NETA World Journal | Winter 2019

END-TO-END TESTING FOR LINE DIFFERENTIAL PROTECTION PAGE 44

R-GOOSE APPLICATIONS IN A SMART GRID PAGE 62

FEBRUARY 24 - 28, 2020

PowerTest 2020 boasts five different paper tracks, 40+ sessions, and a full week of conference activities.

NETWORK

Build relationships and establish valuable contacts with 500+ leaders in the electrical testing industry when you attend engaging events at PowerTest.

Expand your brand power and attract the attention of industry decision-makers by sponsoring and exhibiting at PowerTest 2020.

Welcome to Chicago

Discover a full week of technical sessions, networking events, and more – all designed to showcase the latest industry developments and foster relationship building. Build downtime into your PowerTest itinerary and indulge in a Chicago style hotdog or deep dish pizza, and explore the rich history and local attractions the windy city has to offer. PowerTest 2020: Learning, energizing, renewing. Focused on learning, connecting, updating, and advancing, PowerTest 2020 will be held in one of the world’s most dynamic cities: Chicago.

Enjoy pre-conference mischief with us at Tommy Gun’s Garage.

In addition to serving up amazing entrees, Tommy Gun's puts on a prohibition-themed, audience-interactive, musical comedy show that you'll never forget. You'll be transported to the 1920s with memorabilia, songs by composers like Cole Porter and George Gershwin, and the performers dancing the Charleston.

Sunday, February 23 | 5:00 PM

PowerTest 2020 Mobile App available soon

Don’t miss a single moment of PowerTest 2020. Download the PowerTest Mobile App and get instant access to the full schedule - right at your fingertips!

Mobilize yourself

• View session abstracts and speaker bios.

• Customize your schedule for the events and sessions you plan to attend.

• Set reminders and manage alerts.

• View Trade Show floor plan map and booth information.

• Message other conference attendees.

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• Complete evaluations to earn CTDs/ CEUs as well as provide feedback, vote for your favorite sessions, booths, and hospitality suites.

Advance your knowledge

Learn from industry leaders about the latest developments in the electrical testing industry. The educational opportunities at PowerTest are detailed and engaging.

47 CTD credits* 4.7 CEU credits* AVAILABLE AVAILABLE

*when attending Megger Best Practices Seminar.

Choosing among 27 sessions across 5 learning tracks allows you to focus on your expertise and interests.

1. Electrical Safety

2. Equipment

3. Relays

4. Transformers

5. Reliability

NETA CTD Credits and CEUs are available for all educational sessions throughout the week.

- Voltage current and power monitoring

- Harmonic detection analysis

- Inrush current analysis

- Energy cost analysis and management

- Power factor analysis and correction

- Power demand and consumption monitoring

- Transient detection and analysis

- Data logging

Emerging Technology Symposium

Monday, February 24

Learn about the newest technology, techniques, and the evolution of the electrical testing industry from a panel of selected experts from the industry.

New Product Forum

Monday, February 24

In sixty minutes, attendees will preview the newest products and services shaping the power systems industry from 30 of the leading equipment manufacturers and service providers.

Panel Sessions

Tuesday, February 25

In panel sessions attendees can learn about electrical safety, emerging technologies, relays, or transformers. Two sessions are available for each panel topic, but could completely differ in content as much of the discussion is driven through audience participation. Please come prepared with some thoughts and questions to engage with the panel experts.

Seminars

Wednesday & Thursday, February 26-27

Two days of in-depth, four hour, interactive seminar presentations offer an opportunity to learn about Relay Troubleshooting, Arc-Flash Workshop, Full Time Partial Discharge Monitoring, Changes to the 2021 NFPA 70E, and much more.

Doble Laboratory Seminar

Friday, February 28

Doble's laboratory expert will present a full day, interactive session that combines theoretical background with practical experience. We will share case studies illustrating common problems found in the field.

Connect with industry peers

From a 1920’s-themed speakeasy to hospitality suites and an awards reception, PowerTest offers a multitude of opportunities to socialize and network with colleagues and industry leaders.

Pre-Conference Event*

Sunday, February 23 | 5:00 PM

Go back in time to the 1920’s with the best and longest running show in Chicago, Tommy Gun’s Garage. This interactive speakeasy features gangsters, flappers, comedy, and dangerous fun. Be ready to hide your hooch for this is prohibitionera party.

Cost is $155 per person.

Hospitality Suites

Monday, February 24 | 6:00 PM

Mingle with fellow guests and a host of leaders at a variety of uniquely themed suites complete with food, drinks, and entertainment.

PowerBash Reception*

Tuesday, February 25 | 7:00 PM

Enjoy an evening of awards and entertainment in the company of hundreds of like-minded industry professionals at the PowerBash Reception.

Cost is $35 per person.

*Please note that pre-registration is required to attend the Preconference Event and PowerBash.

Enhance your exposure

Power up your brand. Attract the attention of high-profile industry decision-makers by sponsoring and exhibiting at PowerTest 2020.

2020 TRADE SHOW

Tuesday, February 25 | 12:00 PM

Create new leads and strengthen existing relationships when you present your products and services at the PowerTest Trade Show, a standalone event, that does not compete with any other sessions. By popular demand, PowerTest 2020 is offering lead capture technology to exhibitors, making lead generation more seamless than ever.

PowerTest Sponsorship

Gain industry exposure when you put your brand in front of hundreds of electrical professionals. PowerTest offers a wide array of sponsorship levels to fit every budget.

Products

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Calibration Services

Two in-house labs provide NIST Traceable calibration.

Asset Management

We manage all of your equipment, including analytic reports on asset fleet, cleaning, repair & calibration.

Protec Connect & Customer Web Portal

Renting & managing electrical test equipment just got a whole lot easier.

Sales & Service

Application support & customer service available 24/7.

Nobody Works Harder For You Than Protec

We understand that you need experienced people to align you with the proper equipment, in the right place at the right time.

To better serve our customers, we offer a large, nationwide rental fleet of electrical test and measurement equipment, with all Protec locations stocked with inventory.

The number one choice for mission critical equipment where time, quality and service are vital.

February 25th Exhibits Conference

Hyatt

2020 TRADE SHOW EXHIBITORS

Photo Credit: Rosen Shingle Creek

To

Megger Best Practices

Sunday, February 23

9:00 AM - 4:00 PM

Megger’s Best Practices Seminars are designed to bring you up to speed on new testing techniques and technology as well as offer the opportunity to engage in technical discussions with our expert engineers. Megger’s world-class Applications Engineers utilize their vast industry knowledge and experience to craft an in-depth program backed by Megger’s expertise in the market. This full-day of quality education includes training related to key industry topics as well as some of the best practices to follow when performing offline electrical testing. Pre-registration is required to attend.

For more information or to register, please visit powertest.org/2020-highlights/educational

PowerDB Users Group

Monday, February 24

12:15 PM - 2:00 PM

Annual User’s Group Meeting open to licensed users of PowerDB Pro Software. Agenda will include presentations by the PowerDB Pro development team as well as utility, industrial and contractor groups discussing how this product is an integral part of their business operations.

Pre-registration is required by contacting PowerDB at (979) 690-7925 ext. 702 or by registering at powerdb.com

COVER STORY

FEATURES

7 President’s Desk

Using Communications to Monitor Power Distribution Systems

An increasing number of facilities are exploring and appreciating the communications capabilities of electrical power equipment. Modern electrical system protection and metering devices measure and calculate a significant amount of digital data, and most of this data can be retrieved via communications, enabling systems to monitor multiple devices in a system-wide manner from a central and/ or remote location. Due to the increased availability of communicating devices and equipment, integrating a basic power monitoring system can be simple and can be accomplished without significant effort or significant additional equipment.

By Ryan McClarnon, Utility Relay Company

44

Scott Blizard, American Electrical Testing Co., LLC NETA President

End-to-End Testing for Line Differential Protection

Sughosh Kuber, Megger

52 Fiber Optic Network Operation, Maintenance, and Restoration

Jim Hayes, Fiber Optic Association

62

R-GOOSE Applications in a Smart Grid

Alex Apostolov, OMICRON electronics Corp. USA

10 The NFPA 70E and NETA

Small Things Mean a Lot

Ron Widup and James R. White, Shermco Industries

15 Relay Column

Functional Testing for Sudden Pressure Relay

Steve Turner, Arizona Public Service Company

20 In the Field

Communications Kicks Off New Column

Don Genutis, Halco Testing Services

26 Tech Quiz

Communications

James R. White, Shermco Industries

28 Safety Corner

Communicating Hazards during the Pre-Job Briefing

Paul Chamberlain, American Electrical Testing Co., LLC INDUSTRY TOPICS

72 Medium-Voltage Asset Failure Investigations

Kelly Higinbotham, University of Connecticut, and William G. Higinbotham, EA Technology LLC

84 A New Way to Test Distribution Automation Schemes

Robert Wang, OMICRON electronics Corp. USA

92

Ensure Effective Acceptance and Maintenance Testing with Quality Reporting and Analysis

Steve Park, Electrical Reliability Services — a Vertiv Company

ADVANCEMENTS IN INDUSTRY

101 Communications Security for Field Testing Organizations

Gowri Rajappan, Doble Engineering Company

SPECIFICATIONS AND STANDARDS 106 ANSI/NETA Standards Update 110 Electrical Maintenance: Canada Update

Kerry Heid, Shermco Industries Canada

NETA Accredited Companies

Advertiser List

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Products

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Calibration Services

Two in-house labs provide NIST Traceable calibration.

Asset Management

We manage all of your equipment, including analytic reports on asset fleet, cleaning, repair & calibration.

Protec Connect & Customer Web Portal

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Sales & Service

Application support & customer service available 24/7.

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#1 Great Lakes Electrical Testing Firm

• Full Member of the InterNational Electrical Testing Association (NETA)

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Electrical Testing & Commissioning

•Acceptance Testing •Preventative and Predictive Maintenance •Technical Support•Protective Relays • Transformers• Switchgear • Breakers • Infrared & Ultrasonic Survey • Cable Locating • VLF & Tan Delta Testing• Partial Discharge• Meters• Grounding• Generator Controls• ATS• UPS• Battery Systems • Motor Control Centers • Switches• Capacitor Banks

Electrical Studies

• Short Circuit/Device Coordination Studies • Arc Flash/Shock Hazard Studies • Harmonic/Power Factor/Transient Studies & Corrections Training

• Electrical Safety & Troubleshooting • NFPA 70E

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EXECUTIVE DIRECTOR: Missy Richard

NETA Officers

PRESIDENT: Scott Blizard, American Electrical Testing Co., Inc.

FIRST VICE PRESIDENT: Lorne Gara, Orbis Engineering Services, Ltd.

SECOND VICE PRESIDENT: Eric Beckman, National Field Services

SECRETARY: Scott Dude, Dude Electrical Testing, LLC

TREASURER: John White, Sigma Six Solutions, Inc.

NETA Board of Directors

Ken Bassett (Potomac Testing, Inc.)

Eric Beckman (National Field Services)

Scott Blizard (American Electrical Testing Co., Inc.)

Jim Cialdea (CE Power Engineered Services, LLC)

Scott Dude (Dude Electrical Testing LLC)

Lorne Gara (Orbis Engineering Field Services, Ltd.)

Dan Hook (Western Electrical Services, Inc.)

David Huffman (Power Systems Testing)

Alan Peterson (Utility Service Corporation)

Chasen Tedder, Hampton Tedder Technical Services

John White (Sigma Six Solutions)

Ron Widup (Shermco Industries)

NETA World Staff

TECHNICAL EDITORS: Roderic L. Hageman, Tim Cotter

ASSISTANT TECHNICAL EDITORS: Jim Cialdea, Dan Hook, Dave Huffman, Bob Sheppard

ASSOCIATE EDITOR: Resa Pickel

MANAGING EDITOR: Carla Kalogeridis

COPY EDITOR: Beverly Sturtevant

ADVERTISING MANAGER: Laura McDonald

DESIGN AND PRODUCTION: Moon Design

NETA Committee Chairs

CONFERENCE: Ron Widup; MEMBERSHIP: Ken Bassett; PROMOTIONS/MARKETING: Scott Blizard; SAFETY: Scott Blizard and Jim White; TECHNICAL: Alan Peterson; TECHNICAL EXAM: Dan Hook; CONTINUING TECHNICAL DEVELOPMENT: David Huffman; TRAINING: Bob Sheppard; FINANCE: John White; NOMINATIONS: Alan Peterson; ALLIANCE PROGRAM: Jim Cialdea; ASSOCIATION DEVELOPMENT: Ken Bassett and John White

© Copyright 2019, NETA

NOTICE AND DISCLAIMER

NETA World is published quarterly by the InterNational Electrical Testing Association. Opinions, views and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees or agents (herein “NETA”).

All technical data in this publication reflects the experience of individuals using specific tools, products, equipment and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA.

NETA MAKES NO ENDORSEMENT, REPRESENTATION OR WARRANTY AS TO ANY OPINION, PRODUCT OR SERVICE REFERENCED OR ADVERTISED IN THIS PUBLICATION. NETA EXPRESSLY DISCLAIMS ANY AND ALL LIABILITY TO ANY CONSUMER, PURCHASER OR ANY OTHER PERSON USING ANY PRODUCT OR SERVICE REFERENCED OR ADVERTISED HEREIN FOR ANY INJURIES OR DAMAGES OF ANY KIND WHATSOEVER, INCLUDING, BUT NOT LIMITED TO ANY CONSEQUENTIAL, PUNITIVE, SPECIAL, INCIDENTAL, DIRECT OR INDIRECT DAMAGES. NETA FURTHER DISCLAIMS ANY AND ALL WARRANTIES, EXPRESS OF IMPLIED, INCLUDING, BUT NOT LIMITED TO, ANY IMPLIED WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE.

ELECTRICAL TESTING SHALL BE PERFORMED ONLY BY TRAINED ELECTRICAL PERSONNEL AND SHALL BE SUPERVISED BY NETA CERTIFIED TECHNICIANS/ LEVEL III OR IV OR BY NICET CERTIFIED TECHNICIANS IN ELECTRICAL TESTING TECHNOLOGY/LEVEL III OR IV. FAILURE TO ADHERE TO ADEQUATE TRAINING, SAFETY REQUIREMENTS, AND APPLICABLE PROCEDURES MAY RESULT IN LOSS OF PRODUCTION, CATASTROPHIC EQUIPMENT FAILURE, SERIOUS INJURY OR DEATH.

WELCOME TO THE 2019 WINTER EDITION OF NETA WORLD

As humans, we are drawn to one another and communicate with each other using a variety of methods. Good and effective communication is an essential tool to achieve productivity and maintain strong and lasting working relationships at all levels of an organization. What every interaction has in common is the need for clear and effective communication.

In this issue of NETA World, we look at the way electrical systems communicate internally with controls, devices, and applications to improve the functionality of the protection, automation, and control systems. Articles in this issue range from R-GOOSE technology on the smart grid to new communication devices for monitoring electrical power distribution systems.

Mark your calendar — PowerTest 2020 is February 24–28, 2020! PowerTest 2020 will take place in one of the world’s most dynamic and popular cities: Chicago, at the Hyatt Regency. The PowerTest Conference will feature a symposium and a separate panel session on emerging technologies. Be sure to check it out. I can tell you the venue and programs for PowerTest 2020 are sure to be outstanding. Register today to assure your spot among the leaders in the electrical testing industry.

Here in the Northeast, winter brings some interesting weather. Be aware of ice, snow, sleet, and rain when traveling the roadways. Leave a little extra room between you and the vehicle in front of you. Be aware of walkways, driveways, and parking lots for black ice. It is the season for trips, slips, and falls.

Coach safe behavior … Living injury free every day!

Scott A. Blizard, President

NETA — InterNational Electrical Testing Association Safety First…No One Gets Hurt!

the industry, that never compromises

As North America’s largest independent electrical testing company, our most important Company core value should come as no surprise: assuring the safety of our people and our customer’s people. First and foremost.

Our service technicians are NETA-certified and trained to comply and understand electrical safety standards and regulations such as OSHA, NFPA 70E, CSA Z462, and other international guidelines. Our entire staff including technicians, engineers, administrators and management is involved and responsible for the safety of our co-workers, our customers, our contractors as well as our friends and families.

Our expertise goes well beyond that of most service companies. From new construction to maintenance services, acceptance testing and commissioning to power studies and rotating machinery service and repair, if it’s in the electrical power system, up and down the line, Shermco does it.

SMALL THINGS MEAN A LOT

RON WIDUP and JAMES R. WHITE, Shermco Industries

One of the most important details in NFPA 70E is its definitions. Many people automatically believe they already know the definition of a word or phrase. This is a mistake that can have negative consequences. The place to start is to read Chapter 1, Article 100 Definitions. Once you have a better understanding of the definitions, the rest of the standard becomes much easier to read and comprehend the intent.

For example, the definition of Electrically Safe Work Condition has seen a lot of attention over the last two revisions. Some additional controversy was created when the definition was [essentially] challenged to mean that the only way to assure compliance was that the equipment had to be replaced, rather than maintained. This caused quite a stir, so the definition was expanded and an information note was added, all intended to make the definition clearer.

In the current 2018 edition, the definition of Electrically Safe Work Condition reads:

Electrically Safe Work Condition. A state in which an electrical conductor or circuit part has been disconnected from energized parts, locked/ tagged in accordance with established standards, tested to verify the absence of voltage, and, if necessary, temporarily grounded for personnel protection.

The proposed revised definition of Electrically Safe Work Condition now reads:

A state in which an electrical conductor or circuit part has been disconnected from energized parts, locked/tagged in accordance with established standards, tested to verify the absence of voltage, and if necessary, temporarily grounded for personnel protection.

Informational Note: An electrically safe work condition is not a procedure; it is a state wherein all hazardous electrical conductors or circuit parts to which a worker might be exposed are maintained in a zero energy state for the purpose of temporarily eliminating electrical hazards for the period of temporary time for which the state is maintained.

The accompanying Informational Note points out that an electrically safe work condition is not a procedure, but a state. Once it becomes

an electrically safe work condition, all hazardous energy is no longer available to cause injury or death. The condition is temporary, which means it is intended to be re-energized (maybe not right away), but for a period of time for which the state is maintained. This should make the meaning of the definition clear to everyone.

Only minor editorial changes were made to a few additional definitions to ensure each definition provided in the standard is as understandable as possible. A good example is the definition of Working On (energized electrical conductors and circuit parts), which now has the proposed added text (shown as underlined) and reads:

Working On (energized electrical conductors and circuit part). Intentionally coming in contact with energized electrical conductors or circuit parts with the hands, feet, or other body parts, with tools, probes, or with test equipment, regardless of the personal protective equipment (PPE) a person is wearing. There are two categories of working on : Diagnostic (testing) is taking readings or measurements of electrical equipment, conductors, or circuit parts with approved test equipment that does not require making any physical change to the electrical equipment, conductors, or circuit parts; repair is any physical alteration of electrical equipment, conductors, or circuit parts (such as making or tightening connections, removing or replacing components, etc.).

THE NFPA 70E AND NETA

Users of 70E are familiar with the concept of two working on conditions:

1. Diagnostic testing using approved test equipment, which includes taking voltage readings or tasks that do not make changes to the electrical equipment, conductors, or circuit parts, and

2. Repairs that involve making physical changes to the equipment, conductors, or circuit parts to get it to work again. The idea is to avoid intentionally coming in contact with the equipment, conductors, or circuit parts.

But remember this: Best practices teach us that if the person doing the repair task has first placed the equipment, conductors, or circuit parts in an electrically safe condition using PPE, they have removed the hazard, so there is no need to mitigate the hazard, since it isn’t there. It’s the best way to go!

The 70E standard required this in Article 110.1, which addresses general requirements for electrical safety-related work practices. There is a new first clause in 110.1 (electrical safety program) identified as Priority, which was previously located in Article 105.4 and is proposed as:

110.1 Electrical Safety Program

(A) Priority. Hazard elimination shall be the first priority in the implementation of safetyrelated work practices.

Informational Note No. 1: Elimination is the risk control method listed first in the hierarchy of risk control identified in 100.5(H)(3). See Annex F for examples of hazard elimination.

Informational Note No. 2: An electrically safe work condition is a state wherein all hazardous electrical conductors or circuit parts to which a worker might be exposed are placed and maintained in a de-energized state, for the purpose of temporarily eliminating electrical hazards. See Article 120 for requirements to establish an electrically safe work

condition for the period of time for which the state is maintained. See Informative Annex F for information regarding the hierarchy of risk control and hazard elimination.

This is another example where small things can make a big difference. In this section, hazard elimination is the first priority of safety-related work practices. We should always keep this in mind, as quitting time, personal issues, overtime, fatigue, and countless other items could distract us from keeping elimination as the first priority.

The second informational note also speaks to an electrically safe work condition and refers the 70E user to Informative Annex F. Informative annexes are not mandatory requirements, but contain related and very useful information that should be reviewed and incorporated into work plans and safe work practices. If you haven’t been carefully studying the informative annex material in the 70E, you really should — it’s a great resource for additional knowledge and best practices.

CONCLUSION

The upcoming new (2021) edition of NFPA 70E will have many changes — some very important and some just editorial.

The structure of the document, with shading that highlights any new or revised text, makes it simple to see what has changed, how it has changed, and what has been added. We recommend studying the definitions, Section 130, as well as all of Chapter 1 and Chapter 2. Add in the informative annexes, and there is quite a bit to digest. But this is not like eating distasteful food; it is more like dessert. It should be taken in, reviewed, and taken in again. Every time you do, you will likely find something new that helps us all in our quest for electrical safety perfection.

Be careful out there, and always test before touch!

Ron Widup and Jim White are NETA’s representatives to NFPA Technical Committee 70E, Electrical Safety Requirements for Employee Workplaces. Both gentlemen are employed by Shermco Industries in Dallas, Texas, a NETA Accredited Company.

Ron Widup, Shermco Industries Vice Chairman and Senior Advisor, Technical Services, has been with Shermco since 1983, and currently serves on the company’s board of directors. He is a member of Technical Committee on NFPA 70E, Electrical Safety in the Workplace; a Principal Member of National Electrical Code (NFPA 70) Code Panel 11; a Principal Member of the Technical Committee on NFPA 790, Standard for Competency of Third-Party Evaluation Bodies; a Principal Member of the Technical Committee on NFPA 791, Recommended Practice and Procedures for Unlabeled Electrical Equipment Evaluation; a member of the Technical Committee on NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, and Vice Chair for IEEE Std. 3007.3, Recommended Practice for Electrical Safety in Industrial and Commercial Power Systems. Ron also serves on NETA’s board of directors and Standards Review Council. He is a NETA Certified Level 4 Senior Test Technician, a State of Texas Journeyman Electrician, an IEEE Standards Association member, an Inspector Member of the International Association of Electrical Inspectors, and an NFPA Certified Electrical Safety Compliance Professional (CESCP).

James (Jim) R. White, Vice President of Training Services, has worked for Shermco Industries since 2001. He is a NFPA Certified Electrical Safety Compliance Professional and a NETA Level 4 Senior Technician. Jim is NETA’s principal member on NFPA Technical Committee NFPA 70E®, Electrical Safety in the Workplace; NETA’s principal representative on National Electrical Code® Code-Making Panel (CMP) 13; and represents NETA on ASTM International Technical Committee F18, Electrical Protective Equipment for Workers. Jim is Shermco Industries’ principal member on NFPA Technical Committee for NFPA 70B, Recommended Practice for Electrical Equipment Maintenance and represents AWEA on the ANSI/ISEA Standard 203, Secondary Single-Use Flame Resistant Protective Clothing for Use Over Primary Flame Resistant Protective Clothing. An IEEE Senior Member, Jim was Chairman of the IEEE Electrical Safety Workshop in 2008 and is currently Vice Chair for the IEEE IAS/PCIC Safety Subcommittee.

FUNCTIONAL TESTING FOR A SUDDEN PRESSURE RELAY

BY STEVE TURNER, Arizona Public Service Company

This article presents a functional test procedure for a sudden pressure relay. The sudden pressure relay trips when it detects a sudden increase in gas pressure due to a fault internal to the transformer tank. Recommendations for mounting the relay and a procedure for post-analysis following field trips are also provided.

The sudden pressure relay (Figure 1) offers three main functions:

• Pressure sensing bellows

• Pressure equalizing orifice

• Microswitch

The bellows expands when an internal fault causes arcing, which operates the microswitch. The orifice is a plug with a very small hole that equalizes pressure inside the relay during slow changes due to transformer loading and ambient temperature changes.

Note: The sudden pressure relay can only be applied to transformers with a gas space above the windings inside the tank.

Figure 1: Sudden Pressure Relay

RELAY COLUMN

SUDDEN PRESSURE RELAY PROTECTION CHARACTERISTICS

Figure 2A and Figure 2B illustrate the operating time to trip as a function of rate of pressure rise (psi/sec) and the time required to equalize the pressures between the transformer and sudden pressure relay respectively.

SUDDEN PRESSURE RELAY SCHEMATIC

Typically, the relay includes a seal-in relay and a reset switch. The seal-in relay has alarm and trip contacts and is energized by the microswitch. It closes an alarm contact output and trips. It then seals itself closed until manually reset via the reset switch.

MOUNTING RECOMMENDATIONS

Mount the relay above the maximum oil level in the gas space above the windings inside the tank. The relay mounting should be rigid and well-braced to prevent false operation due to any vibration, which can occur during close-in, high-magnitude through faults.

Figure 4 shows a sudden pressure relay mounted to a transformer tank.

Figure 2A: Operating Characteristic

Figure 2B: Recovery Time

Figure 3: Schematic Diagram

RELAY COLUMN

FUNCTIONAL TEST PROCEDURE

1. Disconnect the sudden pressure relay supply voltage.

2. Record the transformer operating pressure. The pressure must be greater than 3/4 psi for the following tests.

3. Connect a circuit tester across terminals 1 and 2 on the terminal strip (B and C on Figure 3).

4. Remove the test plug from the relay case. The relay microswitch will operate and the circuit tester will indicate a closed contact output.

5. Close the test plug and record the time in seconds required for these same contacts to open.

6. Using the recovery time recorded in #5 and the pressure recorded in #2 as coordinates on Figure 2B: Recovery Time, verify that the point is within the allowed operating area.

7. Disconnect any external trip or alarm circuit.

8. Check that the reset switch is closed.

9. Reconnect the sudden pressure relay supply voltage.

10. Connect the circuit tester across terminals 7 and 8.

11. Remove the test plug. The relay will operate and the circuit tester will indicate an open circuit.

12. Replace the test plug and allow sufficient time (see #5) for the sudden pressure relay to equalize.

13. Operate the reset switch. The contact output across terminals 7 and 8 should fall closed. This check should be performed for each of the alarm and trip circuits.

14. Reconnect the trip or alarm circuits following the correct operation of the relay.

Note: This test procedure is for a specific type of sudden pressure relay, so some steps may vary or not be necessary depending upon the actual type of relay that is being tested.

TESTING AFTER FIELD OPERATION

After a breaker trip resulting from operation of the sudden pressure relay, the transformer and the relay panel must be tested before it is re-energized to prevent possible damage to the coils and insulation.

Three checks are recommended prior to reenergizing the transformer:

1. Functionally test the sudden pressure relay to determine if it is in proper operating condition.

2. Conduct suitable tests and observations to verify that the transformer is undamaged and suitable for re-energization. Contact the transformer manufacturer if in doubt.

3. Contact the transformer manufacturer for any additional instructions concerning maintenance and inspection procedures.

REFERENCE

ABB. “Sudden Pressure Relay Technical Guide.” 1ZUA566ref-210–rev.2 September 8, 2009. Available at www.library.e.abb.com/ public/7ecd37d3c79ef688c1256fa2007003cc/ 1ZUA5663-210_r2_Sudden%20Pressure% 20Relay.pdf.

Steve Turner is in charge of system protection for the fossil generation department at Arizona Public Service Company in Phoenix. After working with Beckwith Electric Company, Inc. for 10 years, Steve spent two years as a consultant in San Diego. His previous experience includes positions as an Application Engineer at GEC Alstom and in the international market for SEL focusing on transmission line protection applications. Steve also worked for Duke Energy (formerly Progress Energy), where he developed the first patent for double-ended fault location on overhead high-voltage transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has BSEE and MSEE degrees from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and a member of the IEEE PSRC.

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COMMUNICATIONS KICKS OFF NEW COLUMN

BY DON GENUTIS, Halco Testing Services

It’s very exciting to kick off the first “In the Field” column. Consistent with this NETA World edition’s theme, an article on communications seemed fitting. As I write this, I realize I assumed the “communications” theme was related to interpersonal communications, but I didn’t communicate well enough to clarify that the theme is probably related to equipment communications such as electronic communication protocols using for metering networks or SCADA. Oh well, I’m just going to push forward and keep writing. Plus technician communications skills have been ignored for much too long.

I used the term interpersonal communication as I understood it, but a quick internet search to ensure I’m not way off provided a very good definition that ties in perfectly to my intended article discussion points. See the following from www.skillsyouneed.com

“Interpersonal communication is the process by which people exchange information, feelings, and meaning through verbal and non-verbal messages: It is face-to-face communication. Interpersonal communication is not just about what is actually said — the language used — but how it is said and the non-verbal messages sent through tone of voice, facial expressions, gestures, and body language.”

“THE MORE YOU SAY THE LESS PEOPLE REMEMBER.”

François Fénelon

TYPES OF COMMUNICATIONS

How do we communicate? Most ways I can think of are listed below.

Verbal: Face-to-Face, Phone, Video

Face-to-face is the most effective method. I think that’s because we can look at others, have their full attention (unless they have a cell phone in their hands), and see their facial expressions and body language. Video might then be second, but this platform’s potential hasn’t been realized.

Phone communications are common and can explain a more complex issue easier than its sometimes-laborious written counterpart. Phone communications can also open the door to getting both parties on the same page toward finding common ground, such as in negotiations, and it often is easier than email negotiations that can quickly become confrontational with finger-pointing.

Written: Letter, Email, Text, Fax, Sign, Label

Letters only contain bad news — bills and lawsuits — but can make an impact on the recipient. The fax is now almost extinct with the advent of email. Everyone seems to love

email, and it has made communication much easier, plus we can now mostly ignore these communications if we want to. We can respond when time allows based on urgency, which in some cases is not at all. Email communications are so effective that advertising campaigns cannot exist without them. However, this mode of communications can be abused as in the case of spam, and email wording can be misconstrued and result in unnecessary hard feelings.

One of the best written communication tools for the technician, next to the test data sheet, is the job hazard assessment (JHA) form, as it makes us carefully think about what we are doing and how to do it safely. It also requires us

to sign the document, which adds an additional element of importance and thought to ensuring the task we are about to embark upon is performed safely.

Body Language, Sign Language

The study and interpretation of body language is a fascinating subject. It has been said these observations can provide insight into what a person is really thinking. Instead of studying this technique, most of us can just get a feel about how someone’s body language provides clues to their actual inner thoughts.

Sign language, which is primarily a means of communications for the hearing impaired, has evolved to help many people communicate. For example, the signals communicated among crane operating crews are another form of effective sign language communications, but we may also have witnessed a less-effective use of sign language by a traffic cop thrusting his arms in various directions. Their efforts sometimes seem to create more congestion and confusion than would otherwise be expected.

COMMUNICATIONS FOR TECHNICIANS

Communication is extremely important for the test technician. Our lives are on the line, and miscommunication can lead to an extremely dangerous situation. Communications must be clear and concise. We must be quick to state the answer and only provide brief clarification — not tell a story.

We must also realize that communications are a two-way street. If not precisely sure what you are being told, just ask (verify). The cartoon displays — in a humorous way — how a simple verbal miscommunication could result in a mishap.

MINI CASE STUDIES

• A utility outage occurred at a major downtown building. Communication with the utility was made between our foreman

through the building engineer. We disliked this situation because the utility was remote, and they did not allow us to apply our lock to their equipment. Near the end of the outage, a miscommunication between the foreman and the utility caused the line side of the main to be energized. Although an incident did not occur, this miscommunication could have easily resulted in injury or death. It was a surprise we won’t forget.

• A similar incident occurred while performing an acceptance ground fault interrupter (GFI) test on a switchboard at a large retail store. While setting up for the test, the foreman went outside to the utility personnel who were working on the pad-mount transformer feeding the store’s service entrance. Although communication seemed to be clear, the utility surprisingly energized the circuit moments after clearing the safety grounds. Did we tell the wrong man? He didn’t indicate he wasn’t the correct person to inform. Did he simply forget?

• I witnessed two instances where people were accidently locked in an elevator for hours due to miscommunication. A technician was locked in an elevator after the utility performed a maintenance disconnect, even though the foreman told the utility to tell us when they were ready BEFORE shutting down, not after. In a second event, a building engineer was locked in an elevator under similar circumstances. He was confident the elevator circuit would be on the automation transfer switch and it should have been.

• Troubleshooting activities can often lead to confusion and miscommunication. In many cases, one must be a detective and keep prying to understand the critical events related to the failure to piece together the puzzle.

• A similar “trust but verify” troubleshooting situation occurred where two competent independent testing teams were thumping the wrong faulted medium-voltage circuit for a couple of days before dismissing the site contact’s incorrect recollection and the incorrect single line drawings and starting the troubleshooting process all over from the beginning.

• Another similar situation occurred — not once but twice — when the responsible cable splicing team conducting the circuit continuity, phase identification, and labeling tasks made labeling errors that caused the testing firm to VLF the wrong circuit. Did they just skip this task because they didn’t understand the importance of the task? Were they untrained to perform the task? Did they merely get confused when applying the label?

• I once texted our project manager, “do you read?” to ensure he got my message. The next day, he seemed upset until I learned he thought I meant “can’t you read” when I actually meant “do you read me?” to have him verify he got my message. We both got a laugh out of it in the end.

• Project specification wording can often lead to controversy. Words with similar meanings can be misinterpreted. “Test” vs. “Set.” “Set” vs. “Calibrate.” “Verify settings” vs. “Set.” Has anyone ever got been caught up in SEL programming vs. setting? That could be an article in itself.

• Even written communication can be difficult in an examination setting. Anyone taking the NETA exam or any other exam can be faced with determining exactly what the question writer is trying to convey. This question seems too easy. Is this a trick question? Should I read this question over again?

• Finally, just today, we sent a colleague to the store to pick up some simple breakfast items for a small office celebration. The list included juices, breakfast sandwiches, pastries, and muffins. The person providing the instructions envisioned breakfast muffins such as blueberry or banana. He was surprised to be handed a bag of English muffins. The end result of this miscommunication was a laugh or two and another trip to the store.

FINAL WORDS

Although we can thankfully be amused by some of these events, we cannot discount the

possibility that disaster could easily have been the outcome of these “In the Field” situations, except for the muffins, of course! I actually like English muffins.

The majority of these events occurred because of miscommunications, assumptions, failure to verify, and even forgetfulness. The challenge facing the technician is to avoid these events. Safety procedures such as lock out/tag out (LOTO) and JHA are extremely important and can help prevent major events from occurring. Understanding the entire task process and the various interfaces with other equipment and other personnel along with concise communications will also help greatly.

So long for now. I really hope we get some good war-story articles from our technicians out there.

REFERENCES

Don A. Genutis. “No Outage Corner: First Rule of Troubleshooting: Trust but Verify.” NETA World, Winter 2016.

Don A. Genutis. “No Outage Corner: What’s in a Sign?” NETA World, Winter 2017.

Don A. Genutis presently serves as President of Halco Testing Services, Inc., a NETA Accredited Company with offices in Los Angeles and Houston. He has held various principal positions during his 35plus year career in the electrical testing field, primarily focused on advancing no-outage testing techniques for the last 20 years, with emphasis on cable and switchgear on-line partial discharge testing techniques. Early in his career, Don acquired and operated the former Westinghouse East Pittsburgh Insulation Research Laboratory, where he gained valuable experience in the understanding of insulation material performance. Don holds a BS in electrical engineering from Carnegie Mellon University and is a NETA Certified Technician. Don has authored 50 technical articles for NETA World and has been featured in EC&M and Uptime magazines. Don’s work is summarized in his book, Partial Discharge & Other NoOutage Testing Methods, published in 2019.

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James (Jim) R. White, Vice President of Training Services, has worked for Shermco Industries Inc. since 2001. He is a NFPA Certified Electrical Safety Compliance Professional and a NETA Level 4 Senior Technician. Jim is NETA’s principal member on NFPA Technical Committee NFPA 70E®, Electrical Safety in the Workplace®, NETA’s principal representative on National Electrical Code® Code-Making Panel (CMP) 13, and represents NETA on ASTM International Technical Committee F18, Electrical Protective Equipment for Workers. Jim is Shermco Industries’ principal member on NFPA Technical Committee for NFPA 70B, Recommended Practice for Electrical Equipment Maintenance and represents AWEA on the ANSI/ISEA Standard 203 Secondary Single-Use Flame Resistant Protective Clothing for Use Over Primary Flame Resistant Protective Clothing. An IEEE Senior Member, Jim received the IEEE/IAS/PCIC Electrical Safety Excellence Award in 2011 and NETA’s Outstanding Achievement Award in 2013. Jim was Chairman of the IEEE Electrical Safety Workshop in 2008 and is currently Vice-Chair for the IEEE IAS/ PCIC Safety Subcommittee.

COMMUNICATIONS

BY JAMES R. WHITE, Shermco Industries

This edition of the NETA World is on communications — a very broad, but necessary subject. This Tech Quiz looks at three types of communication: digital substations, three-way communication, and hand signals for heavy lifting and cranes. Every NETA technician should have knowledge of these.

1. Digital substations are based on which IEC standard?

a. IEC 61800

b. IEC 47855

c. IEC 60947

d. IEC 61850

2. Digital substations eliminate:

a. Copper wire connections

b. Personal interaction with the equipment

c. Copper bus between breakers and other devices

d. CTs and PTs to save space and increase signals

See answers on page 114.

3. Three-way communication first originated in:

a. Nuclear industry

b. Military

c. Airline industry

d. NETA

4. Hand signals are important every time we use a machine to lift or move an object. Which hand signal should be obeyed by a crane operator regardless of who gives it?

a. Hoist

b. Lower

c. Stop

d. Time for a break

No. 128

COMMUNICATING HAZARDS DURING THE PRE-JOB BRIEFING

BY PAUL CHAMBERLAIN, American Electrical Testing Co., LLC

Protection from hazards always begins with proper prior planning. An important aid to correctly and thoroughly planning a job includes using a tool known throughout the industry as a pre-job briefing, commonly called a PJB. This tool is called a tailboard or tailboard meeting in construction parlance, but no matter what it is called, PJBs are all designed to do the same thing: Identify relevant hazards on the job site or while performing a task and communicate those hazards to all persons on the job who might be affected by those hazards.

Communication is key. PJBs should be a give-and-take discussion. All members of the workgroup should participate, whether they are fellow employees or not. If they are affected by your work, or their work affects yours, they should participate.

The updated requirement in NFPA 70E-2018, Standard for Electrical Safety in the Workplace, Article 110.1(I) states the following regarding a pre-job briefing:

Before starting each job that involves exposure to electrical hazards, the employee in charge shall complete a job safety plan and conduct a job briefing with the employees involved.

(1) Job Safety Planning. The job safety plan shall be in accordance with the following:

(1) Be completed by a qualified person

(2) Be documented

(3) Include the following information:

a. A description of the job and the individual tasks

b. Identification of the electrical hazards associated with each task

c. A shock risk assessment in accordance with 130.4 for tasks involving a shock hazard

d. An arc flash risk assessment in accordance with 130.5 for tasks involving an arc flash hazard

e. Work procedures involved, special precautions, and energy source controls

(2) Job Briefing. The job briefing shall cover the job safety plan and the information on the energized electrical work permit, if a permit is required.

(3) Change in Scope. Additional job safety planning and job briefings shall be held if changes occur during the course of the work that might affect the safety of employees.

NFPA goes so far as to include a sample Job Briefing and Planning Checklist under Informative Annex I (Figure 1). This specific form is not required, but a similar form should be created to aid employees in the identification and mitigation of potential hazards.

The Occupational Safety and Health Administration (OSHA) also requires a PJB under 29 CFR 1910.269, Electric Power Generation, Transmission, and Distribution:

• 269(c)(1)(i): In assigning an employee or a group of employees to perform a job, the employer shall provide the employee in charge of the job with all available information that relates to the determination of existing characteristics and conditions.

• 1910.269(c)(1)(ii): The employer shall ensure that the employee in charge conducts a job briefing that meets paragraphs (c)(2), (c)(3), and (c)(4) of this section with the employees involved before they start each job.

• OSHA also requires the PJB to cover “hazards associated with the job, work procedures involved, special precautions, energy-source controls, and personal protective equipment requirements.”

Additional PJBs may be required during the day if the task or workplace location change significantly enough to change the hazards involved in performing the work. The more hazards present to the task performers, the more detailed the PJB must be. More extensive PJBs may need to be conducted for inexperienced employees. The only time a PJB is NOT required is if that employee will be working alone:

OSHA 1910.269(C)(5): However, the employer shall ensure that the tasks to be performed are planned as if a briefing were required.

OSHA’s website, under eTools, suggests using a checklist to facilitate the PJB:

Keeping a written record of job briefings is not specifically covered by the standard, but it is

Identify

The hazards

The voltage levels involved

Skills Required

Any “foreign” (secondar y source) voltage source

Any unusual work conditions

Ask

Can the equipment be deenergized?

Are backfeeds of the circuits to be worked on possible?

Check

Job plans

Single-line diagrams and vendor prints

Status board

Information on plant and vendor resources is up to date.

Know

What is the job?

Who else needs to know — Communicate!

Think

About the unexpected event… What if?

Lock — Tag — Test — Try Test for voltage — FIRST. Use the right tools and equipment, including PPE.

Prepare for an emergency

Is the standby person CPR/AED trained?

Is the required emergency equipment available? Where is it?

Where is the nearest telephone?

Where is the fire alarm? Is confined space rescue available?

What is the exact work location?

SAFETY CORNER

Number of people needed to do the job

Shock protection boundaries

Available incident energy

Potential for arc flash (conduct an arc flash risk assessment)

Arc flash protection boundar y

Is an energized electrical work permit required?

Is a standby person required?

Is the equipment properly installed and maintained?

Safety procedures

Vendor information

Individuals are familiar with the facility.

Who is in charge?

Install and remove temporar y protective grounding equipment. Install barriers and barricades. What else…?

How is the equipment shut of f in an emergency?

Are the emergency telephone numbers known?

Where is the fire extinguisher? Are radio communications available?

Is an AED available?

a best practice to do so. A written checklist can include the hazards, procedures, precautions, and PPE requirements associated with a job, as well as a column for employee signatures indicating they are knowledgeable about job hazards and safety procedures. Such documentation can help ensure that proper briefings are held at the right

Figure 1: Sample Job Briefing and Planning Checklist

SAFETY CORNER

times (for example, beginning of a shift) and that everyone has been informed. For an example checklist, see the “Job Briefing and Planning Checklist” in Annex I of the National Fire Protection Association’s NFPA 70E, Standard for Electrical Safety in the Workplace.

As can be seen in this quote, even OSHA refers back to the sample PJB in NFPA 70E.

Many different versions and styles of PJBs are used by utilities, large manufacturers, and individual testing companies. All of them are designed to do one thing, and they do it fairly well: PJBs aid task performer(s) in identifying and minimizing risks associated with the hazards of doing the task. Some PJBs focus strongly on physical hazards, others focus on task specific procedures, and some help identify human error traps. Since a PJB is designed to be a quick, simple-to-use tool for the task performer, it is difficult to develop a form that encapsulates all of those needs. An employer should be able to identify which hazards within the work are greatest or are a more pressing need to address with the workforce and develop a PJB adequate to identify those hazards.

Every PJB should identify the means to prevent the inadvertent or unexpected release of electrical energy. Since that is one of the greater and most prevalent hazards that exist within the testing industry, the PFJ should identify how it will controlled via means including individual lock out/tag out, switching and tagging, liveline clearances, and/or the use of grounding. It is also wise to allow space on the form for the performer to indicate lock or tag or ground locations to ensure proper removal when the work is completed.

Address and indicate the limited, restricted, and arc flash boundaries on the form. This makes it easier for performers to advise visitors to the work location of the various approach distances. Additionally, the hazard/risk category level or PPE category level and any additional PPE required to complete the task should be indicated on the form.

Th e person-in-charge (PIC) who fi lls out a PJB form should review all hazards with the task performer(s) and give them ample opportunity to ask questions. A PJB should be a give-and-take discussion, not a dictation. Th e PJB review should be conducted with ALL personnel who could be aff ected by task performance or by anyone else whose work could impact the task. Th is includes contractors, subcontractors, and peripheral workers on the jobsite. Once the review is complete, all persons attending the PJB review should indicate as such in some way. It may be as simple as printing their name on the PJB itself, or the PJB may have a separate sign-in sheet. If the task or the job location changes signifi cantly, a new PJB or review and amendment of the original PJB form may be necessary. Should a visitor arrive on-site, they should immediately be prevented from encroaching upon the work area, and the PJB should be reviewed to apprise them of the potential hazards on the jobsite.

CONCLUSION

Identifying and mitigating potential job hazards is important to prevent possible injuries or accidents. It is up to the employer to provide an adequate means to identify and address those hazards. A PJB form is required in most cases, and it is an easy and effective means to identify hazards. Th e employer should ensure the PJB is adequate for the tasks employees will perform, and employees should USE the form to aid in preventing potential injuries. An employee who has suggestions on improving the form should voice those suggestions to the employer. After all, it is the employee’s form to use.

Paul Chamberlain has been the Safety Manager for American Electrical Testing Co., LLC since 2009. He has been in the safety field for the past 21 years, working for various companies and in various industries. He received a Bachelor of Science in safety and environmental protection from Massachusetts Maritime Academy.

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USING COMMUNICATIONS TO MONITOR POWER DISTRIBUTION SYSTEMS

BY RYAN M c CLARNON, Utility Relay Company

An increasing number of facilities are exploring and appreciating the communications capabilities of electrical power equipment. Modern electrical system protection and metering devices measure and calculate a signi cant amount of digital data, and most of this data can be retrieved via communications. Due to the availability of these devices and data, systems can monitor multiple devices in a system-wide manner from a central and/or remote location. For the purpose of this article, these systems are referred to as power monitoring systems. Power monitoring systems are becoming easier to establish, including integration into existing equipment not originally equipped with communications.

is article provides a basic overview of power monitoring systems and outline one example solution. e reference point is a basic monitoring

system for a low-voltage (e.g., 480V) system. However, many of the concepts and principles are applicable regardless of system voltage.

POWER MONITORING SYSTEM BASICS

A power monitoring system usually o ers one or more of the following features:

• Monitor multiple devices or entire systems from one location

• Monitor metered or calculated data (e.g., current, voltage, power, energy)

• Monitor events and alarms

• View system con guration or status

• Control system devices, con gurations, and equipment

Power and Energy Monitoring

Power monitoring systems often provide power and energy information, hence the name. is information can be used to monitor and analyze use, e ciency, historical trends, peak usage, energy/cost allocation, cost control, performance, etc. For example, a facility may have a utility billing structure that incentivizes maintaining power factor above or peak demand below certain thresholds. ese metrics can be monitored, and in some scenarios, the system could even provide alarms or noti cations to pre-warn that values are approaching the threshold.

Overall System Monitoring

A typical power monitoring system can centrally monitor many devices or the entire system from one location. is allows systemwide monitoring of the following:

• Events and Alarms. Remotely monitoring multiple devices or an entire system from one location often translates to faster response time.

• Electrical Service Reliability and Continuity (Uptime). Operations sta can view information such as breaker positions and system voltages in a single snapshot and assess overall status. Figure 1 shows low-voltage circuit breaker data

displayed in a power monitoring system human machine interface (HMI). In this example, current, voltage, power, energy, and breaker position (red = closed) information are all based on communications data obtained from the low-voltage circuit breaker trip unit. e HMI also displays breaker and load identi cation.

Figure 1: Low-Voltage Circuit Breaker Data in a Power Monitoring System HMI

• Power Quality. Power factor and system voltages can be monitored. Advanced systems can also monitor items such as harmonics.

• Verification of Protective Device Settings. Equipment, devices, and settings can be frequently changed and interchanged. Device settings can be veri ed to ensure proper protection and to avoid accidental nuisance trips.

Safety

It is di cult to put a price tag on this simple bene t. Having the capability to monitor and/ or operate devices without exposing personnel to equipment hazards such as shock or arc ash is signi cant.

Asset Management and Maintenance

Power distribution equipment communications can offer valuable information about the equipment itself and/or the load or process equipment that it feeds. is information can be used to track asset performance, loading, operating conditions, predictive maintenance, etc.

Control

Some equipment can be controlled or operated via communications. At a basic level, this capability o ers safety and operational bene ts. Some more advanced systems utilize this for control schemes or protection schemes.

Troubleshoot and Diagnose

Valuable information such as protection target information, date/time, currents, voltages, and waveforms can play a key role in root-cause analysis of power system events and disturbances. Figure 2 shows current waveforms displayed on a remote HMI using communications data from a low-voltage circuit breaker trip unit. is example shows two waveform captures. e top waveform capture shows three-phase currents from a breaker in which the Phase B (red waveform) current transformer wires were discovered to be mistakenly reversed during installation. e

reversed wires would result in incorrect ground fault current calculations — and a possible trip depending on settings and phase current magnitude — and incorrect power calculations. e bottom waveform capture shows the same breaker after the Phase B current transformer wiring mistake was corrected.

WHAT IS A COMMUNICATION PROTOCOL?

A communication protocol is a system of rules that allow two or more devices to transmit and receive information with each other. Modern-day low-voltage circuit breaker trip units commonly utilize the MODBUS communications protocol, which has become an industry standard protocol for connecting industrial electronic devices.

Legacy Protocols

When considering existing systems, it is important to understand that multiple communications protocols cannot successfully coexist on the same local RS-485 network. Legacy OEM trip unit proprietary protocols include Commnet and INCOM. ese trip units typically cannot be placed on the same local RS-485 network as MODBUS RTU devices. However, converters are available in some applications.

Figure 2: Waveforms on a Remote HMI Using Communications Data from a 480V Trip Unit

HOW DOES IT WORK?

A power monitoring system is made up of master equipment, devices, software and drivers, monitoring devices, and network equipment. The following explanation generally applies to most communication systems, but includes some references to RS-485 modbus serial communications, since it is common in low-voltage switchgear communications.

2. A gateway including pre-loaded software and drivers is directly connected to the devices. The gateway can be accessed by computers over Ethernet to display the system information.

Software, Firmware, Drivers

Typically, master equipment requests and obtains communications data from multiple devices. The data is interpreted and can be displayed on HMIs. Low-voltage circuit breaker trip units typically utilize RS-485 (serial) communications networks (twisted shielded pair, daisy-chained).

Products such as trip units and power meters are the devices, and the network is wired to a master device that interprets the data. Each device must be programmed with a unique address to allow the master to identify each device correctly.

Master equipment must be capable of the same communications protocol (language) as the devices.

Master Equipment

Master equipment collects and/or displays the system information on some form of human machine (HMI) or graphical user interface (GUI). This equipment exists in many forms.

Typical master equipment examples include computers, servers, displays, gateways, etc. More complex and elaborate systems may utilize server equipment, gateways, and computers with customized software. However, some turnkey solutions are available, which are more straightforward to install and set up. Two turnkey solution examples are as follows:

1. An HMI computer including preloaded software and drivers is directly connected to the devices. The same computer is used to display the system information.

Master equipment must have software or firmware and drivers, which allow it to interpret the communications information it receives back from devices such as trip units.

Master equipment must have a driver for each device type it is connected to. This driver allows the master to know how to request and interpret specific data from each particular device type. Unfortunately, each device type organizes the communications data differently. Each device type has a published register map that documents each communication register number and the corresponding name for the data in that register. For example, a trip unit manufactured by Brand XYZ utilizes Register 7042 for current Phase A, whereas a power meter manufactured by Brand ABC utilizes Register 188. In this scenario, the master equipment needs a driver for both of these device types to allow it to properly request current Phase A.

In addition, master equipment often includes software or firmware that allows display of the communications information. This interface is often designed to allow the user or operator to view information from multiple devices, ideally in a meaningful, graphical representation. Some interfaces allow viewing multiple devices simultaneously; others only allow viewing information from one device at a time. Many present-day systems utilize Windows PCs with custom software.

Monitoring Devices

Monitoring devices are typically the equipment that measures and/or calculates the data. In the case of power distribution, these devices are often trip units, power meters, or protective relays.

When equipped with communications capabilities, most or all of the metered and calculated data available in the device can be retrieved via communications. In most applications, each device must be configured or programmed with its own unique address, which allows for device identification. This is true for RS-485 MODBUS communications. Each device typically has configuration settings, for example:

to device). Since low-voltage power circuit breakers utilize draw-out construction, RS-485 wires must be routed through a connector that is either automatically or manually connected/ disconnected when the breaker is racked in/ out.

INTEGRATING A POWER MONITORING SYSTEM INTO EXISTING EQUIPMENT

• Baud Rate: Speed

• Parity and Stop Bits: Standard configuration settings to facilitate error detection that must match master equipment settings.

• Reply Delay: Setting to allow devices to process the current request before the master sends a new request

Network Wiring, Cabling, Equipment

Presently, most power monitoring systems utilize wired networks. Low-voltage trip units commonly use RS-485 networks (twistedshielded pair cable daisy-chained from device

Constructing a power monitoring system can be involved and can require specialty staff or communications experts. As devices become more technically advanced, power monitoring systems are also becoming more advanced and complex. However, due to the increased availability of communicating devices, integrating a basic power monitoring system can be simple, and can be accomplished without significant effort or significant additional equipment.

Figure 3 depicts an example of establishing a basic 480V monitoring system using thirdparty retrofit trip units and an industrial HMI computer. The original switchgear and breakers were not equipped with communications

Figure 3: Adding Communications and Monitoring to Existing 480V System

capabilities. Note that this system architecture leverages modern circuit breaker trip units, which can be installed on almost any existing power circuit breaker. This allows the addition of communications to occur in conjunction with breaker maintenance or upgrades. Other than the industrial HMI, no additional dedicated communications products are needed.

• Industrial HMI computer with no moving parts

• Metering, waveforms, graphics

• Pre-installed software and drivers

• Wall-mount in electrical room or control room

Example System-View Screens, Information, and Functionality:

Example System Components and Devices

• Trip units capable of MODBUS communications

• Industrial HMI computer with serial port capable of RS-485 connection

Example System Requirements and Installation Items

• Trip units on low-voltage circuit breakers must have communications capability if voltage, power, and energy features are desired.

• Install RS-485 network (twisted-shielded pair cable, daisy-chained from trip unit to trip unit) in switchgear and on breakers.

• Set each trip unit with a unique address.

• Configure one-line diagram view and HMI settings.

• Install HMI computer in electrical room or control room.

• In this example, software and drivers were included and pre-installed in the manufacturer’s turnkey product. In some scenarios, PC equipment, software selection, and installation may be separate.

Example System Features and Capabilities

• Field-configurable electronic one-line diagram

• Designed specifically to communicate with low-voltage trip units

• System overview of information from multiple devices at a time

• Breaker positions

• Metered values

• Alarms and status

Example Breaker-View Screens, Information, and Actions:

• View waveforms

• View breaker trip history including waveforms

• View breaker settings

• View real-time breaker readings

• View time-current curves

• Execute remote breaker trip (requires enabled security code and local permissive setting)

• View breaker test data

• Acknowledge and reset alarms

ADVANCED FEATURES AND POSSIBILITIES

In addition to the features discussed in this article, power distribution communications systems can off er many advanced features. Some examples are listed below:

• Protection Schemes. High-speed communications between devices allows for many possibilities, including simple and complex protection schemes.

• Smart Predictive Maintenance. With the increase in available data, additional analysis is possible. For some equipment and systems, even a slight increase in electrical loading or energy consumption can be used to identify whether service or maintenance is necessary.

• Wireless. Wireless communications is becoming a more practical and acceptable option. Improvements in capabilities, reliability, and security will continue to make wireless communications an increasingly attractive method.

TESTING AND TROUBLESHOOTING

Although testing and troubleshooting is not the focus of this article, additional information and terminology is provided for reference.

• Confirm Network Wiring Integrity. This can be as simple as verifying continuity throughout an RS-485 network (twisted shielded pair).

• Confirm Device and Master Settings. Ensure configuration settings (baud rate, parity, addresses, etc.) are correct.

• Device Unit Test. Performing a simple is-it-communicating test on individual devices is often a good place to start when troubleshooting a suspected device failure.

• Network or System Tests. If the final HMI master equipment is not available, a basic software tool could be used to communicate with individual network devices one at a time over the network connection.

• Device Manufacturer Tools. Some manufacturers offer a simple test device or a simple software tool to allow testing a single unit.

• Software Tools. Several companies offer software to execute simple communications actions such as requesting MODBUS register data.

• Confirm Network Termination Circuitry Recommendations. Many manufacturers of serial communications devices require or recommend some sort of termination circuitry at the end of the line to prevent reflections. Some devices include internal circuitry that can be switched in or out with dip switches, jumpers, or software settings. Others require externally wired termination components. Others do not recommend and sometimes prohibit external termination circuitry. The bottom line is to consult device manufacturers for recommendations or requirements related to termination circuitry.

• Protocol Analyzers. These tools are available as hardware and/or software tools that capture and analyze communications data. They are typically used as an advanced troubleshooting tool.

• ANSI/NETA ECS-2015. ANSI/NETA ECS-2015, Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems identifies general communications requirements in the Inspection and Commissioning/ Testing Procedures sections.

SUMMARY

Installing a power monitoring system offers many benefits. Establishing these systems often requires special equipment and specialty staff. However, due to the increasing availability of communicating devices and equipment, incorporating a power monitoring system might not be as challenging or expensive as you think.

Ryan McClarnon is Engineering Manager at Utility Relay Company, a manufacturer of digital trip units and conversion kits for power circuit breakers, located in Chagrin Falls, Ohio. He is an IEEE member and a Registered Professional Engineer. Ryan has been in the power distribution/systems field for over 17 years, participates in IEEE standards, and represents URC in NETA and PEARL technical activities. He received a BSEE from Cleveland State University.

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END-TO-END TESTING FOR LINE DIFFERENTIAL PROTECTION

BY SUGHOSH KUBER, Megger

Line differential protection is one of the most popular applications used for transmission line protection. Line differential protection works on the theory of Kirchhoff’s current law, where the magnitude of the current flowing into the line should be equal to the current flowing out of the line. For line differential protection, the zone of protection is defined by the location of current transformers (CTs) monitoring the currents on either end of the transmission line. It is crucial for the protective relays on both ends of the line to communicate with each other when a fault condition is established and issue a trip signal for the in-zone fault.

In Figure 1, a single-line diagram shows the set-up of line current differential relays (87L) installed on either end of the transmission line. The relays monitor current from the CTs they are connected to on the either end of the transmission line. These relays, which are referred to as local relay and remote relay, are connected to each other by means of optical fiber cables for the purpose of communication. When a fault occurs on the line, the relays see the fault at the same time. Based on the information received from the other end, the relays decide what needs to be done: trip or restrain.

Relay manufacturers use different methods to measure and compare currents in differential protection relays, including magnitude comparison, phasor comparison, phase comparison, charge comparison, or various combinations of these options. One popular method is to use the alpha plane characteristic to determine line differential condition. This article discusses line differential protection, the importance of end-to-end testing, and the procedure to test alpha plane characteristics using an end-to-end test method. Specifically, the 87L element is discussed with respect to pick-up accuracy, time of operation, dependability by simulating internal faults, and security by simulating external faults.

UNDERSTANDING ALPHA PLANE CHARACTERISTICS

The ratio of phase currents (or sequence currents) entering or leaving a transmission line is geometrically represented on a complex plane, which constitutes the alpha plane characteristics. Currents considered for the ratio calculation can be either monitored values of phase currents at remote and local relays or derived currents from calculations involving equations that use real and imaginary parts of differential and restrain currents obtained from monitored phase currents. Usage of these algorithms varies by relay models. In Figure 2, k represents the ratio of the currents.

Figure 1: Line Differential Protection Implementation

PHOTO: © ISTOCKPHOTO.COM/PORTFOLIO/MYCTERIA

SIGNIFICANCE OF END-TO-END TESTING

The area of stability and trip can be determined by the characteristic parameters due to which any percentage differential characteristics can be mapped onto the alpha plane. The restrain region is defined by parameters such as the radius of the greater arc (R), radius of the inner arc (1/R), and the angle (α). The radius of the greater arc and inner arc determines the radius of the restrain region (stability area), and the angle (α) represents the angular extent of the restrain region. Each phase has its own alpha plane characteristics. In the example, if the A phase current monitored by the local relay is 3∠0°, then the remote relay will record 3∠180°. The ratio of the remote current to local current would be:

On the alpha plane, this ratio will plot on the real axis to the left of the imaginary axis. As could be seen in Figure 2, this falls in the restrain region, which is also the stability area. This case can be related to nominal load condition or an external fault depending on the current levels. In the case of an internal fault, the currents read by both the relays for their respective phases tend to be in phase with each other as they monitor the currents feeding the internal fault. This will plot the resultant of the ratio to be 0°, which falls in the trip region of the alpha plane characteristics shown above.

End-to-end testing is the evaluation of a relay protection scheme by simulating fault conditions simultaneously at each end of the transmission line. The ability to synchronize the test systems on each end is paramount. This means that test quantities should be injected to all the relay terminals simultaneously. Line differential relays receive a set of currents from their own terminals and data of currents from the remote relay by means of various communication modes. Since the relays send time-stamped information packets to each other, even a slight slip-up of the time during injection can incorrectly stamp the packets reaching the local and remote relays, which can cause incorrect or unintended operation. Hence, a time signal from a global positioning system (GPS) clock is used to synchronize multiple test systems. Time signals are available in various standards such as IRIG-B, pulse per second (1 PPS), precision time protocol (PTP), etc. In this article, the IRIG-B time sync standard is considered for testing.

The end-to-end testing method requires multiple relay test equipment with the ability to decode the IRIG-B signal to trigger injection of analog signals simultaneously (Figure 3). The IRIG-B signal that is obtained by a GPS receiver via antenna is also provided to the relays under test. This kind of testing is used to evaluate a new protection scheme during commissioning of a substation, troubleshoot malfunction of relays, verify the relay setting changes, and other functions. Equipment (hardware/software/accessories) required to perform an end-to-end test includes:

• Two sets of relay test equipment with ability to decode IRIG-B signal and generate currents with magnitude and phase angle as specified in the test plan

• GPS receivers

• Co-axial cables (to connect GPS receiver and relay test sets and relays)

• Two computers (to drive the relay test sets at respective substations)

Figure 2: Alpha Plane Characteristics

• Communication medium between the test technicians, i.e., cell phones or other voice communication equipment

• Test software with pre-built test plans to simulate faults in the protected zone and out of the zone (through faults) for singlephase, phase-to-phase, and three-phase faults, as well as positive-, negative-, and zero-sequence currents.

When implemented correctly, communicationbased protection schemes result in efficient and reliable protection of transmission lines as compared to numerous relays that cannot communicate with each other. It is simpler to test individual relays in a scheme; however, it’s more effective to test an entire scheme as a whole, which validates not only the components, but also the communication aspect of the scheme. Issues that occur with communication-based schemes can be detected by end-to-end testing.

TEST PROCEDURE

A test set-up can be arranged to simulate a system similar to the one shown in Figure 3. IRIG-B signals must be provided to the appropriate inputs of the relay test equipment as well as the relays under test. Necessary test connections to inject analog signals to the relays must be made on both ends. Spare output contacts on both the relays should be programmed for the 87L element. A phase differential pick-up test, radius check tests, angular extent boundary tests, and timing test for an internal fault are performed. In this article, the algorithm in the relay used for testing considers derived currents from calculations involving equations that use real and imaginary parts of differential and restrain currents obtained from monitored phase currents.

Relay Settings

• Phase differential element pick-up — 0.72 pu

• Phase differential element radius (R) — 6

• Phase differential element block angle (α) — 195°

Phase Differential Pick-Up Test

The phase differential pick-up test validates the 87L logic and pick-up setting when the injected current is above the pick-up setting. This test can be performed on each phase at each end separately and does not need time synchronization. Based on the relay setting of 0.72 pu and the nominal current of 5A, the calculated pick-up value in amps is 3.6A. Therefore, the 87L element should pick up at 3.6A.

Radius Check Test

The radius check test is performed to validate the boundary of the restrain region in the alpha plane with respect to the radius from origin. Initially, the test should be conducted to verify the radius setting pick-up of inner arc of the restrain region. The distance from the origin to the inner arc of the restrain region is defined by 1/R as was depicted in Figure 2. Based on the relay settings, 1/R = 1/6 = 0.16. Once the test sets are synched during pre-fault, the test values should be varied during the fault state. The end test value at which the 87L element trips should be 0.80∠0° amps. This result value translates to 0.16 pu distance from the origin to the inner arc.

Figure 3: End-to-End Testing: The Whole Picture

In Figure 4, the alpha plane characteristic shows changes in complex ratio plot based on the varied test value of currents to validate the 1/R setting. Table 1 lists the phase A currents to be injected to local and remote relays during pre-fault and fault states. Based on the currents injected to relays, the relays perform mathematical calculations using differential and restrained equations to calculate derived currents, and the ratio of those derived currents are plotted on alpha plane to define the 87L element operation.

Table 1: Inner Arc Radius Test

After validating the 1/R setting, the next test will verify the radius setting of the outer arc of the restrain region. This radius setting was depicted in Figure 2 as R. To test the R setting, same pre-fault values should be injected as before. However, the fault state currents on the local relay should be varied up to 30 amps, which translates to 6 pu. This is the radius of the restrain region. As soon as the current is increased more than 30A, the complex ratio on alpha plane crosses the restrain region and trips the relay. The test procedure described above is for A phase. The same procedure can be followed to perform tests for B and C phases.

Table 2: Outer Arc Radius Test

Angular Extent Boundary Check Test

This test is performed to validate the angular extent of the restrain region on the alpha plane. The angular extent setting α was depicted in Figure 2. The α setting of the relay is 195°. Therefore, a pre-fault current injection with phase angles ∠0° on local relay and ∠ 180° on remote relay should be done. In the fault state, the angle of the analog currents to the local relay should be varied up in the counterclockwise direction. The relay should trip for a 98° phase angle value.

Table 3: Angular Extent Boundary Check Test 1

Pre-FaultFault

In Figure 5, the alpha plane characteristics show changes in complex ratio plot based on the phase angle variation to validate the angular extent of restrain region. Similarly, the next test should be performed to validate the

5:

Figure 4: Alpha Plane Characteristic Plot — Inner Arc Radius Test

Figure

Alpha Plane Characteristic Plot — Angular Extent Boundary Check Test

angular extent in the opposite direction from origin. The phase angle in fault state should be varied in clockwise direction for the local relay. The relays should trip at a value of –98°. The difference of angular extents between the first and second test is 98° – (–98°) = 196°. This result translates close to the angular extent setting of the relay (195°). The test procedure described above is for A phase. Th e same procedure can be followed to perform tests for B and C phases.

Local Relay 5∠0°5∠ – 98° Remote Relay 5∠180°5∠180°

Timing Test for Internal Fault

An internal fault can be simulated to perform the timing test of the 87L element. Pre-fault and fault states should be set up with the values shown in the test table below. Ideally, the local relay and remote relays should trip close to a cycle as soon as the relays see an internal fault. In Figure 6, the alpha plane characteristic shows the path of complex ratio plot transitioning from restrain region to operate region based on current injection switch from pre-fault to fault state.

A similar set-up of pre-fault and fault states can be set up to simulate external fault currents. Th e relays should restrain from tripping, as the complex ratio of currents plots on to the restrain region on the alpha plane.

Relays may also have settings enabled for 87L negative sequence and 87L zero sequence elements to provide protection for

Table 5: Timing Test — Internal Fault

Figure 6: Alpha Plane Characteristic Plot — Internal Fault Timing Test

single line to ground faults and unbalanced fault conditions. The tests discussed for phase element in this article should also be performed to validate negative sequence and zero sequence elements.

CONCLUSION

Line differential protection has been implemented all over the world by the vast majority of utilities. It is signifi cant to validate the protection scheme for its accurate operation for faults. End-to-end testing validates the entire communication-based protection scheme including the operation of the relays as well as the communication between the relays. Knowledge of endto-end test methods and fi eld experience helps technicians perform the testing more effi ciently. Th is article provides insight on testing line diff erential protection using the end-to-end test method and its importance, as

Table 4: Angular Extent Boundary Check Test 2

well as testing of alpha plane characteristics to validate the line differential element through the pick-up test, radius check test, and angular extent check test.

REFERENCES

James Ariza, G Ibarra. “Application Case of the End-to-End Relay Testing using GPS-Synchronized Secondary Injection in Communication Based Protection Schemes.” Available at: http://www.netaworld. org/sites/default/files/public/neta-journals/ NWwtr06Megger.pdf.

Schweitzer Engineering Laboratories. “SEL 411L Advanced Line Differential Protection, Automation, and Control System instruction Manual,” May 10, 2019. Available at www.selinc.com.

G. Benmouyal. “The Trajectories of Line Current Differential Faults in the Alpha Plane.” Line Current Differential Protection: A Collection of Technical Papers Representing Modern Solutions, 2014

Chris Werstiuk. “End-to-End Testing,” Valence Electrical Training Services, 2010.

Abel Gonzalez. “Advanced End-toEnd Testing Webinar.” Available at https://register.gotowebinar.com/ recording/3052100615461400833

Sughosh Kuber is a Relay and Protection Applications Engineer at Megger North America, where he provides technical support to service companies and utilities responsible for reliable operation of electrical networks. Sughosh brings over 9 years of field experience and academic research in power systems from protection schemes and testing to data analysis for energy efficiency and sustainability. Sughosh received his MS in electrical engineering from New Mexico State University.

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FIBER OPTIC NETWORK OPERATION, MAINTENANCE, AND RESTORATION

© ISTOCKPHOTO.COM/PORTFOLIO/SHULZ

BY JIM HAYES, Fiber Optic Association

All networks are susceptible to problems that affect communications. One consequence of a fiber optic system’s high bandwidth, long distance capability, and security is the extreme dependence of users on the non-stop operation of these systems. Because they can transmit large amounts of data long distances with immunity from signal degradation and extremely high reliability, these systems usually carry the most critical data.

PHOTO:

Fortunately, fiber optic cable plants are very reliable and need no routine maintenance. We tell network owners that once the network is installed and tested, lock it up and keep all unauthorized personnel away from it.

Network operation does not require periodic testing because most equipment has builtin self-testing that monitors link errors and informs you of problems before they become serious. If your cable plant has spare fibers — it

should — they can be used to periodically test the cable plant without disturbing the network.

WHAT GOES WRONG?

It’s a fact of life: When fiber optic systems fail, it’s mostly due to accidental damage. I remember telling a group of network managers that in the fiber optic industry, we say the most common cause of failure is backhoe fade. A member of the group replied, “I’m from

Damage from Gunshots

Damage from Gunshots Squirrel Attack

Damage from a Backhoe

Damage from an Auger

Bonneville Power, and our most common problem is target practice.” There are, in fact, many potential problems.

• Underground cable damage from construction dig-ups or directional boring

• Flooding during storms or ice in winter in manholes, hand-holes, or poorly sealed splice closures

• Aerial cable damage from vehicle accidents, shootings, animals, ice or storms, and vandalism

• Cutting the wrong cable when removing older cables indoors or out

• Breaking patchcords or connectors during moves, adds, or changes

• Getting connectors dirty or not cleaning dirty connectors properly before use

• Misconnections or polarity mismatches when connecting transmitters

• Breaking fibers in splice trays or kinking cable tubes in splice closures when building or upgrading networks

Sadly, there are even instances where disgruntled company employees sabotage links. Even personnel taking visitors on tours have unplugged a connector on an operating link.

Most of these problems affect outside plant cables, but premises cables are still susceptible to damage. With the current push by landlords to remove abandoned cables to comply with the NEC, the likelihood of damage is much higher as workers cut out the old cables.

DESIGN FOR RELIABILITY, PREPARE FOR RESTORATION

We always tell network owners and operators that preparing for restoration starts at the design phase of the project. Communications system reliability depends on a design that has lots of margin, spare fibers in the cable plant, and diverse routing for traffic in case something does happen on a link.

Moving cables in a typical patch panel without damage can be a challenge.

Telecommunications companies usually build route diversity into their network so a problem on one route will allow simply switching to another. Many systems also run backup links on spare fibers ready to switch over if one link fails. Critical systems in utility substations or control rooms should also have redundant connections on diverse routes to ensure connectivity in case of accidental damage. In 1975, the Browns Ferry Nuclear Plant nearly melted down because there was a fire in a conduit that held all three cables designed to provide redundancy.

Of course, communications equipment requires an electric power supply. AC power should be properly conditioned and backup power provided. Backups often have two stages: a) battery backup to make sure the equipment continues running during brief power outages and b) generator power for outages longer than the batteries can last.

SOURCE: JIM HAYES, FOA

When designing a network, plan to order extra components that can be kept after installation is complete to be used when repair is needed. Nothing can be more frustrating than having to wait for components necessary for repairs. When building a network, order extra cables and hardware for installation as insurance.

Leftover components should be stored in a box along with a restoration plan that includes documentation such as cable route diagrams, test results — especially OTDR traces — and any other information that could help locate and fix a problem in the cable plant.

For underground networks, it’s important to provide above-ground markers to indicate the route of the cable plant. The design should also include burying marker tape that can be found with cable-location equipment about a foot underground above the cable. That provides two layers of protection.

Restoration planning should be part of the design. If it was not done originally, now is the time to do it before something happens.

NETWORK FAILURE

If something happens to your network, it’s important to not panic. Quickly fi nd the problem and mobilize the personnel to fix it. Start with some quick checks.

Do not jump to the conclusion that the problem is the cable plant. First, determine that the communications equipment on both ends of the link work properly. Start with a simple check of system power. Some equipment will tell you the problem is with the equipment or the cable plant by something as simple as a green light on the receiver if it’s got power and a connection. If multiple links operate over the same cable plant, diagnosis is easier. If only one link is down, it’s likely the electronics. If all links are down, it’s likely the cable plant.

If the electronics are the problem or are suspected, swap modules for spares. If that

A cleaning kit will quickly remove dirt and contamination, and a video microscope can inspect connectors for dirt or damage.

solves the problem, make sure to send that bad module out for repair ASAP.

If it’s not the electronics, start looking at the cable plant, beginning with the patchcords. They can be tested with an inexpensive visual fault locator (VFL) to confirm they have not been broken or connected wrong. A connector inspection microscope and cleaning kit are a good investment too, since the majority of fiber optic problems are due to dirty connectors. That’s another reason not to let unqualified personnel touch the fibers.

Diagnosing cable problems is a matter of shooting several spare fibers in the cable with an optical time-domain reflectometer (OTDR) and analyzing the traces. Is the cable the expected length? If it’s shorter or it has a high loss event at an unexpected point, it may indicate a damaged cable. Don’t trust the results of just one fiber. Test a few and see what they all look like. If they are all the same, you may have a cable break. If only some fibers show the problem, you may have cable damage in only a few fibers, indicating a problem with a kinked but not totally broken cable or problems at a splice point.

Remember, the OTDR is not 100% accurate. It measures fiber length, not cable length, and

the cable length is approximately 1–2% shorter. Compare the length on the OTDR with data from installation testing and correlate with splice points to reduce location uncertainty. Alternatively, shoot from both ends to locate a break and average distances.

Make certain you are testing the correct cable. Using OTDR testing, one crew thought they had a break in a 6 km underground cable at 4 km. But physical inspection, including digging at the location indicated by the OTDR, showed no problem. In fact, they were testing the wrong cable. They were testing a cable 4km long running in the opposite direction from the patch panel, not the cable they thought they were testing. Their patch panel marking and documentation didn’t match.

This is where documentation helps. Having information on the length of the cable and the location of splice points — especially geographic information system (GIS) data — makes pinpointing problems easier. Comparing traces of problem fibers allows correlation of the problem location to the location of a splice closure or a service loop in a vault.

Splice closures can be the problem. Fibers can get cracked or broken in splice trays, yet not fail for a long time, perhaps after seasons of temperature changes. Splice closures can be improperly sealed, and moisture — or ice in winter — will cause damage. There are even tales of animals such as squirrels or woodpeckers attacking splice closures or cables and causing damage.

Finding a fiber break in a splice tray can be difficult. If you are close enough to use a visual fault locator (VFL), it will pinpoint the break. If the distance to the nearest fiber end is more than 4-5km, a gadget called a fiber identifier may be used.

Sometimes a visual inspection of a cable route will find the cause of the break faster than testing fibers. One tech remembers that a construction team was installing road signs

An OTDR with long launch and receive cables will help diagnose problems in the cable plant.

A visual fault locator (VLF) is extremely useful at finding breaks in splice trays, couplers, etc.

ALAN KOJIMA

Restoration can be in a muddy field along a rural road or in the middle of a busy street in downtown Los Angeles.

nearby when their network went down, so he hopped in his truck and drove to the job site. There he found the construction crew stuffing the broken fiber optic cable back into the hole they had dug with an auger.

Another network went down when a helicopter flew into an optical power ground wire (OPGW) on a tower. That one was easy to find, but hard to fix, but one of our FOA instructors spliced it from a precarious perch in a bucket truck.

And always remember to ask around the offices to see if someone has been working on the network.

REPAIR STRATEGY

Okay, there is a break. How do you fix it? You should have a restoration plan and a restoration kit complete with up-to-date documentation, a list of test and repair equipment — including where to find them — and components set aside for repair. A contact list of knowledgeable people on staff or a contractor on call is also necessary.

Many companies use contractors to install fiber optic cabling because they do not have qualified employees to do the work, or at least not enough with the experience and equipment to do the job. Lacking staff capable of diagnosing problems and making temporary repairs can be problematic, since even a contractor on call 24/7 will take time to respond.

It’s much better to have several employees trained in basic fiber optics who can maintain the network and do basic repairs. For the cost of a few minutes of downtime on a typical communications link, send a couple of techs to an FOA-approved training course and equip them with a basic OTDR, an inexpensive portable fusion splicer, and some basic tools that will allow them to at least patch up the network and get it running before the final repairs are completed.

Everyone knows techs need training, but FOA also recommends that a couple of supervisors attend a training course in person or online. Our experience is that managers who understand basic fiber optics are better equipped to oversee construction, operation, and restoration.

SOURCE: JIM HAYES, FOA

Once the trouble spot has been located, you will want to get the network back up as fast as possible. If it’s a break, you probably will not be able to pull the cable ends out and splice them together again unless you are near some service loops. If you can’t get enough cable to splice (you need a minimum of ~10 m or 30 feet on both ends being spliced), you will have to bring out that extra cable you saved from the installation and splice a length of that to the two broken ends.

Yes, that means you need two splices to make the repair. And you will need two splice closures and about 100 m of cable just to have enough working length. Temporary fixes are OK. Splice together enough fibers to get the network back operational, even forgoing fitting splices into closures, and come back later and carefully splice all the fibers, neatly place the splices in a closure, and replace the cable in its original location.

If you read older documents on restoration, they may suggest temporary repairs using mechanical splices instead of fusion splices. That can work, but was advice from an era when fusion splicers were rare and expensive machines. Today, a simple portable fusion splicer can be purchased for little more than the kit to make a mechanical splice. In our experience teaching techs, a fusion splicer is easier to learn how to use properly.

OTDRs are also now aff ordable, so there is little excuse for a network operator not to have one. However, they do need some training to operate properly. Most are touted as having automatic testing modes that do the work for the tech operating them. Th at may work well on testing dozens of identical

fibers during installation, but doesn’t hold for troubleshooting. For that, training is required.

POST-RESTORATION

Once the restoration is complete, it is important to prepare for the next time a problem arises, including updating documentation and replenishing supplies. The documentation should be updated to reflect changes in the cable plant after repair. This includes any new components, new splices or splice closures, or especially any fibers that are no longer serviceable. New test data (loss measurements and OTDR traces) should be recorded and preferably compared to pre-restoration data.

Leftover Inventories of restoration supplies that are reusable should be updated. Required supplies should be noted and ordered promptly. Remember to update inventories when supplies are received. You never know when you’ll need them.

(Editor’s note: FOA’s Fiber U offers free online courses for technicians and managers.)

REFERENCES

Lochbaum, Dave. “Nuclear Plant Accidents: Browns Ferry Fire,” Disaster by Design/ Safety by Intent #41, July 19, 2016. Available at https://allthingsnuclear.org/dlochbaum/ nuclear-plant-accidents-browns-ferry-fire

Jim Hayes is an author and trainer and President of the Fiber Optic Association. Find him at www.jimhayes.com.

The Power of Positive Results

R-GOOSE APPLICATIONS IN A SMART GRID

BY ALEX APOSTOLOV, OMICRON electronics Corp. USA

The high level of penetration of distributed energy resources (DERs) is one of the main characteristics of the smart grid, and it requires a different approach to the protection of the grid. IEC 61850 is widely accepted around the world due to the significant benefits it provides compared with conventional hardwired solutions. However, many specialists in the industry still hesitate to start using Generic Object Oriented Substation Event (GOOSE) messages for all protection and protection-related functions. This is due mainly to lack of understanding of the differences between hardwired and GOOSE-based solutions. Taking advantage of the benefits is possible only when the fundamentals and applications are well understood.

This article first introduces the concepts of the IEC 61850 GOOSE (generic object oriented substation event).

• Publisher and subscriber functionality

• Multicasting

• Event reporting versus commands

• Repetition mechanism

• Data sets

• Simulation bit

Routable GOOSE (R-GOOSE) is presented later, followed by discussion of several use

cases describing application of R-GOOSE technology for reducing fault clearing time.

GOOSE COMMUNICATIONS

Peer-to-peer is the characteristic communications type for IEC 61850-based systems. It is one of the distinguishing features of the standard that makes it attractive to protection and control specialists. It describes the ability of arbitrary pairs of intelligent electronic devices (IEDs) connected to the substation network to manage the exchange

of information as necessary with all devices having equal rights, in contrast to master/ slave communication. High-speed, peer-topeer communications in IEC 61850-based protection and control systems use a specific method designed to meet a variety of requirements. It is very important that the concept of the generic substation event (GSE) model is not based on commands, but on the sending indication by a function that a specific substation event has occurred. It is designed to support reliable high-speed communications between different devices or applications and allows the replacement of hardwired signals between devices with communication message exchange while improving the functionality of the protection, automation, and control system. It uses a connectionless publisher–subscriber communications mechanism shown in Figure 1.

The model includes several features that can be used to improve the reliability and availability of the system. At the same time, the proper use of these features in a vendor’s implementation will reduce maintenance and increase the flexibility of the system. GOOSE was initially developed for substation communications, but due to the benefits it provides, there is a need

to define how it can be used for substation-tosubstation or wide-area communications.

To understand the differences between substation GOOSE and wide-area GOOSE, we need to look into some of the details of the generic substation event (GSE) model. The GSE method is considered a mechanism for reporting by a logical device. The achievement of speed, performance, availability, and reliability depends on the implementation in any specific device.

The GSE model is used to exchange the values of a collection of data attributes defined as a data set (Figure 2). GOOSE supports the exchange of a wide range of data types organized in a data set.

The publisher writes the values in a transmission buffer at the sending side and multicasts them over the substation local area network to the various subscribers — clients or servers.

The data in the published GOOSE messages is a collection of values of data attributes defined

Figure 2: Publisher Functionality

as members of a data set. The receiver reads the values from a local buffer at the receiving side. A GSE control class in the publisher is used to control the process. If the value of at least one of the data attributes has changed, the publisher’s transmission buffer is updated with the local service publish, and the values are transmitted with a GOOSE message.

The publisher/subscriber mechanism allows the source IED to reach multiple receiving IEDs, thus significantly improving the efficiency of the communications interface. In substation communication networks, this is based on the use of a media access control (MAC) multicast destination address in the Ethernet frame shown in Table 1.

As shown in Figure 3, the interval immediately after a change is very short — a few milliseconds — which later increases until it reaches a value of a few seconds. This method achieves several important tasks:

• Ensures that loss of a single message will not affect the functionality of the system.

• Allows any new device to inform all subscribing devices about its state.

• Allows any new device to learn the state of all publishing devices it subscribes to.

Event: Data Change fast Repetitions

Where:

• Destination address (6 bytes) identifies which station(s) should receive the frame.

• Source address (6 bytes) identifies the sending station.

• Length is 6 octets and contains the value of the destination MAC address to which the GOOSE message is to be sent. The address must be an Ethernet address that has the multicast bit set TRUE.

• If a port has an 802.1Q-compliant device such as another switch attached (such as another switch), these tagged frames can carry virtual local area network (VLAN) membership information between switches, thus letting a VLAN span multiple switches.

• Specific communication services in the subscribers update the content of their reception buffers, and new values received are indicated to the related applications.

Since the GOOSE messages replace hardwired signals used for protection and control applications, IEC 61850 introduces mechanisms that ensure delivery of the required information.

Once a new value of a data attribute has resulted in the multicasting of a new GOOSE message, the repetition mechanism ensures that the message is sent with a changing time interval between the repeated messages until a new change event occurs.

The GOOSE messages contain information that allows the receiving devices to know not only that a status has changed, but also the time of the last status change. This allows a receiving device to set local timers relating to a given event.

At the same time, the repetition mechanism can be used as a heartbeat that allows the continuous monitoring of the communications interface — something that is not possible in conventional hardwired systems.

The state number and the sequence number can be used to detect intrusion, thus allowing significant improvement in the cyber security of the system without the need for encryption or other cyber security methods.

The GOOSE control block class defined in Edition 1 of IEC 61850 (Figure 4) includes the attributes that define the behavior of peer-topeer communications and is related to a logical device — and more specifically, to its Logical Node Zero (LLN0).

• GoCBName (GOOSE control name) identifies a GoCB within the scope of a

Table 1: Ethernet Type II Frame

Figure 3: GOOSE Repetition Mechanism

GoCBRef (GOOSE control reference) — a unique path name of a GoCB within LLN0: LDName/LLN0.GoCBName.

• GoEna (GOOSE enable) indicates that the GoCB is enabled (if set to TRUE) to send GOOSE messages. If set to FALSE, it will stop sending GOOSE messages.

• AppID is an application identification represented by a visible string that represents a logical device in which the GoCB is located.

• DatSet is the reference of the data set whose values of members shall be transmitted.

• ConfRev is the configuration revision indicating the number of times the configuration of the data set referenced by DatSet has been changed. The counter is incremented every time the configuration changes.

• NdsCom (needs commissioning) is TRUE if the attribute DatSet has a value of NULL and is used to indicate that the GoCB requires configuration.

As already mentioned, the content of the GOOSE message (Figure 5) allows receiving

GOOSE message

Parameter name

Parameter type

GoCB class

Attribute nameValve/value range/explanation

GoCBName Instance name of an instance of GoCB

GoCBRef

GoEna

App ID

DatSet

ConfRev

NdsCom Services

SendGOOSEMessage

GetGoReference

Path-name of an instance of GoCB

Enabled (TRUE) | dsabled (FALSE)

Attribute that allows a user to assign a system unique identification for the application that is issuing the GOOSE. DEFAULT GoCBRef

GETGOOSEElementNumber

GetGoCBValues

SetGoCBValues

Figure 4: GOOSE Control Block Class

devices to process the data in order to execute required actions. Some of the attributes in the GOOSE message that help perform the functions described earlier are:

• T is the time stamp representing the time at which the attribute StNum was incremented.

Value/value range/explanation

DatSet ObjectReference Value from instance of GoCB

GoID VISIBLE STRING 129Value from instance of GoCB

GoCBRef ObjectReference Value from instance of GoCB

T TimeStamp

StNum INT32U

SqNum INT32U

Simulation BOOLEAN (TRUE) simulation | (FALSE) real values

ConfRev INT32U Value from instance of GoCB

NdsCom BOOLEAN Value from instance of GoCB

GooseData [1..n]

Value (*) (*) type depends on the appropriate common data classes (CDC).

Figure 5: GOOSE Message

• StNum indicates the current state number — a counter that increments each time a GOOSE message (including a changed value) is sent for the first time. The initial value is 1.

• SqNum is the sequence number — the value of a counter that increments each time a GOOSE message with the same values has been sent. The initial value is 1.

• Simulation is a parameter that indicates that the GOOSE message is used for test purposes (if the value is TRUE) and that the values of the message have been issued by a simulation unit and shall not be used for operational purposes.

• The GOOSE subscriber reports the value of the simulated message to its application instead of the real message depending on the setting of the receiving IED.

This basic concept also applies to the GSSE model, which is similar to the GOOSE model. However, there are two major differences:

• GOOSE provides flexibility in the definition of a data set with different data types, while GSSE provides only a simple list of status information.

• GOOSE mapping to IEC 61850 8-1 supports VLAN and priority tagging.

R-GOOSE

The GOOSE message was designed for peer-topeer substation communications and therefore uses a three-layer stack and MAC multicast. This is not suitable for messages that need to be sent over a wide-area network. For that reason, Technical Report IEC 61850 90-5, Use of IEC 61850 to transmit synchrophasor information according to IEEE C37.118 selected UDP/IP as the option to transmit data over arbitrary large distances.

Internet Protocol (IP) is a Layer 3 protocol. The network layer adds the concept of routing above the data link layer. When data arrives at the network layer, the source and destination addresses contained inside each frame are

examined to determine if the data has reached its final destination. If that is true, Layer 3 formats the data into packets delivered up to the transport layer. IP allows the routing of data packets (IP packets) between different networks over any distance.

User Datagram Protocol (UDP) is a transport Layer 4 network protocol. While Transmission Control Protocol (TCP) is a connection oriented protocol that requires communications between a client and a server to first be established, UDP is connectionless, which makes it more suitable for GOOSE communications.

UDP network traffic is organized in the form of datagrams. A datagram comprises one message unit. The first eight bytes of a datagram contain header information; the remaining bytes contain message data.

A UDP datagram header consists of four fields of two bytes each:

• Source port number

• Destination port number

• Datagram size

• Checksum

UDP checksum protects the message data from tampering. The checksum value represents an encoding of the datagram data calculated first by the sender and later by the receiver. If the checksum does not match, indicating tampered or corrupted data during transmission, the UDP protocol detects it. In UDP, the checksum is optional as opposed to TCP, where it is mandatory.

Many working applications of the IEEE C37.118 protocol confirm that the use of UDP for streaming of the synchrophasor data is a proven method that can also be used for the routable GOOSE.

Considering the importance of the checksum as a cyber security tool, IEC 61850 8-1 Edition 2.1 defines it as mandatory for IEC 61850 implementations. Table 2 shows the UDP field implementation requirements defined in the standard.

Table 2: UDP Field Implementation Requirements

R-GOOSE APPLICATIONS IN SMART GRID

R-GOOSE may have many different applications. It can be used for complex hierarchical system integrity protection schemes (SIPS) at the system’s transmission level in order to communicate the change of state of system components that impact the stability of the system. It also can be used by the SIPS to send GOOSE messages to the system components that are used to execute the required actions.

At the system’s distribution level, the R-GOOSE can be used very successfully for distribution automation applications. It can also play a critical role in smart grids with high penetration of distributed energy resources (DERs).

Distributed generators are typically connected to sub-transmission or distribution systems. e de nition of such systems varies between utilities, and in some cases, systems with voltages as high as 138 kV may be considered as distribution. e addition of distributed generators has a signi cant e ect on the system (Figure 6). It a ects the levels of short-circuit currents, the dynamic behavior of the system following such faults, and the coordination of protective relays and must be considered when selecting the protection system. Line protection settings and criteria should take into account in-feed e ect, possible power swings, and generator out-of-step conditions.

e increased fault clearing times caused by the in-feed e ect of a distributed generator may not be acceptable to customers with sensitive loads. e voltage sag is experienced

not only by users on the faulted feeder, but also on adjacent feeders connected to the same distribution system.

Figure 7 shows the areas impacted by voltage sags or swells on sensitive equipment and demonstrates that the impact depends on

Figure 6: Distribution Feeder with DG

Figure 7: ITIC (formerly CBEMA) Curve

FEATURE

two characteristics. e rst characteristic of a voltage sag — the depth — is a function of the type of fault, fault location, and system con guration. It will also be a ected by the state of the distributed generator — whether it is in service or not. Single phase-to-ground faults lead to voltage sag in the faulted phase and to voltage swell in the healthy phases. e level of voltage increase is also a ected by the grounding of the interface transformer and must be taken into consideration.

e same two fault characteristics also have an impact on the ride-through capability of the DER. Figure 8 shows an example of a ridethrough characteristic. is is something we can’t control, but we must study it in order to be able to predict or estimate the e ects of di erent faults on sensitive equipment.

e second characteristic of the voltage sag — duration — is the parameter we can control by properly applying the advanced features of multifunctional protection relays.

Distributed generator interconnection protection has been the subject of many papers, as well as standardization work such as IEEE P-1547 (Figure 9). It is clear that the location of the fault and the in-feed from the generator will lead to increased fault clearing time and coordination problems. is depends more speci cally on the type of distributed generator and its interconnection with the electric power system.

However, it is not only distribution feeder protection that needs to be accelerated. When a short-circuit fault occurs on a transmission line connected to a substation with DERs connected at the distribution level, the voltage drop caused by the fault must be considered in analyzing the performance of the DER and its ability to ride through the fault.

When the fault is in Zone 2 of the protected transmission line (especially on shorter lines), the time delayed trip will depend on the time delay setting, which may be in the range of 300–400 msec. Such a delayed trip will impact the duration of the voltage sag experienced by a DER in the tripping area of the ride-through characteristic. An accelerated protection scheme can signi cantly reduce fault clearing time and bring it within the stay-connected area of the characteristic.

ACCELERATED LINE PROTECTION SCHEMES

Conventional distance protection does not provide instantaneous tripping for all faults on a protected transmission line. Communicationsbased accelerated schemes allow considerable improvement in overall fault clearing time for any fault within the zone of protection. At the same time, they do not have the high-speed communication requirements line di erential protection has. is is due to the fact that these

Figure 8: Ride- rough Characteristic

Figure 9: Distance Protection of Transmission Line

schemes use a signaling channel to transmit simple ON/OFF data from a local protection device. This provides additional information to the remote-end protection device that can be used to accelerate in-zone fault clearance or prevent operation for external faults. These teleprotection schemes can be grouped into three main operation modes.

In each mode, the decision to send a command is made by a local protective relay operation:

• In intertripping, (direct or transfer tripping) applications, the command is not supervised at the receiving end by any protection function and simply causes a breaker trip operation. Since no checking of the received signal is performed, it is absolutely essential that any noise on the signaling channel isn’t seen as being a valid signal. In other words, an intertripping channel must be very secure.

• In permissive applications, tripping is only permitted when the command coincides with a protection operation at the receiving end. Since this applies a second, independent check before tripping, the signaling channel for permissive schemes does not have to be as secure as for intertripping channels.

In blocking applications, tripping is only permitted when no signal is received, but a protection operation has occurred. In other words, when a command is transmitted, the receiving end device is blocked from operating even if a protection operation occurs. Since the signal is used to prevent tripping, it is clear that a signal must be received whenever possible and as quickly as possible. In other words, a blocking channel must be fast and dependable.

The protection function that sends the permissive or blocking signal to the remote end determines the type of scheme used. If this is a distance element, we usually talk about permissive underreaching or overreaching schemes or blocking schemes. If a directional element is used to initiate the transmission

of a signal to the remote end of the protected line, we have directional comparison schemes. A directional comparison scheme can be permissive or blocking, with directional elements initiating signal transmission and providing supervision at the receiving end.

As an example of an accelerated transmission line protection scheme, consider a permissive directional comparison scheme commonly used to accelerate the clearing of all kinds of faults, including high-resistance faults that are not seen by the distance elements of the transmission line protection relays or line differential relays (Figure 10).

Th e channel for a directional comparison permissive scheme is keyed by operation of the forward-looking elements of the relay. If the remote relay has also detected a forward fault upon receipt of this signal, the relay will operate. Such schemes offer significant advantages, especially when high-speed directional detection methods based on superimposed current and voltage components are used.

Permissive schemes tend to be more secure than blocking schemes because forward directional decisions must be made at both ends of the line before tripping is allowed. Failure of the

DIR FWD

Figure 10: Permissive Directional Comparison Scheme

signaling channel will not result in unwanted tripping because no signal is going to be received, and the relay does not trip based on a forward directional detection only.

CONCLUSION

If the source at either end of the line is weak, the directional comparison permissive scheme uses weak infeed logic.

Current reversal guard logic is used to prevent healthy line protection maloperation for the high-speed current reversals experienced in double circuit lines caused by sequential opening of circuit breakers.

If the signaling channel fails, basic distance scheme tripping will usually be available.

The challenge for the implementation of accelerated transmission line protection schemes is that they require a communications channel which, if it is dedicated, will require additional costs. IEC 61850 R-GOOSE messages are a technology that can help us achieve these goals without the need for additional investments.

R-GOOSE is a version of the popular IEC 61850 peer-to-peer communications method that can be used for wide-area protection and control applications. While the principles remain the same, R-GOOSE uses UDP multicast as the transport mechanism. R-GOOSE offers significant benefits for many diff erent electric power system protection, automation, and control applications, including:

• System integrity protection schemes at the transmission level

• Distribution automation systems

• Accelerated transmission line protection schemes

• Accelerated distribution protection schemes

Such applications will have a positive impact on the efficiency of the protection and control systems in smart grids.

Dr. Alexander Apostolov is presently Principal Engineer for OMICRON electronics Corp. USA in Los Angeles. He has 42 years of experience in power systems protection, automation, control and communications. Alex holds four patents, has authored and presented more than 500 technical papers, is editor-in-chief of PAC World, and is an IEEE distinguished lecturer and adjunct professor at the Department of Electrical Engineering, Cape Peninsula University of Technology, Cape Town, South Africa. He is an IEEE Fellow and a member of the Power Systems Relaying Committee and Substations C0 Subcommittee; is past chair of the Relay Communications Subcommittee; serves on many IEEE PES working groups; and chairs WG C2 Role of Protective Relaying in Smart Grid. He is a member of IEC TC57 Working Groups 10, 17, 18, and 19, and leads the Task Force for Functional Testing of IEC 61850 Based Devices and Systems. He is a Distinguished Member of CIGRE; Convenor of CIGRE WG B5.53, Test Strategy for Protection, Automation and Control (PAC) functions in a full digital substation based on IEC 61850 applications; and a member of several other CIGRE B5 working groups. Alex received his MS in electrical engineering, MS in applied mathematics, and PhD from the Technical University in Sofia, Bulgaria.

Figure 11: Accelerated Protection with R-GOOSE

F1F2

MEDIUM-VOLTAGE ASSET FAILURE INVESTIGATIONS

BY KELLY HIGINBOTHAM, University of Connecticut, and WILLIAM G. HIGINBOTHAM, EA Technology LLC

Medium-voltage cables are an integral part of modern power systems and have existed for over 100 years in various forms. Over the past 50 years, extruded cables have largely displaced paper insulated cables. Extruded cables offer many advantages over older designs, but are similarly prone to failure. Such failures are a significant impediment to improving overall power system reliability.

Since cables are often sealed systems, continual assessment is difficult, and failures often occur without warning or preparation. Figure 1, provided by the National Electric Energy Testing Research, and Applications Center (NEETRAC), compares the costs of testing equipment, replacing all equipment regularly, and running equipment to failure. Each cost is shown as a standard distribution to represent the uncertainty associated with failure costs. It is evident that the costs of testing are significantly lower and have less uncertainty than the costs associated with running equipment to failure or wholesale replacement prior to failure.

This article sets out to sample the results of multiple forensic analyses, determine the common causes of cable failures, and identify how users can acquire accurate information

Figure 1: Cost Option Comparison

on the status of their cables. For the sake of this analysis, cable failures include failures in terminations, splices, connectors, and midcable failures. By being able to accurately determine potential cable issues before the failure occurs, we can plan better outages, improve system reliability, and prevent

collateral damage caused by faults. Asset management and a proper testing schedule have been proven to lower costs associated with unplanned outages due to cable failures.

STUDY BACKGROUND

This article analyzes a subset of the forensic investigations performed by EA Technology on failed cables and components to determine failure mechanisms and set recommendations for similar system components. This analysis can provide insight into fault mechanisms, highlight other at-risk assets, and recommend asset management strategies to reduce future risk of failure. In addition, these reports provide insight into manufacturer quality and jointer workmanship. From these reports, we try to determine proximate cause and ultimate cause.

• A proximate cause is the obvious, direct cause of the failure. Examples include moisture ingress and mechanical damage.

• The ultimate cause is the deeper, systematic reason for a failure, such as poor workmanship, lack of training, or application errors. Other potential actions leading to a systemic cause include seeking the lowest installed cost, which includes decreasing the money spent on training, buying lower grade materials, or increasing the workload on individual jointers. Another explanation can be the current labor market and how difficult it is to find and retain highly skilled jointers.

To get from the proximate cause to the ultimate cause, the authors employed a commonly used management practice called the 5 Whys. By asking “Why?” and then challenging the answer with “Why?” in a serial fashion, the ultimate cause of an event can often be found.

For example, the proximate cause of the Titanic sinking is that it hit an iceberg. While addressing that, one could overlook the

ultimate cause: White Star Line had systematic issues that devalued passenger safety. The hope is that by addressing the ultimate causes of a failure, a wider range of proximate causes can be prevented. Over the course of this article, major trends are developed across both proximate and ultimate causes, and actions are recommended.

It should be noted that this study involved a small number of samples over a short period of time. While the authors believe the results to be representative of actual field conditions, this cannot be guaranteed. Sample size, time period, motivations for investigations, etc., could contribute to variations from a more detailed study. The reader should keep this possibility in mind when considering the findings presented.

FORENSIC FAILURE INVESTIGATION PROCESS

EA Technology’s investigations begin with visual investigation of the samples and analysis of the fault timeline if provided. Th is is followed by review of application parameters and instructions, then mechanical disassembly. Once disassembled, analytic investigation and specialized mechanical testing is completed and a report is provided to the client detailing the fi ndings and recommendations of the investigation.

First, a visual investigation can provide vital details on workmanship and manufacturing errors, evidence of partial discharge, and moisture ingress into the cables. This step often includes documentation of the site and failure conditions. If possible, a representative should be present for removal of the failed component to ensure no information is lost during the process. Being present also provides a better understanding of the factors leading up to the fault.

Next, the team will review the application parameters and instructions provided by the manufacturer at the time of installation. Th ese will be used as a reference for the visual inspection and will be verified to be both accurate and clear. The visual inspection concludes with mechanical disassembly of the failed element. The cable is deconstructed layer by layer and extensively documented with pictures and measurements. This often speaks volumes about workmanship and cable age/ condition.

The next step is the analytical investigation. The details vary based on insulation type, but in general the analytical investigation dives deeply into suspected issues and determines the severity of underlying issues. For XLPE (Figure 2), the sample is boiled in oil of cloves

Figure 2: XLPE Insulation

Figure 3: XLPE Insulation Made Transparent

to make it transparent (Figure 3). This allows the researchers to microscopically examine thin sections of insulation to visualize any inclusion and ambers from the manufacturing process. Inclusions come from foreign matter lodged in the insulation during the extrusion process. Ambers are bits of insulation that weren’t fully converted to the final material. Both can affect the dielectric constant of the insulation, but foreign materials have a more negative effect on insulation quality. Having the insulation transparent also makes it possible to see developing water trees in the insulation. Th ese could have contributed to the fault or could indicate underlying issues based on size and location. For paper oilinsulated cables, the analytical investigation looks into the many mechanical factors that can lead to cable failure. Th is is done by unraveling the paper and looking for two major things:

• First, the overlapping of the strands is checked. Uneven overlapping can cause concentration of the electric fields and in turn lead to partial discharge.

• Second, the strands are checked for waxy patterns located at interstitials of the papers. These waxy residues can indicate partial discharge occurring in the cable and strongly indicate voids or moisture affecting the reliability of the cable.

When necessary, three major specialized material tests are conducted to gather more information on the samples.

• Scanning electron microscopy (Figure 4) performs elemental analysis on inclusions to identify foreign compounds. This can be used to compare the materials in the inclusion to the bulk insulation and possibly determine the impacts the inclusion would have on dielectric constants.

• Scanning differential calorimetry can determine the maximum temperature reached by the component prior to failure. This is important information to determine whether the component was used in the wrong application and whether overheating contributed to fault.

• Mechanical tests of cable components can determine material characteristics that indicate whether a component was appropriate for the application it was used in. This is commonly done for components expected to perform

The findings of all the tests are compiled into a report, and recommendations are drafted based on the findings. Client reports include detailed documentation of the investigation process, conclusions, and recommendations. Conclusions are structured to highlight

Figure 4: Scanning Electron Microscope-Based Elemental Spectroscopy

INDUSTRY TOPICS

proximal and ultimate causes of failure based on the data gathered in the report, and recommendations are provided to address the proximal and ultimate causes of the failure. Th e report often includes several types of recommendations.

• First, suggestions address current at-risk assets to lower the risk of failure. Cable updates are often part of a large program update, so a failed cable could indicate larger system concerns.

• Second, suggestions are aimed at internal modifications that can prevent these issues in the future. These can include a new training program for jointers or an asset management program aimed at preventing end of life failures.

• Finally, recommendations may be aimed at external factors that contributed to the fault. Examples of these are informing a manufacturer of a defect or poor design or changing suppliers to use higher-quality materials.

All recommendations build the foundation for a more reliable system with the aim of reducing failures.

This study compiles the data drawn from a set of reports to analyze the greater trends indicated by their results and recommendations. We

pulled 100 reports generated in 2011–2015 from EA Technology’s forensic analysis report database. After the initial review, 27 of the reports were deemed irrelevant and discarded. Many of these were from lower voltage classes, were mechanical failures, or were a condition assessment report, not a failure analysis report. The remaining 73 reports were sorted and analyzed based on cable age, insulation type, voltage class, installation conditions, failure location, failure causes, and recommendations. These characteristics were graphed and analyzed for evident trends.

FINDINGS

The first metric analyzed was the age of the cable when the failure occurred. It was found that failure occurrence matched the Weibull distribution — the bathtub curve pattern shown in Figure 5. Failures can be classified into three main categories:

• Infant mortality failures make up the largest segment of the graph and last for approximately 10 years after installation.

• Random failures occur for the next 30 years or so. These are intermittent and generally uncorrelated.

• At around 40 years after installation, end of life failures begin to occur.

End of life failures are generally only prevented by replacement, while infant mortality and random failures can be prevented by looking deeply into the causes and responding appropriately.

Next, the report samplings were analyzed across insulation type and fault type (Figure 6). Based on “Historical Overview of Mediumand High-Voltage Cables,” written by the Georgia Tech NEETRAC group, XLPE and PILC cables show a similar ratio of failures per mile of installed cable. The ratio of failures per mile was developed using the data about EPR usage compared to XLPE usage provided by NEETRAC. Comparing NEETRAC’s

Figure 5: Time to Failure

average percentages per insulation type versus this study’s average percentages of failures per insulation type takes into account that EPR is less commonly used than XLPE. This factor may have swayed the data to make EPR look dramatically more reliable than XLPE. While the numbers presented are backed by the various reports referenced, the difference in field failure rates for insulation types is unlikely to be as great as this specific study implies due to external factors not accounted for in this analysis.

Next, we analyzed where the failures occurred (Figure 7). Based on the fault locations seen in the report sampling, 68% of failures occur in places where technicians are working on cables in the fi eld versus 25% of failures mid-cable where technicians likely have had little interaction with the cable. Clearly, the act of working on the cable in the field can introduce failures. Explanations for the midspan failures include mechanical damage before or during installation, incorrect application, manufacturing defects, or simply random failures without a clear reason.

We next characterized and plotted the proximate causes of failure (Figure 8). Reviewing the proximate causes of failure revealed several interesting trends. Assembly mistakes cause 43% of failures commonly found. This indicates a lack of effective communication between manufacturers and

installers or in training of jointers. Another 40 percent is due to preventable damage to the cable, either from moisture or mechanical damage. Small percentages can be attributed to contaminants, circulating currents, and overheating.

What is missing from this picture is the detail of what is causing these failures. Proximate cause provides insight into what happened, but often lacks the complexity of the full reasoning behind a fault. Looking at the ultimate causes of the sampling (Figure 9), we see that the vast majority of faults can be attributed to workmanship errors. Th ese include errors in jointing due to negligence or inexperience, as well as sloppy work and lack of care. Six percent of failures were due

Figure 6: Failure Rate by Insulation Type

Figure 7: Fault Location

Figure 8: Proximate Causes of Failure

Review Equipment Selection

Discuss with Manufacturer

Assess for Mechanical Damage

Review Instructions/Procedures

Retrain Jointer

Perform Visual Inspection

Condition Assessment, Similar Comp.

Consider Replacement

to age, which is lower than expected based on the correlation to the Weibull distribution discussed earlier. Manufacturing defects presented about 11% of all ultimate causes, which is higher than expected. Th ese range from contaminants in the insulation to violation of conductor spacing requirements in the brand new cables. In just 4% of cases, no ultimate cause was found, which suggests steps can be taken to address the vast majority of cable failures.

Perform PD Mapping

Based on the ultimate and proximal causes of failure, several standard recommendations would help prevent future failures (Figure 10). The most commonly recommended

Retrain Jointer

Review Instructions/Procedures

Discuss with Manufacturer

Review Equipment Selection

Discuss with Manufacturer

Assess for Mechanical Damage

Review Instructions/Procedures

Retrain Jointer

Perform Visual Inspection

Condition Assessment, Similar Comp.

Consider Replacement

Perform PD Mapping Retrain Jointer

Manufacturing defect in cable 5% Contaminants 1%

action was to perform partial discharge mapping regularly. Partial discharge is cyclic breakdown of part of the insulation system due to a localized electric field greater than the dielectric withstand capability of that part, while the overall insulation system remains capable of withstanding the applied electric fi elds. Partial discharge, commonly found surrounding voids in the insulation, produces a variety of detectable byproducts such as heat, light, sound, scent, electromagnetic waves, and a high frequency electric current. Since the prevalence of partial discharge can indicate issues with insulation quality, routine partial discharge mapping can help clients plan for outages to address issues before they escalate. Cable partial discharge testing can provide data about how aging and conditions have affected installed cable and help prioritize replacement and repair.

Replacement is a commonly recommended action, yet it is regarded as only one of many options. The prevalence of partial discharge mapping and condition assessment recommendations suggests that proper asset management techniques can help prevent untimely replacement of working equipment by providing additional information about its operating condition. Discussing the fault with the manufacturer was also commonly recommended. By having clear and open

Figure 9: Ultimate Causes of Failure

Figure 10: Recommended Actions for Existing Equipment

communication with the manufacturer, installation errors or application errors are less likely. Similarly, since 11% of faults occur because of manufacturing defects, it is important to have clear quality expectations for the manufacturer. Providing feedback on failed components can prevent future quality issues from costing the user so much long term. Visual inspection is relevant for some faults, but it is considered to be of a limited value since most problems are hidden. This reinforces the value of partial discharge mapping, which provides data about cable condition and longevity that cannot be gathered from visual inspection alone.

Recommendations aimed at preventing failures in future installations (Figure 11) center around providing high-quality training for jointers and ensuring that instructions and procedures are clear and set the technician up for success. Well-trained jointers are key to having a reliable system because such a high percentage of faults can be traced to jointing issues. Talking to manufacturers throughout the process of a program upgrade can ensure instructions are being accurately followed. Finally, choosing the correct equipment for the application is frequently recommended since application errors caused about 4% of the failures from this sampling.

EXAMPLES

The first example is an 11 KV PICAS to XLPE branch adapter that failed one hour after installation (Figure 12). The proximate cause was determined to be incorrect positioning of the adapter tubes. Therefore, workmanship errors were determined to be the ultimate cause of failure. Investigation found many quality issues: Shear bolts were misaligned, there was no putty in the shear bolts, the tubing was poorly cut, and there were gaps in the insulation throughout the sample. Common recommendations for these conclusions include retraining the jointers and assessing the components as a part of the project. This example highlights that finding and fixing the

Number of times recommended

Review Instructions/Procedures

Discuss with Manufacturer

Review Equipment Selection

Number of times recommended

Figure 11: Recommended Actions for New Installations

Figure 12: XLPE-PICAS Joint

Figure 13: Failure Location on 33KV XLPE Joint

proximate cause of the failure is not adequate. Several mistakes all could have led to failure had the first cause not been present. By addressing the ultimate cause of jointer training, all of the workmanship issues and potential failure points would be addressed.

The next example explored a 33KV XLPE joint that failed after 18 months in service. The fault hole is visible through the insulation in Figure 13. The failure occurred because the jointer did not properly deburr a connector. The sharp edge caused mechanical damage and created a concentration of electric fields in the damaged insulation. The takeaway: Poor understanding of instructions, lack of attention to detail, and lack of training all contributed to the failure of this joint.

The final example explored an 11 KV PILC cable that experienced a mid-cable failure after 47 years of service (Figure 14). This failure is a result of age-related partial discharge. Although this cable was in service for an appropriate life span, it is an example of how partial discharge mapping could have prevented an unplanned failure. Catching the partial discharge earlier

would have allowed the client to plan an outage to address the issues.

CONCLUSIONS

With cable failures costing clients significantly every year, identifying trends in occurrences can help reduce future failure-related costs. Forensic analysis allows the community to learn from past failures to promote a more reliable and robust system. Th e following conclusions were drawn from the investigation of 73 forensic analysis reports:

• Cable faults follow a predictable reliability curve and generally can be expected to fail within the first 10 years or after 40 years in service. With about 35% of failures occurring in the first ten years, it is vital to install cables carefully to prevent the majority of infant mortality-related faults.

• Ensuring installations are done following clear and accurate manufacturer’s instructions can prevent ⅔ of faults.

• Since human error is inevitable in every field, a proper asset management program founded on partial discharge testing can help identify and prioritize issues as they develop.

Furthermore, since faults are inevitable, performing a forensic analysis post-mortem can help diagnose the causes of failure and identify trends in the failures associated with a company and suppliers. Although universal trends were shown through these reports, these do not necessarily indicate that every company should prioritize the recommendations in the same manner. For example, Company A may have excellent jointers but poor quality cables; Company B may have the highest quality components, but a few subpar practices are affecting their installations.

A custom assessment and recommendations may expose problems specific to your company or installations. Forensic analysis provides a much more detailed analysis than field review and can even help prevent future failures by looking

Figure 14: Failed PILC Cable

deeper than proximal causes. Even in cases where there is no evident root cause, every investigation adds to our knowledge base and helps us create more reliable systems in the future.

Kelly Higinbotham started her career at Burns & McDonnell as a Substation Engineer in 2018 following graduation from the University of Connecticut with a BS in electrical engineering and a minor in mathematics. She is an Engineer in Training (EIT) in the state of Connecticut and looks forward to pursuing her Professional Engineer license in the next several years. Outside of her professional commitments, Kelly serves as an Alumni Advisor for the University of Connecticut chapter of Phi Sigma Rho, a national sorority for women in engineering.

William G. Higinbotham has been President of EA Technology LLC since 2013. His responsibilities involve general management of the company, including EA Technology activities in North and South America. William is also responsible for sales, service, support, and training on partial discharge instruments and condition-based asset management. He is the author or co-author of several industry papers. Previously, William was Vice President of RFL Electronics Inc.’s Research and Development Engineering Group, where his responsibilities included new product development, manufacturing engineering, and technical support. He is a senior member of IEEE and is active in the IEEE Power Systems Relaying Committee. He has co-authored a number of IEEE standards in the field of power system protection and communications, and holds one patent in this area. William received his BS degree from Rutgers, the State University of New Jersey’s School of Engineering, and worked in the biomedical engineering field for five years prior to joining RFL.

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A NEW WAY TO TEST DISTRIBUTION AUTOMATION SCHEMES

BY ROBERT WANG, OMICRON electronics Corp. USA

With an ever-growing demand for a more reliable distribution grid, utilities are constantly looking for possibilities to optimize their distribution networks by implementing distribution automation. One method to improve the network and reduce permanent outages is using pole-mounted reclosers, due to their wide range of functionality. By introducing built-in voltage sensing on both source and load sides, automation can easily be achieved by using local, built-in logic to isolate a faulted section and closing in a tie recloser to supply power to customers from an alternate source.

Automation schemes utilizing coordinated protection functions provide an easy and lowcost solution to improve reliability. However, the process of isolation and service restoration can take up to several minutes. For critical feeder lines where long, temporary outages are unacceptable, reclosers equipped with highspeed peer-to-peer communication provide

possibilities to locate, isolate, and restore power to unfaulted sections within seconds or faster. With the American Recover and Reinvestment Act of 2009 providing $4.5 billion to the U.S. Department of Energy to modernize the electric power grid, most of the funded SmartGrid projects include communicationassisted distribution automation.

To put such projects into operation, utilities often rely on manufacturers to design and implement the automation scheme. Thorough testing of the entire scheme prior to installation is critical to ensure that the switching logic works as desired for the multitude of fault scenarios that may affect the network and verify that the communication equipment can support the resulting network traffic. The testing process is integral for the verification of the system, but can also be extremely complex, labor intensive, and time-consuming. Th is article suggests an easy-to-apply method to test any distribution automation network that can significantly reduce testing time. At the same time, it covers parameters that can verify correct operation of distributed automation schemes, which are typically not included in routine conventional testing.

FEEDER AUTOMATION CONFIGURATION EXAMPLE

There are many ways to automate feeders using reclosers. One commonly used method is to

connect two feeders at an interconnection point (R5) using a normally open recloser (Figure 1). While the number of reclosers used in the scheme may vary, this example provides a general idea of the concept.

If a fault occurs (Figure 2), R3 must trip first to interrupt current flowing into the fault. To isolate the faulted section, R4 should open next. The feeder supplied by Sub 2 should then be checked to verify that it can supply the additional load between R4 and R5. If the load can be supplied, the normally open R5 will close, restoring power to customers who would otherwise be left out of service.

PHOTO: © ISTOCKPHOTO.COM/PORTFOLIO/METAMORWORKS

Figure 1: Typical Feeder Automation Example with a Tie Recloser

Now that power is restored to customers between R4 and R5, R3 will try to reclose to verify whether the fault was only of a temporary nature.

Achieving this type of functionality can be done in a variety of ways. The simplest method is to rely only on local logic in each recloser; this logic is based on a voltage function. In case of a permanent fault, recloser R3 will typically try to reclose until lockout. Meanwhile, a timer in R4 will initiate after it detects a permanent loss of voltage and eventually open after a set amount of time based on protection settings. Since R5 has lost voltage on one side, an undervoltage timer will start to count and will close after a defined time.

Purely based on voltage logic, this scheme will typically take a minute or more to restore power to non-faulted sections, which may not be acceptable for critical feeder lines. Th is isolation and reconfi guration process can be significantly improved by using communication to or between the reclosers in the field. In case of a fault, the recloser could then quickly send an open or closing signal to downstream and tie reclosers.

COMMUNICATION PLATFORMS AND PERFORMANCE

The automation scheme’s performance greatly depends on the communication platform. A wired network using fiber-optic cables is one of the fastest solutions available, since it offers high bandwidth and low latency. However, implementing schemes with new fiberoptic networks can be very expensive, and

considerations must be made for the number of protection devices and the distances between protection devices. An alternative solution is to use wireless networks, which can be easily established and expanded and can fulfill both bandwidth and latency requirements. Utilities often have a choice to use public or private wireless networks. When deciding whether to implement a public or a private network for communication, a number of factors must be considered. Cost certainly is one factor, but service availability and coverage are also very important. Aside from the communication platform, the performance of the scheme also depends on the number of connected devices, the communication distance, and certainly the communication technology.

TESTING PROTECTION FUNCTIONS

If the scheme’s protection is not based on communication or distributed logic, testing the protective functions of the recloser control can be performed with minimal eff ort via secondary injection testing for individual recloser controls. Some test sets can be universally connected to the control cable interface of any recloser control with short recloser-specific adapters. Some simulate the recloser with up to six voltages and enable three-phase testing of the controller in both lab and field environments.

TESTING DISTRIBUTION AUTOMATION SCHEMES

Testing a distribution scheme with communication and distributed logic verifies the correct functionality of all protection devices in the scheme. A distribution automation scheme can be implemented with hundreds of lines of custom logic code in the recloser control and/or a programmable automation controller. Before a scheme is deployed in the field, it should be thoroughly tested to ensure that the scheme operates as expected, especially once it is put into operation. When a fault occurs, the distribution

Figure 2: Fault Location, Isolation, and Service Restoration in Case of a Fault

automation scheme must identify the location of the fault, determine the best way to clear the fault, and restore the unfaulted line segments through various switching sequences. These switching sequences must also be tested to fully verify the functionality of the scheme.

TYPICAL SCHEME TESTS IN A LAB

To test a distribution automation scheme in a lab, all devices are set up in a test environment. These tests are typically performed as a proof of concept for new projects or for acceptance testing a scheme prior to installation in the field. Using secondary injection test devices connected to each recloser control, various preprogrammed test sequences can be executed to test the logic and the communication, which are essential to the scheme (Figure 3).

Scheme testing can be complex (Figure 4), and may require weeks to complete. To simulate realistic faults in every fault scenario, load and fault values for each operating state must be calculated for every recloser in the scheme. To execute each test case, vocal coordination to turn injection from each test device on and off at designated times to simulate each step of

the test case is required. Any mistakes or miscoordination among test personnel would result in an inaccurate test. After execution, results from each location must be collected, merged, and assessed. If any issues are discovered, the automation logic must be adapted to address the problems.

To synchronously test a scheme involving several reclosers, a single test device can be assigned for each recloser location, which then requires synchronization (e.g., via a GPS or IRIG-B signal).

SHORTCOMINGS OF A TYPICAL LAB TEST

Th is method has proven to work well for lab testing. However, it comes with several disadvantages: The expected test values have to be calculated and programmed into a sequence for every single test device — a very time-consuming process. After running the test, additional time must be spent comparing the time stamps of each test result from each diff erent testing device. All this eff ort can represent additional complications.

Two factors that can influence the performance or even the basic function of the scheme must also be considered. When distribution automation schemes are installed in the field,

Figure 3: Secondary Injection Test Device Connected to Recloser Control

Figure 4: Typical Lab Setup

distances between the individual reclosers can be much farther than when testing in a lab environment. Longer communication distances with possibly weak communication links and waveforms of faults that are different from static fault values can drastically affect the operation and testing of the scheme.

INFLUENCE OF COMMUNICATION EQUIPMENT

Communication equipment used in automated high-speed distribution automation schemes is a critical component. The performance of the scheme greatly depends on the selected communication media, which defines how fast and how much information can be transmitted from one device to another. Only certain technologies provide enough bandwidth, security, and reliability to transmit wirelessly (e.g., an IEC 61850 GOOSE message). Other commonly used wireless transmitting technologies include WiMAX, LTE or 4G.

Transmitting and receiving functions can be affected by greater distances in field installations. In the case of a weak link or overflow on the communication channels, the automated scheme might fail. For this reason, synchronized injection testing into all devices

in the field is recommended to test the scheme under real-life conditions.

TRANSIENT WAVEFORMS

A test under real-life conditions requires the test values to match those of a real fault as closely as possible. With conventional testing methods, static fault values are typically applied, and the resulting reaction from the recloser control is measured. Under realistic fault conditions, a dc offset is present, and depending on the algorithms of the recloser control, one device in the scheme might detect the fault faster than another. To determine the real performance of the scheme, it is beneficial to test with transient signals.

NEW APPROACH FOR SCHEME TESTING IN THE FIELD

Using new software solutions, distribution automation schemes can be tested in the lab or the field while remotely controlled from a single PC. In addition to addressing the issues described previously, this greatly reduces the testing time while providing comprehensive reporting and troubleshooting options.

A power system under test can be modeled in a single-line diagram editor (Figure 5), and devices such as reclosers and circuit breakers can be placed in the network. Infeeds are defi ned by entering the source-impedanceratio (SIR), the line data calculated by using line length and impedance, and loads in the network specified using active and reactive power data. Using this information, the software can calculate the resulting load and fault values for any user defined test case.

The behavior of circuit breakers and/ or reclosers should be defi ned within the simulation software. If the circuit breaker and/or recloser opening and closing times are known or have been previously measured using a breaker timing test device, the software allows the input of those times, which are taken into consideration to ensure a more realistic test. Secondary injection test devices have a built-

Figure 5: Power System Model Using Software

in circuit breaker simulator, which can be extremely beneficial for testing purposes. Using the binary outputs of the test device, the 52a and 52b contacts can be simulated without requiring the circuit breaker or recloser to be connected during the test.

For a lab or field test, a single test set must be connected to each recloser control or relay to inject the appropriate current and voltage inputs and binary inputs (52a/b), as well as receive the resulting binary outputs (trip/close commands). However, when performing a field test, protection points can be located several miles from each other. The system must use either an existing communication network or an external cloud service with remote connection. In this case, all testing devices must be synchronized to GPS for time-synchronized injection (Figure 6).

Once GPS synchronization is established, test devices in the scheme can communicate with each other, as well as with the associated PC running the simulation software over the network. The PC must have access to the network to establish communication with all the test devices. Individual GPS antennas are used to synchronize all test devices at each protection point.

For each test case, a fault can be defi ned within the single-line diagram of the scheme; the software then calculates the resulting fault values for each device at each location. When the test is executed, the software sends the calculated test values into all test sets. Once all the test values at the test devices have been received, the injection begins synchronously.

A closed-loop test would be ideal; after a device issues a close or open command, the software would calculate new values taking into account the changed values after, for example, a breaker opening. This is not possible with a distributed test. When this mode is enabled, the software runs the first test; once a device under test in the scheme reacts, the software recalculates the test values taking this operation into account. It is assumed that a device under test will always react in the same time if the same test values are applied.

Figure 6: Typical Setup for GPS Time-Synchronized Transient Simulation Test of Recloser Controllers Using a Test Device at Each Protection Point

After resetting the scheme, the test is then repeated as the second iteration. The software automatically repeats the calculations after each iteration, taking all breaker and recloser operations into account. This iterative process will continue to reset and run until the system under test no longer reacts. This is typically the case once the fault is isolated and power is restored to segments of the network that are not affected by the fault.

Using this test method, the correct switching behavior of the scheme can be assessed, and it is immediately clear whether the communication equipment can handle the amount of data once the equipment is installed in the field. Thanks to transient test signals, the overall performance of the automation sequence can be measured and assessed. Furthermore, it can be determined whether corrective measures to improve the performance of the system need to be implemented.

CONCLUSION

Th e method and testing process described in this paper are easily applied and allow communication-based automated distribution schemes to be performed in a lab or field

environment to verify the switching logic, the communication equipment, and the communication network’s ability to handle the data traffic. By also using transient test values, the actual performance of the scheme can be evaluated. Results could also be used to compare diff erent communication technologies. By using the iterative closed-loop approach, switching operations don’t need to be defined prior to the test. The software will learn the behavior of the scheme for a certain fault, and the engineer is only required to assess whether the switching operations were performed correctly by the devices under test.

REFERENCES

U.S. Department of Energy, “Recovery Act: SmartGrid Programs,” www.smartgrid.gov/ recovery_act/.

Newton-Evans Research Company, “Distribution Automation: Communications for Feeder Automation Survey,” www. newton-evans.com/distribution-automationcommunications-for-feeder-automation/

OMICRON Energy, “ARCO 400 – The Future of Recloser Testing,” 2016 www.youtube.com/watch?v=9h2yQ2sJeUo.

Robert Wang is a Training and Application Engineer at OMICRON electronics Corp. USA, where he functions as a Regional Application Specialist and Application Engineer with particular interest and focus on distribution automation and power system reliability. He is a member of IEEE PES. Robert received a BS in electrical engineering from the University of Massachusetts Amherst and completed his MEng in power systems engineering from Worcester Polytechnic Institute.

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ENSURE EFFECTIVE ACCEPTANCE

AND MAINTENANCE TESTING WITH QUALITY REPORTING AND ANALYSIS

BY STEVE PARK, Electrical Reliability Services — a Vertiv Company

Coming up through the ranks in the power industry, I quickly realized I didn’t know what I didn’t know! There are so many facets of the power industry: generation, protection and controls, distribution and delivery, reliability, drives, uninterruptable power supplies, system studies, safety, maintenance, testing, as well as other areas that are vital for the safe and reliable delivery and utilization of electric power. How power is used also varies greatly. The power system in a steel mill is different than one in an automotive assembly plant or a data center or a wind or solar farm. They all may use similar components (cables, circuit breakers, fuses, disconnects, transformers, etc.), but the size and complexity of the systems can be very different. As such, acceptance and maintenance testing requirements and complexity will also vary. This paper focuses on how to ensure electrical maintenance and testing projects are effective and provide the information needed to assess the condition of power system assets.

ESTABLISH A TESTING AND MAINTENANCE PLAN

Before discussing project documentation such as test data and reports, an adequate testing and maintenance scope must be established. Many resources can help identify and define which electrical maintenance tasks and testing should

be performed on electrical assets. The most frequently referenced sources are the ANSI/ NETA ATS-2017, ANSI/NETA MTS-2019, and the National Fire Protection Association’s NFPA 70B, Recommended Practice for Electrical Equipment Maintenance. Another source for testing and maintenance recommendations is the equipment manufacturer’s literature.

With all this information at your fingertips, determining which tests to perform, on what equipment, how often, and how to interpret results might be easy — but not necessarily. Those who have reviewed those documents know it is not that clear and concise. The manufacturer’s literature — while the best and most specific source of recommended maintenance and testing for a given asset — is not always readily available and does not always provide specific recommended practices. NFPA 70B and the ANSI/NETA testing specifications, while based on common practices in the industry and available manufacturer recommendations, do not always agree 100%.

Additionally, while these documents provide a good basis for which maintenance and tests should be performed, they do not cover the details of proper test techniques.

They also do not consider the type of power distribution system or the criticality of the equipment. Some systems may include redundant feeds and transformers to increase their reliability and decrease the impact should equipment fail. Equipment supplying power to critical infrastructure may require more maintenance and testing than equipment feeding administrative offices. To ensure an effective testing and maintenance program, the following factors should be considered as you assemble the list and frequency of tests and maintenance tasks to be performed.

1. Criticalness of equipment served

2. Age of equipment

3. Condition of equipment

4. Operating environment of equipment

5. History of equipment

6. System configuration

Substation Maintenance Services

INDUSTRY TOPICS

Businesses operate within a limited budget and can typically only support equipment outages for limited time periods. Therefore, budget and time constraints must be considered when determining which equipment should be tested and what tests and maintenance tasks should be performed.

Testing and maintenance is about risk aversion. The expected level of reliability (or failure) must be established to determine the testing and maintenance scope. When high reliability is required, the system must be designed with adequate redundancy, and certain testing and maintenance tasks must be performed to ensure the proper operation of the primary and redundant system components. If a high level of reliability is required from a system design that lacks sufficient redundancy, additional or more detailed testing and maintenance (time and money) will be required. When considering these important factors and decisions, it is often advantageous for the owner to work with a testing and maintenance service provider to establish a customized scope of work for a testing and maintenance program.

EXECUTE THE PROJECT

Once a testing and maintenance program including scope, test specifi cations, time, and duration has been developed, it is time to release the project for bid, evaluate proposals, and select the best candidate to execute the work. Once a testing fi rm is selected, the owner must ensure all key requirements of the project specifi cations are understood to avoid issues during the execution of the project. Any deviations or alterations should be discussed and agreed to before project execution begins. Th is is the ideal time to ensure all inspection, testing, and maintenance actions are documented and included in the fi nal test report.

Once a larger project begins, times must be established for the owner and the service provider to discuss activities, schedules, and findings. These discussions may not be necessary on smaller projects unless something is discovered that aff ects the ability to reenergize the system or places the system at risk as a result of deterioration or equipment otherwise not suitable for return to service.

Reliable and accurate documentation of test procedures and test data is vital to an effective testing and maintenance project. Depending on the apparatus and tests being performed, variations of a given test or test procedure may be applied. Some tests or procedures will yield similar and accurate results, while others may not provide the expected results or may include or exclude components that affect the results. The person witnessing the testing should be familiar with the test methods outlined in the project specifications. There are times when shortcuts are permitted due to outage window or other site-specific conditions, but the impact and ramifications of these shortcuts must be understood and approved.

To ensure tests are performed correctly and the test results are accurate, the owner should assign a project manager with a strong background in testing and maintenance to all testing and maintenance projects. If the owner’s project

UPS Maintenance and Data Collection

manager does not have a strong background in this field, it may be in the owner’s best interest to hire a third-party project manager.

DOCUMENT THE PROJECT

Reporting and documenting a testing and maintenance project is critical. The test report, which summarizes project activities, test data, analysis, and recommendations, communicates the test results. Other than test stickers, the report is the only evidence that electrical testing was performed.

Th e test data documentation process must be accurate and reliable. Testers must record values accurately and with minimal errors. Measurement values and units, as well as any observations, must be recorded. The tester’s experience level can make a significant difference in the quality of the project’s documentation. In addition to performing the electrical tests, an experienced tester will carefully examine the apparatus and note any signs of damage, deterioration, excessive wear, excessive heating, etc. These inspections should be clearly documented on the test data sheet. The equipment owner should assume that if the inspections and tests are not documented, they likely did not occur.

During the project, test data must be constantly reviewed by the technician to ensure all test parameters are met and any equipment with concerning test data is immediately identified and brought to the attention of the owner. This is where the guidance of a Level III or Level IV certifi ed technician is required. Senior testers can ensure the data is accurate and make sound recommendations based on their years of experience. When less than acceptable test data is discovered, an immediate retest is often warranted to verify the data and ensure the test data has not been affected by a test method, a test equipment defect, or other external influence. Once the test data is verified, the project lead and owner representative must communicate to determine the best course of action. This frequently does not happen.

Topics discussed in these conversations and any recommendations should be included in the project’s formal test report.

The documentation process must involve minimal transcription of information from one source to another to avoid introducing additional errors. If documentation is performed using pencil and paper forms, the report should contain a copy of those same paper forms. Errors are often introduced by transcribing paper forms onto an electronic data form or database. While some testing companies continue to use paper test forms on the project and then input the data into a computer system at a later time, the most accurate and efficient process involves direct input of test data into a reliable database during testing. The key to success in using a data management system is to use standardized forms and a common database where all data can be stored, backed up, mined, and retrieved. This database should not reside solely on a local laptop or office computer; it must be synchronized to a commercial data architecture system with redundancy and regular backup processes to avoid losing the data or placing the data at unnecessary risk of corruption.

STANDARDIZED REPORTING

While the general format of test reports varies from vendor to vendor, basic sections and content should be included. At a minimum, the report should contain:

1. Project summary

2. Description of equipment tested

3. Description of tests performed

4. Protective device settings

5. Test data

6. Test data analysis, evaluation, and recommendations

Within the test data sheets, additional information such as testing organization; clear identification of tested equipment using client names and facility references; pertinent equipment nameplate data; ambient humidity and temperature at time of test

at the test location; project date(s); test equipment calibration information and/or dates (if required); person performing the tests; documentation of inspections, test, maintenance, and calibration performed; documentation of as-found and asleft settings and test results; and observations and comments should be included.

QUALIFICATIONS

Adequate experience and qualifi cations of the testing firm and testing technicians are of paramount importance. Two U.S. qualification agencies are widely accepted: the InterNational Electrical Testing Association (NETA) and the National Institute for Certifi cation in Engineering Technologies (NICET). NICET and ANSI/NETA have established four test

technician certification levels. While large or complex projects may require one or more Level 4 technicians to lead and manage the project, most testing projects can be successfully managed by one or more Level 3 technicians. NETA Level 2 technicians are often capable of performing most testing independently and with little supervision. A Level 1 technician can work as an assistant under the direct guidance and supervision of a more experienced tester.

Qualifications and experience can make a signifi cant diff erence in the quality and success of an acceptance or maintenance testing project. If the owner wants to know everything possible was done to ensure the reliable operation of their electrical equipment, confi rming that the testing company and technicians have adequate qualifications and experience is vital to the accuracy of the results and owner’s peace of mind.

Test technician qualifications are important, but the testing firm must also provide oversight and a thorough review and analysis of the test data. This review typically involves a team of the firm’s subject matter experts not engaged in the testing procedures. The team not directly involved in the testing project usually includes experienced testers, technical writers, and engineers who examine the test data, identify documentation errors, and ensure that any test data not meeting the established project standards is identified. Data not meeting the project standards must be clearly called out in the report, and recommendations for corrective actions should be included.

The test report should provide vital information about the continued reliable operation of the tested electrical equipment. However, it does take time to assemble a comprehensive and accurate report. The delay between performing the testing and issuing the report can be critical if defects or deficiencies are discovered during testing. The owner must ensure that any issues discovered during testing are brought to their attention immediately during the testing phase of the project. This allows the owner time to address any issues while the test team is on site

Circuit Breaker Maintenance Testing

and the equipment is de-energized. If good communication is established during a project testing phase, the test report should not contain any surprises.

Report turnaround time can vary from project to project depending on complexity and size. For large, ongoing projects, periodic reports can be provided on an established schedule (weekly, bi-weekly, monthly) or by progress (completed substation). For smaller projects, reports should be available in a matter of days unless additional test information such as laboratory liquid analysis or other specimen tests must be performed. For medium to larger projects, a turnaround of two weeks is considered reasonable.

Smaller projects may not contain large amounts of complex data or recommendations, but larger projects can contain a mountain of data and recommendations. This amount of data can be overwhelming to review, understand, and digest. For larger projects containing complex testing, the test provider should arrange a follow-up meeting to review the report and outline any critical recommendations or corrective actions. Interpretation and explanation of the data to provide a better understanding is often included during this meeting.

CONCLUSION

Effective acceptance and maintenance testing of electrical equipment and systems starts by using experienced and qualifi ed testing technicians and testing companies that have established reporting systems and procedures. These procedures dictate:

• Identify data to be evaluated during the testing process.

• Immediately identify assets that are defective or produce concerning test results and bring them to the attention of the owner throughout the project.

• Conduct an internal review process using a knowledgeable and competent team — independent of the test technicians — to

ensure all data and recommendations are accurate. This is extremely important to ensure substandard equipment is not unknowingly returned to service.

• Hold a final project review meeting with the owner to present the final report and analysis.

Th e owner is assured the highest level of confidence if they know that the test data has been accurately recorded, managed, and stored in a database that permits quick recall, trending, and data mining. This data is a key asset for owners as they plan for the most effective condition-based maintenance cycle. It can help them identify equipment reaching end-of-life and plan for system upgrades.

Choosing a service provider with the experience, qualifications, test data management, and established internal review systems outlined in this article has an impact on the cost of the project, but a higher level of system reliability and operational assurance is gained. The old adage, “You get what you pay for,” comes to mind.

Steve Park, PE, is Director, Engineering and Technical Services at Electrical Reliability Services, a Vertiv company, where he provides expertise and leadership for sales, marketing, training, and operations, serves as the lead technical writer, and conducts technical and commercial seminars for internal and external customers. Steve has over 40 years in management, leadership, and operational experience in the design, maintenance, testing, and engineering of low-, medium-, and high- voltage power systems and apparatus. He is an SME in power system maintenance, management, equipment testing and evaluation, system studies, electrical safe work practices, and medium-voltage cable testing. Steve led two major operational and organizational changes involving extensive change management of operational systems and processes including establishing a unified data collection and management system for over 40 geographically dispersed offices and creating a centralized engineering and technical support department. He is a former Service Center Manager responsible for sales and operations. Steve is a Professional Engineer, a Level 2 Test Technician, and is OSHA 30 qualified. He received his BS and MS in electrical and electronics engineering from Purdue University and an MBA from Indiana Wesleyan University.

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LEARN WHAT YOUR OIL RESULTS REALLY MEAN.

DOBLE LABORATORY DIAGNOSTICS SEMINAR AT POWERTEST 2020 | FEBRUARY28, 2020

Join us for a one day laboratory seminar on Friday, February28 at PowerTest 2020. Doble’s laboratory expert will present an interactive session that combines theoretical background with practical experience. We will share case studies illustrating common problems found in the field.

• Understand how to determine the condition of electrical apparatus using laboratory tests

• Discover how knowing about aging characteristics of insulating materials can help you extend asset life

• Learn how to take oil samples, avoid common pitfalls, save time and save money by sampling only once

•Detect the presence of incipient-fault conditions and categorize them

• Find out how to assess the condition of the paper insulation

• Establish the correct method of analyzing moisture-in-oil results

• Study the significance of dissolved metals, particulate metals and other particle contamination

• Learn about the quality of new and service aged oils

• Learn how to identify and mitigate issues with corrosive oils

PAR TI CIPANT S W IL L

COMMUNICATIONS SECURITY FOR FIELD TESTING ORGANIZATIONS

BY GOWRI RAJAPPAN, Doble Engineering Company

Cybersecurity is one of the greatest challenges to grid reliability. As more facilities and devices become IP-routable communications-enabled, the threats multiply along with the incredible productivity gains. This additional complexity impacts the work of field testing organizations in the form of a bewildering milieu of new technologies, processes, and regulations. Without awareness of the threats and security best practices, it is easy to feel lost in this complex new reality. This article attempts to fill the knowledge gap by describing real-world cyber threats and how they can impact communication-enabled grid assets. This article discusses best practice countermeasures and what field testing organizations can do to improve security while ensuring that work still gets done.

ADVANCEMENTS IN INDUSTRY

CYBERTHREAT LANDSCAPE

The energy sector is among the most frequently targeted critical infrastructure sectors. Advanced persistent threats (APTs) — defined as targeted attacks by technologically sophisticated, well-funded, and motivated groups, often with the backing of a state actor — have multiplied in recent years, and now constitute the greatest challenge to grid cyber security. In the early years of this decade, only one or two such successful attacks were detected, most notably the Stuxnet attack in 2010 that took out up to a fifth of Iranian nuclear centrifuges. But over the course of this decade, such attacks have multiplied manifold.

One well-studied APT is the 2014 attack by the group variously known as Energetic Bear (because it was thought to target energy sector entities), Crouching Yeti, and Dragonfly. The purpose of the attack was cyber espionage (i.e., data theft),

Energetic Bear group

and so its visible impact wasn’t nearly as severe as the better-known cyberattacks against the Ukraine power grid, but the details of the attack are instructive and resemble other APTs.

Figure 1 shows the various elements of this attack. In general, the various stages of an APT are reconnaissance, social engineering/ phishing, lateral movement, data destruction, and ultimately, an industrial control system (ICS) impact. Reconnaissance may involve identifying approved vendors from websites (company website, vendor news releases, etc.); company assets, locations, and power system information determined from regulatory fi lings and other such public information; and employee information from the company website and social networks such as LinkedIn. Th e objective of the reconnaissance is to identify employees who may get the attacker closer to target assets and systems.

Software update compromised with Trojan

Malware installed on industry website using exploit kit

Industry website

Malware modules and updates made available via command and control server

Compromised web server used for command and control

Spear-phishing email with malicious PDF attachment

Victim visits website and downloads malware

Target

Software update server

Information sent to command and control server for retrieval

Industrial control system (ICS)

Malware performs ICS device discovery

Victim downloads software with Trojan Malware installs and runs downloader to obtain further modules

OPC (open platform communications) server

Figure 1: Dragonfly / Energetic Bear / Crouching Yeti Attack

SOURCE: DR. RICHARD PIGGIN

Th e next step is to target these identifi ed employees through social engineering. This may be in the form of spear phishing, where employees receive a legitimate-looking email — for instance, one that looks to the undiscerning eye to be from a trusted vendor announcing their user conference with a PDF attachment of the conference program. The PDF attachment in this case could be the actual conference program so that it doesn’t cause any suspicion, but it would be altered (weaponized) to include a malware that would infect the computer of any email recipient who opens the weaponized PDF.

The infected employee computers then serve as the staging for further reconnaissance from within the network. This next recon phase may involve techniques such as network scanning to identify assets and keystroke loggers to record user keystrokes and harvest sensitive information such as login credentials. Th e attackers use these launch points to move through the network and possibly erase or alter log files to avoid detection. Once they are able to identify a trusted link to the ICS network, such as the one between the corporate and control center historians, they may be able to exploit any available application vulnerability to enter the ICS network and compromise the control systems. With a higher degree of penetration of IP-based communication all the way down to the substations, such attacks now have the ability to propagate deep into the control and process zones of the utility organizations.

CYBERSECURITY COUNTERMEASURE

Defense in Depth is a key countermeasure strategy to secure communication-enabled systems. According to the NSA (National Security Agency), this is a practical strategy for achieving information assurance in today’s highly networked environment. As shown in Figure 2, Defense in Depth requires balanced focus on People, Technology, and Operations to ensure that defenses exist in all three dimensions. Th is is akin to castle defense,

ADVANCEMENTS

Information Assurance

Defense In Depth Strategy

People

Technology Operations

Robust and Integrated Set of Information Assurance Measures and Actions

where multiple layers of defense such as walls, watchtowers, and moats prevent unauthorized ingress. Examining how Defense in Depth strategies might apply to communicationenabled systems demonstrates that two aspects need to be secured: the communication itself and access to the device.

Data communication should be secured at multiple levels, in keeping with the Defense in Depth strategy. For instance, security measures should be in place for communication links as well as application traffic. Table 1 shows some of the controls that could be used to secure

Table 1: Security Controls in the 4G LTE Communication Network

Security Measure Description

Mutual AuthenticationThe network authenticates the device, and the device authenticates the network. This protects against attacks such as rogue devices or access points.

Enhanced Root Key The root key used to derive the various security keys should be at least 128 bits in length. The cellular and core network keys are cryptographically separated, thereby providing two independent layers of security.

Security ContextNew keys are derived from the master key for each data session. Separate keys are derived and used for signaling and user traffic.

Integrity ProtectionThis mechanism protects signaling. Each message is appended with an integrity tag and is accepted at the receiving end only upon its verification with algorithms such as the 128-bit Advanced Encryption Standard (AES) and SNOW3G cipher used for integrity protection.

Encryption All communications on the air interface are encrypted. The default encryption is at least a 128-bit AES algorithm.

Figure 2: The Defense in Depth strategy includes multiple layers of defense along the three dimensions of People, Technology, and Operations.

ADVANCEMENTS IN INDUSTRY

Table 2: Security Controls for the On-Demand Support

Security Measure Description

Authentication Strong user-credential management controls and policies

AuthorizationRole-based and/or attribute-based granular authorization scheme, whereby access to various modules can be controlled, and the type of access, such as read-only, can be specified

EncryptionStrong end-to-end TLS encryption

Supervised SessionAbility to supervise the session by an administrator

Session LoggingDetailed logging of all the events of a session

Session RecordingRecording capability for the remote session to show live action by the user — should contain metadata to identify the events

Audit

Auditing capabilities provided via the session logs and session recordings

the communication link. The application traffic occurs over this secure communication network and should be further secured at the application layer. This additional security consists of authentication using encrypted credentials and encrypted application payload using transport layer security (TLS). In addition, there could be an end-to-end tunnel between the endpoints.

When facilities and devices are communicationenabled, remote access is technically feasible. If an organization decides to provide remote access to certain facilities or devices, strong measures must be put in place to ensure security. Table 2 shows some of the controls that could be used.

IMPLICATIONS FOR TESTING ORGANIZATIONS

Within a typical utility, groups other than the testing organization control technology and compliance aspects of cyber security. IT may be responsible for the technology aspects, such as firewalls, anti-malware, and access control. The compliance group is responsible for determining policies other groups must adhere to. But ultimately, the testing organization works directly with these assets and must have a good understanding of the reasons for the controls and the policies.

CONCLUSION

Cybersecurity is a discipline that is here to stay and grow in importance with developments such as the adoption of IEC 61850-based digital substations and the deployment of networked sensors such as phasor measurement units (PMUs). It is important for testing organizations to recognize this and become more aware of security threats and countermeasures as it applies to their job function. As more grid assets become communication-enabled and IP-connected, testing organizations must become comfortable working within the layered defenses put in place for them and be able to identify issues that invariably arise with any such complex, multi-layered system.

REFERENCES

SANS Institute. “Anatomy of an ICS Attack.” Available at https://securingthehuman.sans.org/ cyberattackdemo.

Dr. Richard Piggin. “Industrial Control Systems and SCADA Cyber-Security,” IET Engineering and Technology Magazine, Volume 9, Issue 8, 11 August 2014. Available at https://eandt.theiet.org/content/ articles/2014/08/industrial-control-systemsand-scada-cyber-security/.

National Security Agency (NSA). Defense in Depth: A Practical Strategy for Achieving Information Assurance in Today’s Highly Networked Environments. Available at https://www.nsa.gov/ia/_files/support/ defenseindepth.pdf.

Dr. Gowri Rajappan is Director of Technology and Cybersecurity at Doble Engineering. As an expert in cybersecurity and enterprise data technologies, he leads the cybersecurity activities at Doble and chairs the IEC TC57 task group for developing a common information model standard for asset management. Prior to Doble, he worked on cybersecurity and data technologies in support of the United States Department of Defense.

ANSI/NETA STANDARDS UPDATE

ANSI/NETA ECS-2020 REVISION COMPLETED

ANSI/NETA ECS, Standard for Electrical Commissioning of Electrical Power Equipment & Systems, 2020 Edition, completed the American National Standard revision process. ANSI administrative approval was received on September 9, 2019. ANSI/NETA ECS-2020 supersedes the 2015 Edition.

ANSI/NETA ECS describes the systematic process of documenting and placing into service newly installed or retrofitted electrical power equipment and systems. This document shall be used in conjunction with the most recent edition of ANSI/NETA ATS, Standard for Acceptance Testing Specifications for Electrical Power Equipment & Systems . The individual electrical components shall be subjected to factory and field tests, as required, to validate the individual components. It is not the intent of these specifications to provide comprehensive details on the commissioning of mechanical equipment, mechanical instrumentation systems, and related components.

Th e ANSI/NETA ECS-2020 Edition includes updates to the commissioning process, as well as inspection and commissioning procedures as it relates to low- and mediumvoltage systems.

A project intent notification published in ANSI’s Standards Action on May 18, 2018, announced the intent to revise the standard. A 30-day initial ballot period and a 45-day public comment period began on April 26, 2019. A second ballot was issued July 5, 2019, and closed on August 5, 2019. The 45-day second ballot public comment period was scheduled to close on August 20, 2019. The revised edition of ANSI/ NETA ECS will be released in February 2020 at PowerTest in Chicago.

Voltage classes addressed include:

• Low-voltage systems (less than 1,000 volts)

• Medium-voltage systems (greater than 1,000 volts and less than 100,000 volts)

• High-voltage and extra-high-voltage systems (greater than 100 kV and less than 1,000 kV)

REVISION UNDERWAY

FORELECTRICALPOWEREQUIPMENT&SYSTEMS

References:

• ASHRAE, ANSI/NETA ATS, NECA, NFPA 70E, OSHA, GSA Building Commissioning Guide

ANSI/NETA ATS-2017 REVISION UNDERWAY

ANSI/NETA ATS-2017, Standard for Acceptance Testing Specifications for Electrical Power Equipment & Systems is scheduled to complete an American National Standard revision

SPECIFICATIONS AND STANDARDS

ANSI/NETA MTS-2019 LATEST EDITION

ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Equipment & Systems, 2019 Edition, completed an American National Standard revision process having received ANSI approval on February 4, 2019. The revised edition of ANSI/NETA MTS was released in March 2019 and supersedes the 2015 Edition.

process in fall 2020. A project intent notification was published in ANSI’s Standards Action on November 30, 2018. The revised standard is targeted for release in first quarter 2021.

ANSI/NETA ATS covers suggested field tests and inspections for assessing the suitability for initial energization of electrical power equipment and systems. The purpose of these specifications is to assure that tested electrical equipment and systems are operational, are within applicable standards and manufacturers’ tolerances, and are installed in accordance with design specifications.

ANSI/NETA MTS contains specifications for suggested fi eld tests and inspections to assess the suitability for continued service and reliability of electrical power equipment and systems. The purpose of these specifications is to assure that tested electrical equipment and systems are operational and within applicable standards and manufacturers’ tolerances, and that the equipment and systems are suitable for continued service. ANSI/NETA MTS-2019 revisions include online partial discharge survey for switchgear, frequency of power systems studies, frequency of maintenance matrix, and more. ANSI/NETA MTS-2019 is available for purchase at the NETA Bookstore at www.netaworld.org

ANSI/NETA ETT-2018 LATEST EDITION

ANSI/NETA ETT, Standard for Certification of Electrical Testing Technicians, 2018 Edition, was approved by ANSI as an American National Standard on February 22, 2018. It is available now in the NETA Bookstore at www.netaworld.org, where a complimentary PDF copy can be downloaded or a printed copy ordered.

ANSI/NETA ETT establishes minimum requirements for qualifications, certification, training, and experience for the electrical testing technician. It provides criteria for documenting qualifications for certification and details the minimum qualifications for an independent and impartial certifying body to certify electrical testing technicians.

PARTICIPATION

Comments and suggestions on any of the standards are always welcome and should be directed to NETA. To learn more about the NETA standards review and revision process, to purchase these standards, or to get involved, please visit www.netaworld.org or contact the NETA office at 888-300-6382.

Acceptance Testing Services

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Transfer switches • Complete maintenance of ACB’s-OCB’s-SF6 CB’s

UPS & station battery maintenance • Gen. load tests

Transformers

TTR • Power factor testing • Oil testing and field analysis

Oil reconditioning & reclaiming • field replacements

Engineering Services

Arc-flash, short circuit, and coordination studies

Power factor correction • Power quality and harmonic studies

Load surveys • Grounding system design

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ELECTRICAL MAINTENANCE: CANADA UPDATE

BY KERRY HEID, Shermco Industries Canada

There has been much emphasis in Canada recently on looking at electrical maintenance from two perspectives: safety and production. Many times, these go hand in hand. Th e standards committees in Canada are paying specific attention to devices that — when not maintained properly — can have an adverse effect on the electrical safety of workers. These include the most commonly used devices for switching the power system and protection devices that need to operate quickly during faults.

To illustrate what the industry is contemplating, let’s look at two examples of apparatus in a power system: buried underground cable and a low-voltage removable power circuit breaker. The safety and production considerations are quite contrasting.

• A buried underground cable failure would have low probability of creating a dangerous situation for a worker but could have severe ramifications to production or extended downtime. There is always a slim chance the worker is in close proximity to the failure point at one of the exposed ends; if the protection does not operate, the worker could be exposed to some energy. This would be more of a protection failure, and the probability of the worker being in close proximity at the exact time of failure is very low. However, failure of an underground cable could result in lengthy

outage time and a very adverse effect on production, particularly if the fault must be located, exposed, and repaired. Days or even weeks of lost production could result depending on how the system is designed.

• In contrast, a low-voltage circuit breaker failure due to lack of maintenance has numerous safety ramifications to the worker directly. A trip unit malfunction could produce larger than expected arc flash values due to extended trip times, could allow ground fault currents to flow, and could leave extended short-circuit currents without instantaneous tripping. A low-voltage breaker mechanical failure can be hazardous to the worker during racking or operating tasks when the worker is directly engaging with the unit. Many times, these mechanical failures go unnoticed on breakers that do not get exercised regularly, and the worker is at risk unknowingly. From a production perspective, most facilities would have a spare low-voltage breaker and would rack it in with limited interruption to production.

Clearly, there are very different maintenance objectives.

Therefore, it is critical to identify equipment within a maintenance program from a mindset of the different objectives for safety and production.

SPECIFICATIONS AND STANDARDS

The standards committees in Canada are particularly stressing the safety perspective.

CSA Z463, Maintenance of Electrical Systems and CSA Z462, Workplace Electrical Safety both address electrical maintenance. CSA Z462 places maintenance as a critical part of any risk assessment and provides safety-related maintenance requirements in Clause 5. CSA Z463 requires equipment that has adverse effects on workers’ safety when not maintained to be identified and a maintenance program to be built around that.

CSA Z463

CSA Z463 is mid-cycle, and the technical committee is just reorganizing to get ready for the next update in 2023. Since its release in 2018, the standard has been a popular seller for CSA, as many companies are using it as the backbone of their electrical maintenance program. This document requires identification of equipment that, when unmaintained, could have safety ramifications to workers. These identified devices are then required to be part of the electrical maintenance program. CSA Z463 asks users to pay particular attention to the items in the power system that can adversely affect personnel safety and ensure that a maintenance program is in place for those items. The standard indicates which tests and inspections must be performed, but it does not mandate the particular maintenance strategy, as each power system has different operating characteristics. The standard does mandate that equipment that is critical to worker safety must be part of the electrical maintenance program and not “run to fail.”

CSA Z462

not be reflected in 70E. These copyright issues are a challenge for companies working on both sides of the Canada–US border. However, the goal moving forward is to remain technically harmonized as much as possible.

Of specific note in the Z462 safety standard is that Clause 5, safety related maintenance requirements, will be revamped as follows:

1. Consolidate items that are repeated in various clauses.

2. Remove some irrelevant material.

3. Add more about maintenance of equipment that directly affects worker safety.

4. Reorganize the section.

5. Align with CSA Standard Z463, Maintenance of Electrical Systems.

The objective for this revamp is to focus on maintenance program requirements that directly support worker safety.

CONCLUSION

We continue to work in Canada to build on the understanding that electrical maintenance has objectives for safety and production. The Canadian safety standards are committed to ensuring workers can better understand the condition of equipment and how that can determine work tasks, risk mitigation, and selection of PPE.

CSA Z462 is in a revision cycle in line with NFPA 70E. Meetings will be held November 19–20, 2019, in Toronto to review changes to NFPA 70E and to update the Canadian standard. It should be noted that the copyright agreement between NFPA and CSA is not in place at this time, so future revisions to 70E will not be input word for word directly into Z462. In the same manner, changes to the new edition of Z462 will

Kerry Heid is an Executive Consultant with Shermco Industries Canada Inc. After beginning his career with Westinghouse Service, Kerry started the Magna Electric Corporation (MEC) office in Regina in 1996 and became President of the company in 2001. The company grew to over 1,000 employees and earned many prestigious awards as one of Canada’s 50 Best Managed Companies and Canada’s Top 100 Employers. MEC was acquired by Shermco Industries in December 2013. Kerry is a NETA past-President, served on NETA’s Board of Directors for over 10 years, won NETA’s Outstanding Achievement Award in 2010, and is a NETA Certified Level 4 Test Technician. He chairs the CSA Z463 Maintenance of Electrical Systems Technical Committee and has been on the CSA Z462 Workplace Electrical Safety Technical Committee since its inception in 2006. Kerry received CSA’s Award of Merit in 2019.

ANSWERS

ANSWERS

NFPA Disclaimer:

Although Jim White is a member of the NFPA Technical Committee for both NFPA 70E, Standard for Electrical Safety in the Workplace, and NFPA 70B, Recommended Practice for Electrical Equipment

Maintenance, the views and opinions expressed in this column are purely the author’s and shall not be considered an official position of the NFPA or any of its technical committees and shall not be considered, nor be relied upon, as a formal interpretation or promotion of the NFPA. Readers are encouraged to refer to the entire text of all referenced documents.

1. d. IEC 61850 is the standard. IEC standards are moving into the United States, and it is important for us to be familiar with many of them. Digital substations definitely will impact the design, construction, and operation of substations in the near future.

2. a. Digital substations use fiber optic connections to eliminate copper wire. Devices can communicate more quickly and operate more quickly. Current transformers (CTs) and potential transformers (PTs) can be replaced by electronic fiber optic CTs and PTs — although they may not save space or increase signals — or traditional CTS and PTs can be used. Using fiber optics and generic objectoriented substation event (GOOSE) allows events to be transmitted more quickly (4ms) when compared with standard construction.

3. b. Military. Three-way communication has been used by many industries, but the military has required its use since before I enlisted (1971). Three-way communication starts with the person doing or supervising the task (sender) stating what the task is. The second person (receiver) may be an observer or the person performing the task; they will repeat the task. If there is misunderstanding between the two, this must be addressed at this point. The sender then repeats the task so both know they are correct. An example would be:

SenderPlace green wire on terminal 3

ReceiverPlace (or placing) green wire on terminal 3

SenderPlacing green wire on terminal 3

Task to be done

Verification

Final verification

Common behaviors that impede the process of three-way communications include:

• Using slang instead of appropriate work environmental-related terms

• Sender not taking responsibility to validate  whether what was said was correctly received

• Engaging in cross-talk; communicating when the receiver is engaged in another conversation

• Message not clearly stated due to environmental noise, not speaking loudly enough, or not enunciating clearly

• Receiver not verifying understanding of the speaker or not asking questions

4. c. Regardless of who gives it, the stop signal should be immediately obeyed. It’s a safety thing.

NETA ACTIVITIES UPDATE JUNE THROUGH DECEMBER 2019

NETA BOARD MEETING

June 20–21, 2019

Girdwood, Alaska

NETA’s June Board of Directors meeting took place in “The Last Frontier,” Girdwood, Alaska. The meeting focused on budget and program initiatives proposed for the new fiscal year.

NAMO/MUSE MEETING

June 22–24, 2019

Port Hueneme, California

NETA representatives conducted an informational session on the NETA Training and Certifi cation Exam with members of NETA Approved Military Organizations (NAMOs) and the U.S. Navy Seabees Mobile Utilities Support Equipment (MUSE) unit.

NETA BOARD AND MEMBER MEETING

September 19–20, 2019

San Diego, California

NETA’s fall Board and Member meetings held in the Gaslamp Quarter of San Diego focused on association development, membership, PowerTest updates, certification, and standards development. Two of NETA’s Corporate Alliance Partners, Protec Equipment Resources and Circuit Breaker Sales Co., Inc., gave emerging technologies presentations during the membership meeting.

NETA STANDARDS REVIEW COUNCIL MEETING

October 18–20, 2019

Dallas, Texas

The NETA Standards Review Council met to conduct regular business, including

concentration on the upcoming revision of ANSI/NETA ATS, Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems.

NETA ASSOCIATION STRATEGY MEETING

October 21–22, 2019

Dallas, Texas

NETA EXAM COMMITTEE MEETING

November 15–17, 2019

Dunedin, Florida

The NETA Exam Committee oversaw continuing maintenance of the NETA Certification Exams.

Bob Sheppard, Premier Power Maintenance Corporation; Neno Pasic,Tony Demaria Electric, Inc.; and Adis Talovic, Power Products & Solutions, LLC enjoy the rooftop reception following the September Member Meeting.

NEWLY ADDED

EARN CREDITS

NETA ACCREDITED COMPANIES Setting the Standard

A&F Electrical Testing, Inc.

80 Lake Ave S Ste 10 Nesconset, NY 11767-1017 (631) 584-5625

kchilton@afelectricaltesting.com www.afelectricaltesting.com

Kevin Chilton

A&F Electrical Testing, Inc.

80 Broad St Fl 5 New York, NY 10004-2257 (631) 584-5625 afelectricaltesting@afelectricaltesting.com Florence Chilton

ABM Electrical Power Services, LLC

720 S Rochester Ste A Ontario, CA 91761-8177 (301) 397-3500 rob.parton@abm.com www.abm.com/electrical Robert Parton

ABM Electrical Power Services, LLC

2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423

ABM Electrical Power Services, LLC

3600 Woodpark Blvd Ste G Charlotte, NC 28206-4210 (704) 273-6257

ABM Electrical Power Services, LLC

6940 Koll Center Pkwy Suite# 100 Pleasanton, CA 94566 (408) 466-6920

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560

ABM Electrical Power Services, LLC

3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550

ABM Electrical Power Services, LLC

4221 Freidrich Lane Suite 170 Austin, TX 78744 (210) 347-9481

ABM Electrical Power Services, LLC 6541 Meridien Dr Suite 113 Raleigh, NC 27616 (919) 877-1008 rob.parton@abm.com Robert Parton

ABM Electrical Power Solutions 4390 Parliament Place Suite S Lanham, MD 20706 (301) 967-3500

ABM Electrical Power Solutions 3700 Commerce Dr # 901-903 Baltimore, MD 21227-1642 (410) 247-3300

ABM Electrical Power Solutions

317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638

ABM Electrical Power Solutions 814 Greenbrier Cir Ste E Chesapeake, VA 23320-2643 (757) 364-6145

ABM Electrical Power Solutions

1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

Absolute Testing Services, Inc. 8100 West Little York Houston, TX 77040 (832) 467-4446 www.absolutetesting.com

Accessible Consulting Engineers, Inc. 1269 Pomona Rd Ste 111 Corona, CA 92882-7158 (951) 808-1040 info@acetesting.com www.acetesting.com

Advanced Electrical Services 4999 - 43rd St. NE Unit 143 Calgary, AB T2B 3N4 (403) 697-3747

Advanced Testing Systems 15 Trowbridge Dr Bethel, CT 06801-2858 (203) 743-2001 pmaccarthy@advtest.com www.advtest.com Pat McCarthy

American Electrical Testing Co., LLC 25 Forbes Boulevard Suite 1 Foxboro, MA 02035 (781) 821-0121 sblizard@aetco.us www.aetco.us

Scott Blizard

American Electrical Testing Co., LLC

Green Hills Commerce Center 5925 Tilghman St Ste 200 Allentown, PA 18104-9158 (484) 538-2272 jmunley@aetco.us

Jonathan Munley

American Electrical Testing Co., LLC

34 Clover Dr South Windsor, CT 06074-2931 (860) 648-1013 jpoulin@aetco.us

Gerald Poulin

American Electrical Testing Co., LLC 76 Cain Dr Brentwood, NY 11717-1265 (631) 617-5330 bfernandez@aetco.us

Billy Fernandez

American Electrical Testing Co., LLC

91 Fulton St., Unit 4 Boonton, NJ 07005-1060 (973) 316-1180 jsomol@aetco.us

Jeff Somol

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255

brian@ampqes.com

Brian Rodgers

Apparatus Testing and Engineering 11300 Sanders Dr Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280

jcarr@apparatustesting.com www.apparatustesting.com

Jerry Carr

Apparatus Testing and Engineering

7083 Commerce Cir Ste H Pleasanton, CA 94588-8017 (916) 853-6280 jcarr@apparatustesting.com

Jerry Carr

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 michel.c@aec-us.com www.aec-us.com

Michel Castonguay

Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 michel.c@aec-us.com www.aec-us.com

Michel Castonguay

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800

ddevlin@banaelectric.com www.bectesting.com

Daniel Devlin

Burlington Electrical Testing Co., Inc. 300 Cedar Ave Croydon, PA 19021-6051 (215) 826-9400 waltc@betest.com www.betest.com

Walter P. Cleary

Burlington Electrical Testing Co., Inc. 846 Waterford Drive Delran, NJ 08075 (609) 267-4126

C.E. Testing, Inc. 6148 Tim Crews Rd Macclenny, FL 32063-4036 (904) 653-1900 cetesting@hotmail.com www.cetestinginc.com

Mark Chapman

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 info@cepower.net

Jerry Daugherty

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 dave.mitchell@cepower.net

Dave Mitchell

CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 jim.cialdea@cepower.net

Jim Cialdea

CE Power Engineered Services, LLC 9200 75th Avenue N Brooklyn Park, MN 55428 (877) 968-0281 jason.thompson@cepower.net

Jason Thompson

CE Power Engineered Services, LLC 72 Sanford Drive Gorham, ME 04038 (800) 649-6314 mike.roach@cepower.net

Michael Roach

NETA

CE Power Engineered Services, LLC

8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415

info@cepower.net

Jerry Daugherty

CE Power Engineered Services, LLC

1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415

joe.psillos@cepower.net

Joe Psillos

CE Power Engineered Services, LLC 10338 Citation Drive Suite 300 Brighton, MI 48116 (810) 229-6628

ken.lesperance@cepower.net

Ken L’Esperance

CE Power Engineered Services, LLC 10840 Murdock Drive Knoxville, TN 37932 (800) 434-0415

don.williams@cepower.net

Don Williams

CE Power Engineered Services, LLC

3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346

lucas.gallagher@cepower.net

Lucas Gallagher

CE Power Engineered Services, LLC

1260 Industrial Park Eveleth, MN 55734 (218) 744-4200

Joseph Peterson

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

robert.bordas@cepowersol.com www.cepowersol.com

Robert Bordas

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue Suite 505 Davie, FL 33314 (866) 439-2992

robert.bordas@cepowersol.com

Robert Bordas

Control Power Concepts

3750 Las Vegas Blvd S. Unit 3303 Las Vegas, NV 89158 (702) 448-7833 jtravis@ctrlpwr.com www.controlpowerconcepts.com

John Travis

Dude Electrical Testing, LLC

145 Tower Drive, Unit 9 Burr Ridge, IL 60527-7840 (815) 293-3388

scott.dude@dudetesting.com www.dudetesting.com

Scott Dude

Eastern High Voltage, Inc. 11A S Gold Dr

Robbinsville, NJ 08691-1685 (609) 890-8300

bobwilson@easternhighvoltage.com www.easternhighvoltage.com

Robert Wilson

ELECT, P.C.

375 E. Third Street Wendell, NC 27591 (919) 365-9775

btyndall@elect-pc.com www.elect-pc.com

Barry W. Tyndall

Electek Power Services, Inc. 870 Confederation Street Sarnia, ON N7T2E5 (519) 383-0333

tvanderheide@electek.ca

Tim Vanderheide

Electric Power Systems, Inc. 21 Millpark Ct Maryland Heights, MO 63043-3536 (314) 890-9999 s.reed@epsii.com www.epsii.com

Steve Reed

Electric Power Systems, Inc. 11211 E. Arapahoe Rd Ste 108 Centennial, CO 80112 (720) 857-7273

Thomas Reed

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084

Virginia@EPS-International.com

Bruce Eppers

Electric Power Systems, Inc. 1090 Montour West Ind Park Coraopolis, PA 15108-9307 (412) 276-4559

Ed Nahm

Electric Power Systems, Inc. 6141 E Connecticut Ave Kansas City, MO 64120-1346 (816) 241-9990

Joe Dillon

Electric Power Systems, Inc. 1230 N Hobson St. Suite 101 Gilbert, AZ 85233 (480) 633-1490

Louis Gilbert

Electric Power Systems, Inc. 915 Holt Ave Unit 9 Manchester, NH 03109-5606 (603) 657-7371

Cindy Taylor

Electric Power Systems, Inc. 3806 Caboose Place Sanford, FL 32771 (407) 578-6424

Doug Pacey

Electric Power Systems, Inc. 1129 E Highway 30 Gonzales, LA 70737-4759 (225) 644-0150

Electric Power Systems, Inc. 684 Melrose Avenue Nashville, TN 37211-3121 (615) 834-0999

Larry Christodoulou

Electric Power Systems, Inc. 2888 Nationwide Parkway 2nd Floor Brunswick, OH 44212 (330) 460-3706

Garth Paul

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515

George Bratkiv

Electric Power Systems, Inc. 1330 Industrial Blvd. Suite 300 Sugar Land, TX 77478 (713) 644-5400

Houston@eps-international.com

Electric Power Systems, Inc. 56 Bibber Pkwy # 1 Brunswick, ME 04011-7357 (207) 837-6527

Garth Paul

Electric Power Systems, Inc. 11861 Longsdorf St Riverview, MI 48193-4250 (734) 282-3311

t.lindemann@eps-international.com

Teresa Lindemann

Electric Power Systems, Inc. 8515 Calle Alameda NE Ste A Albuquerque, NM 87113 (505) 792-7761

Bill Lewis

Electric Power Systems, Inc. 3209 Gresham Lake Rd. Suite 155 Raleigh, NC 27615 (919) 210-5405

Ray Livingston

Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342

Devin Hopkins

Electric Power Systems, Inc. 7925 Dunbrook Rd. Suite G San Diego, CA 92126 (858) 566-6317

Devin Hopkins

Electric Power Systems, Inc. 6679 Peachtree Industrial Dr. Suite H Norcross, GA 30092 (770) 416-0684

Jeremy Russell

Electric Power Systems, Inc. 306 Ashcake Road suite A Ashland, VA 23005 (804) 526-6794

Chris Price

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502

Daniel Douglas

Electric Power Systems, Inc. 7308 Aspen Lane North Suite 160 Brooklyn Park, MN 55428 (763) 315-3520

Paul Cervantez

Electric Power Systems, Inc. 140 Lakefront Drive Cockeysville, MD 21030 (443) 689-2220

Chris Myers

Electric Power Systems, Inc. 783 N. Grove Rd Suite 101 Richardson, TX 75081 (214) 821-3311

Thomas Coon

Electrical & Electronic Controls 6149 Hunter Rd Ooltewah, TN 37363-8762 (423) 344-7666

eecontrols@comcast.net

Michael Hughes

NETA ACCREDITED COMPANIES Setting the Standard

Electrical Energy Experts, LLC

W129N10818 Washington Dr Germantown, WI 53022-4446 (262) 255-5222

tim@electricalenergyexperts.com www.electricalenergyexperts.com

Tim Casey

Electrical Engineering & Service Co., Inc.

289 Centre St. Holbrook, MA 02343 (781) 767-9988 jcipolla@eescousa.com www.eescousa.com

Joe Cipolla

Electrical Equipment Upgrading, Inc. 21 Telfair Pl Savannah, GA 31415-9518 (912) 232-7402 kmiller@eeu-inc.com www.eeu-inc.com

Kevin Miller

Electrical Maintenance & Testing, Inc. 12342 Hancock St Carmel, IN 46032-5807 (317) 853-6795

brian.borst@emtesting.com www.emtesting.com

Brian Borst

Electrical Reliability Services

610 Executive Campus Dr Westerville, OH 43082-8870 (877) 468-6384 info@electricalreliability.com www.electricalreliability.com

Electrical Reliability Services

5909 Sea Lion Pl Ste C Carlsbad, CA 92010-6634 (858) 695-9551

Electrical Reliability Services

1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440

Electrical Reliability Services

6900 Koll Center Pkwy Ste 415 Pleasanton, CA 94566-3119 (925) 485-3400

Electrical Reliability Services

8500 Washington St NE Ste A6 Albuquerque, NM 87113-1861 (505) 822-0237

Electrical Reliability Services

2275 Northwest Pkwy SE Ste 180 Marietta, GA 30067-9319 (770) 541-6600

Electrical Reliability Services

10606 Bloomfield Ave Santa Fe Springs, CA 90670-3912 (562) 236-9555

Electrical Reliability Services

400 NW Capital Dr Lees Summit, MO 64086-4723 (816) 525-7156

Electrical Reliability Services

7100 Broadway Ste 7E Denver, CO 80221-2900 (303) 427-8809

Electrical Reliability Services

2222 W Valley Hwy N Ste 160 Auburn, WA 98001-1655 (253) 736-6010

Electrical Reliability Services

221 E. Willis Road, Suite 3 Chandler, AZ 85286 (480) 966-4568

Electrical Reliability Services

1380 Greg St. Ste. 216 Sparks, NV 89431-6070 (775) 746-8484

Electrical Reliability Services 11000 Metro Pkwy Ste 30 Fort Myers, FL 33966-1244 (239) 693-7100

Electrical Reliability Services

245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411

Electrical Reliability Services

9736 South Sandy Pkwy 500 West Sandy, UT 84070 (801) 975-6461

Electrical Reliability Services

6351 Hinson Street, Suite A Las Vegas, NV 89118-6851 (702) 597-0020

Electrical Reliability Services

3535 Emerson Pkwy Suite A Gonzales, LA 70737 (225) 755-0530

Electrical Reliability Services

9636 Saint Vincent Ave Unit A Shreveport, LA 71106-7127 (318) 869-4244

Electrical Reliability Services

1426 Sens Rd. Ste. #5 La Porte, TX 77571-9656 (281) 241-2800

Electrical Reliability Services

4099 SE International Way Ste 201 Milwaukie, OR 97222-8853 (503) 653-6781

Electrical Testing and Maintenance Corp.

3673 Cherry Rd Ste 101 Memphis, TN 38118-6313 (901) 566-5557

r.gregory@etmcorp.net www.etmcorp.net

Ron Gregory

Electrical Testing Solutions

2909 Greenhill Ct Oshkosh, WI 54904-9769 (920) 420-2986

tmachado@electricaltestingsolutions.com www.electricaltestingsolutions.com

Tito Machado

Electrical Testing, Inc. 2671 Cedartown Hwy SE Rome, GA 30161-3894 (706) 234-7623 www.electricaltestinginc.com

Jamie Dempsey

Elemco Services, Inc. 228 Merrick Rd Lynbrook, NY 11563-2622 (631) 589-6343 courtney@elemco.com www.elemco.com

Courtney Gallo

EnerG Test, LLC

206 Gale Lane Kennett Square, PA 19348 (484) 731-0200 KMatthews@energtest.com www.energtest.com

Kevin Matthews

Energis High Voltage Resources 1361 Glory Rd Green Bay, WI 54304-5640 (920) 632-7929 info@energis.com www.energisinc.com

EPS Technology 37 Ozick Dr. Durham, CT 06422 (203) 679-0145 www.eps-technology.com

Sean Miller

Giga Electrical & Technical Services, Inc.

2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 gigaelectrical@att.net www.gigaelectrical-ca.com

Hermin Machacon

Grubb Engineering, Inc.

2727 North Saint Mary’s St. San Antonio, TX 78212 (210) 658-7250 rgrubb@grubbengineering.com www.grubbengineering.com

Robert Grubb

Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763-6129 (909) 628-1256 x271 chasen.tedder@hamptontedder.com www.hamptontedder.com

Chasen Tedder

Hampton Tedder Technical Services 3747 W Roanoke Ave Phoenix, AZ 85009-1359 (480) 967-7765

Linc McNitt

Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200

Roger Cates

Harford Electrical Testing Co., Inc. 1108 Clayton Rd Joppa, MD 21085-3409 (410) 679-4477 testing@harfordtesting.com www.harfordtesting.com Vincent Biondino

High Energy Electrical Testing, Inc. 515 S Ocean Ave Seaside Park, NJ 08752-1843 (732) 938-2275 judylee@highenergyelectric.com www.highenergyelectric.com

High Voltage Maintenance Corp. 5100 Energy Dr Dayton, OH 45414-3525 (937) 278-0811 www.hvmcorp.com

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205

High Voltage Maintenance Corp. 1052 Greenwood Springs Rd. Suite E Greenwood, IN 46143 (317) 322-2055

High Voltage Maintenance Corp. 355 Vista Park Dr Pittsburgh, PA 15205-1206 (412) 747-0550

High Voltage Maintenance Corp. 8787 Tyler Blvd. Mentor, IN 44061 (440) 951-2706

High Voltage Maintenance Corp.

24371 Catherine Industrial Dr Ste 207 Novi, MI 48375-2422 (248) 305-5596

High Voltage Maintenance Corp.

3000 S Calhoun Rd New Berlin, WI 53151-3549 (262) 784-3660

High Voltage Maintenance Corp.

1 Penn Plaza Suite 500 New York, NY 10119 (718) 239-0359

High Voltage Maintenance Corp.

29 Diana Court Cheshire, CT 06410 (203) 949-2650

High Voltage Maintenance Corp. 941 Busse Rd Elk Grove Village, IL 60007-2400 (847) 640-0005

High Voltage Maintenance Corp. 14300 Cherry Lane Court Suite 115 Laurel, MD 20707 (410) 279-0798

High Voltage Maintenance Corp. 10704 Electron Drive Louisville, KY 40299 (859) 371-5355

HMT, Inc.

6268 State Route 31 Cicero, NY 13039-9217 (315) 699-5563

jack.mcdonnell@resapower.com www.hmt-electric.com

Jack McDonnell

Industrial Electric Testing, Inc. 11321 Distribution Ave W Jacksonville, FL 32256-2746 (904) 260-8378 gbenzenberg@bellsouth.net www.industrialelectrictesting.com Gary Benzenberg

Industrial Electric Testing, Inc. 201 NW 1st Ave Hallandale Beach, FL 33009-4029 (954) 456-7020

Industrial Tests, Inc. 4021 Alvis Ct Ste 1 Rocklin, CA 95677-4031 (916) 296-1200 greg@indtest.com www.industrialtests.com

Greg Poole

NETA ACCREDITED COMPANIES Setting

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888

Tom.McDonald@infraredbps.com www.infraredbps.com

Thomas McDonald Sr.

J.G. Electrical Testing Corporation 3092 Shafto Road Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com

M&L Power Systems, Inc.

109 White Oak Ln Ste 82 Old Bridge, NJ 08857-1980 (732) 679-1800 milind@mlpower.com www.mlpower.com

Milind Bagle

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 (780) 462-3111 info@magnaiv.com www.magnaiv.com

Virginia Balitski

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 (780) 791-3122

Ryan Morgan

Magna IV Engineering 3124 Millar Ave. Saskatoon, SK S7K 5Y2 (306) 713-2167 info.saskatoon@magnaiv.com

Adam Jaques

Magna IV Engineering 96 Inverness Dr E Ste R Englewood, CO 80112-5311 (303) 799-1273 info.denver@magnaiv.com Kevin Halma

Magna IV Engineering Avenida del Condor sur #590 Oficina 601 Huechuraba, 8580676 +(56) -2-26552600 info.chile@magnaiv.com Harvey Mendoza

Magna IV Engineering 106, 4268 Lozells Ave Burnaby, BC VSA 0C6 (604) 421-8020 info.vancouver@magnaiv.com

Scott Nixon

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 (403) 723-0575

Magna IV Engineering 4407 Halik Street Building E Suite 300 Pearland, TX 77581 (346) 221-2165 info.houston@magnaiv.com Aric Proskurniak

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 m-moorehead@midwestengr.com www.Midwestengr.com

Monte Moorehead

MTA Electrical Engineers 350 Pauma Place Escondido, CA 92029 (760) 658-6098 tim@mtaee.com

Timothy G. Shaw

National Field Services 651 Franklin Lewisville, TX 75057-2301 (972) 420-0157

eric.beckman@natlfield.com www.natlfield.com

Eric Beckman

National Field Services 1890 A South Hwy 35 Alvin, TX 77511 (800) 420-0157

Jonathan.wakeland@natlfield.com

Jonathan Wakeland

National Field Services 1405 United Drive Suite 113-115 San Marcos, TX 78666 (800) 420-0157 matt.lacoss@natlfield.com

Matthew LaCoss

National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625

tylor.pereza@natlfield.com

Tylor Pereza

National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 tylor.pereza@natlfield.com

Tylor Pereza

Nationwide Electrical Testing, Inc. 6050 Southard Trce Cumming, GA 30040-6343 (770) 667-1875

Shashi@N-E-T-Inc.com www.n-e-t-inc.com

Shashikant B. Bagle

North Central Electric, Inc. 69 Midway Ave

Hulmeville, PA 19047-5827 (215) 945-7632 ncetest@aol.com www.ncetest.com

Robert Messina

Northern Electrical Testing, Inc. 1991 Woodslee Dr Troy, MI 48083-2236 (248) 689-8980 ldetterman@northerntesting.com www.northerntesting.com

Lyle Detterman

Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 (780) 988-1455 accountspayable@orbisengineering.net www.orbisengineering.net

Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051

Amin Kassam

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes Santiago, +56 2 29402343 framos@orbisengineering.net

Felipe Ramos

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 www.pacetechnologies.com

Craig Leavitt

Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna, BC V1X 8C8 (250) 712-0091

Pacific Power Testing, Inc. 14280 Doolittle Dr San Leandro, CA 94577-5542 (510) 351-8811 steve@pacificpowertesting.com www.pacificpowertesting.com

Steve Emmert

NETA ACCREDITED COMPANIES Setting the Standard

Pacific Powertech Inc. #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 (604) 944-6697

www.pacificpowertech.ca

jkonklin@pacificpowertech.ca

Josh Konklin

Phasor Engineering

Sabaneta Industrial Park #216

Mercedita, PR 00715 (787) 844-9366 rcastro@phasorinc.com www.phasorinc.com

Rafael Castro

Potomac Testing, Inc.

1610 Professional Blvd Ste A Crofton, MD 21114-2051 (301) 352-1930

kbassett@potomactesting.com www.potomactesting.com

Ken Bassett

Power Engineering Services, Inc. 9179 Shadow Creek Ln Converse, TX 78109-2041 (210) 590-4936

dstaudt@pe-svcs.com www.pe-svcs.com

Daniel Staudt

POWER PLUS Engineering, Inc.

47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

sam.mancuso@resapower.com www.epowerplus.com

Power Products & Solutions, LLC 6605 W WT Harris Blvd Suite F Charlotte, NC 28269 (704) 573-0420 x12 adis.talovic@powerproducts.biz www.powerproducts.biz

Adis Talovic

Power Products & Solutions, LLC 13 Jenkins Ct Mauldin, SC 29662-2414 (800) 328-7382

raymond.pesaturo@powerproducts.biz

Raymond Pesaturo

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617

Power Solutions Group, Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444

bwilloughby@powersolutionsgroup.com www.powersolutionsgroup.com

Barry Willoughby

Power Solutions Group, Ltd.

2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018

sspohn@powersolutionsgroup.com

Stuart Spohn

Power Solutions Group, Ltd.

5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434

fcrawford@powersolutionsgroup.com

Anthony Crawford

Power Solutions Group, Ltd.

172 B-Industrial Dr. Clarksville, TN 37040 (931) 572-8591

Chris Brown

Power Systems Testing Co.

4688 W Jennifer Ave Ste 108 Fresno, CA 93722-6418 (559) 275-2171 ext 15

dave@pstcpower.com

www.powersystemstesting.com

David Huffman

Power Systems Testing Co.

600 S Grand Ave Ste 113 Santa Ana, CA 92705-4152 (714) 542-6089

Power Systems Testing Co. 6736 Preston Ave Ste E Livermore, CA 94551-8521 (510) 783-5096

Power Test, Inc. 2200 Highway 49 S Harrisburg, NC 28075-7506 (704) 200-8311 rich@powertestinc.com www.powertestinc.com

Rich Walker

POWER Testing and Energization, Inc. 14006 NW 3rd Ct Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 www.powerte.com

POWER Testing and Energization, Inc. 303 US Route One Freeport, ME 04032 (207) 869-1200

POWER Testing and Energization, Inc. 4100 International Plaza, Suite 320 Fort Worth, TX 76109 (817) 882-1900

POWER Testing and Energization, Inc. 12755 Olive Blvd., Suite 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

POWER Testing and Energization, Inc. 1041 Red Ventures Dr. Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

Powertech Services, Inc. 4095 Dye Rd Swartz Creek, MI 48473-1570 (810) 720-2280 www.powertechservices.com

Precision Testing Group 5475 Highway 86 Unit 1 Elizabeth, CO 80107-7451 (303) 621-2776 www.precisiontestinggroup.com

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660

kevin.templeman@premierpower.us www.premierpowermaintenance.com Kevin Templeman

Premier Power Maintenance Corporation 2725 Jason Rd Ashland, KY 41102-7756 (606) 929-5969

jay.milstead@premierpower.us Jason Milstead

Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur, AL 35601-8800 (256) 355-1444

johnnie.mcclung@premierpower.us Johnnie McClung

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006

Kevin.Templeman@premierpower.us Kevin Templeman

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100

Kevin.Templeman@premierpower.us

Kevin Templeman

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620

Brian.Ellegiers@premierpower.us

Brian Ellegiers

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660

kevin.templeman@premierpower.us

Kevin Templeman

Premier Power Maintenance Corporation

1901 Oakcrest Ave., Suite 6 Saint Paul, MN 55113 (612) 616-4236

Josh.vareberg@premierpower.us

Josh Vareberg

RESA Power Service

46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868

bruce.robinson@resapower.com www.resapower.com

Bruce Robinson

RESA Power Service

3890 Pheasant Ridge Dr. NE Suite 170 Blaine, MN 55449 (763) 784-4040

Michael.mavetz@resapower.com

Mike Mavetz

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560

jodymedina@groundedtech.com

Jody Medina

RESA Power Service 40 Oliver Terrace Shelton, CT 06484-5336 (800) 272-7711

Bill Hartman

RESA Power Service

13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 roger.torrices@resapower.com

Roger Torrices

RESA Power Service

2390 Zanker Road

San Jose, CA 95131 (800) 576-7372

roger.torrices@resapower.com

Roger Torrices

RESA Power Service

1401 Mercantile Court Plant City, FL 33563 (813) 752-6550

Reuter & Hanney, Inc., a CE Power Company

Northampton Industrial Park 149 Railroad Dr Ivyland, PA 18974-1448 (215) 364-5333 www.reuterhanney.com

Reuter & Hanney, Inc., a CE Power Company

11620 Crossroads Cir Middle River, MD 21220-2874 (410) 344-0300 mjester@reuterhanney.com

Michael Jester

REV Engineering Ltd.

3236 - 50 Avenue SE Calgary, AB T2B 3A3 (403) 287-0156 rdavidson@reveng.ca www.reveng.ca

Roland Nicholas Davidson, IV

Rondar Inc.

333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808

rshaikh@rondar.com www.rondar.com

Rajeel Shaikh

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640

Saber Power Services, LLC

9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 wharrison@saberpower.com www.saberpower.com

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793

Saber Power Services, LLC

9006 Western View Helotes, TX 78023 (210) 267-7282

Saber Power Services, LLC 1908 Lone Star Rd. Mansfield, TX 76063 (210) 296-9970

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 rsorbello@scotttesting.com www.scotttesting.com Russ Sorbello

Sentinel Field Services, LLC 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 gellis@spstulsa.com www.sentinelpowerservices.com Greg Ellis

Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 info@shermco.com www.shermco.com

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 info@shermco.com

Shermco Industries 2231 E Jones Ave Ste A Phoenix, AZ 85040-1475 (602) 438-7500 info@shermco.com

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 info@shermco.com

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 info@shermco.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels Brussels, +32 (0)2 400 00 54

Shermco Industries 2100 Dixon Street Suite C Des Moines, IA 50316-2174 (515) 263-8482 info@shermco.com

NETA ACCREDITED COMPANIES

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 info@shermco.com

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 info@shermco.com

Shermco Industries 12000 Network Blvd Buidling D, Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 info@shermco.com

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 info@shermco.com

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 info@shermco.com

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 info@shermco.com

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 info@shermco.com

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 info@shermco.com

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 info@shermco.com

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 info@shermco.com

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 info@shermco.com

Shermco Industries 1720 S. Sonny Ave. Gonzales, LA 70737 (225) 647-9301 info@shermco.com

Shermco Industries 501 Union West Blvd. Matthews, NC 28104 (910) 568-1053 info@shermco.com

Shermco Industries 5805 Hwy 43 Satsuma, AL 36507 (251) 679-3224

James Irby info@shermco.com

Shermco Industries 5805 Hwy 43 Satsuma, AL 36507 (251) 679-3224 info@shermco.com

Shermco Industries 5211 Linbar Dr. Suite 507 Nashville, TN 37211 (615) 928-1182 info@shermco.com

Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood, SK S4K 0A2 (306) 949-8131 info@shermco.com

Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 info@shermco.com

Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 info@shermco.com

Shermco Industries Canada 1375 Church Avenue Winnipeg, MB R2X 2T7 (204) 925-4022 info@shermco.com

Shermco Industries Canada 3731 - 98 Street Edmonton, AB T6E 5N2 (780) 436-8831 info@shermco.com

NETA ACCREDITED COMPANIES Setting the Standard

Sigma Six Solutions, Inc.

2200 W Valley Hwy N Ste 100 Auburn, WA 98001-1654 (253) 333-9730

jwhite@sigmasix.com www.sigmasix.com

John White

Sigma Six Solutions, Inc. www.sigmasix.com Quincy, WA 98848 (253) 333-9730

Chris Morgan

Southern New England Electrical Testing, LLC

3 Buel St Ste 4 Wallingford, CT 06492-2395 (203) 269-8778

dave.asplund@sneet.org www.sneet.org

Dave Asplund

Star Electrical Services & General Supplies, Inc. PO Box 814 Las Piedras, PR 00771 (787) 716-0925

ahernandez@starelectricalpr.com www.starelectricalpr.com

Abelardo Hernandez

Taurus Power & Controls, Inc.

9999 SW Avery St Tualatin, OR 97062-9517 (503) 692-9004 robtaurus@tauruspower.com www.tauruspower.com

Rob Taurus

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150

monty.janak@tidalpowerservices.com www.tidalpowerservices.com

Monty Janak

Tidal Power Services, LLC 8184 Highway 44 Ste 105 Gonzales, LA 70737-8183 (225) 644-8170

Tidal Power Services, LLC 1056 Mosswood Dr Sulphur, LA 70665-9508 (337) 558-5457

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781

Titan Quality Power Services, LLC 7000 Meany Ave. Bakersfield, CA 93308 (661) 589-0400

Tony Demaria Electric, Inc. 131 W F St Wilmington, CA 90744-5533 (310) 816-3130

neno@tdeinc.com www.tdeinc.com Neno Pasic

Utilities Instrumentation Service - Ohio, LLC 998 Dimco Way Centerville, OH 45458 (937) 439-9660 www.uiscorp.com

Utilities Instrumentation Service, Inc. 2290 Bishop Cir E Dexter, MI 48130-1564 (734) 424-1200

gary.walls@UIScorp.com www.uiscorp.com

Gary Wells

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400

apeterson@utilserv.com www.utilserv.com

Alan D. Peterson

Western Electrical Services, Inc. 14311 29th St E Sumner, WA 98390-9690 (253) 891-1995

dhook@westernelectricalservices.com www.westernelectricalservices.com

Dan Hook

Western Electrical Services, Inc. 5680 S 32nd St Phoenix, AZ 85040-3832 (602) 426-1667

carcher@westernelectricalservices.com

Craig Archer

Western Electrical Services, Inc. 3676 W California Ave Ste C106 Salt Lake City, UT 84104-6533 (888) 395-2021

tking@westernelectricalservices.com

Toby King

Western Electrical Services, Inc. 4510 NE 68th Dr Unit 122 Vancouver, WA 98661-1261 (888) 395-2021

Jason Carlson

Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217

mwallace@westernelectricalservices.com

Matt Wallace

Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661

tking@westernelectricalservices.com

Toby King

RENT ELECTRICAL TEST EQUIPMENT

Providing Testing Solutions for:

• Protective Relays

• Transformers & Motor Analysis

• Partial Discharge/Corona

• Current Injection

• Cable Fault Location

• Switchgear/Circuit Breakers

• Insulation Resistance

• Tan Delta/Power Factor

• Current Transformers

• Ground Grid

Advanced Test Equipment Rentals

Please

in

Raytech’s CAPO 12 offers features that allow you to take advantage of the current and future testing methods.

• Test Voltage up to 12kV | Built in Standard Capacitor

• Test Frequency – 10 Hz to 400 Hz

• Easy to Operate, Accurate & Reliable

• Internal Thermal Printer for Printing Test Results

• Internal Storage for Over 10,000 Test Results

• 5 Year Warranty

For more information regarding the newest test methods and standards for Insulation Power Factor testing, email: Info@RaytechUSA.com

Test partial discharge in less than 10 clicks with MONTESTO 200

Up to now, many of our customers have considered on-line partial discharge (PD) measurement and monitoring to be time-consuming and complicated. This inspired us to develop the portable, user-friendly and versatile MONTESTO 200.

It is designed for both on-line PD measurement and monitoring, indoors or outdoors, on various electrical assets. Plug-and-play connections reduce setup time. Automated software features help to quickly identify insulation defects.

www.omicronenergy.com/montesto200

Matthew Sze Regional Application Specialist