within the division participating on the team. The Major Underground group assigns a crew leader to participate in this team, and to be a safety point person. This individual liaises between the HERO group, management and employees.

The HERO team decides how to organize and implement the program and establishes a specific budget for executing the program.

The HERO program does not have a formal discipline program associated with it.

Process

The HERO program is a peer to peer observation program that is executed by using checklists. Employees will conduct a work task observation and record the observations on one of three checklists – an office check list, see Attachment J , a field checklist, see Attachment K , and a driving checklist, see Attachment L .

An employee who is a potential observer approaches a peer employee and lets them know that he/ she would like to perform an observation. The observer performs a short observation, records findings on the checklist, and, at the conclusion of the observation, shares any noteworthy findings with the employee who was observed. In addition to providing positive feedback, the observer will talk about no more than one item for improvement, if identified.

When the program was implemented, everyone received some training in how to perform an observation. CenterPoint has found the program to be highly beneficial to the observers, in that it forces them to think about safety as it relates to the work being observed.

Afterword, the information from the checklist is entered into a computer program (RADAR) that enables CenterPoint to run reports to identify observation trends, potential risks, and generate safety statistics.

The program measure is the percentage of participation of employees. In Major UG, 84% participate in the program, completing at least four observation forms (checklists) per month.

CenterPoint does provide a yearly incentive to participate in the program. Gift cards are providing to employees that participate for more than three months in a row. CenterPoint will also conduct periodic celebrations for the achievement of selected milestones associated with the HERO program.

HERO teams also develop other initiatives to promote safety, such as developing signs to remind employees of safe practices, such as using a handrail when going up or down stairs.

CenterPoint believes the program to be beneficial. Participation in the program is strong. Corporate safety performance has improved over the past three years, while Major Underground Safety performance has remained static.

Technology

HERO observation information is entered into a purchased database called RADAR data management software^[1] , by Safety Performance Solutions, Inc, which facilitates data recording and report writing.

^[1] http://www.safetyperformance.com/Services/DMS.asp

8.18.4 - Duke Energy Florida

Safety

Special Safety Programs

(Keys to Life)

People

Duke Energy has established certain “Keys to Life,” a listing of behaviors / practices associated with hazards design to maintain personal safety.

Associated with the Keys to Life is a consolidated manual of work processes for working safely. The manual covers every job throughout the enterprise, including nuclear, overhead, and underground network work.

Process

The genesis of the development of the Keys to Life was an employee fatality. The company responded by defining certain practices and behaviors associated with hazards that must be follow. Adherence to the Keys to Life practices is non-negotiable. For the Duke Energy Delivery Operations and Services organization, the Keys to Life areas of focus, for which required safe behaviors have been defined, include:

Driving safely
Personal protective equipment
Pre-job briefings
Work zone safety
Electrical safety
Pole/structure inspection
Falls from elevation
Falling objects/line of fire
Rigging
Confined Space Entry
Trenching/excavations

See Attachment P.

Each of the practices defined in the Keys to Life is supported by a consolidated manual of work processes, organized by specific tasks, and posted online. Subject matter experts (SMEs) from throughout the Duke Energy enterprise are called on to contribute their expertise in the formulation of specific processes included in the manual.

An example of this is the work process for safely entering manholes. To develop this process, SMEs from throughout Duke Energy, including a representative from Duke Energy Florida, came together to craft the enterprise-mandated manhole entry process. The SME-generated work methods are set to the highest standard, perhaps exceeding local operating company standards already in place. The goal is to develop and maintain the most robust standard and apply it throughout the Duke Energy operating companies. Periodically, the company will issue bulletins that augment the work processes, which are then incorporated into the larger manual.

In safety alerts that summarize safety incidents, hazards, or near misses, Duke Energy will reference the associated “Keys to Life Connection,” which reviews the appropriate safe work practices associated with the specific case.

Technology

The Keys to Life manual of work methods is posted online. Electronic bulletins supplement the manual, and are then incorporated into the larger online manual.

8.18.5 - Duke Energy Ohio

Safety

Special Safety Programs

Safety Stand Down Meeting

People

At Duke Energy Ohio, the safety “stand down” meeting is a special meeting convened companywide to discuss a significant issue relative to safety such as a serious accident. EPRI investigators attended such a meeting convened to review an accident involving a contractor.

In such a case, Duke Energy Ohio management will assemble a meeting of the entire department. Meeting content can vary but consists of things such as reading letters / opinions of listening to voice mails from upper management on a particular incident, emphasizing a particular safety principle or discussing a particular accident, and reviewing video’s pertinent to the particular incident. For example, during the Safety Stand Down meeting attended by EPRI, employees viewed a Duke produced video that showcased the experiences of an employee who had sustained a work related injury.

All employees attend these meetings and are given an opportunity to discuss the situation, ask questions and raise related issues.

8.18.6 - Energex

Safety

Special Safety Programs

(Strategic Risk Assessments)

People

Improving safety is a key focus area for Energex, which is driven by the company CEO. The company has embarked upon a system wide effort to change their safety culture.

Energex has established a safety management system, which is a comprehensive framework that guides their safety approach, and addresses strategies for managing the hazards and risk associated with the design, construction, operation and maintenance of the system. Strategies such as their approach to safety training, incident investigation and response, and emergency preparedness and response, are guided by this framework.

Energex has recently reorganized their safety organization, consolidating a corporate safety group, a Service Delivery safety group, and a Power Plant Safety group to form one safety organization.

Process

Energex has implemented a process of performing a strategic risk assessment on their 10 highest risk activities for the purpose of assuring that they have adequate controls established to address those risks.

Technology

The company uses a product called Bow-Tie ( http://bowtiepro.com/ ), which facilitates the creation of bow-tie diagrams, to perform these assessments. Bow-tie diagrams are a tool for communicating risk assessment results by displaying the links between the potential causes, preventative controls and consequences of an event (incident or accident).

8.18.7 - Georgia Power

Safety

Special Safety Programs

Target Zero Safety Program

People

The Georgia Power Underground Network group has a dedicated Health and Safety Advisor who reports to the Health and Safety group within Georgia Power. The Advisor meets regularly with the larger Georgia Power Safety and Health group. The Safety and Health Advisor works closely with the Network Underground manager regarding the operation and maintenance of the network underground system throughout Georgia. In all, the Safety and Health Advisor is responsible for the training and safety of approximately 180 people within the organization.

Process

Since 2005 Georgia Power has instituted a safety program called “Target Zero” aimed at achieving no accidents in a calendar year. If an accident should occur, the company “resets the clock”, so to speak, back to zero, to maintain the focus on eliminating all accidents.

Georgia Power does establish goals related to safety performance, including accidents. Management bonuses are influenced by safety performance. Georgia will also establish group incentives based on achievement of safety targets. Network Underground noted that there have been no serious injuries in the department since the goal has been in place.

Technology

Georgia Power issues safety reports to all departments; documents safety training schedules; and issues Web site blurbs on the company intranet about safety tips, safety competitions, and safety reminders. Bulletin boards are also used throughout the company to re-enforce safety programs and safety and health messaging. Bulletin boards also display recorded deaths at the company.

Georgia Power safety book, called “Section O,” describes the company safety rules.

(See Attachment L )

8.18.8 - National Grid

Safety

Special Safety Programs

Safe & Unsafe Acts (SUSA) Audits

People

Safe and Unsafe Acts (SUSA) is an informal audit process in which someone observes field crew behavior, notes safe or unsafe acts, and then discusses with crew members the safety of those acts. National Grid implemented the SUSA program to find a way to enable managers to communicate effectively about safety with the crews and to continually reinforce safe working habits.

Audits are usually performed by a direct supervisor of the work crew, but can be performed by anyone. The results of the audit are recorded anonymously so that incidents can be reviewed and areas of concern identified in general. Each supervisor undertakes six SUSAs per month, for a total of 72 SUSAs per year. Work Methods people do four SUSAs per year.

Process

Unlike a formal compliance assessment, the Safe and Unsafe Acts (SUSA) visits provide a more informal assessment method where the focus is on dialogue with employees. During a SUSA visit, crews are engaged in questions such as “what is the worst thing that could happen here?” and “how do we avoid it?” In particular, the tone of a SUSA visit is meant to be conversational, and to get employees thinking rather than being passively instructed. Situations are discussed with a focus on how to act when similar scenarios are encountered in the future. Supervisors undertake them six times per month.

While the focus is to informally discuss safety issues to improve working methods, a checklist for performing SUSA visits is also filled out to assist with the process. On it, general information is recorded including the primary and additional tasks the crew is performing (e.g. installing wire), plus the work site location and observers present. Much like the formal assessments, a number of checklist items are scored from “poor” to “very good”, or as either “safe” or “unsafe”, in categories including manual handling (for soft tissue injury prevention), communication and risk assessment, work area safety, personal protection, tool and equipment use, vehicles and mobile equipment, the overall work place environment, driving, work practices, and environmental impacts. Details can be found on the attached SUSA document (See Attachment D)

The SUSA records specific details of “poor” or “unsafe” observations, including the immediate action taken, but unlike the formal compliance assessment, the forms do not include crew member names. The reporting is relatively anonymous as the reporting function of the SUSA forms are not meant to hold individual employees accountable, but rather to allow for a review of incidents to identify the biggest issues and aid with discussion and training.

Technology

A Safe/Unsafe Acts checklist is used for performing these assessments (See Attachment D ).

8.18.9 - Portland General Electric

Safety

Special Safety Programs

Switching and Tagging

People

Crew members (cable splicers) perform switching and tagging under direction from the load dispatchers working in the System Control Center (SCC). Dispatchers are assigned geographically, and from Monday to Friday, two dispatchers cover each of the two PGE regions. One of the regions includes the CORE underground area.

Process

Planned outages follow a structured process informed by a shutdown order that identifies the switching steps, including the location and device to be operated. For a planned outage, the Network Engineering Department creates a shut-down order document using a template and provides the load dispatcher with a three-day lead time to complete the order.

The communication between the crew members and the dispatcher uses three-way communication, with the crew member recording what the dispatcher says verbatim before reading the information back to the dispatcher. After the crew member has read the switching step to the dispatcher, the dispatcher confirms that it matches the switching order. Only after confirmation, the dispatcher issues the order and allows the crew member to perform the switching. Note that for the network, this communication does not occur at every step. The dispatcher provides an order for the crew to open and danger-tag all the associated vaults on the shutdown order. The shutdown order lists all the vaults, and one order specifies when to open and tag all the associated vaults. Only after all of the devices have been operated and tagged will the crew member contact the dispatcher and receive a clearance to install grounds and proceed with the work.

At present, load dispatchers use the network protector to gather information about conditions on the secondary system, but nothing is controlled remotely.

When PGE tags circuits and equipment, this also appears on its geographic information system (GIS) mapping.

8.18.10 - SCL-Seattle City Light

Safety

Special Safety Programs

Manhole / Vault Event Response - A Collaboration between Seattle City Light and the Seattle Fire Department

Introduction / Overview

Many electric utilities in the United States operate underground distribution networks in densely populated major load centers such as cities. These systems, because of both their electrical design (meshed systems) and civil design (underground ducted manhole / vault systems), are highly reliable as they are largely protected from adverse external conditions and less prone to outages than overhead systems because of their inherently redundant design. However, underground systems do occasionally fail and can result in “manhole events”, including smoke emissions from a manhole, fire in a manhole, or a manhole explosion.

The majority of these events originate within the manholes, vaults or in cable ducts between the structures. In most cases, the event causes smoke to emanate from the structures. In rare occurrences a fire is visible, and in extreme cases an ignition of combustible gases which have formed within the manhole causes the manhole cover to be propelled into the air. These manhole events, although rare, can damage surrounding infrastructure, and endanger the public.

Accordingly, electric utilities and EPRI are addressing the problem with research into solutions designed to prevent, mitigate, and contain events. One area of research focus has been to identify utility practices, including approaches, procedures and technologies, that are being used by utilities to respond to and mitigate such events. To this end, in 2018, EPRI issued a survey that seeks to identify practices being employed across the industry to prepare for and respond to manhole events, including understanding what sort of emergency preparedness and response guidelines have been established in the industry, what sort of emergency exercises or “drills” are being performed, and what sort of partnerships have been developed with other emergency response stakeholders, such as fire companies.

For many utilities, the roles of the electric utility responders and of emergency partners such as fire department responders are not well clarified or documented. The 2018 survey of utilities found that only 25% of responding companies have documented procedures for company employees responding to a smoking manhole, and only about 30% have documented procedures for company employees responding to a manhole fire. Further, only about 30% report having documented procedures for first responders responding to a manhole event. In addition, only about 25% of responding companies perform periodic drills that include network situations such as a manhole fire, and of those who do, less than 15% involve other stakeholders, such as the fire department, in those exercises.

Because manhole events are rare, folks responding from the fire department (Fire ) may not be sure what expectations the utility has of them. In the case of a smoking manhole, if the fire company arrives at the site before the utility is on site, what does the utility expect? Should the Fire attempt to put out the fire? Should they wait until the fire burns out? Should they wait until the utility has de-energized the area before attempting to put out the fire? Or should they attempt to control the fire before it spreads, minimizing damage, and possible reducing outage time? What sort of PPE should they utilize? Should they use water or chemicals? What sort of chemicals should be used? Similarly, Electrical responders may not be familiar with the expectations that the fire department resources have of them.

Seattle City Light - Seattle Fire Department Collaboration

This case describes a collaborative effort underway between Seattle City Light (SCL) and the Seattle Fire Department (Seattle Fire) to define roles and expectations, raise understanding and awareness of the Fire Department of the electric company infrastructure and hazards associated with manhole events, and develop and agree to a response approach for manhole events.

History / Background

The collaboration between SCL and Seattle Fire was initiated in 2014, and was championed by the Principal Electrical Engineer at SCL, responsible for their network system, and a Captain within the Seattle Fire Company. The process involved a series of regular meetings conducted between the two groups to clarify SCL’s expectations of Seattle Fire in an emergency, and from that, to formalize the relationship between Seattle Fire and SCL, including definition of roles and responsibilities, definition of practices to be utilized, and development of specialized training, tools and technologies for Seattle Fire to be able meet those expectations. Part of the process for identification of practices included joint field visits to representative SCL facilities, joint visits to other city utilities and fire companies, and participation in industry working groups such as the North American Dense Urban Utility Working Group (NADUUWG).

Vault Response Team

The result of these efforts was the formation within Seattle Fire of a Vault Response Team (VRT), a group of firemen who receive specialized training in responding to electrical fires that occur in the city of Seattle. The VRT is staffed by regular on-duty members of the fire company, and is automatically dispatched on all manhole, vault and substation fires.

See Figure 1.

Figure 1: Seattle Fire Vault Response Team

Seattle Fire has documented procedures and roles for the members of the VRT. They have developed a Standard Operating Guideline (SOG) to guide the VRT when operating at an electrical manhole, vault or substation fire. This guideline provides an overview, key definitions, strategies, and defines the actions that should be taken. This document is complemented by a Vault Fire Response Positional Responsibilities document, which defines the roles and responsibilities of various positions that may be assigned within the VRT including the Incident Commander, Vault Team Leader, The Truck (Power 25) Operator, Nozzle Team, Vault Safety Officer, Cover Team Supervisor, Cover Team, and Aid Members (“Hooks”).

In an emergency, the VRT Team Leader coordinates with Seattle City Light and advises the Incident Commander of hazards and of potential tactical considerations. If appropriate, and with approval of the Incident commander, Seattle Fire will flood a manhole or vault with CO2. In most cases the vault or manhole does not need to be deenergized for the VRT to commence flooding operations to extinguish the fire.

Seattle Fire has created other documents to support and guide this process, consistent with their internal processes, including Command sheets and matrices, and are working on an SOP for Vault and Substation fires.

Power 25 Specialized Fire Truck

Part of mobilizing the VRT was assuring that they had proper equipment to respond to an event, including refurbishing a fire truck (Power 25) so that it is equipped with a NFPA compliant “High Pressure Mobile System”, a system for delivering CO2. This system has a capacity of 900 lbs. of liquid CO2, and a nozzle system capable of moving more CO2 per minute with less nozzle reaction. The truck is also equipped with other tools, including a laptop that is loaded and kept up to date with copies of SCL’s vault / manhole maps, SCL hooks for removing manhole lids, a Kevlar tarp for positioning over the manhole after flooding with CO2 to provide for greater saturation, CO2 detectors, and high visibility barriers for placing around open manholes. The truck also carries an on-board 15 kW generator to provide electric power or lighting if necessary.

See Figures 2 & 3.

Figure 2: Power 25 Specialized VRT response truck

Figure 3: Power 25 CO2 Delivery System

Training

To support the formation of the VRT, SCL and Seattle Fire have jointly developed specialized training for the members of the VRT. Some of the training is taught by SCL experts. VRT members receive 96 hours of specialized training including:

Training in the use of the Power 25 specialized truck and in the deployment of CO2,

Training in the hazards associated with CO2,

Training in hazard recognition so that VRT responders know what to look for. This training includes recognizing hazards in vaults located within buildings, hazards from street vaults and manholes, and hazards from rectifiers.

Training in “sizing up” a vault to determine appropriate action,

Training in electrical theory, including AC / DC systems, and in the difference between network and URD systems.

See Figure 4.

Figure 4: Seattle City Light delivering electrical training

A noteworthy practice utilized by SCL and Seattle Fire is the performance of a joint vault fire exercise, referred to as “confidence training”. The exercise is conducted at an SCL training facility which is equipped with submersible vault and manhole structures for use in training. As part of the confidence training, SCL will create an arc in a manhole by positioning two cables about one inch apart, grounding the one side and applying a voltage (approx. 20kV) to the other by connecting to Hi Pot (thumper) device. An arc is created, which creates a true electrical scenario, and familiarizes VRT crews with the sounds associated with arcing.

The VRT will then “practice” all phases of the process for responding to an electrical event, including donning all appropriate PPE, manning the various positions, and completing all required activities in the proper order, including removing the manhole lid, positioning the CO2 nozzles, flooding the hole, and covering with the Kevlar tarp.

See Figures 5 - 8.

Figure 5: Confidence Training, creating an ARC

Figure 6: Confidence Training - Removing the cover

Figure 7: Confidence Training - Positioning the nozzle, flooding with CO2

Figure 8: Seattle City Light delivering electrical training

Outreach

As part of their on-going efforts to solidify the process and to foster similar collaborations elsewhere, Seattle Fire and SCL have reached out to peer utilities and fire companies nationally, including participating in industry workshops such as NADUUWG, and conducting site visits with other utilities and fire companies to exchange ideas. Seattle Fire has also allowed peer fire companies and utility representatives to visit Seattle and participate in training.

Summary

Manhole events are a rare but potential happening for operators of urban underground systems. By virtue of their scope and impact, these events demand the involvement and coordination of various emergency response stakeholders including fire companies. Responding effectively requires defining response processes, and clarifying roles. Seattle City Light and the Seattle Fire Company have demonstrated an effective and comprehensive approach to meeting this objective that includes support from senior management, appropriate resourcing, documentation of standard operating practices, definition of roles, development and delivery of training, and the performance of periodic exercises. SCL and Seattle Fire’s approach can serve as a model for utilities seeking to coordinate with their Fire response partners.

8.19 - Training

8.19.1 - AEP - Ohio

Safety

Safety Training

People

AEP has a strong culture of safety, which is evident in its attention to safety in the work place, in its work practices, and in its approach to network design.

Process

All Network Mechanics and Network Crew Supervisors have undergone extensive safety training, including lead awareness, de-energization of cables, network protectors, safe manhole entry, and many other safety procedures and practices that are contained in the AEP Safety Manual. Annual safety training for Network Mechanics is also held on topics such as safe handling of new equipment and lead awareness.

Company-wide yearly Safety Stand Downs are also conducted, which focus on specific safety practices in depth. In these “Stand Downs,” workers spend allotted time, usually several hours, focusing on a safety topic.

Technology

The AEP Safety Manual, safety forms, guidelines, and safety best practices documents are available online to all company employees.

8.19.2 - Ameren Missouri

Safety

Safety Training

People

Ameren Missouri holds various safety meetings, ranging from job site tailboard meetings to large company safety meetings. Meetings can be led by a crew foreman, supervisor, manager or safety professional, depending on the type of meeting.

In addition, Ameren Missouri has implemented the practice of kicking off all company meetings with a brief safety message delivered by the meeting host. The meeting host will select a topic of interest for the group and share information on that topic. The topic does not necessarily have to be related to the meeting purpose, but rather a topic that would be of interest and generally apply to the meeting participants.

Process

Ameren Missouri holds various safety meetings, including:

Job site tail board meetings
Morning “5 minute” briefings
Monthly safety meeting
Quarterly Safety meetings
Tool committee meetings
Safety committee meetings
Safety Culture Team meetings

Job Site Tail Board Meetings

Ameren Missouri crew leaders perform job briefings (tailboards) at the beginning of each work day or new job. An element of the job briefings is a requirement to regroup and re-brief when the work environment changes.

Ameren Missouri records the job briefing on a Job Briefing Sheet, including the employees who participated in the briefing.

Morning “5 minute” briefings

Ameren Missouri conducts a daily morning safety meeting (also called a “5 minute briefing”). This meeting is led by a supervisor who prepares a safety related topic. The morning meeting includes time for employee warm-up and stretching exercises. Once a week, Ameren Missouri invites a physical therapist to lead the morning stretching exercises and provide council to employees.

Monthly Safety Meeting

Ameren Missouri conducts monthly safety meetings within each department. For example, the Underground Construction group and Service Test group each convene a monthly safety meeting, with all members of the department represented. A safety professional may or may not be present.

A meeting summary is posted on the Safety bulletin board.

Note than in the Service Test department, union employees also meet quarterly to discuss safety issues. This meeting is evidence of a cultural transition at Ameren Missouri, with individuals taking accountability for their safety.

Quarterly Safety Meetings

Ameren Missouri conducts quarterly safety meetings with all employees. These meetings are administered by Ameren Missouri safety professionals.

Tool Committee

The Ameren Missouri underground group has formed a tool committee comprised of one supervisor, and three field representatives to discuss issues and develop recommendations for worker tools. The Blue Hat representative also participates on this committee.

The tool committee meets monthly. A meeting summary is posted on the Safety bulletin board.

Safety Committee

The Ameren Missouri Underground Construction group has formed a safety committee led by a supervisor and comprised of in house people, including a safety professional from Ameren Missouri’s safety group. This committee discusses departmental safety issues and makes recommendations for change locally. Information from this committee is distributed via the monthly safety meetings, or daily morning 5 minute meetings.

The safety committee meets monthly. A meeting summary is posted on the Safety bulletin board.

Safety Culture Team

Ameren Missouri has formed a Safety Culture Team to focus on understanding cultural barriers to improving safety locally, and to make recommendations for changes to build trust and positively influence the company culture. The committee is comprised of managers and supervisors, including the UG Construction manager. A safety professional is also part of this team.

The safety culture team meets monthly. A meeting summary is posted on the Safety bulletin board.

8.19.3 - CEI - The Illuminating Company

Safety

Safety Training

(Job Skills Demonstration)

People

CEI has implemented a Job Skills demonstration program that assures that Underground Electric Workers in a given classification can demonstrate proficiency in certain skills in order to advance. Electrical workers who demonstrate proficiency in certain skills can move up in pay grade within a specific classification.

CEI has assigned several people (6) to act as advocates for the skills development process. These individuals sit down with every employee and review the skill book, explain how the process should work, ascertain whether the employee is getting the training he/she needs, and act as advocates of the process.

Process

Employees are each given a “skills book” that lists the individual skills they are responsible to learn and demonstrate in order to advance. See Attachment W

The employee will develop these skills through on the job training. When an employee feels he is proficient in a certain skill, he can demonstrate the skill, proving that he has the skills to perform the given task. A supervisor will “sign off” in the skills book indicating that the employee has demonstrated skill proficiency.

As employees within a classification demonstrate skill proficiency, they move up in pay within that classification. There are several pay steps within each classification.

Prior to moving to the highest salary step within a pay grade (Salary step One), an employee must take a progression test. This test (not a skills demonstration but an “on paper” test) is administered by the training department and covers the topics demonstrated in the skills book.

When an employee passes this test and achieves salary step One within a pay grade, they are eligible for advancement to a higher classification.

Typical skills required at each classification include:

Electrical Worker C – learn to pull cable, understanding equipment.
Electrical Worker B – begin to learn splicing, learn a 15 kV transition slice
Electrical Worker A – 33 kV Transition splice, Switching
Leaders – Network Protector Maintenance

Technology

The skills book is a hard copy book maintained manually by the employee. The skills proficiency test is a computer based test administered by the training department.

8.19.4 - CenterPoint Energy

Safety

Safety Training

Job Skills Demonstration Program

People

CenterPoint has a strong focus on formal training and on-the-job training, with advancement to the journeyman levels based on a combination of training, testing, and time of service in the various position levels. CenterPoint has well developed documentation of the skills that must be achieved and demonstrated at each level in order to advance to the next.

Process

Advancement through the Network Tester and Cable Splicer job families involves a three year apprenticeship program that includes a combination of training, job skills demonstration, and testing.

Network Testers are hired as apprentices, and enter into a three year apprenticeship program. They initially attend a three week orientation program that includes pole climbing. New employees must successfully complete this three week orientation to remain in the apprenticeship program. After the first 90 days of being accepted into the program, Network Testers participate in a second three week program where they receive additional overhead line training and company orientation.

The apprenticeship program is broken in to 6 six month classes that include classroom training, OJT, and testing to move from one class to the next. If an individual cannot pass the tests and other requirements, he will not advance. He will be given a second opportunity to pass and advance, If he cannot, he is rejected from the program. (He may be able to find other opportunity within CenterPoint). At the completion of the three year program, the employee becomes a journeyman Network tester.

Similarly, Apprentice Cable Splicers, selected from Helpers who have completed one year with the company, enter the Cable Splicer apprenticeship program. They, too initially attend a three week orientation program that includes pole climbing. After being accepted into the Apprenticeship program, cables splicers participate in a second three month program where they receive additional overhead line training and company orientation. At the completion of the three year program, the employee becomes a journeyman Cable Splicer.

Employees are required to review training modules for selected tasks (example: Splicing – See Attachment F ). The employee is responsible to review the module and discuss its contents with their supervisor. They will then take a written test to demonstrate their understanding of the material included in the module. ). The employee is responsible to review the module and discuss its contents with their supervisor. They will then take a written test to demonstrate their understanding of the material included in the module.

8.19.5 - Duke Energy Florida

Safety

Training

People

Duke Energy Florida uses a combination of classroom training and computer based training to deliver safety training. Experienced Network Specialists lead the delivery of some of the safety related training courses. Others are led by safety professionals.

The Lead Health and Safety Professional for the South Coastal Zone, which includes the Clearwater and St. Petersburg network systems, is responsible for oversight of safety training, safety standards, and safety records, including records of training completion and certifications.

Process

Training is delivered in classes and online. Safety related training includes the following (a partial list):

First Aid
CPR / AED
Environmental Awareness (full day training)
Confined Space Training
Manhole/Vault Entry

The Environmental training covers safe water, oil, and air procedures and requires a full day. First Aid, CPR and AED refreshers are normally accomplished at regularly scheduled Safety Meetings. In total, each employee has about one week of required safety training per year.

OSHA 269 forms, a Duke Energy Form, are on record for each field employee, are maintained by the department supervisors and include verified certification and training for the following:

CPR
First Aid
Job Site Briefings
Confined Space Entry
Trenching and Excavations Procedures
Personal Protective Equipment
Driving and Job Site Observations

The trainee’s supervisor signs a Record of Training (ROT) once training has been completed by the prescribed deadline. These training records are kept online. Forms and certifications are kept up to date as OSHA audits and inspects these forms once or twice a year.

Technology

To keep employees trained and refreshed on safety issues, the company uses MyTraining — an automated system that reminds employees through electronic alerts of what safety compliance training they have to fulfill, and the time period in which to complete that training.

All certifications and training records are kept on line and viewable with PlantView. Hard copy print outs are also available for inspection.

8.19.6 - Duke Energy Ohio

Safety

Safety Training

People

Duke Energy Ohio has technical trainers who run schools for Cable Splicers and Network Service persons.

Duke also has a technical skills specialist, who works closely with field resources on training issues (see Technical Skills Specialist).

Process

Some of the regulatory required training programs run at Duke are:

PCB handling,
lead awareness,
blood borne pathogens, and
manhole entry – confined space training.

Technology

The Dana Avenue facility contains a training center, built in 1990. The Center replicates the various types of construction field resources will encounter in the underground system, both network facilities and non-network facilities.

Within the center, trainers have the ability to energize facilities at operating voltages. As a safety feature, a man must hold a switch while facilities are energized – if the man let’s go to switch, a switch will automatically open, de-energizing the facilities.

The training facility can be used to practice fault locating techniques.

Below are some pictures of the training center.

Figure 1 and 2: Training Center - transformer

Figure 3 and 4: Training Center – Cable Samples

Figure 5 and 6: Training Center – Network Facilities

8.19.7 - Energex

Safety

Training / Safety Training

People

Improving safety is a key focus area for Energex, which is driven by the company CEO. The company has embarked upon a system wide effort to change their safety culture. In the recent past, Energex had experienced three safety incidents, resulting in worker injuries. The company is hoping to leverage the emotion from those events as a driver for changing the safety culture.

Energex has established a safety management system, which is a comprehensive framework that guides their safety approach, and addresses strategies for managing the hazards and risk associated with the design, construction, operation and maintenance of the system. Strategies such as their approach to safety training, incident investigation and response, and emergency preparedness and response, are guided by this framework.

Energex has recently reorganized their safety organization, consolidating a corporate safety group, a Service Delivery safety group, and a Power Plant Safety group to form one safety organization.

Process

Energex conducts certain statutory required training such as switchboard rescue (a training that focuses on how to rescue an employee who makes electrical contact while working in a low-voltage switchboard, such as those used on the low-voltage side of a medium-voltage substation, or located within a mini-pillar), confined space training, and asbestos training. Work leaders receive a one day training session in safety leadership, but a skills-based leading safety program is under development.

Safety training includes practices for dealing with lead conductors. While Energex is shifting to XLPE cabling, it still works routinely with lead (PILC cables within Brisbane). The company has established work practices to minimize employee exposure to lead. Example practices include wearing gloves, not smoking at the work site, and not heating the lead to a point where it becomes a dangerous vapor. Energex believes that as long as workers work within the confines of its required practices, they are safe from lead exposure. Employees (jointers) who work with lead receive annual blood tests for lead exposure.

Training Center

People

Energex has a comprehensive training facility called EsiTrain. (EsiTrain is a brand name, meaning Electric Supply Industry Training.) EsiTrain, a part of Energex, is a registered training organization. This means that Energex must conform with requirements of the Australia Qualifications Framework (AQF) in order to remain a registered training organisation, which allows them to issue a qualification to a trainee. This qualification is recognized throughout Australia and is “fully transportable.” So, an employee who receives a qualification as a cable jointer from EsiTrain would be recognized as a cable jointer outside of Energex.

EsiTrain offers the following two types of training:

Training that gives a qualification (conforms to the AQF), and training that is enterprise specific; that is, required by Energex, and beyond what is required by the AQF (e.g., work practice on accessing a confined space in the CBD network underground system).

The AQF provides a framework that describes “what” an employee must be able to do to achieve a certain qualification. EsiTrain delivers training that provides the “how” to perform the work.

Process

The training is based on Energex’s work practices, which are defined by the Work Practices group, and are well documented. EsiTrain works closely with company SMEs within the Work Practices group (and other areas), and company operating advisory committees (OACs) to build the detailed training curricula. For example, Energex has a work practice for preparing a cable joint. This work practice is written at a level of detail appropriate for a cable jointer who already has the underpinning skills associated with preparing a joint. EsiTrain instructional designers take the information from the work practice and develop it into a training course for apprentices and tradespersons by adding the underpinning knowledge that is required to prepare and complete a cable joint.

The work practices group also decides whether the work practice or task is something for which an employee must demonstrate competency, and if that competency needs to be periodically reviewed. High risk tasks may require frequent refreshers to renew competency, while lower risk tasks may only require a one-time training.

The EsiTrain team also factors in regulatory requirements in developing the training, much of these coming from the two following sources:

The Electrical Safety Legislation

The Electrical Safety Office administers and implements the electrical safety legislation and handles licensing, policing, and proof of the current employee competency and skills. It legislates what competencies in which employees must be proficient. It requires that employees are licensed, and that Energex can show proof of employee competency and currency.

Work place health and safety requirements (internal or external)

The Work Place Health and Safety group requires that Energex has a safe system of work. The Energex safe system of work provides input into which safety training employees should receive, such as training on proper PPE, for example. EsiTrain has experienced resources that serve as trainers located on site at their training facility. The backgrounds of the training positions vary, but they are normally filled by personnel with long term experience working for Energex.

For highly specialized training, Energex may engage the services of an external provider to conduct training. For example, Energex may hire Pirelli Cable to instruct cable jointers on the preparation of a large transmission joint.

Energex believes there is much consistency, validity and reliability in the training that is offered. Energex acknowledges that a challenge for the company is to ensure that any changes it incorporates into the training make sense operationally. The company addresses this by a range of actions including regular meetings with the operational business, embedment of the training group within the operational business and field rotations for technical trainers. This ensures the training staff understands the business needs and that the training meets expectations. Interfacing with OACs is a key step in assuring that business needs are satisfied in the training.

Technology

The EsiTrain facility itself is comprehensive, with various hands-on training facilities for overhead and underground distribution and transmission facilities (see Figure 1 through Figure 10).

Figure 1: EsiTrain facility

Figure 2: EsiTrain facility - SF6 switchgear training area

Figure 3 and 4: ESITrain facility - cable jointing instruction

Figure 5: ESITrain facility - cable jointing instruction

Figure 6: EsiTrain facility. Left side - low-voltage switchboard training area. Right side - pole top termination practice area

Figure 7: EsiTrain facility Manhole of PIT practice area. The dimensions of the work enclosure match the dimensions of a typical pit. Note the cable racks on the right side. Jointers practice assembling joints in this confined space

Figure 8: EsiTrain facility EsiTrain facility - overhead training yard. Parts are energized and parts are de-energized.

Figure 9: EsiTrain facility EsiTrain facility - underground training yard. (Under the pavilion)

Figure 10: Indoor training facility at Energex

8.19.8 - ESB Networks

Safety

Safety Training

People

ESB Networks has a Technical Training Centre, located in Portlaiose, which is about a one-hour drive outside of Dublin. This center provides training services for all of ESB Networks, including all technical training associated with the line worker craft, operations training, and training on equipment commissioning.

The technical training center develops and delivers training based on the needs of the organization, including LV, MV, and HV training, in areas including overhead line work (see Figure 1), cable work, HV substations, metering, driver training, and new equipment commissioning. (For example, it includes training on commissioning new automatic reclosers being installed as part of ESN Network’s distribution automation scheme.) The scope of training offered is driven by the training demand from around the ESB Networks system.

Figure 1: Training yard – overhead section

The center is staffed by approximately 12 training officers who deliver training in the various subjects offered at the center. The center also employs an information technology specialist, who both delivers training himself and supports other training initiatives associated with information technology.

In addition to the staff located at the Technical Training Centre, ESB Networks has three apprentice Training Coordinators located throughout ESB Networks.

Technology

The center itself consists of an indoor training hall, 11 classrooms, a cable workshop, HV testing laboratories, as well as physical representations of LV MV and HV equipment located in a training yard (see Figures 2 through 4). The yard has both a dead system, and a live system, where ESB Networks can train employees in working on voltages up to 48 kV. The training yard also consists of three mock stations, including an urban and rural station.

Figure 2: MV substation training yard

Figure 3: Training yard, UG junctions, top view

Figure 4: Training yard, UG junctions, side view

8.19.9 - Georgia Power

Safety

Safety Training

People

Organizationally, Georgia Power field resources that construct, maintain, and operate the network infrastructure fall within the Network Underground group, a central organization that is responsible for all network infrastructures, led by a manager. The Network Underground group is responsible for network underground infrastructure throughout the state of Georgia, including Atlanta, Athens, Macon, Savannah, and Valdosta. The Network Underground group is responsible for all of the manhole and duct line systems at GA Power, both network and non-network.

The Network Underground group consists of Test Engineers, Cable Splicers, Duct Line Mechanics, Civil Construction Engineers (for design and supervision), Test Technicians, Winch Truck Operator (WTOs), and Light Equipment Operators.

Cable Splicers perform work with the electrical infrastructure such as making up joints and terminations, including preparing lead splices. Cables splicers also pull cable and operate network equipment.

Duct Line Mechanics perform the civil aspects of the work, including duct line, manhole and vault construction. Duct Line Mechanics may also pull cable.

Process

Both the Cable Splicer and Duct Line job groups have a three-year job progression to achieve journeyman status. Both job families require a combination of time, on the job training, formal training and testing to advance. Training, broken into six-month modules, is delivered at the Georgia Power Network Underground training center, and taught by senior personnel. Each module has three-weeks of classroom training and requires extensive on-the-job training (OJT) to reinforce the skills presented in the formal training.

As a part of formal training, Apprentices must pass a test at the end of each six-month module before proceeding to the next level. Apprentices have two opportunities to pass each test. Apprentices receive a salary increase as they pass each level.

If an employee advances to Senior Duct Line Mechanic and wants to switch to Cable Splicer, he must go back through the three-year cable program and pass the apprentice program for a cable splicer. Georgia Power employs many more Cable Splicers than Duct Line Mechanics. The more popular job progression within the company is to move from a WTO to the Cable Splicer apprenticeship (more popular than the Duct Line Mechanic Apprenticeship, even though these positions pay about the same.) Note that the cable splicer job family is more technical than is the duct line mechanic family, and therefore requires more technical training, both formal and OJT.

The Network Underground group exposes apprentices to as many OJT tasks as possible. For example, the group will assign an apprentice with a Senior Cable Splicer to perform a particular task such as the preparation of a straight lead splice. Each Apprentice has an OJT book that contains a checklist of the various tasks that are required. The apprentice’s supervisor must sign and date the OJT checklist when the Apprentice has worked on a particular task. There are some tasks that are not formally part of the training program, but that the network underground leadership expects the apprentices to accomplish during their OJT. One such task is the proper racking of a manhole. It is the apprentice’s responsibility to ensure his supervisor signs and dates completed tasks in the OJT booklet.

Advancement is based on formal training and testing, not on completion of the OJT booklet; the supervisor can make arrangements to ensure each Apprentice receives the appropriate OJT tasks, whenever possible. Formal training often includes hands-on tasks, such as cable splicing. For example, two supervisors can evaluate an Apprentice’s splice and determine whether the apprentice prepared the splice correctly, examine the measurements, and make sure the splice meets Network Underground group specifications. Eventually, throughout the three-year program, these OJT tasks are completed.

Technology

Much of the formal training associated with the advancement to the Journeyman level for Cable Splicers and Duct Line Mechanics is performed at the Georgia Power Network Underground training facility in Atlanta (See Figure 1 through Figure 4.).

Figure 1: Training Center – Network Unit. Note cutaway of termination chamber

Figure 2: Training Center – Joint assembly practice area

Figure 3: Training Center – Full size manhole

Figure 4: Training Center – Termination assemble practice area

All Apprentices, as well as other Georgia Power employees, receive a number of safety-related courses, such as manhole entry, rescue, CPR, and storm emergency drills.

8.19.10 - National Grid

Safety

Safety Training

People

National Grid has two New York training centers, located in Schenectady and Syracuse.

National Grid has technical trainers who run formal training for Cable Splicers and Maintenance Mechanics.

National Grid’s Work Methods representatives work closely with field resources on training issues (see Work Methods).

Process

Employees receive a formal training book upon entering the cable splicer or maintenance mechanic job families and as they progress through the levels to journeyman.

For example, new hires into the program will receive required training such as CPR and first aid. After entering the Splicer school, for example, employees will receive formal training at the training centers as required. (See Job Progression for more information).

All positions start as a Helper for six months. Following this term, candidates take a review exam to determine if they are eligible to progress in the program. Employees can enter either the Cable Splicer program, or the Maintenance Mechanic program.

Each training school session (A, B, & C) is ten days long, typically held in Syracuse, NY. In addition, formal training classes are provided periodically throughout the progression series, such as network protector diagnostics (three days), safety training, etc. All field employees also participate in four days of Annual Expert Training in Schenectady, NY, regardless of their progression status (Helper through Supervisor).

Technology

The formal training Cable Splicers includes courses such as:

Cable Splicer A Training

Safety
Work area protection
Enclosed space training
Tools
Test equipment
Troubleshooting streetlights
Cable, joints and terminations
Hoisting and rigging
Electrical symbols

Cable Splicer B training

Safety
Dig Safe
Transformer theory
Rotation testing
Network system presentation
Pin pointer
Cable joints and terminations

Cable Splicer C training

Safety
Test equipment
Transformers
MOV arrestor’s
Corrosion
Tags
One line diagrams
Forms
Failure paths and causes
Clearance and control
Cable joints and terminations

Additionally, Cable Splicers receive a number of other safety and environmental related courses, including lead awareness and manhole entry and rescue.

National Grid has two training centers that contain classrooms and field equipment used for underground training. One is in Syracuse, NY, and one in Milbury, MA. Most training for UG NYE is held in Syracuse. In addition, Annual Expert Training and some miscellaneous training is conducted at the training center in Schenectady, NY.

8.19.11 - PG&E

Safety

Safety Training

People

PG&E has a well-equipped training center located at Livermore, home to all formal training of field personnel. For example, the formal training required for progression in the Cable Splicer family (known as the PG&E Academy) is conducted at the Livermore facility. In addition, they have a learning center located in San Ramon, which hosts some classroom-based training.

PG&E has technical trainers, who run the PG&E Academy for Cable Splicers,

PG&E’s Senior Distribution Specialists work closely with field resources on training issues (see Senior Distribution Specialist). The senior distribution specialist focused on underground maintains an office at the Livermore training center.

Process

The formal training associated with the PG&E Academy for apprentice cable splicers includes courses such as:

Introduction to Cable Splicing.
- Focuses on PILC cables and teaches the duties of the helper. Content includes manhole safety, job setup, the use of construction manuals and the PG&E Technical Information library (an on line system for accessing technical references), work procedures, and tools. Safety and quality are emphasized and participants must demonstrate the ability to build a lead splice, including using a spilt connector, wiping, and soldering. Students must pass written and practical tests.
Beginning Lead Splicing
- This course revisits the teachings from the Introduction to Cable Splicing course, and requires participants to build six major projects of increasing complexity selected by the course supervisor. This particular course is very hands on.
Intermediate Lead
- This course focuses on safety and revisits some of the teachings from prior courses. This course includes content on basic electricity, transformers, banking transformers, etc. It is a more theoretical course and less hands-on than prior courses.
Advanced Lead Training
- At this point, participants will have from 2 to 2 ½ years of training and experience. This course takes a step back and looks at the big picture. It includes content about the overall electrical system, various system configurations, fault indication, performing fault location including the process for thumping cable, as well as requiring the completion of a complicated splice.
Underground Fundamentals
- This course is provided to both Cable Splicers and Linemen. It focuses on non-lead cables and splices. It includes discussion of pre-molded splices, the function of stress cones, fault finding, cable spiking, grounding, and working with secondary. It is a “back to basics” course, even though it is offered later in the progression for cable splicers. Safety and quality are emphasized.

In addition to these courses, cable splicer apprentices receive a number of safety related courses, including lead exposure and confined space entry.

Technology

PG&E’s Livermore training center is well equipped, containing both classrooms, and field equipment used for hands on training of field personnel.

At the time of the EPRI practices immersion, PG&E was in the process of rebuilding the underground training yard both energized and non-energized portion.

Below are some pictures of the training center.

Figure 1 and 2: Training Center

Figure 3: Training Center – Cable Racks

Figure 4 and 5: Training Center – UG Switch

Figure 6: Training Center – Classroom

Figure 7 and 8: Training Center – UG Yard

8.19.12 - Portland General Electric

Safety

Safety Training

People

PGE uses a combination of on-the-job learning, formal training courses, drills, and computer training to ensure that employees have the knowledge they need and meet safety compliance requirements.

Process

Compliance training includes vault rescue, pole top rescue, and all other federally mandated training.

The vault rescue class is a company-wide training undertaken annually, and workers train in a shallow vault that does not always resemble the deeper network vaults. Accordingly, the CORE may augment this training with more specific vault rescue training geared to the network vaults, which would take place in a live vault because they do not have a deep test vault. PGE also provides annual computer-based training on confined space practices.

The Portland Service Center (PSC) brings in an external vendor to give lead and asbestos training, as needed.

PGE has invested in the documentation of safe work practices in the form of laminated sheets and notes for certain work/tasks, and it plans to expand this concept to include work practices specific to the CORE.

Fire Department Training: PGE periodically coordinates with the Portland Fire Department (PFD) for training, covering actions to take if there is a fire in a vault or manhole. In the past, PGE ran exercises on a yearly basis with the PFD, and it intends to reestablish these. If a vault rescue is needed, the Portland Fire Department (PFD) utilizes their own rescue equipment. The PFD’s response time is good because it operates from locations across the downtown area.

Emergency Drills: PGE conducts system-wide outage restoration drills once a year, prior to the fall storm season. In the past, this included some scenarios that involved the CORE network system. For example, a recent drill was substation-centric, and the tested scenarios simulated the outage of one of the stations supplying the network.

PGE also conducts annual earthquake drills, which are tabletop exercises organized by the Business Continuity Group. These drills do not always involve the network depending on the scenario chosen.

PSC has no written guidelines specifically related to unforeseen events occurring on the network.

During an emergency, PGE follows the principals of the incident command system (ICS) at the management level.

Overhead Training:

The CORE journeymen, who work almost exclusively with urban underground systems day to day, are required to support restoration work on the overhead system when needed. In restoration, they generally work in two-man crews addressing wire-down situations. In order to reinforce these skills, the CORE group conducts annual training on overhead systems in a de-energized training yard, where it reviews various overhead line work scenarios.

9 - Survey Results

9.1 - 2009 Survey Results

9.1.1 - Summary - Overview

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 1.2: Utility Type?

Question: 1.7: Total number of electrical customers served (Total Company)?

Question 1.8: Total number of customers served by Urban Networks Systems?

Question 1.9: Annual network load growth (%)?

Question 1.10: Total Approximate Peak Network load (MW)?

9.1.2 - Summary - Physical/General

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 2.1: What is the number of distinct conventional secondary networks (segregated street grids) served at your company?

Question 2.2: How many feeders make up the preferred network feeder group?

Question 2.3: What is the number of spot networks served at your company? (“Spot network” in this question defined as a service to a facility from a single vault and a common secondary bus without connection to the street grid)

Question 2.4: Network primary operating voltage(s)?

Question 2.5: Primary cable types? (Check all that apply)

Question 2.6: Number of network distribution transformers?

9.1.3 - Planning

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 3.1: Do you have a distinct Network Planning group, or is network planning performed by a general planning organization?

Question 3.2: How many people perform network planning at your company?

Question 3.3: To what level of contingency do you plan your network?

Question 3.4: In your typical network design, do all primary feeders sourcing a given network originate from the same substation, or do you source networks from multiple stations?

Question 3.5: Are network primary feeders planned and designed as dedicated feeders?

Question 3.6: Does your design limit the number of primary feeders entering a vault through a given single duct bank?

Question 3.7: Do you have any current plans to expand the size of your network? (Increase the footprint of the territory served by the network)

Question 3.8: Which of the following best describes your approach to loading your network? (Please check one box only)

Question 3.9: Do you have any network “system hardening” initiatives underway?

Question 3.10: Do you use software to perform network circuit analysis? (Load flow studies, voltage drop analysis, etc)

Question 3.11: If Yes, are you using the software for..?

Question 3.12: Does the same engineer(s) who analyzes the primary system also analyze the secondary system?

Question 3.13: Do you calculate minimum available fault current at the fringes of the street secondary network cables (208Y/120 V) to assure self-clearing of street network cable failures?

Question 3.14: If you are using load flow software, please indicate which software product(s) you are using.

9.1.4 - Design

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 4.1: Do you have a dedicated / distinct network design group? Or are your network designers part of a design group that also performs non network design?

Question 4.2: If yes, does your network design group do both electrical and civil designs?

Question 4.3: How many people perform Network Design at your company?

Question 4.4: Does your network utilize vaults located:

Question 4.5: What type of design are you using for new civil structures such as manholes and vaults?

Question 4.6: If your network utilizes subsurface vaults, do you use automatic sump pumps to clear water accumulation?

Question 4.7: If Yes, does your standard design call for oil sensors on sump pumps in vaults that house oil containing equipment?

Question 4.8: If yes, do these sensors function to prevent the pumping of oil into the street?

Question 4.9: Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers)

Question 4.10: In a building vault, do you tie your neutral in with the building steel / ground system?

Question 4.11: Does your typical network design utilize: (see Graph below)

Question 4.12: Does your network transformer specification call for a one or two chamber design for the primary termination and switch?

Question 4.13: Have you incorporated skid free vault and manhole covers into your civil designs?

Question 4.14: If so, are you retrofitting older existing covers?

9.1.5 - Construction

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 5.1: Do you have a distinct field group focused on the construction, maintenance and operation of the network? Or are your field workers part of a group that also works with non network systems?

Question 5.2: Total number of Network field electrical workers (do not count “civil” workers)

Question 5.3: Do you contract any network electrical (not civil) construction work?

Question 5.4: If using contractors, what % of your total network electrical work is contracted?

Question 5.5: Total number of Network civil construction workers

Question 5.6: Do you contract any network civil construction work?

Question 5.7: How many hours of training (on average, per person) does your field force receive in a year?

Question 5.8: Do you routinely conduct post construction audits to ascertain / assure the quality of the construction?

Question 5.9: Do you have a formal process for reporting construction standards or material specifications deficiencies?

Question 5.10: Do you have a process for inspecting or testing incoming network materials?

Question 5.11: Do you utilize Mobile Data Units in your network fleet?

Question 5.12: If so, what system are you using?

Question 5.13: Do you utilize work management software to assist in assigning resources, scheduling, and managing the execution of network projects?

Question 5.14: What work management system are you using?

9.1.6 - Maintenance

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 6.1: Do you have regularly scheduled maintenance and inspection program(s) for your network system?

Question 6.2: In determining your maintenance frequency, do you perform a risk assessment of your individual equipment, manholes, vaults, etc and vary your maintenance approach based on that risk?

Question 6.3: Do you have a documented, up to date maintenance guidelines for performing maintenance on network equipment? (Example: network transformer maintenance guideline)

Question 6.4: Do you have metrics in place to assess the performance of the network system?

Question 6.5: Is network maintenance, inspection and testing performed by (Check One)?

Question 6.6: If using contractors, what % of your total network maintenance work is contracted?

Question 6.7: Do you regularly perform primary cable diagnostic testing?

Question 6.8: If yes, what is the frequency of cable diagnostic testing?

Question 6.9: In what applications will you perform cable diagnostic testing?

Question 6.10: If yes, please indicate / describe what testing techniques you use.

Question 6.11: If you perform withstand testing, describe how you determine which cables to test.

Question 6.12: When testing cable, what are the expected leakage currents that you would expect to see for healthy cables?

Question 6.13: Do you regularly perform Vault inspections?

Question 6.14: If yes, what is the frequency of the Vault inspections?

Question 6.15: Do you regularly perform Manhole inspections?

Question 6.16: If yes, what is the frequency of the Manhole inspections?

Question 6.17: Do you regularly perform Primary cable and splice / connection infrared inspections?

Question 6.18: If yes, what is the frequency of Infrared testing?

Question 6.19: Do you regularly perform secondary cable and splice / connection infrared inspections?

Question 6.20: If yes, what is the frequency of secondary infrared testing?

Question 6.21: Do you regularly perform Secondary / Grid cable testing?

Question 6.22: If yes, what is the frequency of secondary cable / grid testing?

Question 6.23: If yes, please indicate / describe what testing techniques you use.

Question 6.24: Do you perform heat gun checks as part of your preventive maintenance programs?

Question 6.25: Do you perform cable limiter continuity checks as part of your preventive maintenance program?

Question 6.26: Do you perform Equipment Fluid sampling and testing (such as transformer oil) as part of your maintenance?

Question 6.27: If yes, what is the frequency of sampling?

Question 6.28: If yes, please indicate which tests you perform

Question 6.29: If you perform analysis of fluid samples, what trigger level or criteria are used to determine when:

Question 6.30: Do you regularly perform pressure testing to identify leaks in the primary termination chamber, ground switch chamber, and/or transformer tank?

Question 6.31: If yes, what is the frequency of testing?

Question 6.32: Do you regularly perform Network protector maintenance and testing?

Question 6.33:If yes, what is the frequency of testing?

Question 6.34: When you perform Network Protector maintenance, please indicate which of the following you do. (See graph below)

Question 6.35: Does your NP maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for back feed voltage to assure that the network protectors function correctly (automatically open)?

Question 6.36: Do you use a diagnostic camera to ascertain the condition of ducts and conduits?

Question 6.37: Please list any other routine network maintenance or inspections you are performing, and provide the frequency.

Question 6.38: Are you currently implementing replacement programs for any of your network equipment?

Question 6.39: If Yes, Please indicate which equipment is being replaced.

9.1.7 - Operations

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 7.1: Do you have a dedicated operator within your control room for operating the network?

Question 7.2: Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 7.3: If you remotely monitor information about network devices, please indicate what information you are monitoring. (Check all that apply)

Question 7.4: If you are using remote sensors, briefly describe what type of sensing device(s) you are using.

Question 7.5: If you are using remote sensing, how is the information communicated? (check all that apply)

Question 7.6: If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA System?

Question 7.7: Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker?

Question 7.8: If so, what devices are remotely controlled?

Question 7.9: If you do remotely control devices, indicate from which location(s)you have the ability to do so.

Question 7.10: If you are remotely monitoring and/or controlling network equipment, what vendor/system are you using?

Question 7.11: Do your company’s periodic outages drills normally include network situations?

Question 7.12: If not, do you routinely conduct drills for key network processes such as emergency response?

Question 7.13: Do you have documented, up to date procedures for responding to network emergencies?

Question 7.14: Do you have a procedure that provides guidance in responding to vault fires?

Question 7.15: If so, does it provide guidance to an Operator indicating when it is necessary to de-energize a network due to the emergency?

Question 7.16: Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders)

Question 7.17: Do you use separable connectors (such as “T” Bodies and elbows) in your network system?

Question 7.18: Have you experienced failures with these connectors / connector systems (such as 600A T - bodies)?

Question 7.19: If Yes, please rank the primary causes of the failures you’ve experienced.

9.1.8 - Safety

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 8.1: How many days per year of safety training do your network field personnel receive per person?

Question 8.2: Please indicate the type(s) of safety meetings you conduct. Check all that apply.

Question 8.3: Do you have a “safety person”, (either a fulltime safety professional, or other employee assigned to a safety role) focused on the network?

Question 8.4: If you have a safety person focusing on the network, is this person a full time safety professional, or another employee assigned to a safety role?

Question 8.5: Do you require your network crews to wear flame retardant (FR rated) clothing?

Question 8.6: If so, what clothing system level is required to work in the network (routine work)?

Question 8.7: Do you require incremental face protection, such as a face shield, or goggles and balaclava when working in the network?

Question 8.8: Is a first aid kit on hand when a crew is working in a vault?

Question 8.9: What procedures / tools do you use to determine that a cable is de energized?

Question 8.10: Do you use continuous air quality monitoring when working in a Manhole? Vault?

Question 8.11: Do you require the use of a lifting crane and worker harnesses when working in an Underground Manhole? Underground Vault?

9.1.9 - Distributed Generation

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 9.1: Do you allow inverter based generation to connect to the 208Y/120-volt area network?

Question 9.2: Do you allow induction generators to connect to the 208Y/120-volt area network?

Question 9.3: Do you allow synchronous generators to connect to the 208Y/120-volt area network?

Question 9.4: If you do allow distributed generators to connect to your network, do you have a written guideline that defines the interconnection requirements?

Question 9.5: Do you allow time delay tripping of network protectors that are supplying 208Y/120-volt area networks?

Question 9.6: Are there any administrative codes, rules, regulations, etc established by Public Utility Commissions, Boards of Public Utilities, etc. that cover the connection of co generation to area networks in your service territory?

9.1.10 - Practices of Note

Survey Title : Urban Network Practices Inventory, 2009

Summary Overview Questions 1.1 - 1.10
General/Physical Questions 2.1 - 2.6
Planning    Questions 3.1 - 3.14
Design       Questions 4.1 - 4.14
Construction Questions 5.1 - 5.14
Maintenance Questions 6.1 - 6.39
Operations Questions 7.1 - 7.19
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.6
Practices of Note Questions 10.1

Question 10.1: How many days per year of safety training do your network field personnel receive per person?

9.2 - 2012 Survey Results

9.2.1 - Summary - Overview

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 1.2: Utility Type?

Question 1.7: Total number of electrical meters served (Total Company)?

Question 1.8: Total number of customers served by Urban Networks Systems?

Question 1.9: Annual network load growth (%)?

Question 1.10: Total approximate Peak network load (MW)?

Question 1.11: Total installed capacity of your network (MVA)?

Question 1.12: Average primary circuit loading under no contingencies? (In percent of circuit rating)

Question 1.14: Average primary circuit loading under the worst contingency that is planned for? (Percent of circuit rating)

9.2.2 - Summary - Physical/General

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 2.1: Total number of network feeders?

Question 2.2: What is the number of distinct conventional secondary networks (segregated street grids) served at your company?

Question 2.3: Total Number of Network groups?

Question 2.4: How many feeders make up the network feeder group?

Question 2.5: Total number of network distribution transformers?

Question 2.6: What is the number of spot networks served at your company? (“Spot network” in this question defined as a service to a facility from a single vault and a common secondary bus without connection to the street grid)

Question 2.7: How many feeders (minimum) supply your spot networks?

Question 2.8: Network primary operating voltages(s)? (Check all that apply)

Question 2.9: Please indicate the percentage of each cable type that comprise your network primary cable system (Total should equal 100%)

Question 2.10: For primary cable, which of the following do you utilize (current standards)? check all that apply

Question 2.11: Do you use low smoke zero halogen cable in your secondary?

9.2.3 - Planning

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 3.1: Do you have a distinct Network Planning group, or is network planning performed by a general planning organization?

Question 3.2: To what level of contingency do you plan your network?

Question 3.3: In your typical network design, do all primary feeders sourcing a given network originate from the same substation, or do you source networks from multiple stations?

Question 3.4: Are network primary feeders planned and designed as dedicated feeders?

Question 3.5: Do switch points exist on your network primary feeders for the purpose of sectionalizing a network feeder?

Question 3.6: Do your network primary feeders have tie points with other network feeders?

Question 3.7: If sectionalizing or tie points are installed on your network system, what kind of switches are you using?

Question 3.8: If sectionalizing or tie points are installed on your network system, are the switches manually or automatically controlled?

Question 3.9: Does your design limit the number of primary feeders entering a vault through a given single duct bank?

Question 3.10: In your design, do you allow primary and secondary routed through the same duct bank?

Question 3.11: Are you currently actively planning to increase, decrease, or maintain the geographical size of your network?

Question 3.12: Which of the following best describes your approach to loading your network? (Please check one box only)

Question 3.13: Do you have any network “system hardening” initiatives underway? (for example, rebuilding manholes in flood prone areas, rehabbing deteriorated ceilings, etc.)

Question 3.14: Have you developed any reliability metrics for assessing the performance of the network system?

Question 3.15: Do you use software to perform network circuit analysis? (Load flow studies, voltage drop analysis, etc.)

Question 3.16: If Yes, are you using the software for; • Primary Analysis Only • Secondary Analysis Only • Both Primary and Secondary Analysis

Question 3.17: If you are using load flow software, please indicate which software product(s) you are using.

Question 3.18: How do you collect network load data for modeling purposes?

Question 3.19: Do you perform contingency analysis; that is, review loading and voltage with each feeder out of service?

Question 3.20: In your network system analysis, do you model operation of NP’s due to reverse flows in your system?

Question 3.21: Do you calculate minimum available fault current at the fringes of the street secondary network cables (208Y/120 V) to assure self-clearing of street network cable failures?

9.2.4 - Design

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 4.1: Do you have a dedicated / distinct network design group? Or are your network designers part of a design group that also performs non network design?

Question 4.2: If yes, does your network design group do both electrical and civil designs?

Question 4.3: Does your network utilize vaults located:

Question 4.4: What type of design are you using for new civil structures such as manholes and vaults? Check all that apply.

Question 4.5: What is the size of a typical network vault (new design?)

Question 4.6: If your network utilizes subsurface vaults, do you use automatic sump pumps to clear water accumulation?

Question 4.7: If Yes, does your standard design call for oil sensors on sump pumps in vaults that house oil containing equipment?

Question 4.8: If yes, do these sensors function to prevent the pumping of oil into the street?

Question 4.9: Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers)

Question 4.10: In designing your network vault, what ground resistance do you require from the ground system inside the vault?

Question 4.11: In a building vault, do you tie your neutral in with the building steel / ground system?

Question 4.12: For the primary termination and switch, does your network transformer specification call for a

Question 4.13: Are you using a separately mounted primary switch (not part of the transformer unit)?

Question 4.14: Does your network transformer specification call for units with taps?

Question 4.15: Have you incorporated skid free vault and manhole covers into your civil designs?

Question 4.16: If so, are you retrofitting older existing covers?

Question 4.17: Are you using manhole cover restraints in parts of your system?

Question 4.18: Do you use cable limiters in your network secondary system(s)?

Question 4.19: If you use cable limiters, do you perform a protection coordination study between the NP fuse, cable limiters and the station’s feeder relay?

Question 4.20: If you use cable limiters please indicate where you install them (check all that apply)

Question 4.21: What type of secondary connection technology is used on your networks?

9.2.5 - Construction

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 5.1: Total number of Network field electrical workers (do not count “civil” workers)

Question 5.2: Do you contract any network electrical (not civil) construction work?

Question 5.3: If using contractors, what % of your total network electrical work is contracted?

Question 5.4: Do you contract any network civil construction work?

Question 5.5: If using contractors, what % of your total network civil construction work is contracted?

Question 5.6: Not counting training that is part of your apprentice programs, how many hours of training (on average, per person) does your network field force receive in a year?

Question 5.7: Do you routinely conduct post construction audits to ascertain / assure the quality of the construction?

Question 5.8: If Yes, what are the major items that are assessed during a post construction audit?

Question 5.9: Do you have a process for inspecting or testing incoming network materials?

Question 5.10: If yes, what material is inspected or tested?

Question 5.11: Do you utilize Mobile Data Units in your network fleet?

Question 5.12: Do you use heat resistant / fire proof tape in your network cable systems?

Question 5.13: When you prepare a splice, do you track and record who prepared the splice?

9.2.6 - Maintenance

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 6.1: Do you have a documented, up to date maintenance guidelines for performing maintenance on network equipment? (Example: network transformer maintenance guideline)

Question 6.2: In determining your maintenance frequency, do you perform a risk or condition assessment of your individual equipment, (manholes, vaults, etc), and vary your maintenance approach based on that assessment?

Question 6.3: Is network maintenance, inspection and testing performed by (Check One)?

Question 6.4: If using contractors, what % of your total network maintenance work is contracted?

Question 6.5: In what applications will you perform network primary cable diagnostic testing? (Check all that apply)

Question 6.6: If you are performing periodic primary network cable withstand testing, what is the frequency of the testing?

Question 6.7: Please indicate / describe what testing techniques you use.

Question 6.8: Do you regularly perform Vault inspections?

Question 6.9: If yes, what is the frequency of the Vault inspections?

Question 6.10: Do you regularly perform Manhole inspections?

Question 6.11: If yes, what is the frequency of the Manhole inspections?

Question 6.12: Do you perform Infrared / heat gun checks as part of your preventive maintenance programs?

Question 6.13: Do you regularly perform Primary cable and splice / connection infrared inspections?

Question 6.14: If yes, what is the frequency of Infrared testing?

Question 6.15: Do you regularly perform secondary cable and splice / connection infrared inspections?

Question 6.16: If yes, what is the frequency of secondary infrared testing?

Question 6.17: Do you regularly perform Secondary / Grid cable testing?

Question 6.18: If yes, what is the frequency of secondary cable / grid testing?

Question 6.19: Do you perform cable limiter continuity checks as part of your preventive maintenance program?

Question 6.20: Do you perform Equipment Fluid sampling and testing (such as transformer oil) as part of your maintenance?

Question 6.21: If yes, what is the frequency of sampling?

Question 6.22: If yes, please indicate which of these tests you perform

Question 6.23: Do you regularly perform pressure testing to identify leaks in the primary termination chamber, ground switch chamber, and/or transformer tank?

Question 6.24: If yes, what is the frequency of testing?

Question 6.25: Do you regularly perform Network protector maintenance and testing?

Question 6.26: If yes, what is the frequency of testing?

Question 6.27: When you perform Network Protector maintenance, please indicate which of the following you do.

Question 6.28: During your network Protector testing, do you know/record how fast the NP opens (in terms of cycles usually) when it sees a reverse power flow?

Question 6.29: Does your NP maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for backfeed voltage to assure that the network protectors function correctly (automatically open)?

Question 6.30: Are you using cameras as part of your manhole inspections?

Question 6.31: Do you use a diagnostic camera to ascertain the condition of ducts and conduits?

Question 6.32: Are you currently implementing replacement programs for any of your network equipment?

Question 6.33: If Yes, Please indicate which equipment is being replaced. (Check all that apply)

Question 6.34: Do your crews utilize tablets or laptop computers for maintenance?

Question 6.35: Is your record keeping done electronically or manually?

9.2.7 - Operations

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 7.1: Do you have a dedicated operator within your control room for operating the network?

Question 7.2: Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 7.3: If you remotely monitor information about network devices, please indicate what information you are monitoring. (Check all that apply)

Question 7.4: If you are using remote sensing, how is the information communicated? (check all that apply)

Question 7.5: If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA System?

Question 7.6: Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker?

Question 7.7: If so, what devices are remotely controlled?

Question 7.8: If you do remotely control devices, indicate from which location(s) you have the ability to do so:

Question 7.9: If you are remotely monitoring and/or controlling network equipment, what vendor/system are you using?

Question 7.10: Do you have documented, up to date procedures for responding to network emergencies?

Question 7.11: Do you perform periodic drills that include network situations, such as a network outage or network manhole fire?

Question 7.12: Do you have a means to do a group feeder pickup in the event of a network outage? (Multiple feeders)

Question 7.13: For 480 V network protectors, do you de-energize the primary before removing the network protector fuses?

Question 7.14: For 208 V network protectors, do you de-energize the primary before removing the network protector fuses.

9.2.8 - Safety

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 8.1: Do you have a “safety person”, (either a fulltime safety professional, or other employee assigned to a safety role) focused on the network?

Question 8.2: If you have a safety person focusing on the network, is this person a full time safety professional, or another employee assigned to a safety role?

Question 8.3: Do you require your network crews to wear flame retardant (FR rated) clothing?

Question 8.4: If so, what clothing system level is required to work in the network (routine work)?

Question 8.5: Do you require a incremental face protection, such as a face shield, or goggles and balaclava when working in the network?

Question 8.6: For 480 V NP’s, does your company require NP crews to wear Flash Suits when they open an energized NP?

Question 8.7: Is a first aid kit on hand when a crew is working in a vault?

Question 8.8: Do your crews have an AED (Automated External Defibrillator) on their vehicles?

Question 8.9: What procedures / tools do you use to determine that a cable is de-energized?

Question 8.10: Please indicate which of these manhole / vault entry procedures you utilize:

Question 8.11: Please indicate which of the following design, operational or work procedure changes you have implemented to address network arc flash issues

9.2.9 - Distributed Generation

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 9.1: Do you allow inverter based generation to connect to the 208Y/120-volt area network?

Question 9.2: If yes, What is the maximum allowed size for the inverter based generation at any given service?

Question 9.3: Do you allow the inverter based generation to feed real power back into the secondary of the area network under unfaulted conditions?

Question 9.4: Do you place any limits on the total amount of inverter based generation that can be connected to any given area network? If so, how is that defined?

Question 9.5: Do you allow induction generators to connect to the 208Y/120-volt area network?

Question 9.6: If yes, What is the maximum allowed size for the induction generation at any given service?

Question 9.7: Do you allow the induction generator to feed real power back into the secondary of the area network under unfaulted conditions?

Question 9.8: Do you place any limits on the total amount of induction generation that can be connected to any given area network? If so, how is that defined?

Question 9.9: Do you allow synchronous generators to connect to the 208Y/120-volt area network?

Question 9.10: If you do allow distributed generators to connect to your network, do you have a written guideline that defines the interconnection requirements?

Question 9.11: Do you allow time delay tripping of network protectors that are supplying 208Y/120-volt area networks?

Question 9.12: Are there any administrative codes, rules, regulations, etc established by Public Utility Commissions, Boards of Public Utilities, etc. that cover the connection of co generation to area networks in your service territory?

9.2.10 - Practices of Note

Survey Title: Urban Network Practices Inventory, 2012

Summary Overview Questions 1.2 & 1.7-1.13
General/Physical Questions 2.1 - 2.11
Planning    Questions 3.1 - 3.21
Design       Questions 4.1 - 4.21
Construction Questions 5.1 - 5.13
Maintenance Questions 6.1 - 6.35
Operations Questions 7.1 - 7.14
Safety Questions 8.1 - 8.11
Distributed Generation   Questions 9.1 - 9.12
Practices of Note Questions 10.1

Question 10.1: Please describe any practices of note being utilized to plan, design, construct, operate, or maintain your network system.

9.3 - 2015 Survey Results

9.3.1 - Summary - Overview

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 005: Total Number of Electrical Meters Served (Company Total)

Question 006: Total Number of Electrical Meters Served by Urban Networks Systems?

Question 007: What is the total installed capacity of your network (MVA)?

Question 008: Total Approximate Peak Network Load (MW)?

Question 009: Within your organization, do you have a distinct Network Engineering and Network Planning groups?

Question 010: Which of the following functions does your Network Engineering/Planning group(s) perform? (check all that apply)

Question 011: Within your company, how many Full Time Equivalent resources (FTEs) make up the following functions?

Question 012: Within your company, what percentage of the work for each task is contracted?

Question 013: Within your company, are the following groups centralized or decentralized?

9.3.2 - Summary - Physical/General

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 014: Total number of Network Feeders?

Question 015: How many substations serve your networks?

Question 016: How many distinct conventional distribution secondary network systems (street grids) does your company operate?

Question 017: What is average number of feeders supplying a conventional network (street grid)?

Question 018: What are your network primary operating voltage(s)? (Check all that apply)

Question 019: Do you have networks with primary operating voltages above 15 kV in any of the following configurations?

Question 020: What are your Network Secondary Voltage(s)? (Check all that apply)

Question 021: Total Number of Network Distribution Transformers?

Question 022: What is the average loading during peak for a network transformer? (% of transformer rating)

Question 023: What is the maximum loading you will allow by design for a network transformer under emergency loading?

Question 024: What is the number of secondary spot networks served at your company?

(“Spot network” in this question defined as a service to a facility from a group of network transformers feeding a common bus with little or no connections to a distribution street network.)

Question 025: What is the typical number of feeders required to supply your spot networks?

Question 026: Please indicate the percentage of each cable type that comprise your network primary cable system

Question 027: If you entered Other for the previous question, please specify other conductors and percentages.

Question 028: For primary cable, which of the following do you utilize (current standards)? (check all that apply)

Question 029: Percentage of each Cable Type that Comprise Your Network Secondary Cable System

Question 030: If you entered Other for the previous question(Question029), please specify other conductors and percentages.

Question 031: XLPE insulated conductors (In-network): Installed cables differing from normal operating temp. ratings? (normal operating temp. rating, different rating installed)

If you utilize XLPE insulated conductors in your network, and have installed cables with different normal operating temperature ratings, please list the different normal operating temperature ratings (in Celsius) associated with the different installed cables separated by commas.

Question 032: Do you use faulted circuit indicators (FCIs)? (Check all that apply)

9.3.3 - Planning

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 033: To what level of circuit loading (in % rated circuit capacity) do you design for normal conditions?

Question 034: To what level of circuit loading (in % rated circuit capacity) do you design for a contingency situation?

Question 035: To what level of contingency do you plan your network?

Question 036: To what level of contingency do you plan your spot network (at peak load)?

Question 037: In your typical network design, do all primary feeders sourcing a given network originate from the same substation, or do you source networks from multiple stations?

Question 038: Are network primary feeders planned and designed as dedicated feeders?

Question 039: Do switch points exist on your network primary feeders for the purpose of sectionalizing a network feeder?

Question 040: Outside the substation, do your network primary feeders have tie points with other network feeders?

Question 041: If primary sectionalizing or tie points are installed on your network system, are the switches manually or automatically controlled? (check all that apply)

Question 042: Does your design limit the number of primary feeders entering a vault or a manhole?

Question 043: In your design, do you allow primary and secondary routed through the same duct bank?

Question 044: If you answered yes to the previous question, how do the primary and secondary cables enter the manhole?

Question 045: Which of the following best describes your approach to loading your network?

Question 046: Have you developed any reliability metrics for assessing the performance of the network system?

Question 047:Do you use software to perform network circuit analysis? (Load flow studies, voltage drop analysis, etc)

Question 048: If Yes, are you using the software for…

Question 049: How do you collect network load data for modeling purposes? (check all that apply)

Question 050: In your network system analysis, do you model operation of Network Protectors due to reverse flows in your system?

9.3.4 - Design

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 051: Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers) (check all that apply)

Question 052: In designing your network vault, what ground resistance do you require from the ground system inside the vault?

Question 053: What neutral sizing standard is used in your designs?

Question 054: What is the X/R impedance design requirement used for substations used to feed network systems?

Question 055: If you have primary termination and switch on your network transformers, does your specification call for?

Question 056: Are you using a separately mounted primary switch (not part of the transformer unit)?

Question 057: Have you incorporated skid free vault and manhole covers into your civil designs?

Question 058: If so, are you retrofitting older existing covers with skid free ones?

Question 059: Have you incorporated vented vault and manhole covers into your civil designs?

Question 060: If you answered yes to the previous question, what criteria is used to select locations for vented cover installations?

Question 061: Are you retrofitting older existing covers with vented covers?

Question 062: Are you using manhole cover restraints in parts of your system?

Question 063: Are you retrofitting older existing covers with cover restraint systems?

Question 064: Are you performing targeted cover restraint retrofits based on (check all that apply):

Question 065: Do you use cable limiters in your network secondary system(s)?

Question 066: If you use cable limiters please indicate where you install them (check all that apply)

Question 067: If you use cable limiters, do you perform a protection coordination study between the Network Protector fuse, cable limiters, and the station’s feeder relay?

Question 068: If you use cable limiters, do you rely on the conductor to burn clear as part of your secondary network protection scheme?

Question 069: If you use limiters, do you perform studies of anticipated bolted fault currents in the secondary to assure that faulted sections burn clear or are isolated by appropriately sized cable limiters?

Question 070: By your estimation, what percentage of the time are cable limiters effective?

Question 071: Do you use cable limiters with a viewing port which provides a visual indication of a blown limiter (such as the Tyco Smart Limiter) on your network?

Question 072: What type of secondary connection technology is used on your networks?

Question 073: Are you using arc proof tape and/or fireproof chemicals in your network designs?

Question 074: Do you use high flash point fluids in the fluid filled tanks of network equipment?

Question 075: Do you seal ducts in your manhole system (in addition to sealing customer service ducts)?

Question 076: If you seal ducts, is the reason to minimize the migration of combustible gases through the manhole / duct system?

Question 077: Do you have any additional network “system hardening” initiatives underway?

Question 078: Do you have a sump pump and discharge system inside your street vaults?

Question 079: If you do discharge from your street vaults, do you use any filtering systems or systems which detect the presence of oil and consequently prevent discharge to the street?

9.3.5 - Maintenance

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 080: In determining your maintenance frequency, do you perform a risk or condition assessment of your individual equipment, (manholes, vaults, etc.), and vary your maintenance approach based on that assessment?

Question 081: In what applications will you perform network primary cable diagnostic testing?

Question 082: If you are performing periodic primary network cable withstand testing, what is the frequency of the testing?

Question 083: If you are performing periodic primary network cable withstand testing, what is the duration of the testing? (in minutes)

Question 084: Please indicate / describe what testing techniques you use.

Question 085: Please indicate if your company performs the following activities on a routine basis and at what frequency.

Question 086: If you perform secondary/grid cable testing, can you please describe testing?

Question 087: Are performing periodic secondary network cable withstand testing?

Question 090: If you perform Equipment Fluid Sampling and Testing, please indicate which of these tests are performed?

Question 091: Do you perform cable limiter continuity checks (amp checks) as part of your preventive maintenance program?

Question 092: Please indicate the approximate percentage of each network protector type used in your company for your network secondary cable system

Question 093: When you perform Network Protector Maintenance, please indicate which of the following you do.

Question 094: Are you using Infrared (iR) technology as part of your manhole and vault assessment process?

Question 095: If you use iR technology, what technologies do you use?

Question 096: If you perform iR testing, which activities do you perform iR testing?

Question 097: If yes, which equipment are you using iR on?

Question 098: Does your Network Protector maintenance include conducting periodic “drop tests”, whereby a primary feeder is opened, and measurements are taken for backfeed voltage to assure that the network protectors function correctly(automatically open)

Question 099: Are you using cameras as part of your manhole inspections?

Question 100: Do you use a non-iR diagnostic camera to assess the condition of ducts and conduits?

Question 101: Do you track cable and equipment failures?

Question 102: If you track equipment failures, which of the following do you track?

Question 103: Please provide failures rates/year (if tracked) for the list below:

Question 104: Please describe the failure investigation process and what drives corrective actions.

Question 105: Are you implementing targeted replacement programs for any of the following equipment?

9.3.6 - Operations

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 106: For your field craft positions, which of the following best describes your approach?

Question 107: Do you have a dedicated operator within your dispatch center/control room for operating the network?

Question 108: Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 109: If you remotely monitor information about network devices, please indicate what information you are monitoring.

Question 110: If you are remotely monitoring information about network equipment beyond the primary feeder breaker, is this information tied in with your SCADA System?

Question 111: Do you have the ability to remotely control switches, network protectors or other devices on your network system primary beyond the substation breaker?

Question 112: If so, what devices are remotely controlled?

Question 113: For 480 V network protectors, do you de-energize the network transformer before removing the network protector fuses?

Question 114: For 208 V network protectors, do you de-energize the network transformer before removing the network protector fuses.

Question 115: Do you require the network primary to be de-energized prior to commencing work inside of a manhole or vault?

Question 116: Do you have documented, up to date procedures for responding to network emergencies?

Question 117: Do you perform periodic drills that include network situations, such as a network outage or network manhole fire?

Question 118: Do you perform a network emergency drill at least once a year where your company will simulate a network emergency with key individuals in a room and everyone discusses how they would respond?

Question 119: Do you have a documented procedure for company personnel responding to a smoking manhole (“a smoker”)?

Question 120: Do you have a documented procedure for company personnel responding to a fire in a manhole?

Question 121: Do you have a documented procedure for first responders responding to smoking manholes or fires in manholes?

Question 122: In response to a manhole/vault fire, do you require the cables in the manhole/vault to be deenergized before first responders attempt to extinguish the fire?

Question 123: In response to a manhole/vault fire, do you allow the fire company to pour water into the hole upon arrival?

Question 124: In response to a manhole/vault fire, which of the following methods of fire extinguishment do you utilize?

Question 125: If there is a network emergency, is there a Network Shutdown protocol?

9.3.7 - Safety

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 126: Do you require your network crews to wear flame retardant (FR rated) clothing?

Question 127: If so, what clothing system level is required to work in the network (routine work)?

Question 128: Please indicate which of these manhole / vault entry procedures you utilize:

Question 129: Please indicate which of the following design, operational or work procedure changes you have implemented to address network arc flash issues:

Question 130: Do you require your network engineers to obtain their Professional Engineering (PE) license before they can move to more senior engineering positions?

Question 131: Do you have a formalized training program for cable splicers, Network Mechanics and other individuals working on the network system?

Question 132: Is advancement from apprentice to the journey worker level in a given period of time required as part of the job function (i.e. – automatic progression job)?

Question 133: If you have an automatic progression, what is the amount of time required to achieve the journey worker level?

Question 134: Can you briefly describe your training program for network workers?

9.3.8 - Practices of Note

Survey Title: EPRI Urban Network Practices Survey, 2015

Summary Overview Questions 1 - 13
General/Physical Questions 14 - 32
Planning Questions 33 - 50
Design Questions 51 - 79
Maintenance Questions 80 - 105
Operations Questions 106 - 125
Safety Questions 126 - 134
Practices of Note Questions 135

Question 135: Please describe any practices of note being utilized to plan, design, construct, operate, or maintain your network system

9.4 - 2018 Survey Results

9.4.1 - Asset Management

Question 005: Please provide the following information for your distribution network infrastructure

Question 006: Please indicate the percentage of each cable type that comprise your network primary (MV) cable system

Question 007: Please indicate the percentage of each cable type that comprise your network secondary (LV) cable system

Question 008: Please indicate if your company performs the following activities on a routine basis and at what frequency

Question 009: Do you have any maintenance programs where the maintenance frequency or approach is dependent, at least in part, on a risk or condition assessment of the assets to be maintained?

Question 010: If you perform periodic network primary cable diagnostic testing, please indicate / describe what testing techniques you use

Question 011: Are you using information from cable diagnostic testing to influence investment decisions, such as when to replace cable?

Question 012: Do you perform cable limiter continuity checks (amp checks) as part of your preventive maintenance program?

Question 013: If you perform Network equipment Fluid Sampling and Testing, please indicate which of these tests are performed? (check all that apply)

Question 014: If you perform equipment fluid sampling and testing of network transformers, please describe how you are analyzing the data and using it to drive investments or replacement of these units

Question 015: Are you using Infrared (iR) technology as part of your manhole and vault assessment process?

Question 016: If yes, with which activities do you perform iR testing? (check all that apply)

Question 017: If yes, which equipment are you using iR on? (check all that apply)

Question 018: If you are performing IR inspections, which of these best describe your approach? (Check all that apply)

Question 019: Are you using cameras (non- iR) as part of your manhole inspections?

Question 020: Do you track cable and equipment failures?

Question 021: If you track equipment failures, which of the following do you track? (check all that apply)

Question 022: Please provide the average number of failures per year you experience for the asset types listed below (if tracked):

Question 023: Provide the number of years upon which the average # of failures / year is based. (ex: 3 yrs, 5 yr-rolling ave, etc)

Question 025: Please describe your failure investigation process. Include a description, if applicable, of what drives corrective actions.

Question 026: Are you implementing targeted replacement programs for any of the following equipment? (check all that apply)

Question 027: If Yes, are any of your replacement programs Aged based, such as replacing all transformers >50 years old?

Question 028: If Yes (to question 26), are any of your replacement programs Design based, such as replacing all high rise fluid filled transformers with dry type units, or replacing a certain type of cable?

Question 029: If you are implementing targeted replacement programs not yet describe above, please describe how you are selecting assets to be replaced

Question 030: Do you remotely sense / monitor information about network devices beyond the primary feeder substation breaker?

Question 031: If you remotely monitor information about network devices, please indicate what information you are monitoring.

Question 032: If you remotely monitor information, are you using that information to make investment decisions, such as replacing equipment?

Question 033: If yes, please describe any software you are using to compile data and perform analysis.

Question 034: Please describe any practices of note being utilized to manage network assets

9.4.2 - Manhole Event Preparedness and Response

Question 005: Approximately how many total underground manholes / vaults do you have on your system?

Question 006: Do you require a firewall between two pieces of equipment in one vault? (example, between two network transformers)

Question 007: Are you using a separately mounted primary switch (not part of the transformer unit)?

Question 008: When do you operate a network transformer’s primary switch?

Question 009: Please indicate where you use vented vault and manhole covers to prevent accumulation of gases. (Not including vented gratings for transformer cooling)

Question 010: If you apply vented covers selectively, what criteria do you use to select locations? (check all that apply):

Question 011: Are you using manhole cover restraints in parts of your system?

Question 012: If yes, what criteria do you use to select locations at which to apply a cover restraint? (check all that apply):

Question 013: Are you using arc proof tape in your network designs? (please check all that apply)

Question 014: Do you use high flash point (less flammable) fluids in the fluid filled tanks of network equipment?

Question 015: Do you seal ducts in your manhole system (other than, or in addition to sealing customer service ducts)?

Question 016: If you seal ducts, is the reason to minimize the migration of combustible gases through the manhole / duct system?

Question 017: Do you use cable limiters in your network secondary system(s)?

Question 018: Are you implementing targeted replacement programs for any of the following equipment? (check all that apply)

Question 019: Are any of your targeted replacements driven by equipment that is beyond a particular age?

Question 020: Other than the performance of inspection and maintenance, are you using any other noteworthy approaches aimed at preventing manhole events?

Question 021: Do you remotely sense / monitor information about network devices / vaults beyond the primary feeder substation breaker?

Question 022: If you remotely monitor information about network devices / vaults, please indicate which of the following you are monitoring. (Check all that apply)

Question 023: Do you have a documented procedure for company personnel responding to a smoking manhole (“a smoker”)?

Question 024: Do you have a documented procedure for company personnel responding to a fire in a manhole?

Question 025: Do you have documented, up to date procedures for company personnel responding to other network emergencies?

Question 026: If there is a network emergency, is there a Network Shutdown protocol?

Question 027: Do you have a documented procedure for first responders responding to smoking manholes or fires in manholes?

Question 028: Do you perform periodic drills that include network situations, such as a network outage or network manhole fire?

Question 029: If you perform emergency drills that involve the network, do you sometimes involve other stakeholders, such as first responders (such as the fire department)?

Question 030: In response to a manhole/vault fire, do you require the cables in the manhole/vault to be deenergized before first responders attempt to extinguish the fire?

Question 031: In response to a manhole/vault fire, do you allow the fire company to pour water into the hole upon arrival?

Question 032: In response to a manhole/vault fire, which of the following methods of fire extinguishment do you utilize? (check all that apply)

Question 033: What other noteworthy approaches or technologies are you using to speed the recovery from a manhole event?

9.4.3 - Urban Network Safety Practices Survey

Survey Title: EPRI Urban Network Safety Practices Survey, 2018.

Question 005: Approximately how many total network units do you have on your system (area and spot networks)?

Question 006: Total approximate Peak network load (MW)?

Question 007: Do you have a “safety person”, (either a fulltime safety professional or other employee assigned to a safety role) focused on the network?

Question 008: If you have a safety person focusing on the network, is the person a full time safety professional, or another employee assigned to a safety role?

Question 009: Do you perform routine training on how to conduct a tailboard meeting?

Question 010: How to you determine / assess the quality of your tailboard meetings?

Question 011: Do you have documented, up to date procedures for a safety emergency at the jobsite, such as for extracting an injured man from a manhole?

Question 012: Do you periodically conduct a network exercise (drill) for responding to a safety emergency in a manhole, vault, or multi-level vault?

Question 013: What clothing system level is required to work in the network (routine work)?

Question 014: For 480V network protectors, does your company require crews to wear flash suits (i.e. higher than cat four PPE) or other incremental protection when they open or work in an energized NP?

Question 015: Does your utility test the heat rating or arc flash rating of your tools and clothing?

Question 016: Does your utility buy clothing or tools that are arc flash certified / heat certified?

Question 017: What other types of work in the network, if any, require incremental PPE or other tools? Please describe.

Question 018: For 208 V network protectors, do you de-energize the network transformer before removing the network protector fuses?

Question 019: For 480 V network protectors, do you de-energize the network transformer before removing the network protector fuses?

Question 020: Please indicate which of the following work procedures you have implemented to address network arc flash issues. Please check all that apply.

Question 021: Do you use external disconnects, such as Richards Outside Link Boxes or Eaton VisoBlock, to isolate 480V spot network protectors from the secondary network bus?

Question 022: Please indicate which of these manhole / vault entry procedures you utilize:

Question 023: We utilize sectionalizing devices on network feeders, enabling us to isolate a portion of the feeder

Question 024: If you use solid dielectric type switches, will you thump or proof-test into the switch with the terminations attached?

Question 025: Please indicate which of these activities are part of your procedure for determining a feeder to be de-energized and cutting a medium voltage network cable.

Question 026: Please indicate which of the following activities are part of your network feeder clearance procedures.

Question 027: When the feeder has been cleared, in what position have you left the network transformer primary switch?

Question 028: Are there any differences in your network feeder clearance procedures for a routine clearance (such as for adding a new transformer) and an emergency clearance (such as for a cable failure)?

Question 029: Please describe any noteworthy practices associated with worker safety in network systems that have been beneficial to you, and provide any other comments.

9.5 - 2019 Survey Results

9.5.1 - UG Inspection Practices Survey

Survey Title: UG Inspection Practices Survey, 2019

Question 005: Please provide the number of total submersible enclosures (vaults and manholes) that can be entered by a person. Include both network and conventional (nonnetwork) UG enclosures

Question 006: If you use remotely controlled switches in your Urban UG system, what percent of your total switch fleet in Urban UG is remotely controlled?

Question 007: Please indicate if your company performs the following Inspection activities on a routine basis and at what frequency

Question 008: When performing Urban UG inspections, please indicate which of the following tools you utilize. Check all that apply

Question 009: Does your inspection form provide guidance for prioritizing findings?

Question 010: If so, does the prioritization of the findings drive the time table for performing corrective maintenance?

*Note: Many companies do not have prioritization indicated on the form, however they have defined specific time frames for responding to findings based on priorities.

Question 011: Are you using Infrared (iR) technology as part of your manhole and vault inspection / assessment process?

Question 012: With which activities do you perform iR testing? (check all that apply)

Question 013: Have you established thresholds for action based on iR readings?

Question 014: Are you using cameras (non iR) as part of your manhole / vault inspections (check all that apply)?

Question 015: Do you use faulted circuit indicators (FCI’s) in your Urban UG infrastructure? (Check all that apply)

Question 016: In what applications will you perform network primary cable diagnostic testing? (Check all that apply)

Question 017: In what applications will you perform Non-network primary cable diagnostic testing in urban UG systems? (Check all that apply)

Question 018: If you are performing periodic primary cable withstand testing, what is the frequency of the testing?

Question 019: If you are performing periodic primary cable withstand testing, what is the duration of the testing? (in minutes)

Question 020: Please indicate / describe what testing techniques you use. Check all that apply

Question 021: If you are performing Partial Discharge testing, please indicate which approach(es) you utilize

Question 022: For your network system, do you perform a “Drop test”, where a network feeder is opened at the station and network protectors are tested to assure that they are functioning correctly (automatically open on backfeed)?

Question 023: If you have a secondary network, do you perform any routine diagnostic testing on your secondary cable?

Question 024: In determining your maintenance frequency, do you perform a risk or condition assessment of your individual equipment, (manholes, vaults, etc.), and vary your maintenance approach based on that assessment? (For example, a higher risk vault inspected more frequently than a lower risk vault)

Question 025: Please indicate if your company performs the following Maintenance activities on a routine basis and at what frequency

Question 026: If you perform distribution transformer oil sampling and testing (network and non-network), have you established trigger points for action based on oil sampling results?

Question 027: Do you utilize dissolved gas monitors on UG distribution network transformers?

Question 028: If you utilize dissolved gas monitors on underground distribution, please indicate which devices you utilize and which gasses you are monitoring

Question 029: For primary sectionalizing or tie points installed on your Urban UG system, excluding auto transfer schemes at customer sites, are the switches manually or automatically controlled? (check all that apply)

Question 030: Do you remotely sense / monitor information about devices beyond the primary feeder substation breaker?

Question 031: If you are remotely monitoring information about equipment beyond the primary feeder breaker, is this information tied in with your SCADA System?

Question 032: On your network system, do you have the ability to remotely control switches, network protectors or other devices on your system beyond the substation breaker?

Question 033: If so, what devices are remotely controlled? (check all that apply)

Question 034: On your non- network urban underground system, do you have the ability to remotely control switches, or other devices beyond the substation breaker?

Question 035: If so, what devices are remotely controlled? (check all that apply)

Question 036: Have you been able to leverage remote monitored information to modify your equipment inspection approach?

Question 037: Have you been able to leverage remote monitored information such that it has enabled you to modify your preventive maintenance approach?

Question 038: Please describe any practices of note with respect to Urban UG System Inspection and Maintenance

9.6 - 2020 Survey Results

9.6.1 - PTO Monitoring Survey

Question 005: Has your utility deployed or do you have plans to deploy PTO (pressure, temperature, and oil level sensors) on your network transformers?

Question 006: If Yes, Please indicate which type of sensing you have deployed on network transformers:

Question 007: If you have deployed PTO, what are the goals or rationale for adding PTO to the network transformer monitoring?

Question 008: Where you are applying PTO, what locations in the Network unit are your monitoring? (check all that apply)

Question 009: During network transformer maintenance, do you test PTO sensor functionality, or perform any sort of monitor calibration?

Question 010: If you have deployed PTO sensors to your network transformers, do you have the ability to remotely monitor the information?

Question 011: How is the PTO communications wiring routed?

Question 012: What communications equipment are used for returning telemetry?

Question 013: If you are leveraging PTO monitoring to manage your network transformer fleet, please briefly describe your approach

Question 014: What PTO telemetry combinations are being used for alarms? (i.e. temp up & press down = leak; temp up & press up = normal load increase; temp normal & press up = potential problem)

Question 015: What SCADA analog alarm levels do you set for PTO (i.e. pressure in psi or kPA and the set point)

Question 016: In addition to active monitoring of PTO levels, are you recording and storing monitored levels?

Question 017: What software does your utility use to analyze PTO data?

Question 018: How well have DGA results compared to any PTO data at the same time the oil sample was taken? (for example, have you seen correlations between higher pressures and the presence of dissolved gases in the oil?)

Question 019: Have you had any near miss or other event avoided due to PTO alarms?

9.6.2 - Underground Residential and Underground Commercial Distribution (URD /UCD) Practices Survey

Question 005: How many circuit miles of underground primary URD and UCD cable do you have on your system? (miles)

Question 006: How many total miles of cable do you install in a typical year? (Include new and replacement cable installations)

Question 007: How many total miles of URD / UCD cable do you replace in a typical year?

Summary: Miles of Installs and Replacements of URD/UCD

Question 008: Please indicate the percentage of your installed URD/UCD cable plant by insulation type

Question 009: What percentage of your installed primary URD / UCD cable plant is comprised of unjacketed cable?

Question 010: How many URD / UCD primary cable faults do you experience in a typical year?

Question 011: Please indicate if your company performs the following Inspection activities on a routine basis and at what frequency

Question 012: For the following routine inspection activities, please select the option that best describes your approach

Question 013: If you utilize infrared thermography (IR) in your URD/UCD inspections, have you established thresholds for action based on iR readings?

Question 014: Do you use faulted circuit indicators (FCI’s) in your URD / UCD Infrastructure? (Check all that apply)

Question 015: In what applications will you perform primary URD or UCD cable diagnostic testing? (Check all that apply)

Question 016: If you are performing cyclical primary cable diagnostic or withstand testing on URD/UCD cables; that is, proactive testing of cables on a fixed schedule to ascertain their condition, what is the frequency of the testing? (If you do not perform cyclical diagnostic testing, leave blank)

Question 017: Please indicate / describe what cable diagnostic testing techniques you use on your URD/UCD cables. Check all that apply

Question 018: If you are performing Partial Discharge testing on installed URD/UCD cable systems, please indicate which approach(es) you utilize

Question 019: If you perform partial discharge testing of installed URD/UCD cable systems, do you track failures associated with tested cables for warranty purposes?

Question 020: Do you perform cable injection on URD or UCD cable systems?

Question 021: If you utilize cable injection, do you track failures associated with injected cables for warranty purposes?

Question 022: Which of the following best describes your current prevailing installation approach for new MV URD cables?

Question 023: Which of the following best describes your current prevailing installation approach for new MV UCD cables?

Question 024: Do you perform proactive cable replacement of URD / UCD cables?

Question 025: In analyzing your cable system, are you performing any predictive analysis? If yes, please describe in detail

Question 026: Which of the following best describes your current prevailing practice for replacing or repairing direct-buried URD / UCD cables?

Question 027: In rocky soil areas, do your cable installation / replacement practices deviate from normal practice?

Question 029: Do you perform any routine maintenance (other than inspection) of single phase pad mounted transformers which are part of your URD / UCD system?

Question 030: Do you perform any routine maintenance (other than inspection) of pad mounted switchgear which are part of your URD / UCD system?

Question 031: Do you perform any routine maintenance (other than inspection) of three phase pad mounted transformers which are part of your URD / UCD system?

Question 032: Do you see a need for analytical approaches to better understand underground cable and cable accessory performance? (Example: failure rates by manufacturer, age, insulation type, etc.)

Question 033: Please describe any practices of note with respect to URD / UCD systems

9.7 - 2021 Survey Results

9.7.1 - Infrared Thermography Survey

Question 001: Are your UG field crews equipped with IR cameras?

Question 002: How many UG crews do you have in the field?

Question 003: How long have your field crews been using IR cameras in the field?

Question 004: What are your top two reasons for conducting IR inspections?

Question 005: Are your UG field crews equipped with IR cameras?

Question 006: Do you have a work procedure for taking IR images

Question 007: When do you conduct IR inspections?

Question 008: What components do you instruct line crews to inspect with IR?

Question 009: How do you approach the interpretation of your IR imagery?

Question 010: Which are your top 3 concerns over IR imaging in the field?

Question 011: What do your crews do about camera emissivity settings?

Question 012: Do you maintain IR records?

Question 013: What IR records do you maintain?

9.8 - 2022 Survey Results

9.8.1 - 2022 Underground Distribution Equipment Commissioning Practices Survey

Question 001: For Underground Switches that would be used as part of a dual feeder throw over scheme, which of these tests are performed when the units are received from the manufacturer? Please check all boxes that apply.

Question 002: For Underground Switches that would be used as part of a dual feeder throw over scheme, which of these tests are performed prior to energizing the unit? (may be done in the warehouse or in the field prior to energization) Please check all boxes that apply.

Question 003: For Underground Switches that would be used as part of a dual feeder throw over scheme, please describe any commissioning tests that are performed after energization.

Question 004: For distribution three phase padmounted transformers, which of these tests are performed when receiving the unit from the manufacturer? Please check all boxes that apply.

Question 005: For distribution three phase padmounted transformers, which of these tests are performed before energizing the unit? Please check all boxes that apply.

Question 006: For distribution three phase padmounted transformers, please describe any commissioning tests that are performed after energization.

Question 007: For distribution three phase radial (non-network) transformers, such as those that may be used in building vaults or below grade vaults, which of these tests are performed when receiving the unit from the manufacturer? Please check all boxes that apply.

Question 008: For distribution three phase radial (non-network) transformers, such as those that may be used in building vaults or below grade vaults, which of these tests are performed before energizing the unit? Please check all boxes that apply.

Question 009: For distribution three phase radial (non-network) transformers, such as those that may be used in building vaults or below grade vaults, please describe any commissioning tests that are performed after energization.

Question 010: For distribution three phase network transformers, which of these tests are performed when receiving the unit from the manufacturer? Please check all boxes that apply.

Question 011: For distribution three phase network transformers, which of these tests are performed before energizing the unit? Please check all boxes that apply.

Question 012: For distribution three phase network transformers, please describe any commissioning tests that are performed after energization.

Question 013: For low voltage underground cable systems, including network systems, which of these tests are performed before energizing the cable system? Please check all boxes that apply.

Question 014: Please describe any practices of note with commissioning UG equipment