NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Electricity Supply Infrastructure 

Improvements

Final Technical Status Report

December 2010

Daniel Piekarski and Dana Brad

Northern Indiana Public Service Company

Merrillville, Indiana

Subcontract Report

NREL/SR-5500-49793

February 2011
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

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303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Electricity Supply Infrastructure 

Improvements

Final Technical Status Report

December 2010

Daniel Piekarski and Dana Brad

Northern Indiana Public Service Company

Merrillville, Indiana

NREL Technical Monitor: Thomas Basso

Prepared under Subcontract No. NAT-8-66144-01

Subcontract Report

NREL/SR-5500-49793

February 2011
This publication was reproduced from the best available copy

submitted by the subcontractor and received no editorial review at NREL.

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Northern Indiana Public Service Company 

Electricity Supply 

Infrastructure 

Improvements 

National Renewable Energy Laboratory 

Subcontract Number NAT-8-66144-01 

December 2010 

Final Technical Status Report 

(Rev. 1-19-11) 
 

 

TABLE OF CONTENTS 

1 TRANSMISSION PROJECT INTRODUCTION....................................................................... 5
 

1.1 Protection and Control-Modernization of the 345KV Transmission System................... 6
 

1.2 Installation of Transformer Monitoring Equipment .......................................................... 7
 

2 TRANSMISSION LINE PROTECTION PHILOSOPHY ........................................................... 8
 

3 PROTECTIVE RELAYING EQUIPMENT SELECTION......................................................... 10
 

3.1 System 1 Protection œ SEL-421 .................................................................................... 11
 

3.2 System 2 Protection œ SEL-311L .................................................................................. 12
 

3.3 Backup and Ancillary Protection ................................................................................... 13
 

4 PROTECTION SCHEME DESIGNS ...................................................................................... 13
 

5 TRANSMISSION LINE MONITORING REQUIREMENTS.................................................... 16
 

6 345KV LINE UPGRADE - PROTECTIVE RELAY INSTALLATION & COMMISSIONING .. 17
 

6.1 Protective Relay Acceptance ........................................................................................ 17
 

6.2 Equipment Installation Practices ................................................................................... 18
 

6.3 Relay Settings Development......................................................................................... 20
 

6.4 Field Testing and Commissioning ................................................................................. 21
 

7 TRANSMISSION SYSTEM MODERNIZATION RESULTS .................................................. 22
 

7.1 Self Diagnostic Testing.................................................................................................. 22
 

7.1.1 Self Diagnostic Testing Summary.............................................................................23
 

7.2 Remote Interrogation Features ..................................................................................... 24
 

7.2.1 Experience with Remote Interrogation Features ......................................................24
 

7.3 Fault Location Features and Experience ...................................................................... 24
 

7.4 SCADA Features and Use ............................................................................................ 24
 

7.5 Transmission Line Protection Overall Features ............................................................ 25
 

8 TRANSFORMER MONITOR INSTALLATION...................................................................... 26
 

9 TRANSFORMER MONITORING EQUIPMENT AND DESIGN............................................. 27
 

10 TRANSFORMER MONITOR - INSTALLATION & OPERATION ......................................... 30
 

10.1 Transformer Monitor Installation ................................................................................... 30
 

10.2 Transformer Monitor Operation..................................................................................... 31
 

11 EXPERIENCE WITH USE OF ON LINE SERVERON GAS CHROMATOGRAPHY 

MONITOR .............................................................................................................................. 32
 

12 DISTRIBUTION PROJECT INTRODUCTION....................................................................... 38
 

13 OVERVIEW OF OUTAGE LOCATIONS ............................................................................... 39
 

14 EVALUATE AVAILABLE FAULT HISTORY ON INSTALLED UNDERGROUND CABLE . 41
 

14.1 Underground Fault History (Failure Report Form) ........................................................ 41
 

15 EVALUATE OTHER AVAILABLE DATA ON INSTALLED UNDERGROUND CABLE ...... 43
 

15.1 Underground Cable History (age and quantities).......................................................... 43
 

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15.2 NIPSCO Outage Restoration System (NORS) ............................................................. 44
 

15.3 Local Operating Area (LOA) Priority ............................................................................. 45
 

16 CONDUCT POWER CABLE RELIABILITY AUDIT.............................................................. 45
 

16.1 IMCORP Power Cable Reliability Outline ..................................................................... 46
 

17 IMCORP POWER CABLE RELIABILITY -SURVEY............................................................. 48
 

17.1 Stakeholder Survey....................................................................................................... 48
 

17.2 Stakeholder Meeting ..................................................................................................... 49
 

17.3 Establish Executive Sponsorship .................................................................................. 49
 

17.4 Reliability Audit.............................................................................................................. 49
 

18 NIPSCO CABLE SYSTEM AUDIT RESULTS ...................................................................... 50
 

18.1 Present and Future Reliability ....................................................................................... 51
 

18.2 Composition of NIPSCO System .................................................................................. 52
 

18.3 Failures by Cable Characteristic ................................................................................... 52
 

18.4 Determine Target Population of Cables to be Tested................................................... 55
 

19 PRIORITIZE UNDERGROUND DISTRIBUTION IMPROVEMENT POTENTIAL SITES...... 56
 

19.1 Prioritizing factors.......................................................................................................... 57
 

19.1.1 Cable History (outage history) ..................................................................................57
 

19.1.2 Cable Physical Features...........................................................................................57
 

19.1.3 Customer Considerations .........................................................................................57
 

19.1.4 Cost Considerations..................................................................................................57
 

19.1.5 System Features.......................................................................................................58
 

20	 SUMMARY œ DEFINE SELECTION CRITERIA, PRIORITIZE POTENTIAL SITES ............ 58
 

20.1 Selection of Candidate Populations (Cable Sections) .................................................. 58
 

20.1.1 Hammond, Crown Point, Gary, and Valparaiso Local Operating Areas...................58
 

20.2 Final Selection of Target Population ............................................................................. 58
 

21 IDENTIFY DISTRIBUTION SYSTEM DETAILS.................................................................... 60
 

21.1 Normally Open Loop System ........................................................................................ 61
 

22 CONDITION ASSESSMENT SURVEY ................................................................................. 62
 

22.1 Condition Assessment Survey (Partial Discharge Diagnostics).................................... 62
 

22.1.1 Partial Discharge Diagnostic Specifications .............................................................63
 

22.1.2 Partial Discharge Testing Criteria .............................................................................65
 

22.1.3 IEEE 400-2001 - Guide for Field Testing and Evaluation of the Insulation of 

Shielded Power Cable Systems..............................................................................66
 

23	 PROCESS DOCUMENTATION AND PRACTICES œ CONDITION ASSESSMENT 

SURVEY (PD TESTING)........................................................................................................ 69
 

23.1 Process Documentation of Partial Discharge Diagnostics............................................ 69
 

23.2 Typical Field Practices of Partial Discharge Diagnostics .............................................. 71
 

24 CONDITION ASSESSMENT SURVEY (INITIAL VERIFICATION)....................................... 73
 

24.1 Dissection Analysis ....................................................................................................... 74
 

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25 CONTINUED CONDITION ASSESSMENT SURVEY (PD TESTING).................................. 76
 

25.1 Example of Data Contained in Summary Report Recommendation............................. 76
 

26 CABLE REPLACEMENT....................................................................................................... 77
 

26.1 Description of Cable Replacement Selection................................................................ 77
 

26.2 Cable Replacement Practices in a Normally Open Loop System................................. 77
 

26.2.1 Sectionalizing Underground Cable ...........................................................................79
 

26.3 Cable Repair and Replacement Activities..................................................................... 79
 

27 DISTRIBUTION SUMMARY - CONCLUSIONS .................................................................... 80
 

27.1 Circuit Reliability Testing - Conclusions........................................................................ 80
 

27.1.1 Selection of Candidate Populations (Cable Sections)..............................................81
 

27.1.2 Anticipated Results of Circuit Reliability Testing ......................................................81
 

27.1.3 Actual Results of Circuit Reliability Testing ..............................................................82
 

27.2 Cable Replacement œ Conclusions ............................................................................... 83
 

27.2.1 Anticipated Findings on Cable Replacement............................................................84
 

27.2.2 Actual Findings on Cable Replacement and Repair.................................................84
 

27.3 Sectionalizing Underground Cable œ Conclusions........................................................ 86
 

27.4 Other Findings............................................................................................................... 87
 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

1 Transmission Project Introduction 

Electricity infrastructure across the country is aging rapidly. This has led to 

electrical transmission problems and reliability issues. Upgrading electromechanical protection and control with microprocessor based equipment enables 

the electric transmission grid to operate within more precise limitations, increasing 

transmission capacity and improving the overall performance of the grid. 

Modernization is critical to prevent future transmission problems such as those that 

occurred across the Midwest on August 14, 2003. 

The 345KV transmission circuits are the critical backbone of the electric grid in the 

Midwest. Most of Northern Indiana Public Service Company's (NIPSCO) 345 kV 

Transmission circuits were installed in the 1970's with state of the art protective 

relaying existing at that time. By performing regular periodic relay maintenance 

(inspection, calibration, and functional testing), and by monitoring and promptly 

addressing performance issues with these protection schemes, the reliability and 

security of the NIPSCO electrical system has been maintained over the past thirtyfive years. However, the protective relays used in many of these schemes are 

nearing the end of their life cycle. Furthermore, improvements in technology and 

the advent of the microprocessor make it possible to improve the protection, and 

greatly enhance the monitoring and post fault analysis tools used in system 

protection. The use of these technologies results in greater dependability, security, 

selectivity, and speed of the protection schemes. The cumulative effect produces 

improvements in the overall reliability of the electrical transmission and distribution 

system. 

There are two distinct aspects of the transmission portion of this project: The first 

aspect relates to the modernization of the protection and control schemes of two 

345KV circuits on the NIPSCO system. The second entails the installation of 

monitoring equipment on transmission transformers. 

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Transmission - Final Technical Status Report	 Subcontract Number NAT-8-66144-01

1.1 Protection and Control-Modernization of the 345KV Transmission 

System 

The first aspect relates to the modernization of the protection and control schemes 

of two 345KV circuits on the NIPSCO system. One circuit between St. John and 

Green Acres Substations, and a second circuit between Babcock and Lake George 

Substations. 

The protection schemes on these circuits are being upgraded from primarily solid 

state and electromechanical equipment to new microprocessor based equipment. 

This new microprocessor based equipment has proven to provide the reliability and 

performance that is necessary to protect and control today‘s modern electrical 

transmission system. 

345 KV lines are protected using redundant, multi level relaying schemes we refer 

to as System 1 and System 2. System 1 is typically a four zone distance relaying 

scheme which incorporates permissive overreaching transfer trip or a similar 

communication based scheme. System 2 is typically a current only communication 

based scheme such as current differential or phase comparison. In addition, system 

2 usually adds one electromechanical ground overcurrent backup relay. 

The philosophy of multi level protection dictates that we employ more than one 

relay to trip the line for the same type of fault. We would expect the level one relay 

to trip first, the level two relay to trip next if level one doesn‘t and so on. This idea 

is strengthened by using one system of current only relays such as current 

differential. This will continue to protect the line if there is a loss of potential on the 

other system. As described in the last paragraph, level one would be the zone 

distance/impedance protection. Level two would be the current differential relays, 

level three would be the permissive communications tripping, and level four would 

be the ground overcurrent backup relay. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

1.2 Installation of Transformer Monitoring Equipment 

The second aspect of the transmission project entails the installation of monitoring 

equipment on critical transmission transformers. Power transformers are some of 

the most expensive electric utility assets and are also very vital to the reliability of 

the transmission grid. 

The on-line transformer monitor supplied by Serveron utilizes gas chromatograph 

technology to perform Dissolved Gas Analysis (DGA) of the transformer oil. DGA 

testing consists of taking transformer oil samples to determine the levels of eight 

critical fault gases. These gases are hydrogen (H2), oxygen (O2), carbon dioxide 

(CO2), carbon monoxide (CO), methane (CH4), ethylene (C2H4), ethane (C2H6), 

and acetylene (C2H2). 

 Before the availability of real time monitoring, the typical time to physically 

collect an oil sample in the field, send to a lab for analysis, and await the test results 

would be two or three days. Oil levels could change dramatically within this period, 

so having the data available in real time is a distinct advantage in maintaining the 

life of a transformer. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

2 Transmission Line Protection Philosophy 

Protective relays are devices that constantly monitor the lines and power equipment 

used in the transmission system. When problems occur on the power system, 

protective relays quickly determine the area of trouble and initiate corrective action 

to isolate the problem and limit damage to equipment and personnel. This timely 

action permits the rest of the system to maintain a high degree of service continuity 

and reliability. 

As figure 1 illustrates, relaying components monitor circuit voltage and current 

parameters and are designed to operate automatically to disconnect the protected 

elements from the transmission system. Protective relay outputs initiate power 

circuit breaker tripping to isolate electrical faults (typically in 2 œ 5 cycles) and 

protect power equipment from damage due to voltage, current, and/or frequency 

excursions outside the design capabilities. 

Figure 1 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

The key performance criteria for protective relaying schemes are: 

• DEPENDABILITY - The relaying scheme must operate correctly every time a 

fault occurs within the defined zone of protection. 

• SECURITY œ The relaying scheme must not operate for faults outside its zone of 

protection. 

• SELECTIVITY œ The relaying scheme must be able to detect an electrical fault 

and affect the least amount of equipment possible when isolating the faulted 

section. 

• SPEED œ The relaying scheme must operate in a timely manner (usually within 1 

- 2 cycles) to minimize equipment damage and maintain stability of the power 

system. 

The proper operation of protective relaying schemes during fault conditions has a 

direct impact on increasing asset life of the protected equipment and minimizing 

system disturbance time. Relay or control malfunctions that cause false tripping 

lead to unnecessary customer outages and affect overall system reliability. These 

criteria are especially important to the large industrial customers that our 

transmission system serves. 

Achieving relaying and control system reliability for high voltage transmission line 

protection requires an appropriate level of redundancy and back-up systems. 

Protection systems for these lines usually consist of two independent protection 

groups each using a different relaying design philosophy and each of which is 

capable of performing the required protection functions. For 345KV line protection 

NIPSCO typically employs a phase and ground step zone distance (impedance) 

package as system one. System two is a line current differential protection scheme 

with directional ground overcurrent as further backup. Both systems employ 

Permissive Overreaching Transfer Trip (POTT) as a high-speed pilot-relaying 

scheme. This scheme requires that a reliable communication system be established 

between both ends of the protected circuit. The media used for this communication 

system can be microwave radio, power line carrier, or fiber optic cable. The relays 

at each end of the line communicate with each other over the designated channel 

providing high-speed protection over the full length of the line for all fault types. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

3 Protective Relaying Equipment Selection 

Over the history of electrical system protection there have been three generations of 

protective relaying technology. Electromechanical protection equipment, which 

dates back to the time of Thomas Edison, was the mainstay of system protection for 

nearly 100 years. Solid State technology became prevalent during 60‘s and 

remained popular until the mid 80‘s. Solid State equipment did essentially the same 

function as electromechanical relays but used solid state components (diodes, 

transistors, RC networks) instead of coils and induction disks. 

Figure 2 

The advent of the computer led to the development of microprocessor based 

protective equipment. This technology has distinct advantages over the previous 

generations of protective equipment among which are: 

• Self diagnostic testing 

• Oscillography/Digital Fault Recorder (DFR) Event Reporting 

• Sequence of Events (SER) reporting 

• Fault Location 

• Supervisory Control and Data Acquisition (SCADA) Integration 

• Breaker Monitoring 

• Multifunction Programmability 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

There are many manufactures of microprocessor based protective relays, most of 

which provide the same features and functionality. Among the first to bring 

microprocessor relays to the market was Schweitzer Engineering Laboratories 

(SEL). NIPSCO‘s experience with SEL products over the past twenty years has 

shown them to be superior in regard to performance, service, functionality, and 

reliability. For that reason, while we continue to evaluate and utilize products from 

other manufacturers, the majority of our protection schemes utilize SEL equipment. 

The 345KV line protection modernizations associated with this project will utilize 

SEL relays for System 1and 2 with an ABB directional ground relay used as a 

backup. 

3.1 System 1 Protection œ SEL-421 

The primary protection for the 345KV circuits will be provided by SEL-421 relays. 

The SEL-421 relays in this application will provide four zones of phase and ground 

distance protection with directional overcurrents serving as backup. 

Communication between the relays at each end of the circuit will be done over 

digital microwave. This channel will facilitate Permissive Overreaching Transfer 

Trip (POTT) as well as a Direct Transfer Trip (DTT) scheme that is used for 

breaker failure protection. 

Figure 3 

The major reason for selecting the SEL-421 relay as the system one protection is 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

the combination of speed and reliability that this relay affords. This relay has shown 

itself to provide secure sub cycle fault detection. 

3.2 System 2 Protection œ SEL-311L 

The secondary protection for the 345KV circuits will be performed by SEL-311L 

relays. The SEL-311L relay uses a vector ratio of the local and remote phase and 

sequence currents to provide high speed current differential protection. The SEL311L relay also includes complete step zone distance protection with directional 

overcurrents serving as backup. POTT and DTT schemes are integrated in the 

protection. 

Figure 4 

One of the main benefits of using a current differential scheme is that the protection 

is not compromised by the loss of a single potential transformer (PT) fuse failure. 

When designing the protective systems, the objective is to have a blanket of 

protection that is sufficiently robust to survive any single point of failure. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

3.3 Backup and Ancillary Protection 

While microprocessor relays have led to vast improvement in system protection, 

electromechanical relays do have a few enduring advantages. Electromechanical 

relays are extremely hardy devices with over a hundred years of design research. 

They are not dependent on an external power supply to function. They don‘t have 

A/D converter or ROM failures due to alpha particle transmissions. 

Electromechanical relays are essentially passive devices that can operate for 

decades without failure. For this reason, NIPSCO‘s philosophy for transmission 

line protection is to include one electromechanical protection relay. Since seventy 

five percent of all faults involve ground, a directional ground overcurrent relay is 

employed (typically an ABB IRD-9 or a GE JBCG). 

For breaker protection and control, an SEL-351 relay is used to provide automatic 

reclosing, synchronizing, SCADA control, and breaker failure protection. All 

microprocessor relays receive a satellite synchronized time and date signal. They 

are also connected to the Electric Dispatch Energy Management System (EMS) via 

a Distributed Network Protocol (DNP) channel. 

4 Protection Scheme Designs 

A sample of DC Schematics for the 345KV line protection schemes associated with 

this project are shown in Figure 5 and 6 on the following pages: 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

Figure 5
 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

Figure 6 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

5 Transmission Line Monitoring Requirements 

Automatic transient recording devices such as oscillographs (older analog 

technology) and digital fault recorders - DFR (newer microprocessor technology) 

are essential for monitoring the performance of protective equipment in modern 

power systems. The newer microprocessor based relays, such as the SEL-421 and 

SEL-311L relay that are being used in this project are equipped with DFR 

capability (SEL calls it simply Event Reporting). The relays also capture sequence 

of events (SER report). These devices and relay functions that record analog 

voltage, current and equipment operations, are invaluable tools in the investigation 

of electric system events and their post fault analysis. The results of this monitoring 

have reduced downtime and equipment losses, which leads to greater system 

reliability and customer satisfaction. Transmission monitoring tools have provided 

critical data for documentation and review of system events such as the widespread 

outage of August 14th, 2003. In recent years, the various national reliability 

councils have begun to develop standards for mandatory time synchronized 

disturbance monitoring. Due to the extensive use of microprocessor relays like the 

ones used in this project, and the installation of dedicated DFR and SER units, 

NIPSCO is positioned to be in full compliance with Reliability First/ NERC 

Reliability Standard PRC-002. 

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Transmission - Final Technical Status Report	 Subcontract Number NAT-8-66144-01

6 345KV Line Upgrade - Protective Relay Installation & 

Commissioning 

As with any large scale project, a great deal of coordination and project planning is 

necessary to insure that all the engineering, procurement, construction, operations, 

and field testing functional areas work together to ensure a successful outcome. 

Therefore, a number of interdepartmental meetings take place at various stages of 

the project including, pre-engineering and preconstruction. These meetings/teleconferences ensure that all parties are aware of the scope of the project and the 

project schedule for equipment arrival, engineering print release, construction start, 

electrical clearances, and project completion. Installation and commissioning of 

protective relaying schemes and equipment is done under the oversight of Field 

Technical Services engineers. These engineers are responsible for 

a. Testing and setting of all protective relay and control equipment 

b. Verifying that the engineering drawings are accurate and error free 

c. Certifying of all prefabricated relay panel wiring 

c. Overseeing the deconstruction of old protection equipment (safety and 

accuracy) 

d. After substation engineers come up with interconnection wiring and their prints. 

Technical Services engineers check all new interconnection wiring 

e. Functional testing of the new protection schemes 

f. Performing satellite synchronized end to end commissioning tests 

g. Completing load checks upon energization of new protective 

schemes/equipment 

h. Marking up engineering print, relay information, and protective settings 

documentation 

6.1 Protective Relay Acceptance 

The 345KV line modernizations associated with this project will utilize SEL relays 

for System 1 and 2 protection with an electromechanical relay employed as a 

directional ground backup. 

System 1 œ SEL-421 with Permissive and Direct Transfer Tripping 

System 2 œ SEL-311L with Permissive and Direct Transfer Tripping 

Backup Protection œ - ABB IRP-9 (Directional Ground Overcurrent) or 

- GE JBCG (Directional Ground Overcurrent) 

Breaker Control œ SEL-351 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

All protective relaying devices are acceptance tested to ensure proper operation 

prior to being placed in the field. The equipment is lab tested according to the 

manufacturer‘s specifications. This is true for electromechanical relays and 

auxiliary devices such as: 

Protective Relays œ Directional Ground (GE-JBCG, ABB- IRP-9) 

Metering Equipment œ Digital Ammeters, Voltmeters (Bitronics , ARGA)
 

Auxiliary Tripping devices œ Lockout relays and trip relays (LOR or GE-HGA) 

All microprocessor based devices are acceptance tested to ensure proper self check 

functionality. Furthermore, to test the relay‘s analog inputs, three phase current (1 

amp) and potential (67 V) are fed to the relay with a 30 degree (I lag E) PF angle. 

The relay‘s meter function is then used to verify the proper functioning of the A/D 

converter. Relay inputs are asserted and the output contacts are pulsed. 

6.2 Equipment Installation Practices 

345KV protective relay modernization projects typically require extended circuit 

outages (3-4 weeks). To minimize the system impact, such projects are often 

scheduled when moderate weather is anticipated (Spring and Fall). When project 

timing is not advantageous, NIPSCO employ‘s the use of temporary relaying 

panels to limit circuit clearances to only two days: one day at the beginning and one 

day at the end of the project. While this practice has proven to be extremely 

valuable under adverse conditions, utilizing temporary panels increases the 

complexity and duration of the project. While adequate, the circuit protection 

provided by the temporary panels is also less than ideal. For the modernization 

associated with this project, timing allowed for 3 week outages, therefore the 

temporary panels were not required. For each circuit, the proper line and breaker 

clearances were acquired. The protection and control circuits were de-energized 

and the old relay panels were unwired and removed from service. Relay 

modernization projects entail a tremendous amount of wiring changes. For the 

Babcock project there were 43 pages of wiring removals. Five panels and more 

than 30 electromechanical relays were retired from service. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

Babcock œ Wiring and Relay Panel Removals 

Four new relay panels were installed. The new interconnection wiring to 

neighboring panels was run (233 inter-panel wiring additions). All wiring was 

thoroughly checked by conducting continuity tests (commonly referred to as 

buzzing). 

Old Babcock Relay Panels New Babcock Relay Panels 

The prior pictures illustrate one of the many advantages of the modern 

microprocessor relays. They are multifunctional, i.e. one SEL relay performs the 

functionality of an entire panel of electromechanical relays. As a result, new panels 

contain fewer relays (fewer points of failure), while providing more advanced and 

redundant levels of protection. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

Coinciding with the relay modernization project at Babcock was the replacement of 

a 345KV Breaker. 

Old Air Blast Breaker New SF-6 Breaker 

6.3 Relay Settings Development 

The NIPSCO Transmission Planning and System Protection group is responsible 

for maintaining the T&D system model. Short circuit analysis is performed using 

Aspen Oneliner to develop impedance and overcurrent settings for the protective 

relays. 

Figure 7 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

Once the new protection and control relays (SEL-421, SEL-311L, and SEL-351) 

have been accepted, they are set according to the results of the short circuit 

analysis. Note: Many of the settings on the new microprocessor relays are not 

directly related to the impedance and overcurrent protection functions. With the 

advent of SEL relays, much of the DC control logic once performed by auxiliary 

relays have now been migrated within the microprocessor relay. As a result, the 

settings are much more extensive (e.g. the settings on the SEL-421 are over 100 

pages long). 

6.4 Field Testing and Commissioning 

The new control and protection schemes were fully functional tested. Every 

breaker trip, close, and auxiliary function is checked. Final commissioning of the 

new protection schemes includes the use of satellite synchronized Doble 6150 

units. State simulations of various line faults are created from Aspen One-liner and 

used to simulate actual faults within the various zones of protection. A full battery 

of tests are run that include 3 phase, phase to phase, and phase to ground faults at 

various locations inside and outside the circuits zone of protection. The relay 

responses and event report data are carefully analyzed to verify and ensure that 

performance measures up to industry standards. After all commissioning tests had 

been completed, the circuit is returned to service. 

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Transmission - Final Technical Status Report	 Subcontract Number NAT-8-66144-01

7 Transmission System Modernization Results 

Modernization of transmission line protection has numerous positive impacts upon 

performance and reliability of the transmission system1. 

7.1 Self Diagnostic Testing 

The self diagnostic testing of the SEL-421 and SEL-311L relays allow equipment 

failures to be detected immediately instead of waiting for the next round of periodic 

testing or worse, a misoperation. The microprocessor relays also require less 

maintenance which allows limited manpower to be utilized more effectively and 

productively. 

Both relays perform a variety of self tests. The SEL311L takes the following 

corrective actions for out-of-tolerance conditions. 

➤	 Protection Disabled: The relay disables overcurrent elements and trip/close logic. All 

output contacts are de-energized. The EN front-panel LED is extinguished. 

➤	 ALARM Output: The ALARM output contact signals an alarm condition by going to its 

de-energized state. 

➢	 If the ALARM output contact is a B contact (normally closed), it closes for an alarm 

condition or if the relay is de-energized. 

➢ If the ALARM output contact is an A contact (normally open), it opens for an alarm 

condition or if the relay is de-energized. Alarm condition signaling can be a single 

5-second pulse (Pulsed) or permanent (Latched). 

➤ Line Current Differential Protection Disabled: The relay disables 87L protection and deenergizes outputs OUT201œ OUT206. Relay Word bit 87LPE deasserts and Relay 

Word bit 87HWAL asserts. 

➤	 The relay generates automatic STATUS reports at the serial port for warnings and 

failures. 

➤ The relay displays failure messages on the relay LCD display for failures. 

By using the serial port STATUS command or front-panel STATUS pushbutton, 

the relay self-test results can be viewed. 

1

 Examples of actual data recorded by the relays in this project are designated Critical Energy Infrastructure 

Information (CEII), and are not included in this report. 

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7.1.1 Self Diagnostic Testing Summary 

The Figure below shows the different self tests that the SEL-311L relays performs. 

Figure 8 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

7.2 Remote Interrogation Features 

The remote interrogation features allow for almost immediate access to the relays 

settings and/or event report data. System changes that require protection or 

automation setting alteration can be performed in minutes rather than hours or days. 

The event reports and sequence of events can by analyzed within minutes of the 

system event. The root cause of the system disturbance can be identified and a 

restoration plan developed before first responders arrive at the scene. 

7.2.1 Experience with Remote Interrogation Features 

The microprocessor relays at the terminal ends were equipped with a 

communications processor (SEL-2030) and telephone line sharing switch (Teltone 

SLSS). The relays were time synchronized through the SEL-2030 via a satellite 

clock. All the communications equipment and protective relays were secured with 

multilevel passwords. This design allows for the speedy interrogation of any fault 

event or setting change. Shortly after the Babcock terminal went in service, a 

problem was uncovered with the motor operated disconnect control within the SEL351 relay on the breaker. Remote interrogation made the trouble shooting and 

subsequent scheme changes straightforward with minimal time required. 

7.3 Fault Location Features and Experience 

Fault location data that is readily available from the relays has proven to be an 

invaluable tool for helping field personnel find —hard to find“ faults. Fault location 

within the relays has shown itself to be accurate to within a pole length. In 

addition to fault location, both systems of protection on each circuit is equipped 

with sequence of event recording, historical event logging, and oscillographic of 

event data. A log file of a recent event data for a terminal at St. John included 

detailed information of fault location and magnitude along with oscillographic data 

of a BC phase fault caused by galloping conductors during an ice storm. 

7.4 SCADA Features and Use 

The incorporation of SCADA functions within the protective relaying makes for an 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

improved scheme design. Since both systems are monitoring analog quantities, 

equipment status, and performing control operations, it makes sense to allow the 

protective relaying to be the conduit through which SCADA is performed. The 

elimination of redundant systems makes for a vastly superior field installation. 

The remote terminal unit within the substation (GE Harris D20) communicates with 

the microprocessor relays via an RS485 communication channel which employs 

Distributed Network Protocol (DNP3). Analog, status, and control maps are set 

within the relay to select which elements are to be polled by the RTU and 

subsequently forwarded to the Energy Management System (EMS). 

7.5 Transmission Line Protection Overall Features 

The newer protection schemes are: faster, more reliable, easier to install, easier to 

maintain, provide vastly improved monitoring features, offer greater flexibility, and 

give better overall protection. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

8 Transformer Monitor Installation 

The second aspect of this Transmission project relates to the installation of 

monitoring equipment on transmission transformers. As an asset class, 

transformers constitute one of the largest investments in a utility‘s system. For this 

reason, transformer condition assessment and management is a high priority. Each 

utility‘s grid is unique and investment levels in asset condition and assessment tools 

vary according to risk level and investment return models. While the models are 

different for each utility, the common element in them is that transformer fleets are 

stratified according to the criticality of individual transformers. The variability and 

uniqueness lies in where the prioritization lines are drawn and the investment 

amounts allocated for asset condition and management tools for each level. 

Typically this approach has the most critical transformers receiving the highest 

investment of condition assessment and decreases for each less critical level 

identified. 

Transformers have a finite life. In the US, with an average age of almost 40 years, 

many are now approaching the end of their design life. Higher loads placed on 

transformers, in an environment that demands higher electric energy consumption, 

have taken their toll on transformer longevity. Compound this with the reduction in 

capital budgets, the need to closely manage transformer assets becomes essential. 

Utilities attempt to avoid unplanned failures, lower maintenance costs and defer 

capital expenditures through the appropriate use of transformer condition 

assessment and management tools. 

Monitoring the state of power transformer health, a key component in the path of 

reliable power, has traditionally been accomplished using laboratory Dissolved Gas 

Analysis (DGA) tests performed at periodic intervals. DGA of transformer oil is 

the single best indicator of a transformer‘s overall condition and is a universal 

practice today. However, on-line DGA helps utilities avoid unplanned failures, 

adopt lower cost condition-based maintenance, and defer capital expenditures by 

extending the transformer‘s useful life. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

First generation (1970‘s), as well as some current on-line DGA products available 

today, provide Total Combustible Gas (TCG) or single gas (Hydrogen) monitoring. 

These products provide indication of developing problems in the transformer but 

offer no legitimate diagnostic capability. On-line DGA offerings in the market have 

evolved from this early approach to include multi-gas monitors that detect and 

analyze some or all of the eight fault gases identified in the IEEE and IEC standards 

as well as provide diagnostic capability. 

Newer on-line DGA products have the unique ability to continuously trend multiple 

transformer gases and correlate them with other key parameters such as transformer 

load, oil and ambient temperatures as well as customer specified sensor inputs. 

This capability enables utilities to relate gassing to external events, a key to meeting 

utility reliability and financial goals in the current environment. A study has also 

shown that some on-line DGA tools offer better accuracy and repeatability than 

laboratory DGA. This on-line DGA can improve the decision timeliness and 

confidence when incipient faults are detected. 

9 Transformer Monitoring Equipment and Design 

On line real time oil analysis monitoring takes the place of manually taking 

transformer oil samples and sending them away for laboratory analysis. Traditional 

laboratory analysis utilizes a gas chromatography process. Eight (8) dissolved gases 

can be found through DGA testing œ Hydrogen (H2), Oxygen (O2), Methane 

(CH4), Carbon Monoxide (CO), Carbon Dioxide (CO2), Ethylene (C2H4), Ethane 

(C2H6), and Acetylene (C2H2). These gases are created in the oil from arcing, 

thermal heating, and corona effects. The types and amounts of gases present can 

help determine the type and intensity of the fault creating these gases. 

On line transformer monitors include units manufactured by Serveron, Kelman and 

others. Each can provide real time monitoring of the eight dissolved gases. The 

Serveron unit uses the traditional gas chromatography process, whereas the Kelman 

monitor utilizes a photo acoustic spectrometer process. Based on our operating 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

department‘s familiarity with the gas chromatography process, the Serveron unit 

was chosen for this project. 

A typical Serveron monitor installation is shown in figures 9,10 and 11. Figure 9 is 

the transformer monitor mounted on brackets to the side of the transformer case. 

Figure 10 is the monitor with its swing cover open to show an internal electrical 

panel containing the electronics to monitor the gas levels and for interfacing AC 

power and communications to the monitor. Figure 11 details the oil supply lines 

from the oil moisture and temperature sensor connected to an existing oil port near 

the top of the transformer to the monitor. 

Figure 9 

Figure 10 

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Figure 11 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

10 Transformer Monitor - Installation & Operation 

Serveron provides a detailed checklist of site preparation steps to be taken prior to 

installation. These include: 

• Choosing oil supply and return ports 

• Choosing a cabinet mounting location 

• Providing AC Power 

• Determining need for optional oil inlet cooler 

• Choosing a communication protocol 

• Determining need for optional moisture and oil temperature sensor 

• Ordering helium 

• Ordering stainless steel tubing 

After these steps are completed installation can begin. 

10.1 Transformer Monitor Installation 

The monitor operates by removing oil from the transformer, analyzing the oil, and 

returning the oil to the transformer. Oil is supplied from the top of the transformer 

and returned at the bottom of the transformer. The oil supply port should be at a 

location on the transformer to provide a well mixed sample of the transformer oil, 

which is typically at a top tank valve. The transformer‘s bottom drain valve is used 

for oil return. 

The monitor itself is mounted within an approximate 21-1/4“ wide x 20“ high x 11“ 

deep outdoor cabinet. It can be mounted on the side of the transformer in a location 

not interfering with any transformer operation or maintenance duties, or on a 

separate mounting pedestal which would be attached to the transformer or a 

separate foundation. 

Once the mounting location is determined, 3“ stainless steel tubing is procured and 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

used to connect the top and bottom oil ports to the monitor to provide the oil supply 

and return paths. Tubing should be in continuous lengths in order to avoid using 

fittings and to reduce the possibility of leaks. Teflon tape should be installed on all 

connections, as necessary. 

An external helium tank, used as a carrier gas to help send the sampled gases 

through the chromatograph, is attached to the side of the transformer and connected 

by tubing to the monitor. Also, a gas verification cylinder is mounted inside the 

monitor cabinet. This cylinder is used to calibrate the monitor and contains a trace 

amount of the previously mentioned eight transformer fault gases. 

AC Power and communication and sensor cables are connected within the monitor 

cabinet and externally to the substation service source and the communications 

network. 

10.2 Transformer Monitor Operation 

Oil is circulated from the transformer to the monitor and back to the transformer. 

The frequency of the analysis can be performed at various intervals with a four hour 

interval being set as the default. The analysis takes about 40 minutes. Data is 

accumulated every time a Dissolved Gas Analysis is done. This data is stored 

within the monitor‘s memory, which holds about 2 years of data. 

The Serveron monitor is calibrated at the factory, after installation, and self 

calibrates every three days. 

Data retrieval, setting of caution and alarm levels, and analysis intervals can be set 

by using the Serveron TM View software. 

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11 Experience with Use of On Line Serveron Gas 

Chromatography Monitor 

There are immediate benefits to the use of on-line monitoring of combustible gasses 

via the Serveron TM8. 

The Serveron TM8 units are utilized to trend combustible gasses daily and to report 

any increased gas trending as an alarm. The unit also will detect and alarm if any 

one gas alarm limit is reached. This will identify any concern that might happen 

suddenly and give us the opportunity to take the transformer out of service, and 

through testing, identify any underlying issue prior to a catastrophic failure. 

Caution and alarm limits are set manually in the Serveron TM View software 

(Figure 12) 

Figure 12 

View from the Serveron TM View software limits setting tab 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

NIPSCO‘s alarm limits are as follows for 345kV class transformers: 

Gas Parts per Million

 Hydrogen 50ppm

 Methane 50ppm

 Acetylene 1ppm

 Ethylene 25ppm

 Carbon Monoxide 250ppm

 Moisture Level 25ppm 

Each transformer had a baseline dissolved gas analysis (DGA) sample drawn and 

sent to an outside test laboratory. Shortly after the Serveron TM8 commissioning, 

each Serveron unit sample results were compared to test results obtained from these 

laboratory tests. The Serveron units were found to be very accurate as all 

combustible gas and moisture level results matched the lab results within several 

ppm. 

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Serveron TM8 utilizes the Duval Triangle gas relationship of Acetylene (C2H2), 

Methane (CH4) and Ethylene (C2H4). If a condition exists that has the three 

mentioned gasses present, the levels of each gas is weighted to each other and an 

appropriate cause is identified. Here is a screen shot of the TM View software and 

Duval‘s triangle diagnostic feature. 

Figure 13 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

As we became more familiar with the Serveron units, we discovered several 

features that would improve the gas monitoring devices. The gas monitors did not 

have a user interface or display to view the gas levels without the use of a laptop 

computer. We worked with Serveron to incorporate a display to view the current 

gas levels and last sample date stamp. This feature would quickly identify any fault 

gasses and the last sample performed by our first responders in the case of a fault 

condition. 

Figure 14 - TM8 DISPLAY
 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

Each Serveron TM8 unit alarm contact is hard wired to an alarm annunciator panel 

located in the substation‘s relay house. This normally open alarm contact will 

alarm our dispatching department if an alarm threshold is met. The basic 

monitoring needs are met with this configuration, yet continuous monitoring would 

enhance the overall effectiveness of the Serveron TM8 units providing real time 

trending of data. The transformers equipped with the Serveron gas monitors are 

physically located in remote areas of our territory. Regular on-site downloads at 

these sites would require frequent extensive travel causing inefficiencies to the 

Technical Services department. We outfitted each Serveron unit with a cell phone 

modem that would allow us to download the gas monitors data on a routine 

schedule remotely from our office. Serveron Corporation worked with TMobile as 

their cell phone modem provider. We found that, depending on atmospheric 

conditions, the cell modems would not have a strong enough signal to 

communicate, thus rendering this technology a poor real time communication 

solution to access the Serveron gas monitors. We have recently accessed the 

Serveron units via RS485 communication interface, through internal fiber optic 

network across our company, allowing the real time access of the instrument 

remotely. 

We currently have 9 Serveron TM8 gas monitors in service at NIPSCO. After 

several years of operation, we have experienced numerous issues with the Serveron 

TM8 units. We replaced the oil pump, helium and calibration gas bottles on one 

unit and the sled (main instrument component) and main board on the other unit. 

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Transmission - Final Technical Status Report Subcontract Number NAT-8-66144-01

Below are pictures of a few failed components: 

Figure 15 Figure 16 

PUMP ASSEMBLY SLED ASSEMBLY WITH MAIN BOARD IN 

BACKGROUND 

We have had multiple sled issues, moisture transmitter problems, pump concerns 

and display malfunctions. 

The chronic issues we have been dealing with occur most frequently in the cold 

weather. January temperatures that fall into the single digit range cause many of the 

issues we continue to see with the Serveron units. After speaking with other 

utilities in the southern regions of our country, the concerns increase exponentially 

in the cold ambient temperatures. Serveron is aware of the cold weather issues and 

are in the process of engineering a cold weather climate kit. This kit is estimated to 

be complete and ready for production in the last quarter of 2010. 

Although the Serveron TM8 units have not been robust, their field support service 

is always prompt and professional. The Serveron unit warranty is one year, yet 

Serveron has repaired all the issues we have had to date under warranty. 

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12 Distribution Project Introduction 

NIPSCO‘s electric distribution underground infrastructure is approaching 40 years 

and is developing faults at an increasing rate. This presents a need to consider 

replacing cable at the end of its predicted life cycle or innovative alternate methods 

of proactively identifying only those sections of cable that require replacement. 

Replacement cost of this infrastructure is significantly greater than typical new 

installations because of established property owner obstacles (fences, pools, decks, 

sheds, gardens, etc) and other active underground utilities (natural gas, water, 

sewer, etc). The need to minimize interruptions during the replacement process is 

paramount to maintaining good customer relations. An average underground cable 

fault can take as much as 5 times longer to find and repair than an overhead line 

outage, which is typically visible to the electric line personnel. 

The first step of the distribution project involves identifying and prioritizing areas 

to improve operations and reliability. Next, the prioritized areas are evaluated using 

a cable assessment technology which results in recommended actions for each 

section of cable. Finally, the recommended actions are reviewed and upgrades are 

implemented to improve operations and reliability in Northern Indiana. 

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13 Overview of Outage Locations 

The first step in improving the electric underground infrastructure was to analyze 

the existing system configuration and define the selection criteria using all the 

available records on installed underground cable and fault history. Gathering all of 

the information from the available records was discovered to be a lengthy process 

and one that took extended time to gather and analyze. 

The first step in defining the selection criteria was to analyze data that is available 

that would indicated where outages occur based on underground primary faults. In 

addition to location, the quantity of outages for the same location is one measure of 

severity that will contribute to priority of importance. 

In order to establish a visual baseline of this data, it was decided to create a 

graphical map of each Local Operating Area‘s (LOA‘s) existing trouble area. This 

map was created using data from the NIPSCO Outage Restoration System (NORS) 

and then displayed in a Geographic Information System (GIS) application called 

ArcMAP. Each interruption location appears as a graphical representation on the 

map along with the major roads, with increasing interruptions being displayed by 

different colors as shown in a single LOA example Figure 17 and 18. 

Figure 17 Legend for Overview Map
 

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Figure 18 

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Distribution - Final Technical Status Report Subcontract Number NAT-8-66144-01

After review of the data in each of the maps, the conclusion from the team was that 

this data and map was a good overview of the enormity of the issue, but the NORS 

data alone would not be enough information to define our selection criteria for the 

scope of this project. The next step was to gather additional information on fault 

history. 

14 Evaluate Available Fault History on Installed 

Underground Cable 

There are 2 sources of records for fault history of underground cable. The first 

source of records was from the NIPSCO Outage Restoration System (NORS). This 

system was installed in September of 2000, and directs customer calls about an 

outage to a central system where the calls are tracked. When the outage was finally 

resolved, the outage was classified and can later be retrieved for reporting purposes. 

The second was fault records from paper forms. Since 1998, NIPSCO has had an 

internal procedure for the prioritization of cable replacement projects. The goal of 

this procedure was to —establish the criteria for underground distribution cable 

replacement and determine the priority for distribution cable replacement“. Under 

this procedure, a form was submitted to track primary cable failures and the types of 

repairs made in order to make a reasonable prediction of our current and future 

replacement needs. Over time, the forms accumulated to the point where a database 

was needed to keep track of the data. This database of fault forms is a key piece of 

data in the selection criteria, but the records gathered may also not be complete for 

various reasons. 

14.1 Underground Fault History (Failure Report Form) 

Extensive work was done to validate and enhance as much of the data as possible. 

In order to have a table or database that would relate the fault form records to other 

data that was being collected, additional fields were added to the database version 

of the form so that the records could be validated and key fields could be populated 

with a correctly formatted identification. The fields that were added were the 

Outage Source, From Location 1, and To Location 2. Each record in the database 

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was validated by finding the source location in our GIS system and then locating 

the section of cable defined by location 1 and location 2. If all three points were 

valid, then the record was considered valid. Each of these fields defines a unique 

identification of a device, and when all three are used together, they define a unique 

piece of cable that is traceable to a unique source in other records. 

Figure 19 New Database Fields Added 

During this process, any new faults that occurred were still submitted on paper 

forms and then the key information was entered into the database. 

Figure 20 Cable Failure Report Form 

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15 Evaluate Other Available Data on Installed 

Underground Cable 

The use of historical records forms a basis for understanding the present condition 

of the underground cable system and identifies potential areas for future 

consideration. NIPSCO has logged the installed and retired assets of underground 

cable in a mainframe database system. The records were intended for asset records 

and not for purposes of relating to outage or fault data. Therefore, this data can be 

studied for its historical value of type of cable installed, and miles of cable installed 

per year etc. 

15.1 Underground Cable History (age and quantities) 

The data contained in this mainframe database system was called the Electric 

Distribution Facilities (EDFS) application, and represented Historical Asset 

information about the cable installed between 2 points. This underground cable 

history data retrieved from our database system was in the form of a text file in the 

format illustrated below. 

DRF 

CNDUCR DSTR CNDUCR PRCNDUCR PRCNDUCR PRCNDUCR PRCNDUCR PRCNDUCR CNDUCR CNDUCR 

DPT CIR TYP RFRNC PNT INST SPAN SPAN RMVL CNDU SZ KND 

CD NUM CD ID ID DT VAL CNT DT CD CD CD 

--- ------- ------ -------- -------- ---------- -------- -------- ---------- -------- ------ ------

010 1042 UC P1775010 P2411010 05/05/1987 220 1 - N 2 AL 

Figure 21 

This data was imported into a relational database so that queries and reports could 

be made from the data. The underground primary cable data imported for this 

purpose was 32,434 records. The critical fields each record included are: a code for 

the Local Operating Area, the circuit number, conductor type, device ID on one end 

of the cable, device ID on the other end of the cable, installed date, length, and 

conductor size. Unfortunately, as the underground system grew, the data entry was 

adapted to only keep track of the asset, and did not contain sufficient fields to relate 

the data directly to other key information like the tap pole. Therefore, this data was 

used as secondary information to support the other records. 

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15.2 NIPSCO Outage Restoration System (NORS) 

For the purpose of this data table, when an Outage occurs, and calls from customers 

get entered into NORS, a device category is assigned. NORS makes 

recommendations to a possible source of the outage, based on additional calls that 

come in. The 4 possible categories are DEV_CAT =: 

1) CUSTOMER œ assigned by NORS with only one call, with service from one 

transformer 

2)	 SERVICE TRANSFORMER - assigned by NORS with two or more calls with 

service from one transformer. 

3)	 DEVICE - assigned by NORS with three or more calls with service from three 

different transformers, or more than 50% of the customers. 

4) SOURCE - assigned by NORS when additional data suggests it is a substation 

outage. 

In order to start evaluation of cable faults, we review the data which comes from 

records using the —Underground Primary Fault Code“. However, because this code 

is assigned by the operator upon closing the outage record for a given outage 

number, the DEV_CAT assigned by NORS during the course of the event may not 

provide information in this database which would better locate the area of the 

primary underground fault. Therefore, we will use several sources of data to 

validate an underground fault location. And for the purposes of this priority listing, 

we will only consider data that provides either a tap pole location to underground 

conductor, or a padmount transformer, etc. 

As a result of this query, 504 records were extracted into a table 

—NORS_SourceOutages“. This table was linked through a query using the outage 

source as the relationship to other tables, like; facility mapping tables, cable 

installation record tables, cable fault form tables, and Local Operation Area (LOA) 

priority listings that will be used to help prioritize our sites. 

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15.3 Local Operating Area (LOA) Priority 

Each NIPSCO LOA was asked to submit a list of 10 areas they deem the greatest 

priority in electric distribution underground infrastructure improvement. Each list 

was submitted in a variety of formats and in a typical fashion, using local names to 

identify the area, instead of a tap pole or other source. Once all the lists were 

submitted, a second request was made to revise the list to include tap poles so that 

the locations could be tied to our GIS mapping system. Once all the additional data 

was gathered, it was translated into a table format so that the data could be related 

to the other tables of information. 

16 Conduct Power Cable Reliability Audit 

The next step in improving the electric underground infrastructure was to analyze 

the existing system configuration and using the data gathered, perform a reliability 

audit, which in part, recommends condition assessment surveys (partial discharge 

testing), and results analysis, with resultant recommendation proposals, and a final 

recommended reliability improvement program. A reliability audit covers the first 

critical step necessary to conduct a comprehensive underground cable reliability 

program. By soliciting a Cable Reliability Audit by an independent company, the 

audit will clarify and reinforce good practices and assumptions, and also dispel any 

assumptions that do not contribute to the improvement of the reliability of 

NIPSCO‘s underground medium voltage cable system by means of a cost effective 

method to prioritization system rehabilitation. 

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16.1 IMCORP Power Cable Reliability Outline 

IMCORP2

 was chosen to recommend a comprehensive underground power cable 

reliability pilot program for NIPSCO, to help NIPSCO achieve their cable 

reliability goals. This process involves an IMCORP developed 5 step 

implementation process, which their experience has shown, helps utilities achieve 

their cable reliability goals. —The goal of the process is to: Dramatically improve 

the reliability of our client‘s underground medium voltage cable systems by 

using historical data and a condition assessment survey to assist in the 

development of a proactive repair, replacement, and deferment plan in the 

most cost effective means possible.“ 

The following outline includes the recommended 5 steps and their associated tasks: 

Figure 22 

Step 1. Survey, Reliability Audit & Proposal 

a. Perform stakeholder survey 

b. Hold stakeholder meeting 

c. Establish executive sponsorship 

d. Perform a reliability audit 

e. Select a target population 

f. Analyze cost benefit 

2

 IMCORP is a leader in underground cable reliability consulting and diagnostics. www.imcorptech.com 

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g. Develop proposal 

Step 2. Condition Assessment Survey 

a. Define team 

b. Schedule survey 

c. Optimize logistics 

d. Perform conditional assessment survey 

Step 3. Results & Analysis 

a. Compile results 

b. Perform autopsy validation 

c. Perform Pareto analysis 

Step 4. Recommendation & Proposal 

a. Prioritize actions 

b. Estimate reliability improvement 

c. Analyze cost benefit 

d. Build program proposal 

Step 5. Continuous Reliability Improvement 

a. Define team 

b. Develop process 

c. Implement program 

d. Maintain metrics 

e. Assure reliability 

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17 IMCORP Power Cable Reliability -Survey 

The following represents the details of Step 1, Survey, Audit & Proposal. 

17.1 Stakeholder Survey 

Interview the customer to identify the key individuals (stakeholders) who are 

responsible for cable reliability and will participate in the reliability improvement 

activities. Once the stakeholders are identified, they are interviewed to obtain the 

necessary reliability audit and cost data as outlined below. 

1. Scope and goal of the cable reliability effort 

2. Cost benefit required for a reliability program to be considered 

3. Final budget approval 

4. Historical budget allocationœcapital and O&M 

5. Regulatory concerns and implications 

6. Operation logistics and switching strategy 

7. Accounting and financing considerations 

8. Underground system reliability history and physical data 

9. Responsibility for cable replacement activities 

10. Risk assessment and reliability engineering 

11. Repair, replacement, and testing standards 

12. Replacement cable system design 

13. Costs related to repair, replacement, and failure œpenalty, lost revenue 

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17.2 Stakeholder Meeting 

Once the stakeholders were identified, IMCORP initiated a meeting of the team 

members who represent the core activities of the reliability program. IMCORP 

worked with the NIPSCO team to develop executive sponsorship and determine the 

scope of the program, and reliability and economic goals. 

17.3 Establish Executive Sponsorship 

Make sure executive leadership goals are well defined in the scope and fully 

support the process as it moves forward. 

17.4 Reliability Audit 

IMCORP conducted a reliability audit by collecting all known historical and 

physical data, conducting interviews with key stakeholders, and corroborating 

information. The audit included the following outline: 

1. Operations knowledge base 

a. Engage key operations personnel through interviews 

b. Gather perspective on reliability trends 

c. Collect Anecdotal evidence and case studies 

2. Reliability indices 

a. Review historical records 

b. Analyze current data 

c. Perform Pareto analysis 

3. Failure data 

a. Review Historical records 

b. Current data 

c. Correlate data and pare to analysis 

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18 NIPSCO Cable System Audit Results 

During the years from 1985 to 1990, NIPSCO changed their cable standards to the 

latest technology. Unjacketed cable with cross-linked polyethylene (XPLE) 

insulation was replaced with jacketed cable with tree retardant XLPE or (TRXLPE) 

and strand filled conductor. 

Figure 23 Length of Unjacketed Cable Installed per Year 

By the end of 2005, NIPSCO had installed 1961 miles of underground cable. Of 

the total, 705 miles of unjacketed cable were installed by the end of 1990. 

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18.1 Present and Future Reliability 

Although anecdotal evidence from Local Operating Areas abounds, it is important 

to establish statistically significant data to show failure trends. Three questions need 

to be answered. 1. What is the overall failure rate of the system? 2. Is the failure 

rate increasing, decreasing, or staying the same? 3. What is the failure rate likely to 

look like in a few years? 

To explore the answers to these questions the NORS data covering the last 5 years 

was assessed. NORS tracked 491 outages from the beginning of 2001 through the 

end of 2005. According to this data, the failure rate is increasing by an average of 

approximately 11% per year. 

Figure 24 Failures per month is plotted with the red bars and 

 the yearly increase shown by the orange line. 

The graph shows that NORS tracked nearly 7 failures/100 miles/year in 2005. This 

is 13% above the national average of 6.2 failures/100 miles/year as reported by 

AEIC in 1994. However, a 5 utility survey on the basis of data presented at the 

2004 Fall IEEE PES ICC Meeting shows that the NIPSCO failure rate is 23% lower 

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than the 9.0 failures/100 miles/year average. 

18.2 Composition of NIPSCO System 

To understand the composition of the NIPSCO system, the EDFS assets database 

was used to generate the following pie chart of installed cable length by conductor 

type. 

Figure 25 Percentage Installed Cable by Conductor Type (March 2006) 

18.3 Failures by Cable Characteristic 

To determine what type of cables failed during the 2001 to 2005 time period, 491 

failures recorded by NORS were compared to the Fault Records database. 217 of 

the Fault Records database entries which corresponded with the NORS data had 

cable type information. To draw any further conclusions an assumption needed to 

be made. If the 217 entries of the Fault Records database are a random sampling of 

the 491 failures recorded by NORS, then the following graph is a statistically 

significant presentation of the relationship between the failures and cable type. 

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Figure 26 

NORS Failure Data 2001-2005 by Cable Type 

The above graph indicates that 92% of the failures are emanating from the 15kV 

class unjacketed cable. The EDFS asset database indicates that 95% of the 

unjacketed cable, about 705 miles, was installed between 1970 and 1990. This 

means that 35% of the cable system is causing 92% of the failures. 

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Figure 27 

NORS Failure Data on 705 miles of pre-1991 Unjacketed Cable 

Comparing 92% of the failures caused by 705 miles unjacketed cable to the failures 

recorded by NORS from 2001 to 2005, the above graph is derived. The failure rate 

of the 705 miles of unjacketed cable in 2005 was 17 failures/100 miles/year, or 

nearly 3 times the national average for URD systems reported by the AEIC in 1994 

(6.2 failures/100 miles/year) and nearly 2 times the 2004 ICC survey (9 failures/100 

miles/year) mentioned above. Since 2001, the failure rate has been increasing by an 

average of 18% per year. 

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18.4 Determine Target Population of Cables to be Tested 

Figure 28 

Google Earth Overlay of LOAs with 90% of Failures from 2001-2005 

NIPSCO has nearly 2,000 miles of underground cables that are currently failing at a 

rate of approximately 7 failures/100 miles/year which is 13% above the national 

average of 6.2 failures/100 miles/year as reported by AEIC in 1994. The failure of 

the entire population is increasing at a rate of 11% per year. However, on a closer 

look at the data, 95% of the failures are occurring within the 705 miles of 

unjacketed cable installed prior to 1991 which is only 35% of the entire population. 

The 705 miles of unjacketed cable is currently failing at a rate of 17 failures/100 

miles/year and may be expected to increase at a rate of 18% per year. NIPSCO‘s 

current cable replacement budget can not keep pace with the increase in the failure 

rate. 

One of the outcomes of conducting the reliability audit was to select preliminary 

candidate populations. In general, the scope of the program was generally defined 

to include aged URD cable (>20 years old). However, newer installations with high 

failure rates were also considered. 

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This project was further refined to include a statistically significant population of 

unjacketed cable installed from the 1960s to the late 1980s. An estimate of 

approximately 600 URD cable sections would be identified to have a sufficiently 

large sample. Although 3 phase feeder cable sections are a small percentage of the 

population, they have a large impact on reliability. Feeder cable sections would be 

included in the project on an impact priority basis. 

As shown in Figure 28, a goal is to focus on the Hammond, Crown Point, Gary, and 

Valparaiso local operating areas. According to NORS, these 4 LOAs have 

sustained 90% of the failures on 114 circuits in the last 5 years and have the highest 

percentage of target unjacketed cable population. 

Other steps to consider in the target population are to focus on the circuits with the 

highest percentage of unjacketed cable. Develop a list of cable sections from the 4 

LOAs to be included in this project condition assessment survey. Include the LOA 

priorities whenever prudent. Focus on the cable sections with the highest number 

of failures. Customer Average Duration Index (CAIDI) and other reliability indices 

will not be especially helpful in the selection process, as NIPSCO‘s underground 

system is much smaller than their overhead system. 

19 Prioritize Underground Distribution Improvement 

Potential Sites 

Within a target population area (cables that have already faulted), a key to 

prioritizing these sites are testing methods which lead to the identification, and 

ranking of typical defects found in operating cables of a given year or manufacture. 

When sufficient samples of cables are tested for these defects, a characterization is 

made about the defects potential to cause a fault. Using this information in 

combination with historical fault data, a priority can be created that will rank sites 

with a greatest potential for future faults. These cables would be candidates for 

improvement. However, as time moves on, other sites will also move up the 

priority as they too would eventually be a candidate for cable improvement. 

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Listed below are prioritizing factors to consider in ranking potential sites of 

underground distribution improvement. 

19.1 Prioritizing factors 

19.1.1 Cable History (outage history) 

_ Vintage 

_ Number of failures 

_ Outage duration 

_ Load (kVA) affected 

_ Neighboring cable history 

_ Neutral corrosion 

19.1.2 Cable Physical Features 

_ Insulation type 

_ Conductor size
 

_ Jacket œYes or No 

_ Manufacturer œ if known
 

_ Neutral type 

19.1.3 Customer Considerations 

_ Number of Customers affected 

_ Importance to customer- hospital, government... 

_ Type: residential, commercial, gov. ... 

_ Number of complaints 

_ Safety e.g. stray voltage from corroded neutrals
 

19.1.4 Cost Considerations 

_ Cost of replacement (high or low) 

_ Economy of scale œloop/half loop replacement 

_ Annual reactive restoration expenditures 

_ Cost of outage œplanned vs. unplanned
 

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19.1.5 System Features 

_ Cable insulation type 

_ Design practices œstandards
 

_ Workmanship/training program
 

_ Loading practices/ seasonal load 

_ Loop or radial installation
 

_ Effective lighting arrestors œyes or no 

_ Frequency and magnitude of voltage transients 

_ Conduit, duct, directly buried 

20 Summary œ Define Selection Criteria, Prioritize
 

Potential Sites 

20.1 Selection of Candidate Populations (Cable Sections) 

The project has selected a majority of unjacketed cable installed from the 1960s to 

the late 1980s. Approximately 600 URD (Underground Residential Distribution) 

cable sections are selected to ensure a statistically significant population. 

20.1.1 Hammond, Crown Point, Gary, and Valparaiso Local Operating Areas 

The Focus of the project was on the Hammond, Crown Point, Gary, and Valparaiso 

local operating areas. These 4 LOAs have sustained 90% of the failures on 114 

circuits in the last 5 years of data and have the highest percentage of target 

unjacketed cable population. 

20.2 Final Selection of Target Population 

Using the program scope and results of the reliability audit and cost benefit analysis 

as a guide, the selection of the cable target population is finalized and is listed 

below. The area descriptions, along with LOA names, source and circuit numbers 

are incorporated into the list. 

Selection LOA Name Description Source Circuit 

1.01 Gary Broadway and 90th Street 00805542 12-436 

1.02 Gary Broadway and 89th Street 00902217 12-436 

1.02 Gary Broadway and 89th Street 00902218 12-436 

1.02 Gary Broadway and 89th Street 00902219 12-436 

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Selection LOA Name Description Source Circuit 

1.03 Crown Point West 97th Lane and US 41 00807467 12-618 

1.03 Crown Point West 97th Lane and US 41 00812649 12-618 

1.04 Hammond Griffith Industrial Park 00105647 12-576 

1.04 Hammond Griffith Industrial Park 00054420 12-576 

1.05 Hammond Tanglewood Apts, 167th and 

Indianapolis Blvd 

00095523 12-736 

1.05 Hammond Tanglewood Apts, 167th and 

Indianapolis Blvd 

00082579 12-736 

1.05 Hammond Tanglewood Apts, 167th and 

Indianapolis Blvd 

00082576 12-736 

1.05 Hammond Tanglewood Apts, 167th and 

Indianapolis Blvd 

00044902 12-736 

1.05 Hammond Tanglewood Apts, 167th and 

Indianapolis Blvd 

00044903 12-736 

1.06 Hammond Sherwood Lake Apartments 00082630 12-175 

1.06 Hammond Sherwood Lake Apartments 00082588 12-175 

1.06 Hammond Sherwood Lake Apartments 00094401 12-175 

1.06 Hammond Sherwood Lake Apartments 00085262 12-175 

1.06 Hammond Sherwood Lake Apartments 00075004 12-175 

1.06 Hammond Sherwood Lake Apartments 00082587 12-175 

1.06 Hammond Sherwood Lake Apartments 00081896 12-175 

1.06 Hammond Sherwood Lake Apartments 00084845 12-175 

1.07 Hammond Fran-Lin Parkway and Chestnut Lane, 

Munster 

00105113 12-331 

1.08 Hammond Munster, White Oak Ave and Somerset 

Dr. 

00082250 12-329 

2.01 Laporte Michigan City-Indian Springs 00228806 12-104 

2.01 Laporte Michigan City-Indian Springs 00226573 12-104 

2.01 Laporte Michigan City-Indian Springs 00227322 12-104 

2.02 Valparaiso Valparaiso-Shorewood North 00852506 12-598 

2.02 Valparaiso Valparaiso-Shorewood North 00852925 12-598 

2.03 Valparaiso Valparaiso-Heritage Valley South 00444564 1214 

2.03 Valparaiso Valparaiso-Heritage Valley South 01005201 1214 

2.05 Valparaiso Valparaiso-Shorewood South 01005432 12-427 

2.06 Valparaiso Valparaiso-Heritage Valley North 01002761 1279 

2.06 Valparaiso Valparaiso-Heritage Valley North 00441807 1279 

2.06 Valparaiso Valparaiso-Heritage Valley North 00444563 1279 

2.06 Valparaiso Valparaiso-Heritage Valley North 01001896 1279 

2.06 Valparaiso Valparaiso-Heritage Valley North 00445686 1279 

2.07 Hammond Dyer-Heritage Estates 00066240 12-249 

2.07 Hammond Dyer-Heritage Estates 00066240 12-249 

2.07 Hammond Dyer-Heritage Estates 00083392 12-249 

2.07 Hammond Dyer-Heritage Estates 00084819 12-249 

2.07 Hammond Dyer-Heritage Estates 00054282 12-249 

2.08 Hammond Dyer-Castlewood 00103338 12-655 

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Selection LOA Name Description Source Circuit 

2.08 Hammond Dyer-Castlewood 00095321 12-267 

2.08 Hammond Dyer-Castlewood 00100513 12-655 

2.09 Gary Merrillville-Southlake 00902269 12-546 

2.09 Gary Merrillville-Southlake 00902268 12-546 

2.09 Gary Merrillville-Southlake 00806533 12-546 

2.09 Gary Merrillville-Southlake 00902267 12-546 

2.10 Crown Point Hebron-Apple Valley 00805472 12-422 

2.10 Crown Point Hebron-Apple Valley 00374798 12-583 

2.11 Crown Point Lowell-Fairways 00821656 12-583 

3.01 Hammond Dyer-Heritage Estates 00066460 12-249 

3.01 Hammond Dyer-Heritage Estates 00146788 12-249 

3.01 Hammond Dyer-Heritage Estates 00069844 12-249 

3.01 Hammond Dyer-Heritage Estates 00066239 12-249 

3.01 Hammond Dyer-Heritage Estates 00059965 12-249 

3.01 Hammond Dyer-Heritage Estates 00146787 12-249 

3.01 Hammond Dyer-Heritage Estates 00066243 12-249 

3.02 Hammond Harvest Acres 00102874 12-704 

3.02 Hammond Harvest Acres 00102875 12-704 

3.02 Hammond Harvest Acres 00102872 12-704 

3.02 Hammond Harvest Acres 00096171 12-704 

3.02 Hammond Harvest Acres 00092483 12-704 

3.02 Hammond Harvest Acres 00092482 12-704 

3.02 Hammond Harvest Acres 00092481 12-704 

3.02 Hammond Harvest Acres 00103523 12-704 

3.03 Valparaiso Pheasant Valley 00430515 12-149 

3.03 Valparaiso Pheasant Valley 00430516 12-149 

3.03 Valparaiso Pheasant Valley 00430522 12-149X14 

3.03 Valparaiso Pheasant Valley 00438050 12-149 

3.03 Valparaiso Pheasant Valley 00440942 12-149X14 

3.03 Valparaiso Pheasant Valley 00446121 12-149X14 

3.03 Valparaiso Pheasant Valley 00446718 12-149 

3.04 Hammond Harrison Heights 00082619 12-293 

3.04 Hammond Harrison Heights 00082618 12-293 

21 Identify Distribution System Details 

The distribution underground system under review contains those areas where 

outages have occurred due to primary underground faults. As the list of these 

problematic areas are prioritized and reviewed, it is clear that there are hundreds of 

miles of cable to evaluate. The scope of this projects review will focus on sections 

designed as a —Normally Open Loop System“. 

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21.1 Normally Open Loop System 

A normally open loop system employs a dual source, normally open primary circuit 

concept. In this manner, backup service can be supplied for almost all maintenance 

and emergency outages. The main loop consists of two radial circuits from two 

sources with the interconnection point normally open, and in some cases, additional 

branch circuits are tapped from the main loop. 

A typical loop has two taps off a main line (usually overhead distribution). The 

loop will have one normally open point near the middle of the loop. The normal 

open point is established by connecting one loadbreak elbow terminator to a 

parking stand rather than the transformer bushing, instead of completing the loop. 

During maintenance or emergency events (faulted cable), any single section of 

underground cable can be isolated and all customers on the loop remain in service 

simply by connecting or disconnecting appropriate elbow terminators. 

In non emergency cases, once a section of cable is identified for evaluation, the 

normally open elbow location is connected completing the loop, then the elbow 

from each end of the identified cable section is disconnected, to isolate the cable 

section and create a new temporary open point. While the cable section is isolated, 

all the transformers (all the customers) remain connected and their service is not 

interrupted. 

The potential reliability solutions that can be explored in a normally open loop 

system will allow us to capitalize on the best available options, with minimal 

inconvenience to the customer. They are: 

1. Reduce the number of underground faults. 

2. Reduce the number of customers impacted should future faults occur. 

3. Reduce outage time in the event of future faults. 

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22 Condition Assessment Survey 

In Step 2 of the process, a condition assessment survey (Partial Discharge Test) is 

performed and the end results identify only those sections of cable that require 

action like repair or replacement. Typically, less than one third of the cables tested 

will require full replacement. Using condition assessment survey as a basis for 

improvement requires the test be performed on all cable sections in order to 

determine the next step or plan of action. From the results of the test, solutions 

from cable replacement to completing underground loops can be made on each 

specific area, depending on the need. The following details the specifications of 

the Partial Discharge Diagnostics used. 

22.1 Condition Assessment Survey (Partial Discharge Diagnostics) 

Without specifications and guidelines to follow, a user may not be able to 

distinguish one form of testing from another. In this case, the condition assessment 

survey testing chosen for evaluation is a Partial Discharge (PD) test. However, 

included in this requirement was the need that the testing company have an in-depth 

understanding of the technology, its economic and practical impact on the utility, 

and have a proven experience/track record. Some companies that offer testing are 

offering a simple and superficial PD test without demonstrated qualifications or by 

means of a technology which is unsupported by recognized standards, or years of 

data collected from actual field experience. 

—Partial discharge (PD) is an electrical discharge that does not completely bridge 

the space between two electrodes. When a power cable is placed under electric 

stress of sufficient level, partial discharge may occur at localized defect sites. These 

defect sites are caused by workmanship errors and/or aging and are aggravated by 

power system voltage transients. Defects can be found in joints, terminations, or 

cable insulation. 

On every reel of new cable produced at the factory, a partial discharge (PD) 

diagnostic is routinely conducted. This is performed in an electromagnetically 

shielded room using a 50/60Hz voltage source. The field test, performed after 

installation (acceptance testing) but, before being energized is intended to ensure 

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that the cable was not damaged during transportation, handling and installation and 

that the accessories have been properly installed. The field test, performed 

periodically thereafter, during service (maintenance testing) to determine if the 

cable system remains reliable. To ensure harmony, traceability and relevance, field 

tests must, as well, be conducted at 50/60Hz, with a measurement sensitivity which 

is in line with that in the factory. Noise mitigation and ensuring high sensitivity are, 

therefore, of utmost importance. 

In service, the cable system is subjected to switching and lightning transient 

overvoltages which may trigger electrical treeing in defective cable systems whose 

partial discharge inception voltage level is exceeded by the transients. The test 

voltage level must ensure that defects which may be excited by these transients are 

identified and removed, so the cable reliability is maintained at a very high level. 

This diagnostic process should monitor the relative thresholds of the inception 

(PDIV) and extinction (PDEV). By this process the voltage and pico-Coulomb (pC) 

magnitude thresholds are compared to the acceptable PD levels defined by IEEE 

standards. Interpretation of PD test results requires a thorough knowledge of the 

phenomenon, coupled with a proven data driven experience base. The interpretation 

must be supported by an extensive data-base covering a vast array of cable systems 

and service conditions, obtained over long periods of testing and supported by 

system performance data and laboratory investigations.“3 

22.1.1 Partial Discharge Diagnostic Specifications 

Partial discharge diagnostics for new and existing Cables, Joints and Terminations 

for extruded 5kv, 15kv, 25kv and 35kv class power cable system. 

Diagnostic provider shall be independent of the supplier, manufacturer and 

installing contractor of the cable system. 

22.1.1.1 Voltage Source: 

The Diagnostic provider must use a power frequency (50/60Hz) voltage source to 

energize the cable exceeding nominal voltage level of the cable. The test voltage 

level shall be in accordance with IEEE 400.3 and comply with the requirements of 

the next paragraph. 

3 As stated from the IMCORP Partial Discharge Diagnostic Specification. IMCORP is a leader in 

underground cable reliability consulting and diagnostics. www.imcorptech.com
 

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22.1.1.2 Non-Destructive: 

It is crucial to monitor the response of the cable to a voltage stress that is 

gradually increased from zero to the highest transient voltage which may be 

experienced by the cable system in its particular environment without being above 

nominal voltage for more than 15 seconds. 

22.1.1.3 Experience: 

Diagnostic provider shall have at least 10 years experience utilizing the 

methodology described herein in the electrical partial discharge testing of power 

cables with database to support expert knowledge based algorithms and 

recommendations. 

22.1.1.4 Noise Mitigation: 

Diagnostic provider must have robust digital noise mitigation algorithms to achieve 

a sensitivity in all conditions that is in the range of ICEA and IEEE cable and 

accessory standards. 

22.1.1.5 PD Excitation: 

The cable under test shall be excited by a power frequency voltage source levels 

from 1.5 times nominal voltage and up to 3.0 times nominal voltage (voltage levels 

are agreed upon with customer) to monitor the cable in transient conditions 

experienced during switching, lightning, etc. The relative thresholds of PD 

inception voltages (PDIV) and extinction voltage (PDEV) shall be identified to be 

compared to IEEE standards. 

22.1.1.6 Measurements: 

The PD measurements shall include PD phase information which is used to 

characterize the PD type and relative threshold levels. The PD response of the cable 

shall be recorded at voltage levels that can be compared to IEEE thresholds or 

acceptable levels agreed on by customer. 

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22.1.1.7 Calibration: 

Diagnostic instruments shall be calibrated in accordance with NETA, IEEE, ICEA, 

or other nationally recognized organizations and standards. 

22.1.1.8 Sensitivity: 

The Diagnostic must specify an acceptable sensitivity measurement method and 

achieve a sensitivity level commensurate with that prescribe ICEA for factory 

testing. 

22.1.1.9 Qualified: 

Convincing evidence must be provided that diagnostic testing is conducted by 

qualified individuals, supported by registered professional engineers. 

22.1.2 Partial Discharge Testing Criteria 

° Disconnect and test each cable (out of service) using external, variable 

voltage power frequency source to replicate normal operation and provide a 

voltage level equivalent to the transients expected on the system under test. 

° Diagnostic testing shall include the following four steps: 

o	 Map the cable using a Low Voltage TDR (time-domain 

reflectometry) to locate joints, terminations and cable anomalies 

o	 Sensitivity assessment is to ensure that the test sensitivity is as close 

as possible to the 5 pico-Coulombs (pC) level stipulated by ICEA for 

extruded cables. No diagnostic test shall be deemed reliable if 

sensitivity levels of 50pC and 100pC cannot be met for cables and 

accessories, respectively. 

o	 Diagnostic stress simulation test with time varying, power frequency 

excitation voltage applied. 

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o	 Data analysis, interpretation and recommendations to include 

locations of partial discharges, severity assessment and corrective 

actions. 

° Maximum test voltage used shall be 1.5-3.0 times the operating voltage (Uo) 

of the cable (lineœto-ground) depending on the cable‘s voltage class. An 

example for 35kV class new extruded cable would be to record response 

data at 1.0, 1.3, 1.5, 1.7, and 2.0Uo levels. 

° Provide summarized reports showing cable length, locations of joints, 

terminations, and defect sites, PD inception voltage levels, severity 

assessment and recommendations for future action. 

IEEE Standard Thresholds 

° IEEE 48-1996 Terminations No PD ≥ 5pC up to 1.5Uo 

° IEEE 404-2000 Joints No PD ≥ 3pC up to 1.5Uo 

° IEEE 386-1995 Separable Connectors No PD ≥ 3pC up to 1.3Uo 

° ICEA S-93-639-2000 MV Extruded Cable No PD ≥ 5pC up to 4Uo 

Definitions: 

Inception Voltage: The voltage at which PD first appears is the Inception Voltage 

(PDIV) 

Extinction Voltage: The PD is extinguished when the voltage is reduced below the 

level called the Extinction Voltage (PDEV) 

Pico-Coulomb: a measure of charge used to in defining the magnitude of a PD. 

22.1.3 IEEE 400-2001 - Guide for Field Testing and Evaluation of the Insulation of 

Shielded Power Cable Systems 

Based on the IEEE standards as guidelines, —if the cable system can be tested in the 

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field to show that its partial discharge level is comparable with that obtained in the 

factory tests on the cable and accessories, it is the most convincing evidence that the 

cable system is in excellent condition“. Therefore, any cable that passes IEEE 400 

should not need to be replaced, regardless of it‘s age, or the history of any of the 

same vintage cable. Reliability will improve by only replacing the unreliable cable 

in lieu of traditional replacement of all the cable of a given vintage or manufacture. 

22.1.3.1 Example Partial Test Report œ Unreliable Cable vs. Reliable Cable 

Example Test Report œUnreliable vs. Reliable

Case 1 

Case 2 

Partial Discharge Test Results 

747 

172 175 

0.00 

0.50 

1.00 

1.50 

2.00 

2.50 

3.00 

0 100 200 300 400 500 600 700 800 

Length 

Test Voltage (PU) 

PD Locations Joint Locations Terminations

 Partial Discharge Test Results 

171

160 

145484 

0415699208223266 270324422490 

143168480 

0.00 

0.50 

1.00 

1.50 

2.00 

2.50 

3.00 

0 100 200 300 400 500 600 700 

Length 

TestVoltage(PU) 

PD Locations Joint Locations Terminations 

U

V V

V V V U U UU UU U U U

U

U

Reliable

Reliable 

4.0 

4.0 

Unreliable

Unreliable 

Power Cable Reliability Power Cable Reliability

29 

Figure 29 

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Distribution - Final Technical Status Report Subcontract Number NAT-8-66144-01

22.1.3.2 Typical Partial Discharge Producing Defects 

Typical PD Producing Defects in Extruded Cables 

Void 

Protrusion 

Long 

Water Tree 

Erosion 

Effect of 

PD 

Space Charge 

Chemical 

Change 

Shield 

Interruption 

Electrical 

Tree 

Crack 

Vented 

Water Tree 

Electrical Electrical

Tree

Protrusion 

Electrical 

Tree 

Torn Jacket/ 

Insulation Shield 

Torn insulation 

shield 

Electrical 

Tree 

Void 

Voids 

Power Cable Reliability Power Cable Reliability

56 

Figure 30 

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23 Process Documentation and Practices œ Condition 

Assessment Survey (PD testing) 

23.1 Process Documentation of Partial Discharge Diagnostics 

Documentation is created for each of the IMCORP Diagnostic Survey Tests. The 

individual reports provide test results along with detailed information on each cable 

segment and phase. Information and recommendations from each report are 

condensed into a summary that better enables the client to prioritize repairs and 

build a working reliability program. The IMCORP PD diagnostic survey process 

produces a wealth of information which needs to be condensed and organized into 

actionable information. 

49 PDs from near end: 0.0ft, 89.0pC, at 18.0kV 

-300 

-200 

-100 

0 

100 

200 

300 

0 30 60 90 120 150 180 210 240 270 300 330 360 

Phase (Deg) 

pC 

51 PDs from near end: 0.0ft, 85.0pC, at 18.1kV 

-200 

-100 

0 

100 

200 

0 30 60 90 120 150 180 210 240 270 300 330 360 

Phase (Deg) 

pC 

Figure 31 Partial Discharge Detail 

The detail in figure 31 above is an example of an information level reviewed by the 

IMCORP, and in this case, the partial discharges are from the end termination and 

are mitigated in the field. This level of detail is included in the customer 

documentation. 

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The first level of reporting is the detailed diagnostic report. This report is generated 

by the IMCORP diagnostic software and presents a simplified profile of each cable 

segment (Figure 32) and the severity of each PD site located. 

Figure 32 Simplified Profile of Cable Segment with recommendation 

This report is then reviewed by the IMCORP project manger assigned to the 

program. After reviewing the individual report the IMCORP project manager 

updates the project summary document with the detailed report findings and makes 

the appropriate recommendations on the entire segment. The recommendation will 

be determined by a rule set agreed upon by the customer and IMCORP. This report 

is created for each cable section evaluated. 

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23.2 Typical Field Practices of Partial Discharge Diagnostics 

The following outline describes details to switch and prepare cable segments. 

1.	 Each segment (single-phase or three-phase) to be tested will need to be switched 

out of service before it is tested. 

a.	 The cable grounds must remain connected. 

b.	 The tested cable segment needs to be electrically isolated and grounded. 

c.	 Termination preparation 

i.	 Elbows 

1.	 Far end elbow(s) need to be cleaned, re-greased, and 

parked on a parking bushing(s) or appropriate adapter. 

2.	 Near end elbow(s) need to be cleaned, re-greased, and the 

appropriate adapter connected to the test equipment. 

ii.	 Live Front Terminations 

1.	 Terminations need to be unbolted and cleaned 

2.	 Terminations need to be isolated for grounds 

3.	 The near end termination needs to be connected to test 

equipment 

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d.	 Testing : 

i.	 Customer assist crew starts by selecting a point in the circuit where 

one or more cables can be tested without having to shift the 

location of test truck. 

ii.	 Assist crew prepares the first cable before the arrival of IMCORP 

crew. 

iii.	 As the first cable is tested the assist crew is preparing a second 

cable 

iv.	 As the second cable is being tested, the first cable will be 

reassembled and the next cable is being prepared. 

v.	 The assist crew moves to a second location on the circuit where 

one or more cables can be tested. 

vi.	 The process is repeated from step (ii). 

Figure 33 Typical Equipment Setup 

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24 Condition Assessment Survey (Initial Verification) 

One of the early goals of the Condition Assessment Survey was to verify that the 

technology would be capable of not only determining if a cable needed to be 

replaced, but if the defects detected were actually there and could be verified in a 

dissection analysis. 

Figure 34 Testing in Progress 

In our first testing area, an opportunity developed whereby a section of cable was 

determined to have a severe defect and the defect occurred in an area that 

excavation would cause minimal customer impact. The following pages outline the 

process of defect removal and analysis to verify the technology. 

The cable parallel to Connecticut Dr was tested for partial discharge activity and 

location. As the 60Hz voltage was increased to simulate voltage transients, a partial 

discharge site was located very close to nominal voltage of the cable. As a result, 

the defect was located using a location matching system and removed by NIPSCO 

crews. The sample was sent to the IMCORP sample laboratory and dissected, 

finding several defects, the most significant being the electrical tree the source of 

the PD (see Figure 35 and 36). 

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24.1 Dissection Analysis 

Figure 35 Dissection Analysis Report 

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Figure 36 Additional Electrical Tree Example 

Since this was near the start of the Condition Assessment Survey, early dissection 

analysis was helpful to relate the technology and reports to the actual defect that is 

detected and in this case, removed. 

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25 Continued Condition Assessment Survey (PD testing) 

The IMCORP Diagnostic Survey Testing was continued in each of the identified 

areas. The individual reports provided test results along with detailed information 

on each cable segment and phase. Information and recommendations from each 

report are condensed into a summary in spreadsheet format that better enable the 

client to prioritize repairs and build a working reliability program. 

25.1 Example of Data Contained in Summary Report Recommendation 

The following example illustrates some of the comments that the summary report 

would contain. 

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26 Cable Replacement 

26.1 Description of Cable Replacement Selection 

The goal of condition assessment survey (Partial Discharge testing combined with 

detailed analysis and recommendation) is to assist in the development of a proactive 

repair and replacement plan in the most cost effective means possible. 

The result of the condition assessment determines if the cable should be replaced 

immediately or can wait to be scheduled. In addition, if there is only one defect in 

300 feet of cable (for example), then a cable repair consisting of cutting out the 

defect and replacing it with a short piece of cable is the most effective solution. 

And finally, if the condition assessment surveys results in a cable that has passed 

the tests, then a recommendation of —defer“ is made, which means that no action 

should be required for up to 10 years. 

A cable system is given the label ”Replace‘ when the number of severe defects to be 

repaired has exceeded an agreed upon economic threshold which clearly indicates 

that the repair investment will not be sufficiently lower than the net worth of the 

system asset. Based on this assessment, the maps are created identifying which 

cable sections need to be replaced. Each cable section is replaced using typical 

installation practices outlined below. 

26.2 Cable Replacement Practices in a Normally Open Loop System 

A normally open loop system employs a dual source, normally open primary circuit 

concept. In this manner, backup service can be supplied for almost all maintenance 

and emergency outages. The main loop consists of two radial circuits from two 

sources with the interconnection point normally open, and in some cases, additional 

branch circuits are tapped from the main loop. 

A typical loop has two taps off a main line (usually overhead distribution). The 

loop will have one normally open point near the middle of the loop. The normal 

open point is established by connecting one loadbreak elbow terminator to a 

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parking stand rather than the transformer bushing, instead of completing the loop. 

During cable replacement, any single section of underground cable can be isolated 

and all customers on the loop remain in service simply by connecting or 

disconnecting appropriate elbow terminators. 

In cable replacement cases, once a section of cable is identified for replacement, a 

new conduit is installed between the 2 ends using typical damage prevention 

guidelines of trenchless technology. 

Once new cable is pulled in the conduit and excavated externally to the end 

locations, additional company safety rules are implemented in switching and 

working near live conductors. The normally open elbow location is connected, 

completing the loop, then the elbows from each end of the identified cable section is 

disconnected, to isolate the cable section and create a new temporary open point. 

While the cable section is isolated, all the transformers (all the customers) remain 

connected and their service is not interrupted. The new cable is routed in place of 

the old cable and new terminations are made on the new cable and the old cable is 

retired from service. Finally, the new temporary open point is re-connected to the 

loop, and the original normally open elbow location is disconnected and the circuit 

is returned to normal. 

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26.2.1 Sectionalizing Underground Cable 

In a given underground circuit, physical requirements of cable replacement 

sometimes do not permit cable replacement of one for one. In some cases, cable 

that runs from point A to point B in the original direct burial installation cannot be 

replaced with one direct path. When the path of the new cable is complicated, 

additional termination points need to be installed to facilitate cable replacement 

installation. These additional new termination points —sectionalize“ or divide a 

cable into sections to help in troubleshooting, which breaks up areas into smaller 

sections with fewer customers. The equipment that is installed is routinely referred 

to as sectionalizing cabinets or sectionalizing pedestals. 

26.3 Cable Repair and Replacement Activities 

The final step in improving the electric underground infrastructure is to take action 

on the results of the condition assessment survey (Partial Discharge Test). In this 

case, the number one action item to improve reliability is to repair or replace cable 

that has been identified. Having been tested and determined in need of action, only 

repair or replacement will restore the reliability to the electric underground 

infrastructure and avoid future faults. In the original scope of this project, the list 

below outlines the areas where the first improvements were made based on the 

recommendations of the condition assessment survey. Most of the cable is in 

existing established developments and neighborhoods, and the technique of 

underground guided boring was used to install most of the new cable. In addition 

to cable terminators and splices, pedestals used to sectionalize circuits were also 

installed as needed to facilitate replacement. 

The area descriptions below represent the areas of cable replacement for this report. 

Selection LOA Name Description Circuit 

1.01 Gary Broadway and 90th Street 12-436 

1.02 Gary Broadway and 89th Street 12-436 

1.03 Crown Point West 97th Lane and US 41 12-618 

2.01 Laporte Michigan City-Indian Springs 12-104 

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27 Distribution Summary - Conclusions 

The distribution underground system analysis incorporated a thorough review of 

problematic areas that needed improvements. This review incorporated the findings 

of Circuit Reliability Testing that created a proactive work plan to systematically 

target areas for improvement by factual data from definitive results and analysis. 

The anticipated result was that near 1/3 of the target areas for improvement would 

need cable replacement and that the benefit of proactive cable replacement would 

maximize our ability to reduce the number of future underground faults. The 

implementation of the recommended solutions was anticipated to have a positive 

impact on the reliability of the system as well as the restoration time should an 

outage occur. These results were also anticipated to be a catalyst to embark on a 

long-term electric underground infrastructure improvement program. 

27.1 Circuit Reliability Testing - Conclusions 

The Circuit Reliability Testing was performed on 576 cable sections, which is in the 

range that was targeted for this project. It was anticipated that approximately 1/3 of 

the cables may need replacement, but even this number is a far greater number of 

Circuit Sections than our yearly budgeted dollars for Cable Replacement would 

allow. However, the percentage of cable to replace was a major part of the project 

scope, which is to compare an anticipated recommended replacement rate to the 

actual recommended replacement rate. This replacement rate will help establish a 

future testing rate that matches budgeted cable replacement dollars. In order to do 

this comparison, a significant statistical population was recommended to be tested. 

This population was decided to be near 600 cable sections that were in most need of 

improved reliability. 

Circuit Reliability Testing creates a proactive work plan to systematically target 

areas for improvement by factual data from definitive results and analysis. 

Budgeted dollars are put where they are most needed. 

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27.1.1 Selection of Candidate Populations (Cable Sections) 

The project selected a majority of unjacketed cable installed from the 1960s to the 

late 1980s. Approximately 600 URD (Underground Residential Distribution) cable 

sections were selected to ensure a statistically significant population. The focus of 

the project was on the Hammond, Crown Point, Gary, and Valparaiso local 

operating areas. These 4 LOAs have sustained 90% of the failures on 114 circuits 

in recent years of data and have the highest percentage of target unjacketed cable 

population. 

Using the program scope and results of the reliability audit and cost benefit analysis 

as a guide, the selection of the cable target population was finalized and tested. 

27.1.2 Anticipated Results of Circuit Reliability Testing 

The original analysis and proposal by IMCORP provided an estimate and analysis 

for Single Phase and Three Phase cable. Since the three phase percentages were the 

same, only the single phase will be summarized in the following: 

Single Phase Analysis 

Condition assessment data: (typical data percentages) 

No. of cable sections ....................................................1,000 

No. of cable sections to defer action ............................556 (55%) 

No. of cable sections to repair .....................................297 (30%) 

No. of cable sections to replace ...................................147 (15%) 

Percent of cables deferred (defer + repair) ...................85% 

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27.1.3 Actual Results of Circuit Reliability Testing 

After testing, an analysis of the data for Single Phase and Three Phase cable is 

combined and summarized as follows: 

Single and Three Phase Analysis 

Condition assessment data: (actual data percentages) 

No. of cable sections ....................................................576 

No. of cable sections to defer action ............................350 (60.8%) 

No. of cable sections to repair .....................................123 (21.4%) 

No. of cable sections to replace ...................................103 (17.8%) 

Percent of cables deferred (defer + repair) ...................82.2% 

27.1.3.1 Comparison of Actual vs. Anticipated Results of Circuit Reliability Testing 

Comparisons of the Actual vs. Anticipated results were favorable. To a great 

degree, the percentages of cable sections in each category were near prediction, 

with only a 2.8% greater number of cables needing replacement than predicted. 

Therefore, the anticipated savings and other estimates are expected to fall in line. 

Single and Three Phase Analysis 

Condition assessment data: (actual data percentages) 

Actual Anticipated
 

No. of cable sections ........................................576..............................1,000 

No. of cable sections to defer action ................350 (60.8%) ...............556 (55%) 

No. of cable sections to repair .........................123 (21.4%)................297 (30%) 

No. of cable sections to replace .......................103 (17.8%)................147 (15%) 

Percent of cables deferred (defer + repair) .......82.2% ........................85% 

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27.1.3.2 Detail Summary of Circuit Reliability Testing by LOA Area 

The following summary shows the breakdown of recommendations for each of the 

LOAs tested. As a result of Circuit Reliability Testing, we have discovered that we 

will need to budget for replacement, approximately 20 cable sections, out of each 

100 sections that are tested. 

Recommendation 

% of 

Sections 

Total 

Selection Crown Point Gary Hammond Laporte Valparaiso 

IMMEDIATE 

REPLACEMENT 5.2% 30 5 2 6 1 16 

SCHEDULE 

REPLACEMENT 12.7% 73 7 6 36 2 22 

Total Replacement 17.8% 103 12 8 42 3 38 

IMMEDIATE 

REPAIR 4.2% 24 16 8 

SCHEDULE 

REPAIR 17.2% 99 8 18 56 2 15 

Total Repair 21.4% 123 8 18 72 2 23 

INSPECT 1.6% 9 1 1 1 6 

RETEST 0.3% 2 1 1 

DEFER ACTION 58.9% 339 13 35 189 6 96 

Total Defer 60.8% 350 15 37 190 6 102 

Total Tested 576 35 63 304 11 163 

27.2 Cable Replacement œ Conclusions 

Having been tested and determined to be in need of action, only the repair or the 

replacement of the cable will restore the reliability to the electric underground 

infrastructure and avoid future faults, thus having a positive impact on the reliability 

of the system. Previous approaches to underground improvement were limited to 

reacting to outages or performing wholesale replacement of cable, which limits the 

areas that could be addressed with the budgeted dollars. 

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27.2.1 Anticipated Findings on Cable Replacement 

A cable system is given the label ”Replace‘ when the number of severe defects to be 

repaired has exceeded an agreed upon economic threshold which clearly indicates 

that the repair investment will not be sufficiently lower than the net worth of the 

system asset. Based on this assessment, the maps are created identifying which 

cable sections need to be replaced. Each cable section is replaced using typical 

installation practices. This cable replacement and repair makes long-term upgrades 

to system assets in the most cost effective manor. 

27.2.2 Actual Findings on Cable Replacement and Repair 

27.2.2.1 Replacement Findings 

The label ”Replace‘ was used when the number of severe defects to be repaired has 

exceeded an agreed upon economic threshold which clearly indicates that the repair 

investment will not be sufficiently lower than the net worth of the system asset. 

There were 2 subcategories for replacement; immediate replacement and scheduled 

replacement. Our findings were that most of the replacements became scheduled 

replacements due to the fact that the resources needed for replacement were unique 

and equipment and crews for this needed to be scheduled. However, immediate 

replacements did tend to get scheduled first whenever possible. 

The results of the testing also became a catalyst to embark on a long-term electric 

underground infrastructure improvement program. Using the remaining data of 

cable that was tested, a long-term program was outlined to improve the 

underground infrastructure at NIPSCO. Since the number of cables identified 

outran a single years budgeted dollars, cable repair or replace findings continue to 

be validated as some of those sections identified exhibit faults before they get 

scheduled for replacement. It is recommended that the testing rate keep pace with 

the anticipated replacement statistics, and be replaced as soon as the budget allows, 

and within a year if possible. 

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27.2.2.2 Repair Findings 

The label —Repair“ was less straight forward than the replace label. Although our 

guidelines were based on 2 repairs in 300 feet of cable, a decision to repair or 

replace these sections required more engineering evaluation. In some cases, cables 

identified as repair were instead replaced because of the staging of the crews to 

replace adjacent cable sections. Also, other site conditions such as fences, sheds, 

driveways etc., - would prevent a repair of the designated location. 

There was a short evaluation of an IMCORP cable matching technique to help 

locate the exact location of a repair site. This technique is described as follows: 

Once a defect or failure site has been located by the IMCORP Estimator system or other fault 

location set, the Matcher is used to locate the physical location of the site. To locate a site the user 

takes the estimated location from one end of the cable and, using a measuring wheel, wheels out the 

cable path to the estimated location. The cable is exposed and a transmitter is attached to the shield 

power cable. On one end of the cable a receiver is connected. The receiver computes the location of 

the transmitter and the actual location value is compared with the estimated value form the 

diagnostic or fault location test. If there is a difference between the estimated value and location of 

the transmitter the actual location of the defect or fault is exactly the difference of these two 

measurements away. 

Although the technology was effective, the cost of using an experienced technician 

or keeping an in house technician skilled at using the matching technique was 

beyond the scope of this project. It is estimated this technique would be most cost 

effective on longer runs of cable (at least twice our system average length of 325 

feet) with only 1 or 2 defects, since this would indicate that the repair investment 

would be sufficiently lower than the net worth of the system asset (replacement of 

the cable). 

In most cases, if the repair was near one end of the cable, the repair was to splice a 

section of cable from beyond the defect area, to its nearest end. In the case of a 300 

foot piece of cable, a defect would typically need to be within 100 feet of the end to 

warrant a repair; otherwise it would just be replaced. 

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27.3 Sectionalizing Underground Cable œ Conclusions 

Each area under test was already primarily in a loop configuration. This project 

installed sectionalizing pedestals as well as fused sectionalizing pedestals (a fuse 

senses the fault condition and operates to open and sectionalize the circuit). These 

pedestals were installed mostly in three phase loop applications. The three phase 

sectionalizing pedestals were installed when the original direct burial installation 

could not be replaced with one direct path, or its path was reconfigured to a better 

functional layout. Single phase fused sectionalizing pedestals were installed when 

there were single phase taps to transformers etc, from a three phase loop circuit. In 

this way, a fault on a single phase circuit would be limited to the single phase 

loads, and the three phase loads would remain energized. 

We have found that when our direct buried cable installations are replaced, the new 

conduit installations usually require some sectionalizing pedestals to accommodate 

the new configuration. The exact need for sectionalizing pedestals will not become 

evident until engineering is done with estimating the project. 

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27.4 Other Findings 

After the critical repair and replace cable sections have been addressed, another 

option to improve reliability is to complete the loop in an underground circuit. If a 

section is a radial feed (only fed from one direction) then reliability will suffer 

because the one section must be repaired before all the customers beyond the failure 

on that radial section have power. Completing the loop reduces the number of 

customers affected for the longer duration outage, and will allow power to be 

restored in a shorter amount of time. Due to priority of the problematic areas, only 

areas that already had a majority of the components tied in a cable circuit loop were 

considered for this project and therefore, no additional cable circuit loops were 

created as part of this project. 

Lastly, an option for infrastructure improvement considered for this project was the 

use of Faulted Circuit Indicators, to help restore power in a shorter amount of time. 

However, it was decided that long term solutions (like cable testing and 

replacement) were a better permanent solution vs. Faulted Circuit Indicators, which 

improve restoration time but still require a more permanent solution for the cable to 

be addressed in the future. Faulted Circuit Indicators were felt to be valuable as a 

tool, for use in areas that had not yet been tested, but had just begun to have cable 

faults. In this way, the ability to locate, isolate the faulted section, and restore 

service would be improved until such time as cable testing and cable replacement 

could be implemented. 

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PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

February 2011

2. REPORT TYPE

Subcontract Report

3. DATES COVERED (From - To)

4. TITLE AND SUBTITLE

Electricity Supply Infrastructure Improvements: Final Technical 

Status Report, December 2010

5a. CONTRACT NUMBER

DE-AC36-08GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

Daniel Piekarski and Dana Brad

5d. PROJECT NUMBER

NREL/SR-5500-49793

5e. TASK NUMBER

DP05-2001

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Northern Indiana Public Service Company (NIPSCO)

801 East 86th Ave., Merrillville, IN 46410

8. PERFORMING ORGANIZATION

REPORT NUMBER

NAT-8-66144-01

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401-3393

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL

11. SPONSORING/MONITORING

AGENCY REPORT NUMBER

NREL/SR-5500-49793

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service

U.S. Department of Commerce

5285 Port Royal Road

Springfield, VA 22161

13. SUPPLEMENTARY NOTES

NREL Technical Monitor: Thomas Basso

14. ABSTRACT (Maximum 200 Words)

This report is about a work effort where the overall objectives were to establish a methodology and approach for 

selected transmission and distribution (T&D) grid modernization; monitor the results; and report on the findings, 

recommendations, and lessons learned. The work reported addressed T&D problems and solutions, related reliability 

issues, equipment and operation upgrades, and respective field testing. 

15. SUBJECT TERMS

electricity infrastructure; 345 kV Transmission circuits; electricity supply infrastructure improvements; electrical 

transmission;

16. SECURITY CLASSIFICATION OF: 17. LIMITATION 

OF ABSTRACT

UL

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a. REPORT

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