Utility Information Exchange

• 1: P180.002 Underground 2021 ARP Utility Information Exchange - June 17, 2021
• 2: P180.002 & P180.004 Issues with Cable Locating and Abandoning Underground Cable – Dec 10, 2021
• 3: P180.002 Underground Infrared Thermography Utility Information Exchange - May 18, 2022
• 4: P180.002 Underground Padmounted Equipment Inspection - July 28, 2022
• 5: P180.002 Underground Corrosion (part of Task force Meeting), May 16, 2023

1 - P180.002 Underground 2021 ARP Utility Information Exchange - June 17, 2021

Attendees

The UIE was attended by EPRI member companies and EPRI staff. The list of member company attendees appears in Table 1.

Company	Name
AEP	Cory Jeffers
Ameren	John Rowland
Central Hudson	Taryn Black
Con Edison	Tom Campbell, Yingli Wen
Consumers Energy	Mark Lyons
DTE	Naera Haghnazarian, Adam Jacobs, Abdalla Sadoon
Exelon - ComEd	Jimi Conway, Urbano Gallardo
Exelon - PHI	Andrew Deen
First Energy	Dean Phillips
HECO	Randall Tom, Charlyne Nakamura
National Grid	Hernan Yepez
PECO	Dustin Nace
Portland General Electric	Jeff Kaiser
Salt River Project	Logan Tsinigine, Rick Hudson, Jason Gunawardena
Southern Company - APC	Stephen Daniel
Southern Company - GPC	Mike Pearman
Southern Company - MPC	Robery Boyd
Taiwan Power	Will Chang
WEC Energy	Mike Smalley

Utility Information Exchange Summary

The following sections provide a summary of the responses gathered during the individual question roundtables.

Question 1: Utilization of Remote Monitoring

The first question posed to the group contained multiple parts:

• Are you utilizing any remote monitoring outside the substation?
  • Where?
  • What are you are monitoring?
  • On what equipment is it being applied?
  • What technology are you using?
  • How are you communicating?

The following responses were shared:

• Consumers Energy
  • Gave a presentation at the 2017 NADUUWG presentation on “Circuit West” where a pilot for online monitoring was underway
  • Pilot uses localized fiber optic network
  • Able to monitor load, switch positions, relays, and is control-enabled
  • The circuit is a hybrid circuit – duct and manhole non-network that connects to URD system
  • SCADA enabled equipment is connected to this system
• HECO
  • Most monitoring implemented at HECO is in the substation. Efforts now beginning at augmenting with monitoring technology outside the substation
  • Data is brought back through SCADA
  • Initially looking at faulted circuit indicators (FCI’s) to help with fault locating activities
  • Also monitoring recloser status / operation
  • Communication is primarily through cellular back to control center
  • Network improvements are underway including installation of fiber optic to all vaults. Now in second or third year of 5 year program.
• SRP
  • Using faulted circuit indicators and reclosers (IntelliRupter®)
    • Cooper fault indicators are connected through Verizon cellular
    • IntelliRupters® (several tens of them installed) are monitored through field area network and wireless where needed
  • Replacing capacitor controllers with Cooper product that ties into SRP area network
  • Power quality monitoring at large industrial customers is also in place.
    • PQ monitors in place to capture large voltage swings at the customer switchgear or substation depending on the situation
  • Monitoring primarily current and sometimes voltage at cap banks
  • Also have one switch outfitted with current and fault indication monitoring capability
• AEP
  • Currently employing extensive real time monitoring capability, including:
    • Circuit loading
    • Temperature
    • Oil pressure
    • Status on vacuum interrupters, network protectors, etc.
    • Network and secondary voltage
  • Using Eaton VaultGard communications platform
  • Fiber backbone installed at all vault locations to act as communications channel.
    • Data are collected at local cluster locations, compiled, then fed back to a centralized location
  • Currently preparing/implementing pilot program to look at real-time distributed temperature sensing (DTS) for real time cable ampacity ratings.
    • Looking to use single fiber run within each duct bank to sense temperatures in adjacent ducts
    • Aiming to eliminate need to run CYMCAP calculations
• FirstEnergy
  • Not currently utilizing monitoring outside of the substation
    • Twelve networks (small)
    • Monitoring tied in through SCADA
  • Currently using some fault indicators to monitor portions of URD system
• Ameren
  • Currently monitoring radial and network UG systems.
  • Using S&C IntelliTeam® equipment
    • Padmount switchgear
    • IntelliRupters®
    • Switchgear inside building
  • Monitoring includes several features:
    • Switch status
    • Fault status
    • Voltage
    • Current, etc.
    • Network protectors include monitoring as well. This includes:
    • Status
    • Water level
    • Handle position
    • Looking to add pressure, temperature, and oil level (PTO) sensors
    • ETI relaying on 277 V network protectors
    • Eaton CM52 on 480 V network protectors
  • Communications system is radial cell system through a private vendor
    • Considered adding fiber but currently building private LTE network for Ameren. May move to that for all network protectors with a targeted 2022 start up
• National Grid
  • Utilizing monitoring on their network system
  • Currently undertaking a monitoring pilot project in Buffalo. Project will include transformer monitoring including:
    • Online transformer DGA (likely Qualitrol multi-gas module)
    • Oil temperature
  • Volt-var optimization (VVO) to come
• Exelon - PHI
  • Monitoring is use on network system and is focused on network transformers
  • Communications are via RMS system – radio backbone through Itron
  • Monitored features include:
    • Water level
    • Temperature
    • Pressure (primary and NP)
    • Status
  • Also conducting pilot program with Richards ETI & Eaton solutions
  • Exploring use of other equipment for automatic restoration and fault location:
    • Smart fault circuit indicators from Sentient
    • Underground interrupters which are similar to a recloser but without reclosing capability.
  • Pilot underway on condition assessment monitoring technology:
    • Active partial discharge monitoring system for cables.
    • Planning to use on several feeders which include river crossings or are historically poor performers.
    • Believe communications will be Cellular.
    • Manufacturer will perform analysis on recorded discharge activity.
  • Retrofitting FCI’s on URD system padmount equipment. Planning to expand to network in the future.
    • Central Hudson
  • Currently working on deployment of monitoring on network system (<50% setup).
    • Uses ETI system.
    • Monitored features include:
    • Current.
    • Voltage.
    • Network protector status.
    • PTO sensors.
    • Water ingress.
  • Communications via 3rd party cellular.
  • Now constructing private wireless network.
• Con Edison
  • Monitoring all network transformers using PTO.
  • Communication is via RMS powerline carrier system.
  • Pilot program looking at integrated T-body sensors which can measure current, voltage, and phase angle.
• DTE
  • Conducting pilot study for CNIGuard manhole monitoring unit (1 year complete, starting 2nd year).
  • Unit includes multiple sensor types:
    • IR camera.
    • Combustible gas detection.
  • Monitoring current and fault status on network banks.
  • Cellular signal for CNIGuard.
• Southern Company - Alabama Power
  • Uses feeder communications system.
    • SCADA with comms back to operators.
    • Monitoring and control of these devices.
  • Communications channel is SouthernLink – private cellular LTE system.
  • Automatic throwover switches (ATO’s) are on SCADA system.
  • All network protectors monitored and communicate via fiber optic network.
  • Pilot to monitor network transformers with DGA and temperature monitoring.
• Southern Company - Mississippi Power
  • Same as APC excluding network system monitoring.
  • Stand by generation agreements with status and control on the switchgear.
• Exelon - PECO
  • Monitoring is very limited in underground outside of the substation.
  • Current monitoring over fiber optic network.
  • Secondary system uses PSI network monitoring for voltage and current. System operation is currently limited.
  • Communications through powerline carrier between stations and cellular modem back to central location.
  • There have been many issues with this communications path.
  • Piloting 3M sensor for measuring voltage, current, temperature, water level.
  • Sensus radio for communications.
  • One switch being monitored over Sensus radio.

Question 1 Key Takeaways

• Limited deployment of monitoring systems outside of substation with the focus being network systems.
• Field systems to date are focused on measuring voltage, current, and temperature. Additional status indicators are also routinely recorded.
• Several pilot projects underway.

Question 2: Data Interpretation and Usage

The second question for discussion involved the following topic:

• If you are using remote monitoring, please describe how you are using the information.
  • Have you established alarms / thresholds?
  • What sort of analysis and reporting have you deployed?

The following responses were shared during the roundtable discussion:

• Consumers Energy
  • Work mostly on substation equipment not so much out on UG system.
• HECO
  • Most work on FCI’s – comes back strictly as an alarm at this time, no data to interpret.
  • Not ready to establish threshold levels at this time.
• SRP * Data from Cap bank controllers has been most useful so far:
  • Monitoring the neutral and operation of the cap bank switch.
  • Identify if there is abnormal operation of the cap bank switch (e.g. phase gets stuck).
  • No response criterion has proven useful as it indicates that troubleshooting is required and a team can be dispatched.
• AEP
  • Piloting a few different data interpretation / analysis approaches.
    • Cyme software using real time data including AMI data.
    • Running state estimator using the data that are coming in.
  • Visualization using dashboard view of data (ABB product).
    • Incorporating maintenance (DGA) into dashboard.
    • Combining different data into visualization.
  • Converting all data into “data lake” and housing internally. Enables them to push and pull data across platforms and not have to work with many different datasets
  • Working with Eaton to do secondary fault detection using data from network protectors.
• FirstEnergy
  • Nothing to report on this topic.
• Ameren
  • Using network data for loading alarms (66% of transformer kVA rating).
  • Network protector monitoring allows Ameren to operate in abnormal conditions due to switching during restoration efforts.
  • Able to detect equipment failures.
  • Conducting a trial for DTS within cable ducts – monitor actual cable temp and identify overloaded circuits.
• Exelon - PHI
  • Using data to try and understand how much solar and DER is on the system.
  • Also using data to detect backfeed on the system (most likely from DER site).
• Central Hudson
  • No established alarms / thresholds.
  • Focused on getting relays communicating properly back to central location.
  • Working to figure out how to leverage data but focused for the time being on getting everything hooked up and working.
• DTE
  • Manhole monitoring system from CNIGuard has internal alarms setup.
    • Key personnel receive text messages to dispatch crew when alarm goes off
    • Two threshold levels (yellow and red).
  • IR camera alarms as well. Alarm triggers on fluctuating temperature.
• Southern Company - Alabama Power
  • System in place that collects data from each switching device (SCADA Tools):
    • Voltage.
    • Current.
    • Switch position.
    • Open/close.
    • Alarms for high voltage, low voltage, and current.
  • Network transformer pilot project underway.
  • Not collecting the data but planning to start later on.
• Mississippi Power
  • Same as APC.
  • Alarm thresholds set on status fields only (e.g. battery alarm, etc.).
• Exelon - PECO
  • PSI secondary monitor (not fully functional right now).
    • When working, reported current and provided alarm on set threshold.

Question 2 Key Takeaways

• Most participants indicate alarming to be the most common data captured.
• Efforts starting to look at combining data and developing ways to extract information from the data through visualization and other means.

Question 3: Challenges to Implementing Monitoring

The third question for discussion was:

• What was the most difficult challenge to implementing online monitoring?

The following responses were shared during the roundtable discussion:

• Consumers
  • Convincing IT to allow engineering to install and connect the monitoring equipment to the system.
  • The need to bring on many different consultants with an ambiguous scope.
• HECO
  • Retrofitting old equipment with new sensors and other devices. Lots of trial and error trying to adapt the sensors and relays to the old equipment.
• SRP
  • Communication problems getting the data back for use.
    • Line of sight wireless communication can get blocked.
    • Need to monitor the wireless connections.
    • May need additional power and maintenance on transmitter system.
  • Communication errors cause alarms which need to be addressed and this becomes a problem if there are too many alarms – created group just to handle comms issues.
• AEP
  • Size of rollout was a challenge to manage given the numerous different Op-Co’s involved.
  • Material issues along the ways
    • Submersible subpanels were a problem as they would leak and cause issues with the electronics inside
  • Training the crews takes time to get everyone up to speed
  • Contractors help at the start but then the management of the system becomes inhouse – “Day 2” after the contractors leave. Need to be ready for this.
• Ameren
  • Difficult to keep communications working
    • Cell connections had issues at antennas in vaults / manholes.
  • Powering up the equipment was an issue.
  • CM52’s – comms exit when placed in vault is hard to get to and water can get into the cabinet.
    • Had to redesign the bulkheads and put the equipment higher up on the vault wall
• Exelon - PHI
  • Issues with maintaining communications.
    • Buildings are a problem that they block comms.
    • Trucks park over vaults and this disrupts.
    • Worked to install repeaters to improve wireless signal.
    • Unable to install fiber as it is not considered to be a distribution asset at PHI.
  • Training of crews.
• Central Hudson
  • Finding resources to implement / install the equipment has been difficult.
  • It is challenging to find an appropriate place to store all the data.
    • Current system only stores 13 months of data and then these data need to be moved somewhere else.
• Con Edison
  • Sealing of all the boxes for comms and wiring against water ingress. IP68 is not effective enough for vault applications.
  • Different generations of monitoring equipment. Procurement of proper connectors and wires has been difficult especially during COVID.
• DTE
  • Communications problems.
    • Double decker manholes have been a problem.
    • Trying to shift to DTE mesh network.
• Southern Company - Alabama Power
  • Installing new sites for monitoring.
    • Initially there were many different groups involved (structures, radios, programmers, etc.) and the process took 6 months to get a location installed and operational.
    • Streamlined to be 3-4 weeks now.
• Southern Company - Mississippi Power
  • Same as APC.
• Exelon - PECO
  • Communications are problematic.
  • Water intrusion issues which damages electronics.
  • Corrosion occurs at the connections.
  • Access to resources for getting equipment installed and operational.

Question 3 Key Takeaways

• Communications is the biggest challenge facing utilities in deploying monitoring systems outside the substation.
  • Wireless is impacted by structures and other obstacles.
  • Utilities are working towards installing fiber systems to overcome communications challenges.
• Suitability of accessories and mounting equipment to manhole / vault environment (i.e. submergence ratings seem optimistic).
• Access to resources and coordinating installation is more complicated than non-monitored situations and so it is difficult to coordinate all the personnel that need to be involved.
  • Streamlining can be done but is not simple to implement.

2 - P180.002 & P180.004 Issues with Cable Locating and Abandoning Underground Cable – Dec 10, 2021

EPRI Hosts:

• Tom Short, tshort@epri.com, Distribution Safety
• John Tripolitis, jtripolitis@epri.com, Underground Distribution Assets
• Josh Perkel, jperkel@epri.com, Underground Distribution Assets

These are notes from a utility exchange webcast on November 10, 2021.

Introduction:

Utility 1 presentation:

• Abandoned cables have been clouding URD cable locating effort
  • Focusing on residential and commercial
  • Abandoned cables often aren’t mapped
  • Abandoned cables sometimes tone better than the in-use cables
• Standards for abandoning underground cables
  • Most cable replacement methods don’t remove the old, buried cables
  • Need to map abandoned cables
  • Do we electrically “float” the ends?
  • Do we ground one or both ends?
  • Do standards vary across jacked concentric neutral cables or jacketed cable or secondary cables?
• What are the best practices and techniques for locating the abandoned cables?

Tom Short:

• Shared an application that models the current flow across an energized cable and a parallel abandoned cable.
• The app can be found at: https://distribution.epri.com/safety/2021/ug/
• The model suggests:
  • The cable with the bigger neutral is more likely to show up when searching with an active search method.
  • Both cables will appear the same using a passive method
• This suggests that it might be best to disconnect the inactive cable at both ends
• The program considers two jacketed concentric neutral cables. The results would vary if one cable is unjacketed.

Have you had issues related to mislocating a cable due to an abandoned cable?

Utility 1: Yes, we’ve had issues with abandoned cable underground.

Utility 2: We do not have issues to the extent that an older city might. We sometimes run into concentric neutral cable, and we are usually able to remove it.

Utility 3: We used to trench and pull out the band cable. This might be more of a problem going forward since we are doing more directional drilling. We have had this issue on a few occasions. We keep our maps up to date.

Utility 4: Yes.

Utility 5: We have had minor issues mislocating, I don’t know if it’s due to abandoned cable. We cut cable below ground and don’t ground it but leave it isolated. For putting something new, it’s not an issue.

Utility 6: Has not heard of any specific issues with this.

Utility 7: Not aware of issue mislocating cables due to abandoned cables.

Does bare concentric neutral vs. jacketed make a difference?

Utility 1: Don’t have many details about cable types, but in one case it was concentric neutral cable where energized was poorly located, but the deenergized cable was located very well.

Utility 2: We have difficulty getting a tone on bare, unjacketed concentric cable because it tends to erode.

Utility 3: Have not heard much one way of the other. Losing the concentric neutrals is an issue.

Utility 4: Older cables with exposed concentric have contributed to the problems in locating the cables.

Utility 5: Everything new is jacketed.

Utility 6: We do have some corroded unjacketed cable due to flooding, salt, and weather conditions. I can imagine they would be hard to locate.

Utility 7: Our older cables are unjacketed. There might be issues identifying those. We now mainly install jacketed cables.

Are there other sources of mislocating? (e.g. water pipe)

Utility 1: Water and gas are examples as well as phone cable. They run both parallel and at angles to the abandoned wires. (“All of the above”)

Utility 2: Yes, we have experienced mislocating due to gas, telephone, fiber, and leftover lead jacket

Utility 4: Yes, water and communication lines.

Utility 5: Trouble with deep facilities at highway crossings. We sometimes put marker balls near the surface as a solution to this problem.

Have you had other issues related to cable locating?

Utility 1: Infrastructure improvements that are still grounded are a problem. It appears that tone bleeding is a larger problem when the ground is very saturated. We find that the abandoned bare concentric neutral is energized over anything else. The actual soil might be a problem. We have a lot of clay and not much rock. The problem is more common in the spring and the fall.

Utility 2: Our locating difficulty often comes from discerning which is the wire we are looking for [from non-abandoned utilities]. There is a lot of stuff in the ground. A small percentage of issues are from direct parallel circuits.

Utility 4: We have challenges during wet seasons and also very dry periods. Fault locating under pavement/concrete is a problem, too. Abandoned cables prolong outages during restoration events while ensuring the correct cable is marked/located.

What technologies are used to locate cables?

Utility 1: The standard is direct connection to the structure (at a transformer for example). Both active and passive modes are used. We don’t ourselves use ground penetrating radar, but other companies we own do. The ground penetrating radar doesn’t let us positively identify a specific utility – it only lets us know there is something there.

Utility 2: We have a locating wand. It has both active and passive modes.

Utility 4: Mostly passive and active. We rarely use ground penetrating, via a contractor.

Utility 5: Mostly direct connect on the transformer or other above ground device. We sometimes have trouble with the paint. No ground penetrating radar.

Utility 7: Only aware of radar use (of contractors for this company).

Are multiple approaches used?

Utility 1: Yes, both active and passive in one device.

Utility 2: Yes, both active and passive in one device.

Utility 4: Both passive and active.

What utility records do locators have available?

Utility 1: We have GIS maps that include existing abandoned cable, and we share this with our contractors.

Utility 2: We have GIS maps that include abandoned cable.

Utility 3: Circuit maps. We don’t have a many old cables in the ground.

Utility 4: We have records for self-locating, usually for faults. They are GIS records. They do include abandoned cables. We also use 811.

Utility 5: We have a mapping system that we share with our line locators. It includes the abandoned facilities as well as gas and our other assets.

Utility 6: We have a GIS system and a specific layer for abandoned cables.

Utility 7: Doesn’t know what contractors have, but we have a GIS system. Not sure what abandoned line indications are in it.

Will those records include abandoned cables?

Utility 1: In theory it has the abandoned cables, but in practice when a cable is replaced, workers update [replace] the existing cable record, so the information about the abandoned cable is lost.

Utility 2: The GIS maps include abandoned cables. Record keeping is manual and so not always accurate.

Utility 3: If crews are replacing a cable, they usually mark it on a circuit map. The maps will typically show the presence of an abandoned cable.

Utility 4: We have records for self-locating, usually for faults. They are GIS records. They do include abandoned cables. We also use 811.

Utility 5: Yes.

Utility 6: Yes, in a specific GIS layer.

When a cable is marked, what’s the normal “dig distance” that a contractor would normally use? Is there a standard or guideline on that?

Utility 3: The dig distance is likely 18 in but would have to double check.

Utility 5: The dig distance is 18 in.

Utility 6: Hand dig within 18 in of the markout.

Utility 7: 3 ft for hand dig.

What are the best strategies for location to prevent mislocating?

Utility 1: Idea - potentially take the abandoned cable three feet out of the structure and cut it off at both ends to see if that eliminates the problem. We have photos of the abandoned cable that has been cut in the transformer sitting in water. They do not always disconnect the neutral.

Utility 3: There is a cutback requirement at the substation. They will cut back to the substation boundary.

Utility 5: The better signal, the better the results. Cross-bonding with coms makes it harder to locate.

Utility 6: We don’t have any best strategies to prevent mislocating.

Are cable replacements done by contractors, utility crews, or a mix?

Utility 1: Contractors.

Utility 2: A mix.

Utility 3: Almost always contractors.

Utility 4: Contractors. They typically do directional boring. We will do it ourselves in the case of an outage or under a time constraint.

Utility 5: Contractors.

Utility 6: Contractors.

Utility 7: We mainly use contractors.

Do you have a standard on how to replace cables?

Utility 1: No

Utility 2: We have service standards that we follow. There might be one for replacing cables.

Utility 3: The standards are only the end result specifications.

Utility 4: Does not see much in the construction standards. It’s more of a work practice.

Utility 5: No, not specifically for replacing cables. We have abandoning and installation guides. We have looping guidance and an overall aged cable replacement program guide.

Utility 6: We do not have a standard for that. We have a standard for how it should be built.

Utility 7: Yes.

Do you have requirements for how to disconnect the ends of abandoned cables (including neutrals)?

Utility 1: No, that is what we are hoping to learn.

Utility 2: It was our practice to clear the neutrals – cut cable, remove the concentric from that spot, then take the neutral back to the individual cables.

Utility 3: For URD, no. (For manhole applications, there are requirements.)

Utility 5: Older stuff was a polypad at grade level. Now they lop everything off – neutrals and conductor below grade. This is not a requirement but just what we tend to do.

Utility 6: We don’t have standards for abandoning cables. We have standards for how cables should be abandoned on the underground.

Utility 7: We follow similar practices to the rest of the utilities that spoke.

When replacing UG cables with parallel cables, how much separation is used? Do you have a minimum or maximum suggested separation?

Utility 1: We have no standard for this in place.

Utility 3: None as far as I know.

Utility 4: We have construction standards. Typically, if you’re boring, you’re just trying to get a good path.

Utility 5: We use the same standards as constructing single-phase or three-phase circuits, which is 1 ft. This is to keep a safe clearance from the testing equipment – we treat all cables within 12 in as hot.

Utility 6: We don’t have any separation requirement as far as I know.

Utility 7: We don’t have a specific requirement for proximity to our own cables. Near other utilities we try to stay 1ft away.

Are abandoned cables noted in GIS or other database?

Utility 1: Yes, in theory in GIS although they often get over-written when new cables are installed.

Utility 2: Yes, abandoned cables are noted in GIS.

Utility 3: We don’t have underground marked on the GIS, so abandoned cables are marked on a paper map.

Utility 4: We have maps. They aren’t 100% because sometimes there are older abandoned cables that we do not know about.

Utility 5: Abandoned cables are noted in the GIS system as an additional layer.

Utility 6: We do have abandoned cables in GIS.

Utility 7: Yes.

Does the replaced cable often end up out of the expected path from point A to point B?

Utility 1: Yes, occasionally. It depends on the feeding and boring and skill of the crew out there.

Utility 2: Yes.

Utility 3: I would say yes, but typically it’d be in the same run.

Utility 4: Sometimes, but we hope they are put in our maps appropriately.

Utility 5: For the most part they end up in the expected path.

Utility 6: Usually in the correct location.

Utility 7: It’s usually fairly accurate.

Our state is starting to require everyone to provide X,Y,Z coordinates of all installations. Anything with 12-in deviation from the proposed location needs approval.

Discussion

Utility 1 (person 1): If there are best practices, could we push this through state 811 programs? For any utility?

Tom: It sounds like the best practice is cutting back, but the question is how far back it needs to be to be effective.

Utility 1 (person 2): We would love equipment that can help us identify the correct cable in this scenario. Our experts do not know how to resolve the problem. Price tag matters, but we are going to continue to face this problem because we can’t fix decades of abandoned cables. Is anyone aware of equipment or advice to mark the appropriate cables?

Utility 1 (person 3): One of the vendors has a new piece of equipment out that is somewhat effective at this. They claim that they can catch the live wires over the dead wires in places where they had trouble with this in the past. Their sales person is not overselling it – maybe it isn’t a perfect solution but it can be helpful. We are looking forward to doing our own tests.

Tom: do you know why it works better than existing technologies?

Utility 1 (person 3): No, it still uses magnetic locating. It has to do with the antenna configuration. It’s made by Vivax.

Tom: Any other discussion items?

Josh Perkel: In the cases you have jacketed cables and unjacketed cables, do they have the same specifications like the amount of neutral and conductor size? Or do the new cables tend to be a different design than the previously abandoned ones?

Utility 5: We’ve seen some #2 stranded from the 60s, 70s, and 80s, but everything since then has been #1 solid to prevent any chance of water migration into it. They’re single phase, three phase circuit-type cables. For the most part, what we’re replacing is quite similar. There might be a small size change. Sometimes, we replace the oldest #1 with a #1 solid again.

Tom: What about the neutral?

Utility 5: The neutral is the same size. The jacket goes over it. It’s the same size concentric-style neutral.

Utility 7: We’ve had problems with the old ones that were unjacketed and replaced as well as the older jacketed ones that were replaced.

Utility 1 (person 1): We’re mostly replacing bare concentric neutral cables. The new cables we’re replacing with are jacketed. Sometimes the replacement is slightly higher voltage, like replacing 15-kV cable with 25-kV cable to facilitate a voltage conversion or get rid of step-up/step-down transformer. We still have close to 100 million feet of bare concentric neutral cable in the ground from before 1985. It’s starting to get old. Much of the process is how to do this right going forward.

3 - P180.002 Underground Infrared Thermography Utility Information Exchange - May 18, 2022

EPRI Hosts

• John Tripolitis, jtripolitis@epri.com, Underground Distribution Assets
• Josh Perkel, jperkel@epri.com, Underground Distribution Assets

Attendees

The UIE was attended by EPRI member companies and EPRI staff. The list of member company attendees appears in Table 1.

Company	Name
Ameren Services Co.	John Roland
Ameren Services Co.	Paul Aten
American Eletric Power Service Corp.	Cory Jeffers
American Eletric Power Service Corp.	James W. Robbins
American Eletric Power Service Corp.	Matt Myers
BC Hydro	Aaron Norris
Consolidated Edison, Inc.	Divith Aruni Babu
Consolidated Edison, Inc.	Michael Donohue
Consolidated Edison, Inc.	Paul Volmar
Dominion Energy, Inc.	Marty O’Baker
DTE Electric Company	Patty Hasa
Exelon Corporation	Ali Syed
Exelon Corporation	Andrew Morris
Exelon Corporation	Beata Okruta
Exelon Corporation	Dustin Nace
FirstEnergy Service Company	Elizabeth Akosile
Hawaiian Electric	Ikaika Mokiao
Lincoln Electric System	Winston Larson
Los Angelos Dept. of water and power	Bryan Castillo
Los Angelos Dept. of water and power	Frank spencer
Los Angelos Dept. of water and power	Richard Trujillo
Los Angelos Dept. of water and power	Yousseff afif
National Grid UK, ltd.	Hernan Yepez
Portland General Electric Co.	Aharown Luke
Portland General Electric Co.	Brad Spiering
Portland General Electric Co.	Eric Bryant
Portland General Electric Co.	Jeff Kaiser
Salt River Agricultural Improvement and Power District	Jason GunaWardena
Seatle City Light	Hamed Zadehgol
WEC Energy Group, Inc	Marty Koutnik

Utility Information Exchange Summary

The following is a summary of responses gathered during the individual question roundtables

Topic: Infrared thermography assessment in the field

Companies participating in the Round Table session

• Portland General, PGN

• LADWP

• AEP

• Ameren

• Con Edison

• National Grid

• SRP

• We Energies, WEC

• Seattle City Light

• ComEd

Q1: Why do you do IR inspections on your UG system assets?

• PGN

  • Safety

  • Preventative maintenance

  • Both were 4 years ago – not happening recently

• LADWP

  • They have an inspection group and crews do inspection when they go into vaults

  • They are inspecting for any weak spots

• AEP

  • Policy in place for 12 years

    • They have actions for different temperature ranges.

  • Primarily for safety and is used for every entry into a structure

• Ameren

  • Safety check and when rebuilding manholes

• Con Edison

  • Safety check before entry

  • Planning for proactive cable replacements (condition assessment) – scheduled inspections

  • Most inspections are on 120/208 V system

  • 260,000 plus structures to inspect at least once every 8 years

  • Installing IR sensors in other monitoring devices

• National Grid

  • Worker safety – inspection done before operating any separable connector

  • Reliability – structure inspection to assess condition

• SRP

  • Scheduled cycle inspection to identify issues with equipment (reliability)

  • They do not enter energized manholes but when they did they would do IR prior to entry

• WEC

  • No IR program for some time

  • Trying to come up with a procedure

    • Proactive mainline feeder patrol

  • Starting to get more involved with manhole-duct system. Before they would only do a visual inspection

    • Thinking to start using IR in structures

    • Expectation is that crews will IR scan prior to working

• Seattle City Light

  • Good indicator of loading on the circuit and can be used for maintenance and planning

  • Also used to find manhole event precursors

• ComEd

  • Safety and reliability

  • Standing practice to do IR scan before doing any work in the manhole

  • Occasionally they will do IR inspections of cable system components

  • For transformers, they will do IR inspections for preventative maintenance rather than safety

Q2: If you use IR, what thresholds have you established for action?

• PGN

  • Actions are based, in part, on the experience of the line worker

  • Delta T levels for OH and UG based on ITC work (which was based on ComEd)

  • No adjustment for thickness of the insulation

  • No consideration for component history / known issues

• LADWP

  • Look at differences in temp ( ΔT ) between different components.

  • >26F ΔT, major deficiency, immediate repair. No work in structure until hazard mitigation.

  • Between 14 and 26F ΔT, deficiency, repair in reasonable time, work can continue if workspace can be made safe.

  • Between 5 and 15F ΔT, possible deficiency, notify supervision. Works can continue.

• AEP

  • They have thresholds

    • Minor delta T < 45 F

    • Intermediate 45 – 72 F

    • Serious > 72 F

• Ameren

  • Unofficial policy at this time

  • Temperature differences between the phases

• Con Edison

  • Primary and LV secondary

    • Delta 15C – splice compared to cable on either side of the splice and same cable to other sections of the cable

    • Secondary

      • 55C hotspot

      • Delta T of 15C compared to other cable in the same structure – repair within 1 year (applies to all UD cable) – No work allowed in the structure

      • 93C hotspot – emergency ticket for immediate repair

• National Grid

  • 12 year old procedure

  • Includes delta T table

    • < 10F Normal, begin work

    • 11-20F, do not operate and schedule repairs

    • > 20F, schedule immediate repairs

• SRP

  • 12 to 18 degrees difference requires a response within 6 months

  • 19 to 45 degrees difference requires a response between 2 to 4 weeks

  • 46 degree or more difference will require a response withing 3 days

• WEC

  • Focused on 200 A & 600 A elbows

  • < 4C over reference

  • 4-14C intermediate

  • >15C immediate repair

  • 3/C PILC cable joints are a challenge and it is unclear what criteria to use – would welcome comments from other utilities

• Seattle City Light

  • Nothing in writing

  • Advised field crews to reach out to engineering if Delta T exceeds 5C

• Exelon (Based on information provided by Com Ed and PEPCO)

  • Safety focused

  • 1-5F localized ΔT – low priority, fix in under 2-3 years

  • 6-25F ΔT – Fix within one year

  • > 26F ΔT – Fix within 14 days

  • Spot temp > 167 F, Fix right away ( either 24 or 48 hrs)

Q3: Have you developed a way to demonstrate or quantify the benefits of your investments in IR testing to your internal stakeholders?

• PGN

  • PM system

    • System did not work well and so could not help

  • No database connecting IR measurements to actual condition / findings when components were taken apart

• LADWP

  • Needs to reach out to inspection group for more information

• AEP

  • Have the means to quantify but have not made use of it

    • Data about failures and IR are captured in a database

• Ameren

  • In early stages of deploying IR

  • Too early to say

• Con Edison

  • Difficult to quantify

  • Many examples of locations that have been identified and others where they were not able to inspect prior to a manhole event occurring

  • They use cost of manhole event as reference to show the value

  • Efficiency in quickly finding issues inside manholes / vaults

• National Grid

  • Hotspots are logged and viewed as a “catch” and are reviewed internally with staff for increased learning and safety awareness

• SRP

  • Believe IR is a good predictor of future failure but have not found a good way to quantify the benefits

• WEC

  • No way to demonstrate or quantify

  • They also use IR in inspecting URD

  • Cited an example that demonstrated value to their management involving a customer with flickering lights, where they had to send multiple troubleshooters out with a PQ employee. (3 total)

    • Lots of personnel

    • Was able to identify issue by loading service and using IR. Bad connection identified within a few seconds.

    • Savings in labor and time for identifying and solving issues

• Seattle City Light

  • No need to demonstrate value internally

  • Left to discretion of engineering and network crews

• ComEd

  • Haven’t needed to develop a way

  • Safety and identification of hot components in structures is recognized as valuable

Q4: What metrics, if any, do you use?

• PGN

  • No

  • Would like to relate to risk (customer interruptions, crew safety, etc.)

• LADWP

  • No

• Con Edison

  • Corporate level risk – secondary cable is part of key risk indicator

• SRP

  • Time between initiation of work order and completion

  • Temperatures used to prioritize the work

• WEC

  • No metric to track

  • Thinking maybe CAIDI may be a way to track

• Seattle City Light

  • Would need to depend on the system

  • Operations of protection system

  • Arc flash risk

  • Comprehensive view

• ComEd

  • Not using any at this point

  • Scheduled inspections and completion are probably the only metrics they are using with respect to IR

    • Example: Does work get done on time?

4 - P180.002 Underground Padmounted Equipment Inspection - July 28, 2022

EPRI Hosts

• John Tripolitis, jtripolitis@epri.com, Underground Distribution Assets
• Josh Perkel, jperkel@epri.com, Underground Distribution Assets

Attendees

The UIE was attended by EPRI member companies and EPRI staff. The list of member company attendees appears in Table 1.

Company	Name
Ameren Services Co.	Patrick Ridgley
Ameren Services Co.	Paul Aten
American Electric Power Service Corp.	Cory Jeffers
American Electric Power Service Corp.	Matt Myers
BC Hydro	Jason D’Cunha
BC Hydro	Thomas Huitika
Central Hudson Gas & Electric Corp.	Amanda Lugo
Central Hudson Gas & Electric Corp.	Taryn Black
Consolidated Edison, Inc.	Andrew Reid
Consolidated Edison, Inc.	Frank Doherty
Consolidated Edison, Inc.	Mohamad Ali-Bappim
Consumers Energy	Leslie Shaughnessy
Dominion Energy, Inc.	Adam Flowers
Dominion Energy, Inc.	Amy Carrion
Dominion Energy, Inc.	Liz Sullivan
Dominion Energy, Inc.	Leonard Sandberg
Duquesne Light Co.	Dan Antonucci
Duquesne Light Co.	Matt Thimons
Exelon Corporation	Aiye Fabiyi
Exelon Corporation	Ali Syed
Exelon Corporation	Dan Barabas
Exelon Corporation	Merle Turner
Exelon Corporation	Najwa Abouhassan
Exelon Corporation	Rebecca Kartheiser
FirstEnergy Service Company	Dean Philips
Georgia Transmission Corp.	Mohamed Aly
Lincoln Electric System	Tim Menter
Lincoln Electric System	Winston Larson
Los Angeles Dept. of Water & Power	Marnelli Batra
National Grid UK, Ltd.	Hernan Yepez
Portland General Electric Co.	Bobby Kosowski
Portland General Electric Co.	Jeff Kaiser
Salt River Project Agricultural Improvement and Power District	Chance Bellflower
Salt River Project Agricultural Improvement and Power District	Logan Tsinigine
Salt River Project Agricultural Improvement and Power District	Rick Hudson
Saudi Electricity Co.	Nouh Al-Herz
Southern Company	Robert Boyd
Southern Company	Scott Strahan
WEC Energy Group, Inc.	Amin Khanlar
WEC Energy Group, Inc.	Marty Koutnik

Utility Information Exchange Summary

The following is a summary of responses gathered during the individual question roundtables. Responses are provided in the Excel file at the following link.

Questions

1. Do you perform periodic inspections of Padmounted Equipment?

If yes, please briefly describe your program:

1. What equipment to you inspect?
2. How often?
3. Who does your inspection? Your own employees or contractors?
4. Is your inspection program limited to the exterior, or do you open equipment and inspect the interior?
5. Does your inspection approach include the use of IR?
6. Do you take and record photographs or video of inspected units?

2. Is your inspection approach informed by a written guideline?

If yes,

1. does your guideline include criteria for assigning criticality or severity (such as determining the severity of corrosion, for example)?
2. does your guideline indicate expected times within which repairs must be made based on severity of findings?

3. Do you record your inspection findings?

1. If yes, please describe how that is done (on paper, utilizing a handheld application, or other).
2. Also describe any computer systems / WM systems into which data is being recorded.

4. If you are tracking inspection data, please describe how you leverage that data.

1. Are you performing any predictive analytics?
2. Do findings inform replacement decisions?

5 - P180.002 Underground Corrosion (part of Task force Meeting), May 16, 2023

Companies who participated in the information Exchange

• AEP
• PECO
• Con Edison
• SRP
• Central Hudson
• OG&E
• Dominion
• FirstEnergy
• PHI
• CPS Energy
• Commonwealth Edison
• National Grid
• WEC

Question 1:

For equipment in below grade vaults:

• Please describe the main corrosion issues you encounter
• Please describe your approach to identifying, preventing and remediating corrosion

Responses / Comments

AEP

• Issues vary across system as conditions can be different among geographically disparate operating areas
• Routine inspections are important for identifying issues. Replacement decisions are based on inspection findings

PECO

• Inspections are used to identify corrosion issues. Replacement decisions are based on inspection findings
• Corrosion prevention techniques include standards associated with equipment tank materials and coatings
• PECO also uses passive cathodic protection on switches and transformers
• Inspections include an assessment of anodes used for cathodic protection. Anodes are inspected on a 6 year cycle for transformers, and a 3 year cycle for switches

Con Edison

• The main corrosion concerns are network transformer corrosion and switch corrosion
• In addition, corrosion of steel beams and re-bar within the structure is a concern. Structural corrosion can create access issues
• Con Edison installs anodes on units
• Visual inspection of the units is used to ascertain corrosion severity and decide on replacement

SRP

• Almost no below grade vaults or equipment in below grade vaults
• No significant corrosion issues with this sort of equipment

Central Hudson

• Primary issues are with network transformer and protector corrosion
• Structure roofs, the tops of equipment tanks, and the first foot at the bottom of transformers are the most common areas for corrosion
• CH places anodes for cathodic protection at the bottom part of transformer
• Ch has tried plastic sheeting to divert water entering the structure from the grate away from the equipment tank tops; however, this approach was difficult to implement, and limited structure access in some cases
• To remediate corrosion identified through inspection, CH has tried sandblasting away rust and then repainting, but found this expensive. Primary remediation approach is to replace units identified through inspection.
• CH noted that corrosion issues found during inspection may include cable system components

OG&E

• Transformers are their main issue, as units have direct exposure to water dripping on them as units are situated under the vault grating
• Switches and other equipment seem to perform better since they are wall mounted and not located under the grating
• If, through inspection, corrosion is identified early, OG&E may sand and recoat equipment tank sections
• OG&E uses galvanized ladders in vaults; if corroded, they will remove, repair and recoat the ladders
• For vaults that contain standing water, they may place UG transformers on a 6 inch stainless steel I-beam to keep the transformer above the water in order to forestall corrosion.

Dominion

• Conditions may vary, for example, they experience salt water in the eastern part of VA
• Identify corrosion through inspection
• Have been replacing the tops of the transformers for about 12 years
• Most of their corrosion issues are with transformers and switches that are under water
• Utilized Mg anodes, but led to build up on transformers. Switched to Zn but then had to reduce the size
• One strategy they used was to specify corrosion resistant coatings on transformers
• Initially used metal I-beams to raise transformer off the ground, but experienced corrosion of the beams. Switched to a concrete beam to raise transformer

FirstEnergy

• Have had corrosion issues with transformers
• Different ways of addressing corrosion across their operating companies.
• One strategy to prevent debris and moisture from affecting transformer tops is to install sheeting over the tops of transformers using corrugated fiberglass roofing material. This is effective, but the material can break and fall onto the transformer
• Keep vaults dry as much as possible – but sump pumping may not be possible due to oil contamination
• Metal cable racks on the wall are an issue – switched to a fiber reinforced cable rack
• Cast in place ladder rungs tend to corrode away
• Focus on avoiding scrapes and scratches in transformer coatings to prevent corrosion

PHI

• In their equipment tank specifications, other than network transformers, they are moving away from mild steel and towards stainless steel. Network transformers continue to be mild steel
• Aggressive inspection program, including recording corrosion findings.
• A challenge is identifying how much rust is acceptable. It is hard to see the rust, especially in locations under the paint
• PHI specifies anodes (32 – 3 lb Mg anodes) , they replace the anodes if found more than 50% consumed during inspection

CPS Energy

• CPS does not experience major issues with UG equipment corrosion
• During their normal inspection cycle for transformers (yearly), CPS Energy does a visual inspection for corrosion.
• A vault inspection checklist is completed by crews, includes corrosion findings.
• If a corrosion finding is repairable, the crew can take care of it then

Com Ed

• Not much trouble with corrosion of UG transformers. The bulk of their corrosion issues are with structural items, such as cable racks.
• For transformers, specify a robust coating system and most are in dry vaults
• Transformers are not placed directly underneath grating. Drip edge helps keep moisture from dripping on transformer
• Cable racks seem to be more of an issue; Com Ed is replacing older galvanized steel racks with stainless & composite racks
• Bronze supports did not work well

National Grid

• Same corrosion problems as most utilities experience
• NE gets runoff from road treatments in their vaults
• Prevention strategies include the use of stainless steel tanks, and special coatings.
• The have experienced corrosion issues with pressure relief devices (PRDs) used on network transformers. Switched from an Al to a brass flange
• Had had corrosion issues with galvanized steel ladders and cable racks
• Install Mg anodes in the manholes
• Utilize support I-beams (concrete or granite slabs) to support transformers
• Use Tin coated copper bonds for all the equipment
• 5 year cycle inspection

We Energies

• No network, but do have under sidewalk type vaults on their system
• Use stilts under equipment to keep them off the floor in the vaults. Use Concrete supports under transformers an switches.
• Use sacrificial anodes
• Use a basin on the top of transformers to cover the top of the transformer, and keep the salt spray off of the units
• Use other diversion techniques as well to keep salt water from hitting equipment
• Use stainless steel equipment as a corrosion prevention strategy
• Do not experience problems with their cable racks.
• Perform a Bi-annual inspection of the manhole. The inspection card is stored at the manhole. (Change prompted by an incident where a ladder broke away from the frame and an employee fell).
• Noted that they have corrosion the lift off slab, corrosion of the roof of the structure, and cracking walls.

To download a PDF of this summary, click here.