urd system inspection, maintenance and replacement practices discussion topic community insights...

URD System Inspection, Maintenance and Replacement Practices

Discussion Topic

Community Insights Conference

August 19-21, 2015

Minneapolis, MN

2015 Electric T&D Benchmarking

Agenda

◼ Introduction Discussion Topic Objective and Approach Webinar Organization Webinar Participants

◼ Background URD Definition URD Cable Installation Practices Common Reliability and Maintenance Issues

◼ Webinar Key Findings Impact of design and construction standards on URD system reliability Cable management programs – similarities and differences Equipment replacement programs – similarities and differences Equipment inspection programs -- similarities and differences Program effectiveness KPI measures

◼ Company Practice Discussions In-Conduit versus Direct Buried Design Choice – CenterPoint Energy – Richard Moffatt Cable-In-Conduit Challenges and Strategies – Southern California Edison – Seema Abraham

Appendix A – Tabulation and Analysis of Webinar Responses Appendix B – URD System Features and Terminology

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Introduction

◼ Most utilities in North America began installing large amounts of URD infrastructure in the mid-1950s to early 1960’s, in response to the following factors: Increasing demand for housing and commercial development in suburban areas surrounding

larger cities Decreasing acceptance of overhead electric circuits from an aesthetics perspective The introduction and ongoing refinement of primary cable designs that used polymer-based

insulation compounds.

◼ In many areas, local building regulations now require that all utilities in new developments be installed underground. As a result, the size of the North American URD infrastructure continues to grow.

◼ A large portion of the installed URD cable plant in North America is reaching the end of its reliable service life. The failure rate of older vintage cable has become problematic at many utilities. Older URD “live front” equipment is also becoming problematic from an employee safety perspective.

◼ Utilities are now looking for strategies to help them optimize their capital and maintenance spending while sustaining or improving the performance of their URD systems. A great deal of academic research and industry information exchange has taken place over the past 10 years on the topic of “life-cycle-cost optimization” for URD systems

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Objective and Approach

◼ The primary objective of this discussion topic was to develop a good understanding of the current and historical practices of our T&D community companies related to the design, construction, maintenance and replacement of URD systems, with particular focus on:

1. How URD design and construction standards (current and historical) have impacted system performance and the development of company URD inspection, maintenance and replacement programs

2. How state/provincial regulations have impacted the company programs

3. The technologies, methods and labor resources that are now being used in the programs

4. The KPI measures that are being used to evaluate program effectiveness

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Organization of URD Discussion Topic Webinars

Webinar #1URD Standards and Maintenance IssuesMay 21, 2015

Webinar #2URD Cable Management PracticesMay 28, 2015

Webinar #3URD Equipment I&M PracticesJune 4, 2015

• URD design and construction standards –current and historical

• Reliability trends • Problematic

equipment

• URD primary riser I&M• URD switchgear and

junction box I&M• URD transformer I&M • URD secondary

equipment I&M

• Trends in cable failure rates

• Cable rehabilitation policies

• Cable treatment programs

• Cable replacement programs

Asset Managers URD Standards

Engineers Distribution Reliability

Data Experts

Asset Managers URD Cable Mgmt

Program Managers Field Supervisors/

Manager s

Asset Managers URD I&M Program

Managers Field Supervisors/

Managers

Issues that were discussed:

Company subject matter experts that participated in the discussions:

Webinar Participants

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BG&E

CenterPoint Energy

ComEd

CPS Energy

KCP&L

Oncor Electric Delivery

Southern California Edison

Tucson Electric Power

Westar Energy (Webinar #1 only)

Background


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URD Definition

“URD” refers to a type of electrical distribution that has the following characteristics:

Primary cable and secondary wire are installed below grade, either directly in the ground (“direct-buried”) or in plastic conduit.

Primary cable can have either copper or aluminum phase conductor, is typically insulated with a polymer material (HMWPE, XLPE, TRXPLE or EPR, depending on cable vintage), usually has copper concentric neutral installed outside of the insulation and may or may not have a plastic jacket over the neutral

Equipment components such as switchgear, junction boxes, distribution transformers and secondary terminals may either be installed above grade, on foundation pads, or below grade, in an enclosure or vault.

Switchgear and transformers may either be “live-front” or “dead-front” design Primary circuit topology to distribution transformers may either be “radial feed”, “loop feed” or “dual

feed” Secondary circuit topology to secondary pedestals may either be “radial feed” or “loop feed”

Appendix B describes common URD system features and includes definitions for all of the technical terms referenced above, in the “Webinar Key Findings” section of this presentation and in the slides contained in Appendix A.

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URD Cable Installation Practices

◼ Direct buried construction: the majority of the cable is installed in the ground through cable plowing, trenching or boring operations (see picture on left, below). Conduit is used only at road, railroad and river/stream crossings and/or in locations where the soil is particularly rocky

◼ Conduit-based construction: Rigid plastic pipe of various diameters and wall thicknesses is installed for all planned cable runs. The conduit for the primary cable is run to the base of the riser poles, under the equipment foundations and into below-ground precast equipment vault boxes. Where it is necessary to make long cable runs or turns in the cable routing, precast “cable pull boxes” are installed and connected to the conduit between equipment locations. This aids the initial cable installation process and enables any potential future cable repair or replacement work to be accomplished more efficiently. A similar approach is used on the secondary side with the secondary conduit running into smaller boxes commonly called “handholes”. The installation sequence typically starts with open trenching followed by manual installation of conduit and pull boxes, backfilling and then cable pulling through the conduit pipe (see picture on right, below)

Direct buried construction(primary distribution line in residential front yards)

Conduit based URD construction(service feeds to multifamily residential development)

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URD Cable Installation Practices (Continued)

◼ Cable-in-conduit (CIC), also referred to as Cable-in-Duct (CID) construction: the primary cable and secondary wire is pre-inserted into flexible tubing by the manufacturer. The CIC/CID product is installed in the ground through cable plowing or trenching. Regular plastic conduit is used only at road, railroad and river/stream crossings.


Plastic conduit tubingURD cable

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Common Reliability and Maintenance Issues – URD Cable

◼ A large portion of the current installed URD cable plant in North America is reaching the end of its reliable service life. Gradual deterioration in the effectiveness (dielectric strength) of cable insulation and in the integrity of the neutral wire occurs over time as a result of ongoing exposure to water and corrosive chemicals found in soil. In addition, early vintage URD cable used insulation materials, splicing technology and manufacturing methods that were decidedly inferior to what is available today. As the early vintage URD cable population has aged, its impaired reliability has become a major concern at many utilities.

As of the end of 2009, the challenge facing the U.S. utility industry looked like this:

Problematic early vintage cable that was replaced from early 1990’s through 2009

Early vintage cable that started to become very problematic by the early 1990’s

Source: Research paper by J.P.Ainscough, P.E., and Ian W. Forrest, P.E., Presented at the IEEE PES-ICC Fall Meeting, November 11, 2009, Scottsdale, AZ

30 Years

Replacing 150 million feet = 28,400 miles/year!

20 Years

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Common Reliability and Maintenance Issues – URD Cable (Continued)

◼ In addition to the deterioration and premature failure problems that companies have been seeing with their early vintage cable systems, any type of cable system can be damaged and eventually fail as a result of poor installation practices, moisture and chemical caused corrosion, circuit overloading, excessive heat, lightning strikes on attached equipment, dig-ins, frost heaving of supporting soil, subterranean root growth

and other factors

Cable faults on 2 cables

◼ When cable failures do occur, the cable repair and service restoration process is relatively prolonged and costly due to the complexity and labor-intensity of the work steps required to: Identify and isolate the failed cable segment through switching and grounding operations Determine the location of the fault within the cable segment (special testing is often required) Disconnect cable from equipment, remove the terminations (e.g., elbows) and pull the cable out of

the conduit (for in-conduit systems) or excavate (for direct buried systems) in order to expose the damaged portion of the cable.

Cut out the damaged portion of cable, splice in a section of new cable (two splices are required) and reinstall the cable in the conduit, reinstall the terminations and reconnect the cable to the equipment (for cable pulled out of conduit systems)

Perform switching operations to put the repaired cable segment back in service Backfill excavations and perform any needed surface restoration work (for direct buried systems)

Deteriorated concentric neutral (unjacketed cable)

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Common Reliability and Maintenance Issues -- URD Equipment

Electric Reliability Issues:◼ Moisture penetration may cause corrosion or deterioration of cable terminations, gaskets and other

connection devices on URD equipment, leading to electrical faults. ◼ Primary risers and URD equipment components may fail as a result of poor manufacturing or

installation practices, overloading, excessive dirt or road salt contamination, vehicle accidents and lightning strikes

◼ Animal and insect infiltration and the accumulation of water and debris in above-ground equipment cabinets and underground equipment enclosures can cause operating problems and electrical faults

◼ Soil erosion, frost heaving and subterranean root growth under equipment foundations and vaults may cause equipment to tilt, affecting its appearance and performance. Transformers that are not level can overheat and fail.

Safety, Operability, Environmental and Appearance Issues:◼ The external appearance and physical security of above-ground equipment cabinets may be

degraded as a result of natural forces (e.g., paint deterioration and rusting) or vandalism. ◼ Equipment switching activity can sometimes result in dangerous flashovers, particularly on older

vintage live front equipment ◼ Oil leaks from transformers and some types of URD switchgear may pose environmental hazards

◼ Above-ground equipment may be damaged by people accidentally hitting the equipment with vehicles and lawn equipment and other actions, intentional or unintentional. Primary riser components may also be damaged or exposed to the public as a result of vehicle accidents or vandalism

◼ Utility access to operate and maintain above-ground equipment may be compromised as a result of landscaping changes, the planting of large trees/shrubbery or the construction of fences and other structures too close to the equipment.

URD Equipment -- Run to Failure or Perform Scheduled I&M?

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Fire ant infestation

Infrared scanning of connections

Internal inspection and cleaning Note the PPE: rubber mat, rubber glovesand sleeves

Aesthetics and possible security issues

Source: Osmose Utility Services, Inc. sales pamphlet , 2009

Webinar Key Findings


Key Findings: Standards Impact on URD System Reliability and Company Programs

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◼ The webinar responses show that deficiencies in early vintage URD cable material standards have caused significant reliability problems at all of the companies that participated in the webinars and have lead all of them to initiate large scale cable management (diagnostic testing, treatment and/or replacement) programs

◼ The webinar responses also show that weaknesses in early vintage URD equipment (switchgear and transformer) design standards have caused operating problems after decades of use and have lead most of the companies to initiate proactive equipment replacement programs

◼ The webinar responses did not shed any light on the impact of past or current URD equipment standards on the companies’ current equipment inspection and maintenance programs: Over the years, the companies have made similar equipment choices and report similar

equipment issues today, yet their current inspection programs vary widely.

Key Findings: Standards Impact on URD System Reliability and Company Programs (Continued)

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◼ The webinar responses also did not shed any light on what impact the following URD system design choices have had on current URD system reliability and/or on company URD equipment inspection, maintenance or replacement programs: Direct buried versus in-conduit construction Loop versus radial design of primary circuits Front yard (road accessible) versus backyard (non-road accessible) construction.The participating companies have made different choices on the above system parameters, but the reliability impact is hard to isolate due to the dominant influence of the early vintage cable material deficiencies. Also, some companies have changed their minds on the above parameters one or more times since they began installing URD systems.

◼ In the following areas, current URD standards are identical or very similar across the group of companies that participated in the webinars: All are now installing jacketed concentric neutral cable with TRXLPE or EPR insulation All primary equipment is dead front and installed above grade All secondary is radial feed from the transformer to pedestal or handhold

The first two design choices were responses to the problems encountered with early vintage cable and equipment. The webinars did not shed any light on why all of the companies that participated in the webinars are installing radial secondary distribution, while some other North American utilities install secondary loops.

Key Findings: Regulatory Impact on Programs

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◼ None of the companies that participated in the webinars have any regulations that deal specifically with cable treatment or replacement.

◼ None of the companies that participated in the webinars have any regulations that deal specifically with URD equipment replacement.

◼ Only two of the companies that participated in the webinars have regulations that deal specifically with URD equipment inspections

Key Findings: Cable Management Programs

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◼ Reported URD cable failure rates range from 0.048 to 0.35 failures per year per mile of installed cable

◼ The companies have very different “repair versus replace” policies regarding their immediate response to individual cable failures. The differences in those policies do not seem to correlate with differences in the companies’ cable failure rates

◼ 88% of the companies (8 of 9) have large-scale programs to rehabilitate (treat and/or replace) older vintage URD cable, but the methods of organizing the programs and determining what cable gets addressed first vary across the webinar participants

◼ Of the companies that are now replacing cable, 75% (6 of 8) are also treating some cable, with half of those companies using the UtilX products and methods and the other half using Novinium products and methods

◼ 63% (5 of 8) of the companies that are treating and/or replacing cable have incorporated diagnostic testing into their programs to narrow the focus and save money, with two using UtilX on-line testing technologies and three using IMCORP off-line testing.

Key Findings: Cable Management Programs (Continued)

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◼ Reported cable replacement costs range from $45 per foot to $100 per foot

◼ Reported cable treatment costs range from $15 to $25 per foot

◼ All companies contract at least a portion of the construction trades work on their cable replacement and treatment programs

Key Findings: Equipment Replacement Programs

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◼ 67% (6 of 9) of the companies that participated in the webinars are now proactively replacing older live front URD equipment that has become problematic from an operability and employee safety perspective.

◼ Most of the companies are replacing their problematic equipment in conjunction with their proactive cable replacement programs

◼ A few also have separate programs to replace certain types of early vintage equipment independent of cable replacement work, such as below grade (“siloed” or “submersible”) transformers.

.

Key Findings: Equipment Inspection Programs

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◼ 50% of the companies that participated in webinar #3 (four of eight) have scheduled inspection programs that encompass all or most of their URD switchgear and transformers. The inspection cycles and methods vary across companies

◼ Only three (38%) have scheduled inspection programs for URD primary risers. The inspection cycles and methods also vary for those three programs.

◼ None of the companies that participated in the webinar perform scheduled inspections of URD secondary equipment (pedestals, enclosures or handholes)

◼ The above referenced differences in inspection programs cannot be correlated to any significant differences in past or present equipment standards nor to the companies’ current URD system reliability levels

◼ At all companies, internal inspections of equipment (dead front or live front, scheduled or unscheduled) are performed by “electrically qualified” labor, and mostly by company employees.

◼ Two of the four companies that have scheduled inspection programs contract portions of their inspection work

Key Findings: Program Effectiveness KPI Measures

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◼ KPI measures tracked on URD cable management programs: Cable failure rates per mile (for total system and/or by cable vintage) – 75% (6 of 8)

are currently tracking this measure Cost per foot to treat and/or to replace cable – 63% (5 of 8) are currently tracking Failure rates of cable that was treated (as a separate class and/or as compared to

the failure rates of similar vintage untreated cable) -- 60% (3 of 5) of the companies that are treating cable track this measure

Cable program impact on worst performing feeder reliability statistics -- 13% (1 of 8) are currently tracking

◼ KPI measures tracked on URD equipment replacement and I&M programs: None of the companies that participated in the webinars are tracking any specific KPI

measures related to their equipment replacement or I&M programs

Company Practice Discussions


Company Practice Discussions

CenterPoint EnergyRichard Moffatt, Senior Consulting Engineer

In Conduit vs. Direct Buried Design Choice

Southern California EdisonSeema Abraham, Senior Project Manager – Reliability & Infrastructure Replacement

Cable-In-Conduit Challenges and Strategies

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Appendix A Tabulation and Analysis of Webinar Responses


Webinar #1 - Current URD Design and Construction Standards – Page 1 of 4

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The phase to phase operating voltages for URD systems at the companies that participated in the webinars range from 4kV to 35kV.

All of the companies are now using jacketed concentric neutral cable with TRXLPE and/or EPR insulation.

Pre-formed cold shrink splices are the most common splice type

BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson Electric

Westar

URD System Operating Voltages and Primary Cable & Splice TypesOperating voltages (phase to phase)

13kV and 35kV

12kV and 35kV

12kV 13kV and 35kV

12kV, 13kV and 25kV

12.47kV, 13.2kV and 35kV

12kV and 16kV

4kV and 13kV12.47kV

Cable Types 500AL and #2AL, Jacketed TRXLPE

1/0 AL, jacketed TRXLPE

#2 CU jacketed EPR and 3/0 AL jacketed EPR

jacketed EPR on mainline; jacketed TRXLPE on URD single phase dist.

1/0 AL, jacketed EPR

jacketed TRXLPE with 260 mil insulation thickness

jacketed 1/0 AL,TRXLPE with 220 mil insulation thickness

1/0 AL and 2/0 AL, jacketed EPR

jacketed TRXLPE

Splice types Cold shrink Cold shrink Cold shrink on mainline, heat shrink on URD distribution

Heat shrink Cold shrink Cold shrink Cold shrink Cold shrink Cold shrink


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Most of the companies are now installing their new URD cable in plastic conduit. Two companies direct bury their primary.

Most companies use both radial and loop design in residential developments based on # of transformers criteria. Two companies use loop designs in all residential developments and one uses radial design in all developments.

The group fairly even split between those who always or mostly construct in front yards (road accessible locations) and those who always or mostly construct in backyards (non-road accessible) locations


Westar

URD Primary Cable Installation Method and System Design Cable installed in conduit or direct buried?

Direct buried In plastic conduit, no spare conduit

Direct buried In plastic conduit, no spare conduit

In plastic conduit, no spare conduit





Use Cable-In-Conduit (CIC) products?

No No No No No No No No Yes

Radial or loop feed design for residential?

Loop or radial based on # transformers criteria

Loop for both single family and multi-family residential

Radial - 4 or fewer XFMRs; Loop - 5 or more XFMRs

Loop Loop or radial based on # transformers criteria

Loop Radial Radial - 2 or fewer XFMRs; Loop - 3 or more XFMRs

Loop design target; for phased construction will operate radial until loop can be completed

Front yard or back yard construction?

Mostly front yard

Mostly backyard

Mostly backyard

Both - more backyard because of developer preference

Front yard Front yard; other locations only if there is a paved ROW

Front yard Front yard or by paved alleys

Both


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On new installations, all of the participating companies are now installing above grade primary equipment that that has a dead front design.


Westar

URD Switchgear, Junction Boxes and Transformers

Live front or dead front design?

Dead front Dead front XFMRs (no switchgear)

Dead front Dead front XFMRs (no switchgear)

Dead front Dead front Dead front Dead front XFMRs and 3 phase mainline switchgear (no single phase)

Dead front

Installed above grade or in underground vaults?

Above grade Above grade Above grade Above grade Above grade Above grade Above grade Above grade Above grade


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On new installations, the majority of the participating companies install their secondary wire in conduit. Two companies direct bury their secondary.

All of the companies use a radial feed design for their secondary runs from transformers to pedestals/secondary terminals.

Most companies currently install above grade secondary pedestals/terminals


Westar

URD Secondary Distribution

Wire installed in conduit or direct buried?

Direct buried In conduit Direct buried In conduit In conduit, In conduit In conduit In conduit In conduit, some is CIC

Radial or loop feeds from transformers to pedestals

Radial Radial Radial Radial Radial Radial Radial Radial Radial

Pedestals installed above or below grade?

Above grade Above grade Above grade Above grade Above grade Above grade Handholes, Below grade

Above grade Above grade

Webinar #1 - Historical URD Design and Construction Standards – Page 1 of 2

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All of the participating companies installed unjacketed XLPE and/or HMWPE cable in the past.

Most companies used hand taped splices in the past Some companies installed different types of conduit in the past which have proven to

be problematic (CIC tubing, transite and orangeburg pipe duct). Some companies that now build loop systems and/or install in front yards did the

opposite in the past.


Westar

Historical Standards for Primary Distribution – Differences from Current StandardsPrimary distribution cable and conduit

Older construction used unjacketed XLPE cable; used hand taped splices prior to 1985.

Used XLPE 1/0 AL and HMWPE #2 CU and 1/0 AL cable in the past. Have gone back and forth on direct buried vs in conduit; most recent switch back to conduit was in 2013

Older 4KV and 35KV systems used a variety of cable types including #4 copper poly-lead and PILC; also installed unjacketed XLPE cable in the 1970's. Older splices were hand taped

In the past installed unjacketed XLPE cable, direct buried. Older residential ciruits were radial feed.

Pre-1983 cable was direct buried. Used HMWPE, XLPE and EPR prior to 1990 when we went to EPR only. Mostly backyard in the past

Used unjacketed HMWPE and XLPE cable in the past. Have gone back and forth on direct buried vs. in conduit; most recent switch back to conduit was in the mid-1990's. Older residential ciruits were radial feed and were often installed in rear lot line.

Used CIC up until 2003. Older cable was unjacketed XLPE. Installed some primary cable and secondary wire direct buried in the past. Some rear lot line construction in past. Used both transite and orangeburg pipe duct in the 1960's

Used 1/0 AL unjacketed XLPE cable prior to the 1980's and some unjacketed EPR between the 1980's and 2000. Have always installed in conduit but some older conduit (pre-1980’s) was transite pipe

In the past installed unjacketed cable, direct buried. Older splices were hand taped.

Webinar #1 - Historical URD Design and Construction Standards – Page 2 of 2

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All of the participating companies installed live front equipment in the past. Most companies installed some of their primary and secondary equipment below

grade in the past, in vaults or precast enclosures


Westar

Historical Standards for Primary and Secondary Equipment Installations - Differences from Current Standards

Primary equipment type differences (live front versus dead front)

Installed live front switchgear and transformers in past

Installed live front transformers on 12kV systems in past

Just changed from live front to dead front design for 3 phase switchgear, also used live front single phase switchgear and transformers in the past

Installed live front transformers in past

Installed live front transformers in past

Installed live front switchgear and transformers in the past



Installed live front switchgear in past

Primary and secondary equipment installation differences (below grade versus above grade)

Installed some transformers in vaults in the past, along with sub-surface modules

Installed some secondary pedestals below grade in the past

Many below grade "siloed" transformer installations in the past (OH XFMR in a cylinder with a fiberglass top)

Installed some transformers in vaults in the past

No difference – have always used above grade equipment

Installed some transformers and secondary pedestals below grade in the past.

Installed most transformers below grade in fiberglass enclosures in the past.

Installed some switchgear below grade in the past

Webinar #1 - Current URD System Reliability

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Six of the nine participating companies reported that the reliability of their URD systems was better than that of their overhead distribution systems.

Four companies said that their URD reliability was improving, three said their URD reliability was deteriorating and two said that their URD reliability had leveled off in recent years


Westar

Current URD System Reliability

Current URD System Reliability Compared to Overhead

Data shows that URD reliability is better than Overhead



No comparison data is available, but believe that URD reliability is better than Overhead

Data shows that that URD reliability is better than Overhead

No comparison data is available, but believe that URD reliability is worse than Overhead

SAIDI data shows that URD reliability is worse than Overhead

No comparison data is available


URD Reliability Trend

Improving --The number of URD faults has leveled off, while number of customers impacted per fault has decreased

Leveled off -- 62% of customers are now served from URD distribution

Improving due to investment in cable rehabilitation

Improving due to investment in cable rehabilitation

Gradual deterioration

Deteriorating Deteriorating – we are stepping up our cable rehabilitation programs to prevent any further deterioration

Overall system reliability has leveled off, 70% of customers are served from underground systems

Improving

Webinar #1 - Problematic Equipment and Current Proactive Replacement Programs

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Westar

Problematic Equipment and Proactive Replacement Programs

Current Problematic Equipment

Older vintage cable and live front equipment

Older vintage cable and live front transformers

Older vintage cable and live front equipment, including "siloed" transformers

Older vintage cable and some concerns about older live front equipment



Older vintage cable


Direct buried unjacketed cable and rusted transformers and junction boxes

Current Active Replacement Programs


Older vintage cable and replacing live front transformers when replacing cable

Older vintage cable and live front equipment, including "siloed" transformers

Older vintage cable

Older vintage cable and replacing live front transformers when replacing cable

Older vintage cable

Older vintage cable, live front equipment and UG oil filled switches

Older vintage cable and replacing live front equipment when replacing cable

Rusted transformers and junction boxes.

All of the participating companies reported that their older vintage non-jacketed cable was problematic from a service reliability perspective and all but one now have proactive programs to replace that cable.

Most companies also expressed concerns about their older live front equipment from an operations and employee safety perspective, and 67% (6 of 9) are now proactively replacing some of that equipment

Webinar #2 - Cable Failure Rates and Repair vs. Replace Policies

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BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson ElectricOverall Failure Rate - # cable failures per circuit mile per year

Data not available

Data not available

0.27 0.35 0.05 0.20 0.048 0.05 to 0.10

Cable Failure Trend

Decreasing Level Decreasing Decreasing Increasing Increasing Increasing Increasing slightly

Cable with highest failure rates currently

Pre-1985 vintage unjacketed XLPE cable

Older vintage cable

Pre-1985 vintage unjacketed XLPE cable

Older vintage unjacketed XLPE cable

Cable installed between 1972 and 1977

Pre-1993 unjacketed cable

Older vintage cable

Old unjacketed concentric neutral cable

Post-Failure Repair versus Replace Policies

Repair cable span if there were no other failures within rolling 18 months; Replace cable span upon 2nd failure within rolling 18 months

Repair cable span. Also create future project to replace loop as part of proactive replacement program (subject to program priorities)

Repair cable span

Repair cable span. Also create future project to replace cable span as part of proactive replacement program (subject to program priorities)

Repair cable span if there were no previous failures; Replace cable span upon 2nd failure (cumulative)

Repair cable span. Also create future project to treat or replace cable span as part of proactive program (subject to program priorities)

Replace failed cable span from structure to structure

Repair cable span

The six companies that track per cable failure rates reported rates ranging from 0.048 to 0.35 failures per circuit mile per year.

Four companies are experiencing increases in cable failures, three are experiencing decreases, and the failures have leveled off at one company.

The post-failure repair versus replace policies vary across the group of companies and those variances do not seem to correlate with either the current cable failure rates nor the current trends in those rates

Webinar #2 - Cable Replacement Programs – Page 1 of 4

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Currently Have a Cable Replacement Program?

Yes, we have a large program budget supporting reactive replacements based on failure threshold criteria. We have also just started a small cable treatment program.

Yes, a proactive cable replacement program that is currently addressing reliability issues on 450-500 URD loops per year

Yes, a proactive integrated treatment and replacement program that started in 2007 and should be completed in 2017. So far we have treated or replaced more than 5,000 miles of early vintage cable

Yes, a proactive program to replace 35 miles per year of old cable under an $18.5 million annual budget. This is part of an overall cable rehabilitation program through which we have treated or replaced about 1,600 miles of older vintage cable to date.

Yes, proactive programs for both cable replacement and cable treatment

Yes, proactive programs for both cable replacement and cable treatment

Yes, a proactive program focused on addressing the early vintage cable problems on our Worst Performing Feeders. We have also just started a cable treatment program.

Yes, a proactive program focused on addressing the early vintage cable problems on our Worst Performing Feeders under a $3 million annual budget.

Program Organization Scheme

Cable span URD Loops URD Loops Subdivision Circuit branches (half loops)

Cable span Cable span Circuit

All of the companies that participated in the webinars have active cable replacement programs.

The programs are organized and tracked in different ways -- e.g. by cable spans, branches (half loops), full loops, full subdivisions or circuits


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BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson ElectricRanking/Selection Criteria

Replace all cable spans which have had 2 or more failures within a rolling 18 month period

Loops are ranked and selected based on cable vintage, use of conduit, # of equipment failures and # of loop failures. Further selection is based on diagnostic testing results but we replace all pre-1970 vintage cable without testing.

Loops are ranked and selected based on #outages, # customers and duration of outages

Subdivisions are ranked and selected based on number of cable failures

URD circuit branches are ranked and selected based on cable failure rates and vintage

Cable spans are ranked and selected based on cable vintage and then failure history. We are focusing on pre-1993 unjacketed cable.

Worst Performing Feeder selection criteria plus further ranking and selection of individual cable branches/loops on those circuits based on cable type, vintage and # failures over past 3 yrs

Worst Performing Feeder selection criteria plus further ranking and selection of individual cable branches/loops on those circuits based on cable type and vintage.

Perform Diagnostic Testing to Identify and Replace Only The Bad Cable Segments?

No Yes, use IMCORP partial discharge testing. We replace only the bad segments on a loop if less than about 70% of the cable spans test bad. If more than 70% test bad, we replace the entire loop

No No Yes, use IMCORP partial discharge testing

No for URD distribution cable; Yes for mainline cable (have used both IMCORP partial discharge testing and UtilX CableWISE testing)

Yes, use IMCORP partial discharge testing

No for URD distribution cable; have recently used UtilX CableWISE testing on 600 amp mainline cable

The companies have different criteria for ranking and selecting what cable will be addressed first.

Five of the companies use diagnostic testing to help narrow the focus and thereby save money or get more cable replaced under a fixed budget.


39

Construction methods to replace cable vary based on the companies’ current and past construction standards (direct buried vs. installed in conduit) and problems that are encountered in the field with some of the existing conduit/duct.

All companies contract at least a portion of their cable replacement work.

BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson ElectricConstruction Method to Replace

Install new cable direct buried, 99% through directional boring

Pull bad cable out and new cable into existing conduit if conduit is at least 3" in diameter, otherwise install new conduit through directional boring and pull in new cable. Do not install a spare conduit.

Install new cable direct buried, almost always through directional boring

Pull bad cable out and new cable into existing conduit if we can. However, most of the cable being replaced now is direct buried so we are typically installing new conduit through open trenching and pulling in new cable. Do not install a spare conduit.

Pull bad cable out and new cable into existing conduit if available. Otherwise we install new conduit through directional boring and pull in new cable. Do not install a spare conduit.

Pull bad cable out and new cable into existing conduit if available. Otherwise we install new conduit through directional boring and pull in new cable. Do not install a spare conduit.

Pull bad cable out and new cable into existing conduit if available. Otherwise we install new plastic conduit and pull in new cable. Do not install a spare conduit.

Pull bad cable out and new into existing conduit (including old transite duct) if available and not obstructed. Otherwise we install new plastic conduit through directional boring and pull in new cable. Do not install a spare conduit.

Construction Trade Labor

Company and contractor

Contractor Contractor Company and contractor

Contractor Contractor Contractor Company and contractor

Major Issues Encountered in the Field

Interference with other UG utilities

Rear lot line access, concrete cover

Rear lot line homeowner obstructions

Easement encroachments/ obstructions

Switching and hold-off clearance delays, hitting solid rock when boring

Rear lot line access, interference with other UG utilities

Pulling new cable through existing CIC duct, outdated maps, congestion

Blocked or collapsed old transite duct


40

The reported replacement costs range from $45 to $100 per foot of cable replaced.

75% of the participating companies (6 of 8) replace problematic live front equipment when they replace cable. Most also perform equipment inspection and corrective maintenance tasks at that time.

BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson ElectricAverage Replacement Cost Per Foot

Data not available

Data not available

Are tracking, but cannot share our data

$100 per foot $50 per foot $45 per foot $50 to $100 per foot

Data not available

Program Effectiveness KPI Measures Other Than Replacement Cost/Foot

Overall system cable failure rates

None Overall system cable failure rates + just started tracking failure rates on loops that were replaced




Measures are under development

Overall system cable failure rates and rack program impact on worst performing feeders

Is Live Front Equipment Replaced When Cable Spans are Replaced?

Yes Yes (transformers)

Yes (transformers)

No Yes (transformers)

No Yes, when part of proactive cable replacement program. No, when replacing cable reactively

Yes, when part of proactive cable replacement program. No, when replacing cable reactively

Other work performed when cable is replaced

Equipment inspection and corrective maintenance and replace all terminations

Equipment inspection and corrective maintenance and replace all terminations; also replace all transformers when replacing entire loops

Equipment inspection and corrective maintenance, add lightning arrestors and faulted ciruit indicators where appropriate.

Equipment inspection and corrective maintenance


Equipment inspection and corrective maintenance, usually replace terminations

None Equipment inspection and corrective maintenance; replace any equipment that is showing signs of significant deterioration

Webinar #2 - Cable Treatment Programs – Page 1 of 4

41

75% (6 of 8) of the participating companies are proactively treating some cable to prevent potential failures, extend its service life and postpone cable replacement.

The two companies that are not treating cable arrived at that decision for different reasons

As with cable replacement, the organization schemes for treatment programs vary across the group.

BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson ElectricCurrently Have a Treatment Program?

Yes, just starting a relatively small program after completing a pilot project last year.

No Yes, as a part of an overall integrated treatment/ replacement program. We first attempt to treat.

Yes, a proactive program that has a budget of $2.5 to $3.0 million per year. To date we have treated 451 miles of old cable.

Yes, a large proactive program to treat early vintage cable to prolong its service life.

Yes, proactive program

Yes, just starting a treatment program after completing a pilot project that involved about 40,000 feet of cable

No

Reasons for Not Having a Treatment Program

Proceeding cautiously with the current program due to a past program that was not successful

Analyzed in past and decided it would be too difficult and costly for us due primarily to splice issues

NA NA NA NA NA Considered in past and decided it would not be cost effective because of our low cable failure rates and the fact that most of our existing cable is installed in conduit

Program Organization Scheme

Cable span NA URD Loop URD Loop Circuit branch Cable span Circuit NA


42

The companies have different criteria for ranking and selecting what cable will be addressed first by their treatment programs.

Two of the companies that are treating cable use diagnostic testing to help narrow the

focus and thereby save money or get more cable treated under a fixed budget.


Ranking/Selection Criteria

Focusing now on post-1985 spans with 2 or more failures (cumulative). Cannot effectively treat pre-1985 cable because we were using hand taped splices

NA (don’t treat) Loops are ranked and selected based on #outages, # customers and duration of outages

Loops are ranked and selected based on number of cable failures

URD circuit branches are ranked and selected based on cable vintage and failure history

Cable spans are ranked and selected based only on failure history. We then test neutral strength. If less than 25% of original design strength, we will not treat but will refer to replacement program

Poor Performing Feeders with large amounts of URD cable

NA (don’t treat)

Perform Diagnostic Testing to Identify and Treat Only The Bad Cable Segments?

No NA (don’t treat) No No No No for URD distribution; Yes for mainline (have used both IMCORP partial discharge testing and UtilX CableWISE testing)

Yes, use IMCORP partial discharge testing

NA (don’t treat)


43

Half of the companies that are treating cable are using the UtilX “low pressure” method. The other half are using the Novinium methods, either “Unsustained”, “Sustained” or a combination of the two.

All of the companies that are treating cable contract at least a portion of the construction trades work.

BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson ElectricTreatment Method and Materials

UtilX low pressure method

NA UtilX low pressure method

Novinium, Unsustaimed method. Have also used UtilX low pressure method in the past.

Novinium -- about half with the Sustained method and half with the Unsustained method

UtilX low pressure method

Novinium, Sustained method

NA

Construction Labor


NA Contractor plus UtilX technicians


Contractor Contractor Contractor (for trades work) plus company (for switching)

NA

Major Issues Encountered in the Field

Interference with other UG utilities

NA Rear lot line homeowner obstructions

Easement encroachments/ obstructions, digging up splices that need to be replaced

Switching and hold-off clearance delays, blocked splices that need to be replaced, getting fluid to flow through tight cable bends on low profile eqt. connections

Rear lot line access/ obstructions

Outdated company maps, hand taped spices

NA


44

Reported treatment costs range from $15 to $25 per foot of treated cable.

None of the companies are replacing equipment when they treat cable, but most do perform equipment inspections and corrective maintenance work at that time.


Average Treatment Cost Per Foot

Data not available, just started program

NA (don't treat) 1/3 the cost of replacing cable

$20 per foot, 1/5 the cost of replacing cable



Data not available, just started pilot

NA (don't treat)

Program Effectivness KPI Measures Other Than Treatment Cost/Foot

None, just started program

NA (don't treat) Overall system failure rates; also tracking failure rates on treated loops; currently 1.5% per year

Overall system failure rates; also racking failure rates on treated loops; currently 1% per year

Overall system failure rates; also tracking failure rates on treated loops; have seen a 66% reduction factor compared to untreated loops of same vintage

Overall system failure rates

None. Just started pilot

NA (don't treat)

Other work performed when cable is treated


NA (don't treat) Equipment inspection and corrective maintenance and add lightning arrestors and faulted ciruit indicators where appropriate.

Equipment inspection and corrective maintenance, limited equipment replacements

Replace many terminations (elbows) to allow treatment; also perform general equipment inspection and corrective maintenance work

Equipment inspection and corrective maintenance, usually replace terminations

None NA (don't treat)

Webinar #3 - URD Switchgear and Transformer Inspection Programs - Page 1 of 3

45

Four companies have regularly scheduled inspection programs that cover all of their URD switchgear and transformers. Two of those programs are governed by state regulations.

All companies inspect individual equipment units when performing other work activities and perform any needed corrective maintenance at that time

BG&E CenterPoint ComEd CPS Energy KCP&L Oncor SCE Tucson ElectricDo you have a scheduled inspection program that covers all URD switchgear and transformers?

Yes. We also inspect and perform corrective maintenance when doing other work that involves the equipment.

No scheduled program, but we do inspect and perform corrective maintenance when doing other work that involves the equipment

Yes. We also inspect and perform corrective maintenance when doing other work that involves the equipment

No scheduled program, except for Automatic Transfer Operation (ATO) switchgear which we inspect on a 6 month cycle. We do inspect and perform corrective maintenance on all types of equipment when doing other work that involves the equipment


No scheduled program, but we do inspect and perform corrective maintenance when doing other work that involves the equipment. We also train and incent our field people in all occupations to be on the lookout for unlocked equipment and report any deficiencies that they find.


No scheduled program, except for Automatic Transfer Operation (ATO) switchgear which we inspect on a 1 year cycle. We do inspect and perform corrective maintenance on all types of equipment when doing other work that involves the equipment

Is program driven by state regulations?

No NA No No Yes No Yes No


46

The time cycles for detailed inspections for the most common applications of dead front URD equipment range from 5 years to 10 years.

Three companies perform infrared (IR) scans of terminations and connections Only one company does contact voltage testing on the equipment cabinets


URD switchgear and transformer inspection cycles

Most deadront eqt: 5 yrs All live front eqt: 2 yrs ATO switches: 1 year

(All above are detailed external and internal inspections)

NA (no program)

Most eqt: 10 yrs Eqt. at airports: 5 yrs Switchgear at schools: 2 yrs XFMRs at schools: 1 yr (All above are detailed external and internal inspections)

ATO switchgear: 6 months

External walking patrol: 4 yrs Detailed external and internal inspections: 8 yrs

NA (no program)

Detail inspection of all above ground equipment and structures: 5 yrs Detail inspection of all below ground (subsurface) equipment and structures: 3 yrsSimple visual inspection (Drive by): Annual

ATO switchgear: 1 yr

Have inspection checklists or forms?

Yes, covering both external and internal condition

NA Yes, covering both external and internal condition

No Yes, for External patrol

NA Yes, covering both external and internal condition

No

Perform IR scans?

Yes NA No No Yes, for detailed inspections

NA Yes, during detailed inspections

No

Test for contact voltage on cabinets?

No NA Yes No No NA No No


47

URD switchgear and transformer internal inspections are performed exclusively by “electrically qualified” labor and mostly by company employees.

The companies are not tracking any specific KPI measures to help evaluate the effectiveness of their URD switchgear and transformer inspection programs


Inspection labor sources and qualifications

Three phase eqt: company, electrically qualified Single phase eqt: Contractor, electrically qualified

NA (no program)

Company, electrically qualified (pool of 32)

Company, electrically qualified

External patrol: contractor, not electrically qualified, Detailed inspections (external and internal); Company and contractor, electrically qualified

NA (no program)



Program Effectiveness KPI Measures

None NA None None None NA None None

Webinar #3 - URD Primary Riser Inspection Programs - Page 1 of 3

48

Only three companies have regularly scheduled inspection programs for their URD primary risers. Two of those programs are driven by state regulatory requirements.

All companies inspect risers and perform any needed corrective maintenance when doing other work that involves the pole


Do you have a scheduled inspection program that covers all of your URD primary risers?

No scheduled program, but we do inspect and perform corrective maintenance when doing other work that involves the riser pole


Yes, as part of overhead equipment inspection program. Also inspect and perform corrective maintenance when doing other work that involves the riser pole


Yes. As part of overhead equipment inspection program. Also inspect and perform corrective maintenance when doing other work that involves the pole

No scheduled program, but we do inspect and perform corrective maintenance when doing other work that involves the riser pole.

Yes, as part of overhead inspection program. Also inspect and perform corrective maintenance when doing other work that involves the pole


Is the program driven by state regulations?

NA NA No NA Yes NA Yes NA


49

The inspection cycles range from 4 to 5 years for the three companies that do inspect primary risers.

Two of the three programs include infrared scanning of riser cut-outs, potheads, jumpers, etc.


URD primary riser inspection cycles

NA (no program)

NA (no program)

External visual inspection: 4yrs

NA (no program)

External patrol: 4 yrs Detailed inspection: 12 yrs

NA (no program)

Detailed inspection: 5 yrs

NA (no program)

Have inspection checklists or forms?

NA NA Yes NA Yes, for external patrols

NA Yes NA

Perform IR scans?

NA NA Yes NA Yes, for detailed inspections

NA No NA


50


Inspection labor sources and qualifications

NA (no program)

NA (no program)

Company, electrically qualified (pool of 32)

NA (no program)

External patrol: contractor , not electrically qualified; Detailed inspections: Company, electrically qualified

NA (no program)


NA (no program)

Program Effectiveness KPI Measures

NA NA None NA None NA None NA

Two of the three companies use “electrically qualified” company labor to perform all of their riser inspections. One company uses electrically qualified company employees for detailed inspections but uses a contractor with non-electrically qualified employees to perform external inspection patrols.

The companies are not tracking any specific KPI measures to help evaluate the effectiveness of their URD primary riser inspection programs

Webinar #3 - URD Secondary Equipment Inspection Programs

51


Do you have a scheduled inspection program for URD secondary equipment?

No scheduled program, but we do inspect and perform corrective maintenance when doing other work that involves the secondary equipment



No scheduled program, but we do inspect and perform corrective maintenance when doing other work that involves the secondary equipment, and when doing cable rehabilitation work on nearby primary cable


No scheduled program, but we do inspect and perform corrective maintenance when doing other work that involves the equipment. We also train and incent our field people in all occupations to be on the lookout for unlocked equipment and report any deficiencies that they find.



None of the companies that participated in Webinar #3 have regularly scheduled inspection programs for any URD secondary equipment

All companies inspect and perform any needed corrective maintenance tasks when doing other work that involves the secondary equipment

Appendix B URD System Features and Key Terminology

53

URD System Design

◼ URD systems are most commonly fed from overhead primary feeders. The URD is connected to the overhead feeder at one or more “primary risers”, also referred to as “riser poles”. The URD primary cable runs up the pole and is attached to overhead jumpers through a transition terminal that is called a “pothead”. The overhead jumpers are then connected to the overhead primary feeder through fused disconnect switches called “cutouts” (see picture on page 29)

◼ When URD systems are fed from underground mainline feeders, they are typically connected through a type of switchgear commonly called a “transclosure” or “switch-fuse unit (SFU)”. Within some URD systems, circuit branches may be tapped off of underground circuits in non-switchable equipment that is commonly called a “primary junction box”.

◼ Three basic design approaches are used for the layout and connection of URD primary distribution:

1. Radial Feed – Only one end of the URD system is connected to a source circuit and the primary cable is “daisy chained” between the transformers served by the system. If a fault occurs on any section of primary cable, all customers served by the system will lose power. After the fault has been located and isolated, all customers connected “upstream” from the fault can be re-energized but those connected “downstream” cannot be re-energized until the primary cable has been repaired or replaced.

2. Loop Feed – Both ends of the URD system are connected to the same source circuit and there is an open connection within the system. It is essentially two radial feed URD systems that can be interconnected. Any primary cable fault that occurs on one side of the open connection will only affect the customers located on that side. After the fault has been located and isolated, customers connected “upstream” from the fault on the primary system can be re-energized from their original source direction and those connected “downstream” can be re-energized from the other direction, through switching operations that move the open connection to first equipment component beyond the fault location (see picture on page 31).

3. Dual Feed – Transformers serving individual large customers are connected through switchgear to two separate URD systems, each of which is energized from a different source circuit. If a fault occurs on one URD system or its source circuit, service can be switched over, either automatically or manually, to the alternate URD system while the fault is being located and repaired.

Example Details of A Three Phase URD Primary Riser

54

“Pothead”

Overhead jumpers

Source: ArresterWorks website

55

URD System Design (Continued)

◼ Two basic design approaches are used for the layout and connection of URD secondary:

1. Radial Feed – Service wires for individual customers are either connected directly to a URD transformer or a secondary distribution line is extended from a single URD transformer to one or more “secondary pedestals”, which serve as the point of attachment for one or more individual customer services.. If there is a fault in the transformer or on the secondary distribution, all customers served by the transformer will lose power and all of the affected customers will remain out until the transformer or secondary distribution has been repaired or replaced. (see picture on page 31)

2. Loop Feed – Secondary distribution wire is extended from two adjacent URD transformers to multiple URD secondary pedestals in a “daisy chain” fashion, with an open connection within the secondary distribution. It is essentially two radial feed secondary systems that can be interconnected. Any transformer or secondary distribution line fault that occurs on one side of the open connection will only affect the customers located on that side. After the fault has been located and isolated, customers connected “upstream” from the fault on the secondary distribution can be re-energized from their original source direction and those connected “downstream” can be re-energized from the other direction, through switching operations that move the open connection to the first pedestal beyond the fault location.

Example Residential Subdivision With Looped Primary and Radial Secondary (Front Yard Construction In Conduit)

56

Source: NSTAR ElectricDesign Standard. August 31,2009

Cable Pull Boxes

Transformers

Secondary Distribution (Radial)

Secondary Pedestals and Services

RisersNormal Open Point in This

XFMR

Secondary Distribution (Radial)

Secondary Pedestals and Services

57

URD Equipment

URD switchgear and transformers are offered in a wide variety of configurations for both above-ground and below- ground installations. However, all of this equipment falls into one of the following two basic design types:

1. Live Front Equipment is so constructed that, when cabinet doors are open, there are exposed live (electrically energized) metal components that could be touched from the front of the assembly by someone working on the equipment.

2. Dead Front Equipment is so constructed that there are no exposed live (electrically energized) metal components that could be touched from the front of the assembly by someone working on the equipment. All bushings and terminals are covered with insulating material.

Due to the presence of exposed live metal components, operating or maintaining live front equipment is generally considered to be more risky than operating or maintaining dead front equipment. However, such equipment has been safely operated and maintained over many decades by trained electrical workers who are aware of the hazards and who wear appropriate personal protective equipment (PPE). Many utilities continue to purchase and install this type of equipment. At the same time, there are utilities that are now proactively replacing their older live front equipment due to issues that have arisen with the switching mechanisms after decades of exposure to the elements (some companies have reported violent unexplained flashovers when operating that older equipment).

The live front versus dead front distinction is important when utilities determine the source, training and field qualifications of personnel who are allowed to inspect and/or maintain equipment while it is energized. Generally utilities will not allow anyone other than a fully trained “electrically qualified” line worker or troubleshooter to open the cabinet doors of energized live front equipment and/or to reach into the cabinet for any reason. For dead front equipment, many utilities allow people with less extensive training and field qualification (e.g., engineers and design technicians, URD installers, meter & service technicians) to open up the primary side and perform a few relatively routine and low risk I&M tasks there (e.g., visual inspection, removing debris, checking cable tags) and also to perform cleaning and actual disconnection/reconnection work on the secondary side of energized transformers, as long as there is a physical barrier between the primary and secondary compartments.

58

URD Cable

◼ Most of the URD primary cable that is still in operation today in North America has copper or aluminum phase conductor covered by a “conductor shield” and then a layer of one of the following four types of insulation:

1. HMWPE (High Molecular Weight Polyethylene) -- used on cable installed in the 1960’s through 1970’s

2. XLPE (Cross-Link Polyethylene) -- used on cable installed in the 1970’s through 1990’s

3. TRXLPE (Tree-retardant XLPE) – used on cable installed in the 1980’s to now

4. EPR (Ethylene Propylene Rubber) -- used on cable installed in the 1980’s to now

◼ The cable insulation is encapsulated in an “insulation shield”. Copper “concentric neutral” wire or strap is then installed on top of the insulation shield. “Jacketed’’ cable then has a plastic cover installed over the concentric neutral to provide enhanced protection from damage during the cable installation process and ongoing protection from moisture and corrosive elements that may be present in the soil. “Unjacketed” cable does not have that final protective cover.

Conductor Shield Aluminum Conductor (stranded)

Insulation Insulation Shield

Concentric Neutral Wires

Jacket

59

URD Cable Installation Practices

◼ Direct buried URD construction: the majority of the cable is installed in the ground through cable plowing, trenching or boring operations (see picture on left, below). Conduit is used only at road, railroad and river/stream crossings and/or in locations where the soil is particularly rocky

◼ Conduit-based URD construction: Plastic pipe of various diameters and wall thicknesses is installed for all planned cable runs. The conduit for the primary cable is run to the base of the riser poles, under the equipment foundations and into below-ground precast equipment vault boxes. Where it is necessary to make long cable runs or turns in the cable routing, precast “cable pull boxes” are installed and connected to the conduit between equipment locations. This aids the initial cable installation process and enables any potential future cable repair or replacement work to be accomplished more efficiently. A similar approach is used on the secondary side with the secondary conduit running into smaller boxes commonly called “handholes”. The installation sequence typically starts with open trenching followed by manual installation of conduit and pull boxes, backfilling and then cable pulling through the conduit pipe (see picture on right, below)

◼ Cable-in-conduit (CIC), also referred to as Cable-in-Duct (CID) construction: the primary cable and secondary wire is pre-inserted into flexible tubing by the manufacturer. The CIC/CID product is installed in the ground through cable plowing or trenching. Regular plastic conduit is used only at road, railroad and river/stream crossings.

Direct buried construction(primary distribution line in residential front yards)


Example Details of Conduit Based URD Construction

60

Source: NSTAR ElectricDesign Standard. August 31,2009

61

URD Cable Treatment

Cable treatment (sometimes referred to as “cable rejuvenation”) is the injection of a silicone-based fluid into the strands of underground electric distribution cable. The fluid migrates into the conductor shield and insulation, modifying the chemistry of the insulation, restoring its dielectric strength and thereby extending cable life. Use of cable treatment can provide significant economies to companies that have a lot of problematic old vintage cable to address because total per foot treatment costs are typically less than 50% of cable replacement costs, depending on field conditions and the methods that would be used for cable replacement.

There are two major cable treatment methods in use which have different requirements, advantages and disadvantages:

◼ Unsustained Pressure Rejuvenation (UPR), also referred to as Low Pressure Treatment: A major advantage of this treatment method is that the fluid is able to flow through prefabricated splices unless they are blocked. Also, for smaller cable sizes (including all standard URD distribution cable), the cable can be reenergized after the injection process has been started. A major disadvantage is that the cable life extension warranties offered by most vendors are no longer than 20 years. Also, after the injection has been completed, the fluid feed tank must remain connected to the URD cable for a 60 to 120 day soak period and full dielectric recovery of the cable takes up to 24 months.

◼ Sustained Pressure Rejuvenation (SPR): The advantages of this treatment method are that the soak period and dielectric recovery periods are relatively short (less than one day, and approximately 7 days, respectively) and the cable life extension warranties provided by most vendors are longer (typically 25 to 40 years). The disadvantages are that the fluid does not flow through prefabricated splices (splices must be located and replaced before injection is attempted) and the cable must remain de-energized while the injection is being completed (customers on radial feed systems will typically experience at least a two hour outage, including switching time) .

Two well known U.S. cable treatment vendors, Novinium and UtilX, were merged in 2015. Together these companies had about a 30% share of the underground cable treatment market in North America and about a 10% share of the worldwide market in 2014.

URD Cable Treatment

62

Source: Novinium presentation at the North Carolina APPA Conference – March 5-7,2014

63

URD Cable Diagnostic Testing

Many utilities are now performing diagnostic testing of their older vintage URD cable prior to performing any proactive cable treatment or replacement work. This can result in significant savings because testing has shown that a large portion of the installed cable does not have any defects and is capable of providing reliable service for many more years.

There are two established technologies that are now commonly being used for diagnostic testing of URD cable, each of which has unique advantages and disadvantages:

◼ Offline Partial Discharge Testing is able to measure a cable system’s response to a specific stress level and accurately predict its future performance under various loading and voltage levels. It is also able to pinpoint the exact location of defects within a cable segment. This type of testing is commonly used in acceptance testing of new underground construction on critical circuits. The challenge of using this type of testing on existing URD systems is that the entire circuit branch that is being tested must be taken out of service while the testing is being performed. IMCORP is a major current U.S. vendor of this type of testing, marketing it under the name “Factory Grade Testing”.

◼ Online Partial Discharge Testing is performed while the cable system is in operation. This type of testing can accurately identify which cable segments do and do not have defects that are likely to cause future cable failures under normal system loading, but cannot pinpoint the exact locations of the defects. Also, it cannot reliably predict how cable would perform under stress levels that are significantly higher than those that were experienced during the testing process (e.g., response to a lightning strike or a major overload). Its primary advantages are that customers are not inconvenienced during the testing process and its overall cost per foot is typically less than that of off line testing, because no system switching is required. UtilX is a major current U.S. vendor of this type of testing, marketing it under the name “CableWISE”.

Example Inspection Patrol Form – External Inspections

64Source: KCP&L (furnished by Travis Clark)

Riser PolesURD Equipment

Example Detailed URD System Inspection Form – (Internal and External Inspections)

65

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Source: Woodbury County (Iowa) Rural Electric Cooperative website

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