TURNING THE CORNER ON CYBER-SECURE PROTECTION TESTING PAGE 52
QUICK GUIDE TO DISCHARGE TESTING PAGE 64
WHAT IS THIS NERC? PAGE 72
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Maysam Radvar, PEng, PE, and Casey Whitt, Ready Technologies, a division of Shermco
What effects will NERC PRC-027-1 have on the bulk electrical system (BES)? Here’s a deep dive into the standard’s requirements and implementation.
Bryan Gwyn, Sagar Singam, and Joe Stevenson, Doble Engineering Company
Utilities with a culture of NERC compliance can better avoid penalties and overcome the uncertainties of regulatory change.
Sanket Bolar, Megger
Capacity testing is an effective way to track battery health and ensure reliability.
Kyle Heron, Premier Power Maintenance
Better understanding the North American Electric Reliability Corporation and its requirements helps ensure BES reliability.
TABLE OF CONTENTS
INSIGHTS AND INSPIRATION
8 Luke Leifeste: When Troubleshooting Is Mission-Critical
IN EVERY ISSUE
7 President’s Desk NERC and NETA
Eric Beckman, National Field Services
NETA President
12 NFPA 70E and NETA
Key Points of NFPA 70E’s Safe Work Practices
Ron Widup, Shermco Industries
21 Relay Column
Analysis of Generator Protection Operations
Steve Turner, Arizona Public Service Company
24 In the Field
MCC Catastrophic Failure at a Client Facility
Adam Murray, Advanced Electrical Services Ltd.
29 Safety Corner
Hand Protection
Paul Chamberlain, American Electrical Testing Co., LLC
36 Tech Quiz
The Life and History of James (Jim) R. White Virginia Balitski, Magna IV Engineering
38 Tech Tips
Grounding and Bonding Meter Sockets
Jeff Jowett, Megger
INDUSTRY TOPICS
80 An Intelligent System for Condition Assessment of Power Transformers
100 Advancements in the Industry Traveling Wave Relay Application, Commissioning, and Initial Experience
Fari Elhaj and Scott Cooper, OMICRON electronics, and Anthony Savesind and Francisco J. Sanchez, Salt River Project
110 CAP Spotlight
A-Rent: Quality Equipment and Responsive Service
NETA NEWS
113 September Member Meeting
SPECIFICATIONS AND STANDARDS
116 ANSI/NETA Standards Update
IMPORTANT LISTS
121 NETA Accredited Companies
130 Advertiser List
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• Documenting Process Calibrators
• Grounding/Insulation Testers
• High Voltage Test Equipment
• Power Factor Test Equipment
• Multimeters
• Transformer Test Equipment
• Power Analyzers & Scopemeters
• Clamp Meters
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Toll free: 888.300.NETA (6382)
Phone: 269.488.NETA (6382)
Fax : 269.488.6383
neta@netaworld.org
www.netaworld.org
executive director: Missy Richard
NETA Officers
president: Eric Beckman, National Field Services
first vice president: Ken Bassett, Potomac Testing
second vice president: Bob Sheppard, Premier Power Maintenance
secretary: Dan Hook, Western Electrical Services, Inc.
treasurer: John White, Sigma Six Solutions, Inc.
NETA Board of Directors
Virginia Balitski (Magna IV Engineering)
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)
Dan Hook (Western Electrical Services, Inc.)
David Huffman (Power Systems Testing)
Chasen Tedder, Hampton Tedder Technical Services
Ron Widup (Shermco Industries)
non-voting board member
Lorne Gara (Shermco Industries)
Alan Peterson (Utility Service Corporation)
John White (Sigma Six Solutions)
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; technical: Alan Peterson; technical exam: Dan Hook; continuing technical development: David Huffman; training: Eric Beckman; finance: John White; nominations: Dave Huffman; alliance program: Jim Cialdea; association development: Ken Bassett and John White
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,
NERC AND NETA
NETA has been setting standards that pave the way for the minimum requirements to ensure an electrical system operates reliably and safely since 1972.
As a result of several widespread blackouts compromising the electric grid, the North American Electric Reliability Council (NERC)was appointed in 2006 by the Federal Energy Regulatory Commission (FERC) to develop various standards to aid in the reliability of electric grid infrastructure. Since then, NERC has been specifically responsible for ensuring reliability for the bulk electric system (BES).
These standards started out very basic and were somewhat limited in terms of what was minimally required of utility owners. Over the past 15 years, the standards have developed and become more detailed. The standards now not only include protection and maintenance requirements, but as technology has developed and become more susceptible to cyberattacks, NERC has also developed standards associated with cyber security. These requirements are found in Critical Infrastructure Protection (CIP).
In this issue of NETA World, we take a look at some of some of those specific requirements and how you can go about meeting them.
PowerTest 2022 will be at the Hyatt Regency in Denver, Colorado, on February 28–March 4, 2022. This will be NETA’s 50th anniversary, so you will not want to miss it. I’m excited to be able to get back together with everyone in person.
Plan ahead and always put safety first!
Eric Beckman, PE, President International Electrical Testing Association
LUKE LEIFESTE: WHEN TROUBLESHOOTING
IS MISSION-CRITICAL
Chief Petty Officer Luke Leifeste is a MUSE Technician (Mobility Utility Support Equipment) deployed by the U.S. Navy to create, secure, and repair electrical power supply systems in Africa. With nearly 18 years in the military, he says the intrigue of troubleshooting in the field keeps him inspired for the next challenge.
NW: How would you describe the nature of your work overseeing electrical-power critical missions for the U.S. Navy?
Leifeste: As far as military appointments go — it’s great, but it’s dangerous. There are pressures and stress, but I would describe those instances more like challenges. Since July, I’ve been stationed at Camp Lemonnier in Djibouti, Africa. My core job is in mobile power generation — generally from a 1-megawatt, 20-foot shipping container up to a 120,000-lb, 2.5-megawatt locomotive engine.
I work on substations as well but on a much smaller scale. For example, we install substations in shipyards so the ships can come in and get the power they need, or people have enough power to perform maintenance on them. I also work in back-up power generation, like in submarine bases that require multiple sources of power. As you can imagine, a submarine losing power can be a serious problem.
NW: What path brought you to this work?
Leifeste: Honestly, I didn’t know what I wanted to do as a career, so the Navy seemed like a good idea. When I first joined in 2004, I wanted to do something in electricity — but
was told no because I am partially colorblind — so, I started as a heavy equipment construction mechanic. While learning my trade, I heard about MUSE and knew that’s what I wanted to do. I knew that was my path.
In 2008, I was accepted into MUSE and attended the Army Prime Power School in Virginia. It was an intense, one-year program that included math, physics, science, mechanical and electrical system engineering, and the fundamentals of power generation and operation. At the end, you select a specialty, and I chose electrical testing and troubleshooting. I have always been interested in electricity — how it works and how it’s used in the world — and I am inspired by how important it is to society. It’s a field with a lot of opportunity.
NW:What keeps you dedicated to the work?
Leifeste: I’m always learning something new. I never get bored. The work is very intriguing to me. There’s always some sort of challenge. I love working with my team to deliver critical power and see the end result.
NW: What about this work is challenging for you?
Leifeste: In Djibouti, the only power they have is what they produce themselves. That means lots of logistics to keep plants up and running. When you’re working out of an overseas base, it can be hard to get the parts you need, plus COVID certainly has hindered certain projects and even kept them from happening.
When you go on a mission to install power and the power is on, no one really thinks about it. However, when the power is off, people are asking questions. It can be challenging to work through that stress quickly but also safely. The power is needed to make sure the mission continues. That’s why I like MUSE; the strength of the program is in the experience and knowledge of the team that supports the mission.
NW: What advice would you have for a young technician, or someone interested in this field?
Leifeste: The work can be daunting, but if you have a passion for it, you’ll take the time to learn it however you can. There’s always
something new to learn, and after each level you reach, you can look to the next level that you want to be. That’s what keeps me going. You just have to bring the passion and the desire to learn.
NW: What does a good workday look like for you?
Leifeste: A great day is when we solve an issue, no matter how long it takes. I remember once in Guantanamo Bay, we were staying late, exhausted, installing these units and trying to figure out a problem. We decided to take a rest and leave, come back the next day. In the morning, we came back as a team and figured it out. When the customer sees what you do and appreciates your skillset and what you did to troubleshoot, that’s a good day. It’s a relief and an accomplishment, and those are the days that keep me going.
NW: What does a bad day look like?
Leifeste: In the electrical field, the worse day is someone getting hurt. But other than that, I’d say when something isn’t working and you
“THE
PRESSURE IS REALLY ON WHEN YOU CAN’T BRING THE POWER BACK ON, BUT WE USE THOSE TIMES AS LEARNING EXPERIENCES, AS HARD AS THEY MAY BE.”
can’t figure it out, and all eyes are on you. Or, if you make a mistake — and that does happen sometimes in the field — and it affects your ability to get the unit up…like if you miss something or don’t do something correctly. It’s easy to get a little angry at yourself; it happens to everyone on this job. The pressure is really on when you can’t bring the power back on, but we use those times as learning experiences, as hard as they may be.
NW:What energy trends do you believe will affect your work moving forward?
NETA World is looking for technicians, emerging leaders, and industry thought leaders to be featured in our new Insight & Inspiration department. If you know someone who would make a great interview — or if you would like to be interviewed yourself — please contact Carla Kalogeridis at ckalogeridis@netaworld.org
Leifeste: I expect to see a lot more renewables. As the technology continues to grow, customers ask, “Why aren’t we using more of these?” Solar and wind haven’t been as reliable, but it’s getting there. Everything is demand-based, and the wind is not always there. The sun is not always there. But the technology is improving all the time, and I see it growing in the future. It’s a good thing, and we ought to embrace it, but we need energy when we need it. We’ve got to integrate more renewables into the energy grid.
NW: What would you like to see the electrical power industry focused on in the coming year?
Leifeste: The continued advancement of technology. We’ve come so far, but there are serious challenges in cybersecurity and its effects on the electrical power industry. Those have to be considered and addressed. Getting more advanced gives us the ability to do more while reducing cost and increasing reliability.
A Wide Range of Test Systems Available
FAULT ON FEEDER M1A: PLANNING RECOVERY USING NFPA 70E
BY RON WIDUP, Shermco
Previously, we discussed a 15 kV feeder fault at a manufacturing plant and how NFPA 70E is an important tool for the electrical worker to use in the field as they troubleshoot, repair, and restore the equipment to get the facility up and running.
To recap, here’s what happened:
The main circuit breaker in one of the plant’s three medium-voltage substations experienced a fault, arc flash event, and subsequent trip of the entire lineup, apparently due to a rodent that caused a phase-to-phase fault in the 15 kV potential transformer (PT) compartment. The fault traveled into the medium-voltage bus assembly in the metal-clad switchgear lineup, ultimately causing the main breaker to trip and de-energizing a large portion of the facility.
We also highlighted that before work begins, you need to assess the risk. You also need to apply several principles of safe work practices before you begin — principles such as:
1. Identify the hazards and minimize the risks [done].
2. Establish an electrically-safe work condition [done].
3. Protect employees, both workers on the project and other bystanders.
4. Plan all the tasks to be performed.
5. Anticipate unexpected events, and have a plan to deal with them.
6. Ensure the qualifications and abilities of anyone working on the project.
7. Determine the condition of maintenance of the electrical equipment.
8. Use correct tools and appropriately rated portable meters.
In the first article, we made it through point 1 and point 2. We will now cover points 3 through 6. For the entire Part 1 article, please see the Summer 2021 NETA World at www.netaworldjournal.org/key-points-of-nfpa70es-safe-work-practices/.
POINT 3: PROTECTING BYSTANDERS AND WORKERS
The smoke has cleared, and people are showing up to the scene to see what happened and to lend a hand. Some have a legitimate reason to be there, others do not. What should you do?
Key Point — Article 130.7(E) Alerting
Techniques
First, set up alerting techniques and barricade the area to keep unauthorized personnel
out of the repair worksite. After a significant electrical fault event, temporary or partial power is typically restored, and the affected area contains various physical and electrical hazards. It’s important to keep away people who may not have a grasp on all of the hazards that now exist.
What should you use? Take advice from NFPA 70E, as it provides excellent guidance on alerting techniques and equipment barricading. If you study Article 130.7(E), you will find guidance on:
1. Safety signs and tags
2. Barricades
3. Attendants
Key
Point
—
Article
130.7(F) Look-Alike Equipment
Something that happens time and time again is confusion around look-alike equipment. Think about it: When facilities, especially large facilities, are built, the electrical equipment is
Barricades keep unauthorized personnel out of the work area.
THE NFPA 70E AND NETA
Look-alike equipment can become a blur.
often purchased from one manufacturer and is commonly supplied as the same type, style, and ratings.
Place four, five, or even 20 switchboards or substations in a facility, and it all looks the same. Now, take a portion of that equipment out of service to work on it, and it becomes very easy to confuse the de-energized equipment from the energized equipment. NFPA 70E recognizes this and specifically addresses it in 130.7(F) Look-Alike Equipment.
POINT 4: PLANNING THE TASKS
We know what happened. We know what needs to be done to repair the faulted equipment. But to do it safely and efficiently, you need to have a plan.
Key Point — Informative Annex I: Job Briefing and Job Safety Planning Checklist
One of the best ways to get guidance on the many considerations of job safety is to utilize information found in 70E’s Informative Annex I. Not only are you required, per 110.5(A), to implement and document an overall electrical
safety program (ESP), but job briefings must also be included in the ESP elements.
Before starting each job, the person in charge must conduct a job briefing. In situations such as this with a faulted main-breaker cubicle, severe arcing and smoke damage, and temporary power circuits in and around the work area, it is especially important to have a detailed plan…and most important… to communicate it effectively with all those involved.
POINT 5: ANTICIPATING UNEXPECTED EVENTS
The facility did not expect a large rodent to walk across the 15 kV PT compartment and blow it up. This was an unexpected event and was not planned for.
But the work you are doing to remediate the issues should be planned and should include considerations built in for unexpected events. A few examples of unexpected event planning:
• What is the expected time frame for the repair…and what if you don’t finish it on time?
Faulted equipment remediation requires extra attention to job planning and communication.
– Are the workers putting in excessive hours?
– Are production personnel coming in to start the facility back up?
• If you are running on temporary power, do you have a fuel contingency?
• You open up the switchgear and find additional problems. Do you have an after-hours source for parts and equipment?
• What about the upstream devices – did you damage something else?
• Is there a re-energization plan when the repairs are completed?
When performing repairs after a significant fault event, it is wise to under-promise and over-deliver. Be conservative in the timing of your repair estimates and clear-headed in your promises. This makes for a safer recovery, puts less pressure on the workers in the field, and leads to a more effective execution of the tasks in front of you. Anticipate all the “gotchas” before they get you. Take your time and think it through. After all, it’s electrical equipment!
AIR-CELL BLADDERS
POINT 6: ENSURING THE QUALIFICATIONS AND ABILITIES OF WORKERS
This is electrical work. It is dangerous, and it can kill you.
Please, make sure you and your people have the necessary knowledge, skills, and abilities for any of the tasks they are expected to perform.
Key Point — Article 100, Definition of Qualified Person
NFPA 70E is very clear on the definition of a qualified person, which states:
One who has demonstrated skills and knowledge related to the construction and operation of electrical equipment and installations and has received safety training to identify the hazards and reduce associated risk.
The personnel performing the task, whatever it might be, must be qualified for the task
Recognize the Unqualified
THE NFPA 70E AND NETA
they are expected to perform. It’s important to note that being a degreed engineer, a certified technician, or a licensed electrician does not automatically make you qualified for the task in front of you.
A qualified employee must understand the construction and operation of the equipment or the circuit that is associated with the required task. Do you understand 15 kV potential transformer (PT) and current transformer (CT) circuits? Do you understand the construction and operation of medium-voltage circuit
breaker cell interlocks and insulation systems? What about line-to-ground clearances and allowable cable bending radii? These are all decision-making elements of our feeder M1A repair, and the worker must have the skills and knowledge to navigate these points.
If your people are qualified, and they understand the hazards, risks, construction, operation, nominal voltages, normal operation requirements, and how to properly interact with the equipment…the likelihood of having a safe, successful repair and restoration of power is greatly increased.
Stayed tuned for the next issue of NETA World as we determine the equipment’s condition of maintenance and use tools and portable meters to bring the facility back online and bring this unexpected electrical fault event to a close.
And finally, always turn it off before working on it!
Ron Widup is the Vice Chairman, Board of Directors, and Senior Advisor, Technical Services for Shermco Industries and has been with Shermco since 1983. He is a member of the NETA Board of Directors and Standards Review Council; a member of the Technical Committee on NFPA Standard for Electrical Safety in the Workplace (NFPA 70E); Principal member of the National Electrical Code (NFPA 70) Code Panel 11; Principal member and Chairman of the Technical Committee on Standard for Competency of Third-Party Evaluation Bodies (NFPA 790); Principal member and Chairman of the Technical Committee on Recommended Practice and Procedures for Unlabeled Electrical Equipment Evaluation (NFPA 791); a member of the Technical Committee Recommended Practice for Electrical Equipment Maintenance (NFPA 70B); and Vice Chair for IEEE Std. 3007.3, Recommended Practice for Electrical Safety in Industrial and Commercial Power Systems. He is a member of the Texas State Technical College System (TSTC) Board of Regents, a NETA Certified Level 4 Senior Test Technician, State of Texas Journeyman Electrician, a member of the IEEE Standards Association, an Inspector Member of the International Association of Electrical Inspectors, and an NFPA Certified Electrical Safety Compliance Professional (CESCP).
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BY STEVE TURNER, Arizona Public Service – Generation System Protection
This article analyzes several protection operations for large combustion turbine generators. Generator protection trips tend to be rare, so any major event is always of interest.
EVENT 1: CLOSE-IN THREE-PHASE FAULT
A large gas combustion turbine generator experienced a close-in three-phase fault during a rainstorm. The generator terminal voltage is rated 13.8 kV line-to-line, and the machine is high-impedance grounded. The phase VTs
are connected open delta. Figure 1 is the corresponding oscillography captured by the generator protection relay.
The fault was located close to the phase VTs and just external to the generator differential zone of protection. The fault was properly cleared by
the 50 high-set phase instantaneous protection, which operated just under two cycles following fault inception. The generator breaker tripped open four cycles later. The pre-fault load current was 50% of the rated full load.
Figure 2 shows the fault impedance ZAB, ZBC, and ZCA measured by the generator protection relay. The pre-fault load impedance drops close to zero ohms following fault inception.
Figure 3 shows the machine rotor, which was pulled for inspection due to the fault.
EVENT 2: ROTOR GROUND FAULT
The second event is a rotor ground fault that occurred for another large combustion turbine generator — also during a rainstorm. Figure 4 shows the rotor field resistance to ground measured by the generator protection relay over a period of one month leading up to the event.
The orange plot is of interest and represents the measured rotor field insulation resistance to ground. The ground fault occurred between 0728-2021 and 08-02-2021. Review of the plot shows that the field resistance dropped to zero, then slowly began to increase back to the prefault nominal value over the course of several
Figure 1: Oscillography for Event 1
Figure 2: Fault Impedance Measured by Generator Protection Relay
Figure 3: Rotor
4: Rotor Field Resistance to Ground
days. The ground was due to water ingress that evaporated over time after the rainstorm. The spike was due to testing following the event. The relay reports a large value when the measuring module is removed from service.
CONCLUSION
Two very different causes of large generator protection trip events were analyzed. They demonstrate the proper setting and operation of modern protection devices as well as the data-capture capability that allows for accurate understanding of the respective initiating insulation failures.
Steve Turner is in charge of system protection for the Fossil Generation Department at Arizona Public Service Company in Phoenix. Steve worked as a consultant for two years, and held positions at Beckwith Electric Company, GEC Alstom, SEL, and Duke Energy, where he developed the first patent for double-ended fault location on overhead high-voltage transmission lines and was in charge of maintenance standards in the transmission department for protective relaying. Steve has BSEE and MSEE degrees from Virginia Tech University. Steve is an IEEE Senior Member and a member of the IEEE PSRC, and has presented at numerous conferences.
Figure
MCC CATASTROPHIC FAILURE AT A CLIENT FACILITY
BY ADAM MURRAY, Advanced Electrical Services Ltd.
AES personnel were dispatched to a gas plant in northern Alberta, Canada, for emergency repair of a failed 600 v MCC bus. Before the technicians arrived, the 600 v bus components had already been disassembled by facility personnel to prepare for installation of a new MCC section. For our client, getting the facility back up and running was more critical than performing an in-depth investigation.
However, using information and photographs available to us, the technicians explored potential root causes. Moisture, humidity, and condensation were discussed but quickly ruled out due to a functional climate-control unit in the building and the inherently low relative humidity of this area.
Figure 1: Clues to Root Cause
1. Loose Vertical Bus Connection Point – After Disassembly
2. Heat Dissipation
3. Fault Inception Location Likely Due to Molten Tin Dripping Between Phases
Figure 1 shows that the A-phase bus experienced a high degree of heating between the vertical bus connection and the adjacent horizontal bus connection where the eventual failure occurred. This is apparent due to the high level of oxidation on the bus bar and the lack of tin plating.
A loose vertical bus connection would have dissipated heat into the nearby horizontal connection that was thermally and electrically insulated with vinyl tape. This allowed heat to accumulate within this portion of the bus.
At this point, the A-phase bus bar got hot enough to allow the tin plating to melt and molten tin to drip down on top of the adjacent B-phase bus. This would have effectively created a conductive path between phases allowing subsequent ionization of surrounding air and a flash-over arc (Figure 2).
The root cause of this failure was eventually determined to be loose vertical bus connections that were not recognized during the initial commissioning three years prior. As part of our own internal investigation, we asked the client for previous maintenance records on the failed equipment. The client stated that no previous maintenance had been completed. We determined this to be a key contributor to the failure. This deficiency might have been recognized prior to the eventual catastrophic failure if contact resistance testing had been performed during maintenance.
LESSON LEARNED
The catastrophic failure of the 600 v MCC could have been mitigated and potentially avoided during commissioning or maintenance activities by employing several procedures and tools that are available to us as testing technicians:
• Check the torque on all bolted connections if possible.
• Use a higher current contact resistance testing, if possible, within rated equipment capacity (i.e., a 400 A primary-injection test system vs. a 10 A hand-held contact resistance test set).
• Ensure all vertical bus connections were tested by removing bottom-mounted MCC cells. Removing higher mounted cells would suffice if it’s the only possible way, although most vertical bus sections only have a single bolted connection at the top or middle, so testing at any
Figure 2: Fault Inception Location
Side View of Fault Inception Location After Partial Disassembly
IN THE FIELD
point would confirm the state of the connection. Going to the ends of the bus is always a better test where applicable.
• Visually inspect the bus where accessible to identify anomalies such as insulating tape or clear plastic wrap trapped under the connection or a layer of corrosion/ dirt/oxidation inside the connection.
RECOMMENDED TESTS
When testing bolted electrical connections, several additional test procedures are recommended:
• All bolted electrical connections should be tested with a contact-resistance tester. NETA’s recommended current value is 100 A DC; however, if a higher available test current falls under the confines of the equipment’s rated capacity, it should be used because some high-resistance connections don’t manifest until higher current levels.
• If dealing with a 4,000 A bus, consider using a higher-output test unit and more diligently checking the torque on all bolted connections.
• Inversely, if the equipment is only rated for 20 A, for example, a 10 A test can be used if torque cannot be confirmed.
• Torque checks should always supplement testing if the connections are easily accessible. Specific items to be considered for testing include:
– Vertical bus connections usually accessed by temporarily removing MCC buckets
– Grounding provisions such as Pfisterer ground balls
– Higher-current disconnect switches and breakers (refer to ANSI/NETA ATS and ANSI/NETA MTS for more information)
– Fuse connections (connection only), but be cautious when performing contact resistance around a fuse. A low-current test unit or multimeter can be used if fuse integrity needs to be confirmed.
THEORY
Simply put, a high-resistance connection can generally result in two things we do not want:
• Overheating leading to melted components and potential catastrophic failure
• Voltage drop leading to downstream equipment damage
Remember back to what most of us learned in school. In the case of loose bolted electrical connections, one of the hazardous scenarios as it pertains to our work can be boiled down to when equipment connections cannot sufficiently pass rated current without overheating. This high-resistance connection will effectively create heating. The severity of the heating can be modeled by the P = I^2*R formula, where P is equal to power. This could simply be understood to be directly proportional to the heating effect at this poor connection. I and R are equal to current and resistance, respectively.
The heating effect can also be accelerated by things such as well-insulated connections (thermally and electrically), tight enclosed spaces without airflow, and the positive feedback loop of connection having higher resistance as heat increases. A hot general environment, such as an MCC located in a small building with no A/C in the summer, will also accelerate the effect.
Downstream equipment can also experience a voltage drop from heating. The magnitude of this drop can be modeled by V = I*R, where I is nominal bus current, and R is the resistance of the connection. The following quote from Fluke Corporation’s website discusses the effect voltage drop can have on current unbalance:
“Voltage unbalance at the motor terminals causes high current unbalance, which can be six to 10 times as large as the voltage unbalance. Unbalanced currents lead to torque pulsation, increased vibration and mechanical stress, increased losses, and motor overheating.
ANSI/NEMA standard MG 1 prescribes a 1% limit for voltage unbalance, noting that current
unbalance can be expected to be six to 10 times the voltage unbalance on a percent basis. If the current unbalance exceeds 10%, the supply voltages should be corrected to less than 1% unbalance, or the motor must be de-rated.”
– Fluke Corporation
CONCLUSION
proportional and can cause major issues for plant equipment downstream.
Adam Murray is a Technical Services Manager at Advanced Electrical Services Ltd. with four years of experience testing and commissioning in the industrial and utility sectors of Western Canada. At AES, Adam is responsible for management of medium- to large-scale electrical commissioning and maintenance projects for the many clients they support across Western Canada. He is a NETA Level 2 Technician who studied electrical engineering technology at the Southern Alberta Institute of Technology.
The effects of high-resistance connections can ultimately lead to further issues not typically considered when thinking in terms of resistance. These effects are exponentially • Full Member of the InterNational Electrical Testing Association (NETA)
Licensed Electricians (IBEW-JIW) • Member of the National Electrical Contractors Association (NECA)
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HAND PROTECTION
BY PAUL CHAMBERLAIN, American Electrical Testing Co. LLC
Workers’ hands are the most commonly injured body part. Whether the hazard comes from rotating machinery, pinches between two materials, heat, chemicals, or electricity, your hands are under constant attack. Without them, every task would be difficult to perform. This article identifies the common hazards and risks to a worker’s hands as well as ways to mitigate injuries and promote safety.
CHEMICALS
Many commonly used chemicals in the workplace can cause chronic illness by way of dermal absorption and may go undetected by the worker. Therefore, direct contact must always be avoided. Some chemicals cause burns on the skin that can be painful and debilitating and may take a long time to heal. Chemical burns and dermal absorption potentially result in serious or even fatal injuries.
Employers and employees must each ensure proper use of gloves specific to the type of chemical being handled. Many materials are used for glove construction; some are better suited than others for resisting breakthrough or permeation.
• Breakthrough time can be determined using an ASTM standardized test for the elapsed time between initial contact of the chemical on one side of the glove material and the analytical detection of the chemical on the other side of the glove material. If there is no breakthrough, the glove is marked ND (none detected). Breakthrough times generally reflect how long a glove can be expected to provide resistance when totally submerged in the chemical.
• Permeability of the material (permeation rate) is how long it takes a chemical to pass through the glove on a molecular level. Glove thickness can affect the permeability of a material. ASTM provides a test, and the glove manufacturer must rate the permeability of the glove on its fact sheet. Always refer to the manufacturer’s fact sheet to determine the correct glove for handling a chemical.
LACERATION/ABRASION/ CRUSHING
Cutting a finger while removing insulation, scraping a hand on a sharp panel-door edge, or slamming a finger with a tool can be hard to avoid. Human beings are fallible, but we can minimize the impact of these injuries by using hand personal protective equipment (PPE) such as leather, cotton, or rubberized gloves. In some circumstances, Kevlar or metal gloves
may be necessary to provide the highest levels of protection. Leather gloves are the standard protective equipment for all general injuries and are relatively inexpensive.
A good rule of thumb is that gloves will be necessary if a tool is necessary as part of the job. A job hazard analysis, along with good, oldfashioned common sense will help determine the probability of being lacerated or otherwise injured while performing a task. Much like other forms of PPE, gloves must be inspected for damage and wear and replaced as necessary.
Various work methods can go a long way toward reducing preventable hand injuries. For example, instead of using a knife to strip insulation, use a wire stripping tool. Instead of a razor blade or scissors to open letters or boxes, use a safety knife (Figure 1).
Maintaining proper guarding on tools such as circular saws or right-angle grinders will reduce the potential for injury. Inspect tools regularly to ensure the guarding has not been removed or compromised. Removing the guard may aid in getting a job done quicker or easier, but it could cost a finger — or worse.
ERGONOMICS AND REPETITIVE MOVEMENT
Carpal tunnel syndrome is one of the most common hand injuries in the United States. It is even harder to prevent when activites outside of the workplace contribute to these injuries. Other common types of repetitive motion injuries include tendonitis and bursitis, which are injuries to tendons and bursae, respectively.
Carpal tunnel syndrome is not an occupational hazard exclusive to those using a computer. In
Figure 2: Carpal Tunnel Syndrome Exercizes
Figure 1: Safety Knife
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addition to its impact on those who type all day, it is a hazard to anyone who performs repetitive hand motions, mechanical gripping, small-part assembly, or encounters vibration in fields such as mechanics, factory work, or an electrical trade. Education is the best method of prevention for repetitive motion injuries.
To avoid these injuries, perform frequent range-of-motion exercises (Figure 2) to warm up and prevent and alleviate injury.
Many tools are available to promote proper ergonomics and posture, including a wave-style keyboard (Figure 3) or a trackball mouse.
Take a minute or two to get up and move around and stretch for every hour sitting and working on a keyboard. Several manufacturers of ergonomic mice and keyboards have companion software that reminds the worker to stretch and suggests more effective stretching exercises depending on use.
Hand tools such as right-angle power drills and t-handle drivers can provide proper hand positioning, which helps prevent hand and wrist strain. Padded palms and fingers can help
SAFETY CORNER
prevent repetitive motion injury while using vibrating tools such as a hammer drill or jig saw or while using impact tools such as a hammer.
PROTECTING AGAINST ELECTRICAL SHOCK
Electrical shock injuries to the hands are common in the electrical testing industry. The best prevention for this type of shock is to wear the proper voltage-rated gloves (Figure 4).
Inspection and Testing
Gloves must be tested using an ASTM standard to ensure they properly protect the worker. The chart from Salisbury (Figure 5) indicates the voltage level where each glove is designed to be used. The cuff length must be adequate to protect the forearm from electric arc.
Gloves must be regularly re-tested to the ASTM specification. Two OSHA standards indicate the appropriate test intervals:
• OSHA 1910.137, Personal Protective Equipment – Electrical Protective Devices. This regulation states that gloves must be electrically tested before first issue and every 6 months thereafter.
• OSHA 1910.268, Special Industries – Telecommunications. This regulation states that natural rubber insulating gloves must be electrically tested before first issue, 12 months after first issue, and every 9 months thereafter. Any unissued glove that has not been tested within 12 months must be retested before issue to an employee.
Figure 3: Wave Keyboard
Figure 4: Voltage-Rated Glove
Prote cti ve Rubb e r Equi pme nt L ab e ling Char t
Figure 5: Glove Labeling
The date of last inspection must be marked on the glove or tracked by another means to confirm the expiration date has not been exceeded. OSHA 1910.137(b)(2)(xii) states that the employer shall certify equipment has been tested in accordance with the requirements of paragraphs (b)(2)(viii), (b) (2)(ix), and (b)(2)(xi). The certification must identify equipment that passed the test and the date it was tested. Individual marking of the glove (i.e. equipment identification numbers) and entering the results of the tests and the dates of testing onto a tracking log is an accepted means of meeting this regulatory requirement.
Users must inspect PPE before each use and after any action that may cause damage. This inspection does not need to be tracked, but it does need to be conducted by the user to ensure their safety. The user must visually
inspect the gloves for any physical damage such as punctures, cuts, knicks, cracks, scratches, or abrasions. The user must also inspect the glove for any chemical deterioration of the material by looking for swelling, softness, stickiness, or hardening.
Ozone may also cause rapid deterioration of rubber goods. The glove must be inflated to no more than twice its normal size to ensure the rubber stretches, and the glove must be inspected for breaks in the material by listening and looking for a defect. If a portable inflator is not available, the glove can be manually inflated by rolling the cuff towards the fingers and spreading the fingers to look and listen for escaping air from holes.
This procedure should be repeated with the glove turned inside out to ensure a thorough inspection. Additional detailed inspection
guidelines and procedures can be found under ASTM F1236, Standard Guide for Visual Inspection of Electrical Protective Rubber Products.
CONCLUSION
With so many bones, ligaments, tendons, and joints keeping hands and wrists working, there is ample opportunity for injury in the workplace and during everyday activities. Proper protection, training, equipment, and
techniques go a long way to protecting these important assets.
Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field since 1998, working for various companies and in various industries. He received a Bachelor of Science from Massachusetts Maritime Academy.
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THE LIFE AND HISTORY OF JAMES (JIM) R. WHITE
BY VIRGINIA BALITSKI, Magna IV Engineering
Jim White’s prolific career in the electrical field expanded across many decades with a particular focus on training, education, and safety. Jim was Vice President of Training Services at Shermco Industries, a NFPA Certified Electrical Safety Compliance Professional, a NETA Level 4 Senior Technician, and a dedicated and well-respected professional.
Jim’s contribution to the electrical industry was immeasurable, and he will be greatly missed. This Tech Quiz pays tribute to his life and accomplishments in the electrical industry.
1. In which issue of NETA World did Jim write his first Tech Quiz?
a. Spring 2007
b. Winter 2004
c. Fall 2002
d. Summer 2005
2. How many consecutive Tech Quizzes did Jim White author?
a. 76
b. 70
c. 58
d. 82
3. In which branch of the United States Armed Forces did Jim White serve during the Vietnam War?
a. Army
b. Air Force
c. Navy
d. Coast Guard
4. Jim’s involvement with NETA began in what year?
a. 2002
b. 1986
c. 1998
d. 1996
No. 135
5. What technical committees was Jim a member of?
a. NFPA 70E, Electrical Safety in Workplace
b. National Electrical Code Code-Making Panel (CMP) 13
c. ASTM F18, Electrical Protective Equipment for Workers
d. NFPA 70B, Recommended Practice for Electrical Equipment Maintenance
e. All of the above
6. In what year did Jim win the IEEE/IAS/ PCIC Electrical Safety Excellence Award?
a. 2011
b. 2013
c. 2015
d. 2010
Virginia Balitski, CET, Manager –Training and Development, has worked for Magna IV Engineering since 2006. Virginia started her career as a Field Service Technologist and achieved NETA Level 4 Senior Technician certification. She has since dedicated her time to the advancement of training and safety in the electrical industry. She is a Certified Engineering Technologist through ASET – The Association of Science & Engineering Technology Professionals of Alberta. Virginia is also current Vice-Chair of CSA Z462, Workplace Electrical Safety and is a member of the NFPA 70E, Electrical Safety in the Workplace Technical Committee and has been recently appointed to the NETA Board of Directors.
LV/MV Switches • Relays - All Types • Motor Control Centers • Grounding Systems • Transformers • Insulating Fluids • Thermographic Surveys • Reclosers • Surge Arresters • Capacitors • Batteries
CoNSulTING AND
• Ground Fault Systems
• Equipotential Ground Testing
ENGINEERING SERvICES
• Transient Voltage Recording and Analysis
• Electromagnetic Field (EMF) Testing
• Harmonic Investigation • Replacement of Insulating Fluids • Power Factor Studies
GROUNDING AND BONDING METER SOCKETS
BY JEFF JOWETT, Megger
In an actual reported case, a severe storm blew down a large tree that struck a residence. A meter that should have been reporting 240 V reported a phase-phase voltage of 124 V. The falling tree had pulled down the service, which had then been re-attached by a service crew. A routine voltmeter check revealed 118 V between the left hot leg and neutral, but 241 V between the right hot leg and neutral. A proof test with a copper wire driven into the earth revealed 88 V between the neutral and the wire.
The socket enclosure was live! The service crew restoring the drop had mistakenly connected the socket’s neutral to an energized conductor. The transformer fuse had failed to blow. The socket was energized at 120 V, even though the socket had a driven ground rod. Poor grounding soil had rendered the rod
inadequate to blow the transformer fuse and clear the fault.
Such an incident calls for a closer look at ground protection. When effective, grounding should protect persons from injury and property from damage. It should facilitate the
Figure 1: The human body can survive a considerable shock, but fault currents passing through the heart are most likely to cause a fatality.
operation of protective devices before damage occurs, and it should facilitate the operation of digital systems and the reliability of data.
A commonly heard aphorism states that current will follow the path of least resistance. This is of some interest as a generality, but is not strictly true. Current will divide according to the Law of Parallel Resistances. The danger here is the assumption that as long as the system is “grounded,” everyone is safe from shock and electrocution because fault currents will follow the “path of least resistance” into the earth via the grounding conductor and electrode (rod).
This is true as long as the grounding system doesn’t allow more than a few milliamps to pass through any alternative path, such as a human who has crossed a voltage gradient from an electric motor to a water pipe. And the tolerance isn’t much. A human body is shocked by 5 mA and injured by 10 mA. Therefore,
the grounding system must be installed and periodically maintained at values within these parameters. Its mere existence is not enough.
In the United States, the utility may provide the customer with a solidly grounded system, an impedance grounded system, or an ungrounded system. Regardless of these alternatives, the customer will have a grounding electrode system and equipment grounding. Equipment grounding is a connection of non-currentcarrying parts of the electrical system to ground. These can be motor frames, outlet boxes, conduits, raceways, cable armor, and the like. Connections must provide an effective groundfault current path. In a solidly grounded system, the neutral points have been intentionally connected to earth ground as well.
The National Electrical Code (NEC) states that electrical equipment and wiring — including other conductive material likely to become
energized — shall be installed in a manner that creates a low-impedance circuit that facilitates the operation of overcurrent devices or ground detectors for high-impedance grounded systems. This circuit must be capable of safely carrying the maximum ground-fault current likely to be imposed on it from any point in the wiring system where a ground fault to the electrical supply source may occur. The earth shall not be
used as the sole equipment grounding conductor or effective ground-fault current path.
Therefore, all metering equipment (cabinets, conduits, sockets) must be bonded to system neutral for solidly grounded systems to prevent equipment from becoming energized in a lineto-ground fault. Relying on a ground rod alone may not provide enough current flow to clear a
Figure 2a: Ground-Fault Sensor Installation Around All Circuit Conductors
Figure 2b: Ground-Fault Sensor Installation Around Bonding Jumper Only
fault. If a meter control cable conduit is used for the bonding path, a bond must exist between the conduit and the enclosure. A bond wire can be installed in the conduit in lieu of using the conduit itself, as in the case of PVC conduit. The bond wire should be larger than the size of the meter control wires. If a metal conduit, the bond wire should be bonded to one end of the conduit, preferably the meter end.
With the ground rod or other electrode (grid, mesh, etc.) being thus augmented by parallel connections, the question may be raised as to the usefulness of the rod itself. But the earth ground is invaluable in limiting the voltages due to lightning strokes, line surge, and other similar disturbances. The ground rod enables dissipation of lightning into the earth, where it will neutralize the buildup of charge in the clouds. System voltage to ground is thereby stabilized during normal operation, which is particularly useful in maintaining the operation of sensitive data systems within required parameters.
Separate grounding of the meter is not necessary if located close to the grounded service entrance or utility transformer. However, if located a distance away from both, it is suggested to ground the meter to
the
on the
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Figure 3: Ground electrodes are essential for lightning protection.
neutralize any potential between the earth and the enclosure that is bonded to system neutral.
The primary purpose of the equipment grounding conductor is protection against shock and fire while providing a stable reference for electronic equipment. It is bonded to the neutral conductor and grounding electrode conductor at the service entrance, and there should only be one point of connection with the neutral conductor. The equipment grounding conductor does not carry current during normal operation — only in the event of a fault current. It is preferable to ground meter equipment by bonding to the system neutral inside the enclosure. The equipment grounding conductor may be required for grounding if the meter is located on the load side of ground-fault protection or on the load side of the service disconnect and a long way from it. Meter equipment should never be bonded to both the equipment grounding conductor and the neutral. This practice can create parallel paths
for neutral current to flow on the equipment grounding conductor between equipment and service disconnect. It may flow across surfaces of sockets and enclosures. If the meter is on the load side of ground-fault protection, the enclosure can be grounded by the equipment grounding conductor.
Parallel paths for neutral current flow should not exist across surfaces of meter equipment or through grounding conductors inside enclosures. In order of significance, these unwanted currents can present a safety hazard, a fire hazard, and power quality problems. If a person gets in series with such an unexpected current, a fatality could result. Poor connections could result in heating from such a current and result in fire in severe cases. And such currents produce noise that affects the performance of sensitive electronic equipment.
Not all voltage systems are equal with respect to code requirements.
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• The NEC recognizes a significant difference in safety between 120/208 V and 277/480 V systems with respect to arc faults and arc flashes. Article 230.95 requires ground-fault protection on 277/480 V systems rated 1,000 A and higher.
• IEEE adds some caution regarding clearance of enormous ground faults on higher energy systems. IEEE Std. 242–1986, Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems, 7.2.2 cites the high magnitude of ground-fault currents that can occur on solidly grounded 480 V systems. And IEEE Std. 141–1993, Recommended Practice for Electric Power Distribution for Industrial Plants, 7.2.4 states that solidly grounded systems are the most likely to escalate into phase-to-phase or three-phase arcing faults in 480 V and 600 V systems.
• NEC 230.95 calls for ground fault protection for solidly grounded wye services of more than 150 V to ground but not exceeding 1,000 V phase-to-phase for each service disconnect rated 1,000 A or more. These recommendations are based on awareness of arc fault danger on grounded 277/480 V systems. On larger services, the current required to sustain an arc can be less than the rating of the circuit breakers.
At the other extreme are ungrounded systems where there is no intentional connection between conductors and earth ground. These circuits have the advantage of continued operation after a ground fault on one phase. The purpose is to enable continued production in industrial facilities until a convenient time for shutdown and corrective maintenance. However, there are potential problems with allowing a ground fault to continue indefinitely. A voltage 1.732 times rated will appear on ungrounded phases. Transients of six to eight times normal voltage may appear from line to ground during normal switching, which can cause insulation failures on other points in the circuit, exacerbating the original problem.
This can cause a second ground fault to appear on another phase, which in turn could develop a dangerous phase-phase fault.
High-impedance grounded systems have the neutral connected to ground through a resistance that limits ground-fault currents to very low values, typically under 10 A. By modifying the ungrounded system to mitigate some of the problems, the high-impedance ground also allows operation to continue so as to not limit production. Faults are easier to locate on this system than on ungrounded ones and can be removed. Transient over-voltages are eliminated. The disadvantages are similar to those on an ungrounded system. The unfaulted phases rise to line-to-line voltage, further stressing insulation. Additionally, a line-to-line fault can be created by a second line-to-ground on another phase. IEEE Std. 242–1986, 7.2.5 states that ungrounded systems offer no advantage over high-resistance grounded systems and are used less today than the latter.
CONCLUSION
Industrial production as well as office data management can be negatively impacted by poor or improper grounding. Personnel can be put in danger. It is advisable, therefore, to follow code and all relevant standards to keep systems operating at maximum efficiency and safety. Haphazard grounding can produce loss of revenue, fire, and even lethal accidents.
REFERENCES
Christian, Trent. “Grounding and Bonding Meter Sockets,” presented at Southeastern Meter School and Conference, Auburn University, August 2021.
Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and MultiAmp for electrical test and measurement instrumentation. He holds a BS in biology and chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co., which became Biddle Instruments and is now Megger.
NERC PRC-027-1
OVERVIEW AND IMPLEMENTATION
BY MAYSAM RADVAR, PEng , PE, and CASEY WHITT, Ready Technologies, a division of Shermco
As generation is connected to the grid, the available short-circuit current is evolving, increasing in areas where synchronous resources are installed and decreasing in areas where inverter-based resources, such as solar and wind power, are installed. With the U.S. Department of Energy’s recent plan to drastically increase the amount of solar connected to the grid over the coming decades, one sure fact is that existing and future sites can expect upcoming changes to short-circuit levels.
This has a variety of impacts on the grid, including altering the coordination of installed relays, which is the concern of the three-part NERC PRC-027-1, Coordination of Protection Systems for Performance During Faults that became effective in April 2021. PRC-027-1 Requirements R1 and R3 relate to the establishment and implementation of a site
procedure to ensure coordination is maintained across electrically connected entity boundaries. Requirement R2 requires the reassessment of applicable relay settings against the actual available short-circuit current levels, as opposed to the previously existing — and potentially drastically different — levels used to originally determine the settings. This article dives deeper
into each of these three requirements, what they include, and which protective elements are applicable, generally from a generator owner’s perspective.
REQUIREMENT R1
Overview
Requirement R1 itself is composed of three parts, all with the overarching concern of establishing a procedure for developing protection settings while also mitigating the introduction of any potential coordination concerns.
Part 1.1 requires that a procedure be designed for reviewing the data used in short-circuit models for accuracy, so that the model, and therefore the fault levels taken from model simulations, can be the most accurate reflection
of the existing system. This ensures that any protection developed using these fault-current levels will be appropriate and effective not only in simulation, but also in the real-world application. The Supplemental Material section of standard PRC-027[1] further elaborates on what this review should include. If a generator owner does not maintain a short-circuit current model, this portion of the standard may require communicating with the transmission planner or other entity that does own the short-circuit model so that the site-specific information can be reviewed.
Part 1.2 requires another review procedure. Once the protection settings of applicable elements have been developed, there should be a systematic procedure to check that they meet technical criteria. No single set of technical criteria is included in the standard, as the criteria is unique for each site depending on protection philosophy, system configuration, and more. Therefore, the technical checkpoints should be outlined by and specific to each entity.
Part 1.3 requires a procedure to communicate settings between electrically connected entities. Four communication procedures are included:
1. Communicate proposed settings.
2. Respond to connected entities that provide proposed settings and state coordination concerns or confirm coordination.
3. Communicate verification of coordination concerns being resolved.
4. Communicate updated settings if changes need to be made to those originally communicated due to unforeseen circumstances.
Applicable Elements
Protection elements that are on bulk electric system (BES) elements and that require coordination with electrically connected entities — i.e., have a zone of protection that will overlap with the zone of protection of other elements owned by a separate entity — are applicable to this portion of the standard. For a generator
NO SINGLE SET OF TECHNICAL CRITERIA IS INCLUDED IN THE STANDARD, AS THE CRITERIA IS UNIQUE FOR EACH SITE DEPENDING ON PROTECTION PHILOSOPHY, SYSTEM CONFIGURATION, AND MORE.
owner, this may include switchyard elements such as distance (21), overcurrent (50/51 or 67 if directional towards transmission system), or differential (87) protections. Phase and ground protections should both be included. Breaker failure (50BF) protection should also be included in communication because, while this protection itself does not need to coordinate with those from other entities, it will affect the coordination timing of the protective elements that will cause it to operate.
the reach should also be communicated. The transmission planner may also request additional information in order to assess the coordination.
REQUIREMENT R2
Overview
Requirement R2, the assessment portion of the standard, includes three potential assessment paths.
REGARDLESS OF GENERATION TYPE OR SPECIFIC SYSTEM CONFIGURATION, IDENTIFYING THE ZONES OF PROTECTION OF THE ELEMENTS UNDER ASSESSMENT IS CRUCIAL TO DETERMINING COORDINATION.
A generator owner will also have applicable elements on their step-up transformers and generation, though there are some differences between synchronous and inverter-based resource (IBR) sites.[2] Like the switchyard, distance (21), overcurrent (50/51/51V), and differential (87) protections should be considered and included if their zones of protection extend into zones of protection owned by another entity. Phase and ground protections should be included, as should beaker failure (50BF) protection and negative sequence/unbalanced phase (46) protection. For a synchronous site, protections on the generator bus and generator step-up transformer (GSU) will usually be applicable, except potentially generator differential protection (87G), as it may not extend past the GSU depending on the protection philosophy at the site. In contrast, for an IBR site, protections on the main power transformer (MPT) are usually applicable, while those on the feeders, pad-mount transformers, and inverters do not typically have zones that extend far enough to require coordination with the transmission protections.[2]
Note that the above guidance is based on a typical site configuration and protection philosophy but should not be considered a universal representation. Each site is unique and should carefully consider its specific system and protection schemes to determine which elements require coordination with other entities.
Generally, a generator owner should communicate the protection operating time or characteristic and the settings that will affect this timing to the transmission planner. For distance elements, the settings that determine
The first is fairly straightforward; it allows a generator owner to review protective element coordination every six years or sooner. This review should be conducted using faultcurrent levels from a short-circuit model that has been reviewed and updated as required by Requirement R1.
The second option allows a generator owner to compare fault-current levels from a short-circuit model that has been reviewed and updated as required by Requirement R1 against an established fault-current baseline every six years or sooner. This method potentially avoids a full coordination review if the deviation of the updated fault levels from the baseline is less than 15%. The fault level deviation must be considered at every bus with connected BES elements.
If the updated fault current deviates more than 15% from the baseline, the updated values should be established as the new baseline once a coordination assessment has been performed. The baseline can be updated before this level of deviation has been reached but can only be established after a coordination assessment has been completed.
The third option allows for a combination of the two methods. A site may choose to divide their system so that one portion is assessed using the first option and the other portion uses the second option.
Per PRC-027, fault-current baselines should have been established prior to the standard becoming effective in April 2021. If a site has not established a baseline, the first option is the only path for the
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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.
first PRC-027 assessment performed. The faultcurrent baselines can be established after the assessment is completed if the site chooses, and the second or third option could be used for the next PRC-027 assessment in six years or sooner.
Applicable Elements
Similar to Requirement R1, elements that require coordination with electrically connected entities are applicable to Requirement R2 — but only those that are dependent on faultcurrent levels to develop their settings. This includes phase and ground distance (21) and overcurrent elements (50, 51, 51V, and 67 if directional towards the transmission system).
Note that if a site uses a wye-delta connected transformer with the wye-connected winding on the transmission side, then ground elements on the delta-connected side of the transformer do not need to coordinate with those on the wyeconnected side for a fault in the transmission system. This is because the delta-connected winding will trap and circulate zero-sequence currents from the fault on the wye-connected side, effectively isolating the wye-connected and delta-connected zero-sequence systems and eliminating the need for coordination between elements that measure such currents.
Coordination
Requirement R2 is the assessment portion of the standard. It requires existing protection settings to be reviewed to ensure their operation
is properly coordinated. What does it mean to be coordinated? There is no one definition, as it is very dependent on protection philosophy, system configuration, breaker operation, etc. Generally, the goal of coordination is to protect equipment and isolate faults while keeping as many pieces of equipment in service as possible. However, how this is implemented from site to site will vary. Coordination for a site with one generator and one transformer will look different than a ring of bus generators which will look different than a wind or solar site.
Regardless of generation type or specific system configuration, identifying the zones of protection of the elements under assessment is crucial to determining coordination. The order of operation of protections will vary from site to site, but the concept of primary and backup elements and protection zones remains applicable.
In protective systems, there are multiple definitions of primary and backup protection. There can be primary and backup protection for the same zone but provided by different types of elements, such as primary differential protection and backup overcurrent protection. There can also be primary and backup protections that perform the same function and provide redundancy in case of misoperation or equipment failure, as shown in Figure 1 (although redundant protection may be a more appropriate name for such a setup). Additionally, there can be primary and backup protections that have different primary zones of protection, but the backup will operate if the primary does not operate for a fault in its zone after a given time, also shown in Figure 1. This final type of primary and backup protection is the concern of PRC-027 coordination. Elements identified as providing backup protection should typically operate approximately 0.5 seconds after those identified as providing primary protection.[3]
To assess coordination, a site should use the actual settings used for the protective elements. This may require pulling the settings from the relay if they are not available. Relay tests can
Figure 1: Primary and Backup Protection
also be used but can be more difficult than relay-specific settings to interpret and use in coordination assessment programs such as SKM Power*Tools, ETAP, ASPEN OneLiner, or other similar software.
REQUIREMENT R3
Overview
The final portion of the standard essentially requires that the processes established in Requirements R1 and Requirement R2 are followed. Following the flow of the established procedure may look something like the following:
1. A need for new or revised protection settings has been identified due to adding new protection elements, a mis-operation in an existing element, or another cause. Alternatively, existing settings may have been identified as needing revised settings due to a periodic Requirement R2 coordination review or a deviation of 15% or more from the fault current baseline.
2. If the new/revised element is applicable to Requirement R2 (i.e., the settings are developed using fault-current levels and require coordination with other protection systems) or a periodic or fault-current deviation review is being conducted, then the short-circuit model data should be reviewed and updated following the procedure developed per Requirement R1.
a. If the site is using the baseline faultcurrent option for Requirement R2, the updated fault-current levels may be established as a new baseline as well.
3. Develop the settings using the appropriate short-circuit levels.
4. Conduct a review of the settings following the procedure developed per Requirement R1. This could be a third-party review, a program checker, or some other method as explained in PRC-027-1.[1]
5. Communicate the proposed settings and any other necessary information to
electrically connected entities following the procedure developed per Requirement R1.
a. If an entity receives proposed settings, they must review the settings and respond, stating either coordination concerns or acceptable coordination.
b. If coordination issues are identified, the entities must work to resolve them to the point possible.
c. Verify resolution once any potential coordination issues are resolved.
6. If any protection setting changes need to be made to those initially communicated to connected entities, those new settings should be communicated. A change in settings could be required due to implementation issues, mis-operation, or other concerns.
a. As good practice, relay testing and setting documentation should take place as well.
CONCLUSION
This article provided an overview of the PRC027 requirements, along with some guidance on how to implement them. This is not a comprehensive guide on the standard, however, and implementation will vary from site to site.
Additional recommended reading:
• For further descriptions on the components of PRC-027 and the reasoning behind its criteria: NERC Reliability Standard PRC-027-1 and the Supplemental Material section
• For element applicability: Transmission-toGeneration Protection System Coordination Guidance and Practices, a joint document by the North American Transmission Forum (NATF) and the North American Generator Forum (NAGF)
• For coordination guidance: NERC System Protection and Control Subcommittee. Considerations for Power Plant and Transmission System Protection and Coordination
COVER STORY
REFERENCES
[1] NERC Reliability Standard PRC-027-1, Coordination of Protection System Performance During Faults, 2007.
[2] NERC System Protection and Control Subcommittee. Considerations for Power Plant and Transmission System Protection Coordination, Technical Reference Document — Revision 2, July 2015.
[3] NATF, NAGF. Transmission-to-Generation Protection System Coordination Guidance and Practices, Version 0.94, 2020.
Maysam Radvar, PEng, PE, has been a Senior Power System Engineering Manager for Ready Technologies, a division of Shermco, since 2010. After acquiring a BSEE and MSEE at the University of Alberta, he has established his career in the field of power systems
and protection systems. Maysam is interested in performing NERC compliance studies, generator baseline testing, NERC MOD-026 and MOD-027 testing, power system dynamic and transient stability analysis, power system protection design, and renewable energies. He is a Senior Member of the IEEE Power and Energy Society (SMIEEE), the North American Generator Forum (NAGF), and the Western Interconnection Compliance Forum (WICF). He is a Professional Engineer in the states of Washington, Wyoming, Colorado, and Maine, as well as in Alberta, British Columbia, Saskatchewan, and Ontario, Canada.
Casey Whitt has worked for Ready Technologies, a division of Shermco, since she graduated from Oregon State University in 2019 with a BS in electrical and computer engineering and a minor in computer science. Her current area of focus is assessing NERC compliance, particularly for renewable sites, but she also has interest in renewable energy positive sequence modeling, electromagnetic transient modeling, and protection system design. She is currently working towards her Professional Engineer license.
JET Electrical Testing, LLC is a 24/7 full service testing company founded upon the premise of providing exceptional customer service and the most highly skilled technicians in the industry. The team of project managers, engineers, support staff, and field technicians form the cohesive team in which customers have relied on year after year. JET specializes in commissioning, preventative maintenance, equipment repair, apparatus testing, and emergenc y response/troubleshooting. Electrical system reliability is JET’s goal.
TURNING THE CORNER ON CYBER-SECURE PROTECTION TESTING
BY BRYAN GWYN, SAGAR SINGAM, and JOE STEVENSON, Doble Engineering Company
Matters of NERC PRC and NERC CIP compliance intersect during protection system testing on substation networks. In the modern regulatory environment, the benefits of computer-based relaying are challenged by the costs of cyber security and disrupted or insufficient relay testing practices. The way forward demands interconnected data and the ability to track critical metrics automatically. Organizations can modernize while ensuring compliance readiness by implementing systems that integrate protection and cyber domains into scalable management platforms.
Electric power utilities that operate bulk electric system (BES) generation and transmission facilities confront more challenges than ever before. The stakes surrounding system reliability have never been higher, and the pressure on workers — especially
protection and control (P&C) and information technology (IT) personnel — is tremendous.
Every turn in the modern utility work environment is seeing demands to modernize and deploy re-envisioned operations that
rely heavily on automation. Devising new philosophies and practices at a time when the grid is undergoing rapid power delivery transformations and cyber attacks are pervasive can significantly disrupt and overload the workforce.
Personnel in P&C and IT areas of utility operations perform work that directly affects system reliability. Despite evolving power system conditions and increased defenses against cyber threats, they must maintain stability with existing systems while plotting next steps to keep pace with advancing technologies. On top of it all, they face unique responsibilities concerning mandates that are enforced by the North American Electric Reliability Corporation (NERC).
COMPLIANCE
NERC Critical Infrastructure Protection (CIP) refers to a set of requirements that
bind utilities to the protection, security, and maintenance of computer infrastructures that affect BES reliability. NERC CIP standards specify measures utilities must abide by to defend devices, software, and data against cyber threats. Twelve CIP standards are presently subject to enforcement, and some of them are being revised while new ones are being proposed for future enforcement.
NERC Protection and Control (PRC) standards require proof that elements affecting the reliability of protection and control systems among BES facilities are being addressed by utility engineering and maintenance processes. NERC PRC standards confront orthodoxy within P&C operations by expressly stating the metrics that are expected and the time that is allowed for attaining them. Some PRC standards allow alternatives to time limits if evidence can be presented that substantiates the necessary criteria. There are nineteen
PHOTO:
enforceable PRC standards, and as with CIP standards, there are PRC standards that are presently being revised and new ones that are being drafted.
NERC compliance means different things to IT and P&C teams, though cyber security and protection system reliability are interrelated subjects with evolving technical and regulatory responsibilities. CIP mandates affect PRC mandates and vice versa, and P&C teams and IT resources who support them are both affected by the complexities of dealing with various data from utility electronics and electrical equipment.
NERC PRC-005, Protection System, Automatic Reclosing, and Sudden Pressure Relaying Maintenance if used on BES facilities.
COMPLIANCE PROGRAM
SUCCESS IS INFLUENCED GREATLY BY THE INVOLVEMENT OF STAKEHOLDERS WHO CAN REVEAL THE COMPLICATIONS ENDEMIC TO CYBER SECURITY WHEN IT COMES TO ROUTINE PROTECTION ENGINEERING AND TESTING RESPONSIBILITIES.
Personnel who engineer and test protection systems cannot do their work without company-issued computers installed with authorized software applications. It is not uncommon for P&C personnel to use dozens of software applications given the numerous device types and data formats in play. Consequently, security patches and software updates needed for P&C software applications can overwhelm IT support staff. Safeguards in place for CIP compliance can impede P&C workers who face PRC compliance deadlines. Regardless, NERC-mandated requirements must be completed on time, and thorough documentation must be kept that could be needed as evidence for compliance audits.
RELAYS
Microprocessor-based relays are multi-function, networked devices that perform analog–digital/digital–analog signal conversions and algorithmic protection, automation, communication, and control processes. Microprocessor relays have software from their respective manufacturers that is used to program the devices. The files produced by the manufacturers’ software contain settings data in different proprietary formats. Test technicians who commission microprocessor relays and those who perform periodic maintenance testing on them deal with hundreds or even thousands of settings not to mention logic parameters that must also be verified.
A significant number of electromechanical relays are still used and usually have their own set of engineering and testing files, records warehousing, test materials, and maintenance practices. Electromechanical relays are singlefunction analog protective devices that require calibration during maintenance; they fall under
Purely digital relays — intelligent electronic devices (IEDs) — are multifunction, algorithmic, protection and control devices that have proprietary configuration software, though additional programming steps are necessary. IEDs must be set to respond properly to digital signals being emitted by other IEDs in substation network infrastructures. In protection and control systems based on the IEC 61850 standard, IEDs process digital signals containing power system quantities and inter-device communication streams in separate process bus (protection system) and station bus (control system) networks. IED programming involves not just the device itself, but also the configurations of other IEDs and even the process bus and station bus networks as a whole. The devices are nodes of substation networks.
Interactions Affecting PRC and CIP Compliance
NERC PRC-027 Coordination & PRC-004 Misoperations
• Power System Data
• Setting Calculations
• Coordination Studies
• Communication with Connected Entities
Power System Model
NERC PRC 005 Maintenace
• Deploy Settings and Patches
• Track Intervals and Results
NERC CIP-007 System Security
Security Patch Management
NERC CIP-010 Change Management and Vulnerability Assessments
Maintain Cyber Asset Security
• Maintain Transient Cyber Assets
NERC CIP-013 Supply Chain Risk
Figure 1: Complying with NERC PRC and NERC CIP standards introduces complexities in utility operations.
Microprocessor-based relays and IEDs used on BES facilities come under both PRC and CIP compliance mandates. As devices that affect the reliability of protection systems on BES facilities, they must be tested within required time intervals. As computers on BES facilities, they are considered cyber assets and added care must be taken during testing to prevent malware incursions into substation networks.
Protection system device testing requires specialized electrical equipment that usually is paired with control software provided by the respective test instrument manufacturer, although stand-alone protection test software also exists in the power industry marketplace. P&C departments might have designated personnel who specialize in testing certain relays, or they might have crews equally capable of testing across relay types. They might perform automated tests with certain relays and manual tests with others. They could outsource testing if in-house resources are too few or are inexperienced, or perhaps if they lack the necessary test instruments. In any event, they are responsible for compliance with NERC PRC and CIP standards as well as maintaining test records as evidence for compliance audits.
Protection system engineers use software tools that compute relay protection settings from configured power system models. Relay settings and configuration data are usually managed in various mediums from scanned documents to spreadsheets and databases to relay manufacturers’ proprietary software files, although protection system asset management software is available commercially. The settings records of relays on BES facilities are subject to both PRC and CIP standards; BES relay settings must be verified on the actual devices, and settings data can only be applied to devices in secured computer-to-device exchanges.
Network topologies that are home to today’s protection and control systems are managed by operational technology (OT) personnel in concert with IT departments that have enterprise cyber security top-of-mind. P&C personnel who previously faced limited, if any, company oversight of their work computers now operate under much more scrutiny and control. The systems and applications they use must be secured and maintained centrally through OT/IT, which invites challenges to ongoing support of older products and slows the adoption of the latest-and-greatest tools personnel might need.
COMPLIANCE
In essence, PRC compliance and CIP compliance are tightly integrated parts of overall NERC compliance programs. Although separately enforceable, they are mutually consequential. Utility compliance officers identify, track, and report on NERCmandated elements within these standards but may not realize or plan for how the mandates impact workers. A best practice is proactive coordination between compliance officers and subject matter experts from OT/IT and P&C areas of the organization. Compliance program success is influenced greatly by the involvement of stakeholders who can reveal the complications endemic to cyber security when it comes to routine protection engineering and testing responsibilities.
Utility information systems can be separated by functional areas. For example, compliance management systems in the domain of compliance officers are separate from cyber
security management systems that reside with IT. Protection system models and relay settings data are managed by protection engineers, whereas information about protection testing is found on field computers and shared drives or in filing cabinets.
For compliance program strategies to be effective, utilities need central data, information, and workflow management. OT/IT and P&C areas can become tasked with refining and expanding existing in-house systems. Where there are limits, workarounds are devised. Commercial software products that are used become integrated as far as possible, but varied data formats and diverse work processes within P&C cause gaps that in-house central management approaches don’t overcome.
Many utilities use commercially available central management software that can consolidate, standardize, and integrate cyber security, protection engineering, protection
testing, and compliance. Ultimately, these systems ensure cyber-secure transactions of critical data in mediums that do not hinder worker efficiency, even if workers have different needs and come from separate functional areas.
TRACKING AND REPORTING
With effective central management of cyber assets and P&C work details, compliance officers have visibility into numerous interconnections between processes and individual CIP and PRC standards. Having such visibility proves invaluable when plotting work steps for teams to follow. For instance, consolidated information about CIP and PRC mandates can enable compliance teams to focus on priorities (the mandates) and offload tracking and reporting functions to the software systems’ automated management functions. Analytical tools can provide crucial insights about compliance-related activities and the effects they have on reliability.
For example, PRC-004, Protection System Misoperation Identification and Correction requires utilities to formalize procedures surrounding the identification and correction of unforeseen or unexpected protection system operations. Faulty test practices and incorrectly applied relay settings are two main causes of relay failures, and NERC mandates that utilities track how they investigate and resolve mistakes within their operations.
NERC PRC-004 tracking could expose one additional factor that leads to relay misoperations: overdue maintenance testing. Another standard, PRC-005, Transmission and Generation Protection System Maintenance and Testing requires utilities to provide evidence that relays and other protection system components are tested in regular maintenance intervals. Auditors want to see that utilities have viable protection system maintenance programs to the extent that they have the capacity to reach all BES protection system facilities and that testing and calibration is accomplished by required deadlines.
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MISOPERATIONS
But what if protection system misoperations result from relay settings that weren’t correct in the first place? Another NERC PRC standard, PRC-027, Coordination of Protection Systems for Performance During Faults, effective April 1, 2021 , addresses that issue by mandating periodic settings reviews and protection system coordination studies.
The new requirements affect protection engineers who must produce evidence of a formal process they adhere to when developing settings. Under PRC-027, protection engineers must also revisit system models, recalculate all protection settings values, and re-coordinate protection schemes.
NERC
WANTS UTILITIES TO ENACT PROCESSES TO PROACTIVELY FIND INCORRECT RELAY SETTINGS, CORRECT THEM, AND COMMUNICATE CORRECT SETTINGS INFORMATION TO AFFECTED ENTITIES IN A TIMELY MANNER.
NERC addresses the likelihood that protection settings may become invalid as changes in fault currents occur. These changes may be due to changes in the power system such as changing power system characteristics as a result of significant additions of inverter-based renewables coming online that can affect protection system operability on the BES. NERC wants utilities to enact processes to proactively find incorrect relay settings, correct them, and communicate correct settings information to affected entities in a timely manner.
PRC-027 brings into focus the accuracy of protection settings over time. Requirement 1 (R1) of the standard concerns the accuracy of the original power system models upon which protection settings are first calculated. The settings that go into service in protection schemes are only as good as the data in power system models. For this reason, PRC027 R1 mandates that power system models are reviewed and updated.
Another part of R1 concerns review of protection system settings. Protection engineers must periodically revisit the settings for accuracy, but also to ensure that neighboring, electrically joined utilities have settings on record that coordinate with one another, such that protection systems operate in the intended sequence during faults. Settings verification between affected utilities is a two-way street, and both share responsibilities under this PRC-027 requirement.
Why is this necessary? Because power systems change over time. With the PRC-027 standard,
PRC-027 Requirement 2 (R2) concerns protection system coordination. Under R2, protection engineers must verify that coordination studies are performed on the affected protection systems any time there have been significant changes to the BES. Similar to R1, if any settings changes arise from coordination studies being performed, protection engineers must contact any affected electrically joined utilities and communicate the new settings information to ensure all protection systems in that area are coordinated properly for handling power system faults.
Concerning the communication to neighboring utilities of settings change information, R1 and R2 are not completed until there is documentation that the communication took place. Further, the matter of settings changes on electrically joined BES facilities isn’t a oneand-done situation; both entities remain in consultation with one another back-and-forth until their respective peer-reviewed coordination studies can validate the settings are accurate within the given schemes involved. Both entities must agree and sign off to this effect, which is the documentation NERC auditors want to see provided with PRC-027 evidence.
DOCUMENTATION
NERC standards PRC-004, PRC-005, and PRC-027 are just three examples of standards that affect protection engineers and relay testing crews by requiring documented proof that activities are performed as mandated. The documentation these standards require can come from the same data source if a robust central management system is implemented that tracks lifecycle relay test details, maintenance intervals, relay settings and configuration changes, and associated work assignments. Many other NERC PRC standards impact protection engineers that also require evidence of compliance.
Protecting PRC compliance data and enabling automation while P&C teams do their work is possible with commercially available central management software. However, software automation depends on the human element. OT/IT teams need to be aware of processes and procedures P&C teams have in their compliance
responsibilities. Conversely, P&C workers need to accept their roles and responsibilities in cyber security.
Implementing a central management system that supports PRC compliance reporting and officeto-field workflows takes a consultative process involving company stakeholders and the software vendor. A quality supplier will have a proven track record with many installed utility customers. The ideal supplier will offer configurable software and a detailed statement of work (SOW) that is clear and captures the full scope of the implementation project. The system must comply seamlessly with instituted cyber security measures and offer powerful administrative controls over user access privileges.
CYBER ATTACKS
Unrelenting cyber attacks on utility computer networks have increased concerns of adaptive measures cyber criminals will take to achieve their objectives. NERC CIP standards challenge
CYBER SECURITY MEETS PROTECTION TESTING:
ARE YOU READY?
Utility professionals have many demands placed on them – managing capital projects; bringing renewables online; maintaining the grid; upskilling the workforce – and it all makes for a full and challenging workday.
And all the while they need to make sure they are compliant with rigorous reliability standards.
When it comes to protection system engineering and testing, cyber security is critical. Scalable management platforms from Doble seamlessly integrate NERC PRC and NERC CIP requirements into protection engineering and testing workflows. Compliance readiness is automatic and transparent while professionals do their work.
• Transient Cyber Asset Program – hardened devices with professionally managed security and software
• Patch Assure – NERC CIP-007-6 R2.2 compliant advanced patch management for OT and IT applications
• PowerBase – protection and enterprise asset, test*, workflow and compliance management software
• *RTS – universal protection testing and field process software
• *Protection Suite – comprehensive protection test software of Doble Power System Simulators
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Interactions Affecting PRC and CIP Compliance
NERC PRC-027 Coordination & PRC-004 Misoperations
• Power System Data
• Setting Calculations
• Coordination Studies
• Communication with Connected Entities
Power System Model
NERC PRC 005 Maintenace
• Deploy Settings and Patches
• Track Intervals and Results
NERC CIP-010 Change Management and Vulnerability Assessments
• Maintain Cyber Asset
• Maintain Transient Cyber Assets
NERC CIP-007 System Security
• Security Patch Management •
NERC CIP-013 Supply Chain Risk
Central Management Plan
• Secure, expandable data warehousing that supports system protection and cyber security
• Non-disruptive processes and workflow controls
utility cyber security programs to elevate their defenses by reducing their threat vectors.
NERC CIP-013, Supply Chain Risk Management in particular mandates that utilities have security controls concerning computer software and hardware products being procured. At issue are cyber threats that may be posed to the BES if the products are compromised coming from the vendor. CIP-013 requires proactive communication from vendors if cyber security risks are determined in products sold to utilities, and utilities must coordinate risk management plans in their supply chain procurement processes to prevent onboarding products that could pose cyber security risks.
NERC CIP-010, Configuration Change Management and Vulnerability Assessments exists to prevent unauthorized changes on BES cyber
• Transparent engineering, maintenance, and compliance coordination
• Automated trending, analysis, messaging, and reporting functions
systems by external intruders. Utilities must determine and address vulnerabilities before hackers have the opportunity to exploit them for nefarious purposes.
CIP-010 requires vulnerability assessments every 36 months that look for gaps in and assess the effectiveness of preventive measures against malicious cyber attacks. One measure that can prevent hackers from accessing cyber systems is maintaining up-to-date security patches. Unpatched software allows hackers to run malicious code by using a known, unpatched security bug, and so cyber hackers always try to exploit unpatched systems.
As part of vulnerability assessments under CIP010, utilities must produce evidence that they have reviewed installed patches, that they have a security patch review and mitigation process,
Figure 2: Integrated data and workflow processes supported by a central management platform ensure
and NERC CIP compliance.
and that they have processes for other cyber security vulnerability mitigations concerning software and software patches on cyber assets.
Requirement 4 (R4) of CIP-010 requires utilities to deploy transient cyber asset (TCA) computers for workers to use when connecting to cyber assets like microprocessor-based protective relays. Having secured TCAs prevents the possibility of malware being introduced onto cyber assets during maintenance.
Taken together, the requirements of CIP-010 impact OT/IT workers who must support security patching for a multitude of P&C software applications and manage those updates on TCAs across their organization. Baseline configurations of all cyber assets comprising cyber systems must be monitored and vulnerability assessments must be performed every 36 months to detect any means by which unauthorized changes to BES cyber assets could occur.
NERC CIP-007, Systems Security Management requires a process for assessing, tracking, and installing cyber security patches on BES cyber assets. Utilities must operate their patch management process every 35 days to avoid non-compliance penalties. Given the high volume of devices and applications this standard affects, efficient monitoring and control practices are critical. Commercial patch management that addresses CIP-007 requirements is available that provides a seven-day turnaround and can be a valuable solution for overwhelmed OT/IT resources.
Compliance with NERC PRC and NERC CIP requirements would benefit from some form of automation to offload burdens from personnel who already have heavy workloads. The optimal scenario is central management from an integrated platform of software systems that can track data from front-end testing and maintenance activities to protection system engineering to back-end compliance and cyber security processes.
Ultimately, PRC requirements come down to assurance that protection systems will operate as intended to maintain reliable power delivery on the BES. NERC mandates that utilities
ensure their relay settings are reviewed and that they are properly coordinated across the grid.
Protection engineers must demonstrate consistency and thoroughness in all aspects of the settings development and deployment process. Personnel who test relays must maintain cyber-secure measures while entering substations and performing work on substation networks. When they test relays — cyber assets — they have additional responsibilities to defend against cyber attacks while ensuring relays are properly set and correctly functioning.
NERC CIP requirements affect PRC compliance activities by requiring TCAs to be used by field crews. Additionally, the software P&C personnel need on their TCAs must be patched and monitored regularly, and the TCAs themselves must be tracked.
An integrated management platform must support the monitoring and patch management of testing software used in the field on TCAs. It must also handle power system model data and relay settings lifecycle changes generated by protection engineering teams. It should offer modules for connecting P&C data to enterprise asset management (EAM) systems, even offering specialized P&C work management components that augment EAM workflows. It must also provide straightforward, configurable reporting in all aspects for any stakeholder.
The platform must be supported by a relational database that can offer structured data for linking to external systems. Utilities working with a supplier to implement an automated central management system have the opportunity to look at existing processes and shed inefficient or unnecessary practices.
Through a consultative implementation process, utilities can harmonize different data from various sources and for different stakeholders into a modern way of working that benefits all parties:
• Field crews will operate with the applications they need and use TCAs seamlessly with test equipment and relays.
• Protection engineers will have templates that standardize settings development and will seamlessly flow settings data into power system models for efficient coordination studies.
• Compliance officers will have dashboards and simplified reporting.
• OT/IT personnel will have decreased administrative burden.
CONCLUSION
Effective NERC compliance programs are those that enable utilities to achieve objectives. Right now, the benefits of substation automation and renewables are becoming tangible, but digital protection systems and the effects of inverterbased generation on the BES need workers’ focus to overcome these complex issues. Compounding the complications they already face with inefficient compliance program operations can prevent modernization from happening. Utilities that work from a culture of NERC compliance and have the proper tools to do their jobs are in the best position to avoid financial penalties from
non-compliance and overcome the uncertainties of technological and regulatory changes over time.
Bryan Gwyn, PhD, CEng, is the Senior Director of Solutions at Doble Engineering Company where he brings strategic leadership to engineering teams in protection system and cyber security subject areas that advance new product and service offerings for the global power delivery marketplace.
Sagar Singam is a Cyber Security Engineer with Doble Engineering Company where he performs consultative professional services in the delivery of Doble cyber security solutions.
Joe Stevenson is a Product Marketing Manager with Doble Engineering Company where he develops marketing strategies and materials in support of Doble protection software.
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QUICK GUIDE TO DISCHARGE TESTING
BY SANKET BOLAR, Megger
Batteries serve as the main source of power in a substation in the event of an AC outage. They power critical loads and equipment like relays, indicator lamps, circuit-breaker control, motor operators, SCADA, event recorders, etc. As the battery is truly put to the test only during an outage, it is important to monitor battery health on a regular basis as part of preventive maintenance so they can be relied upon when AC fails. Capacity testing or discharge testing is an effective way to track battery health and thus ensure reliability.
NERC/FERC REQUIREMENTS
The North American Electric Reliability Corporation (NERC), certified by the Federal Energy Regulatory Commission (FERC) as the Electric Reliability Organization (ERO) in 2006, develops and enforces reliability standards among all bulk power system (BPS) owners. To ensure a reliable protection system, NERC covers stationary battery maintenance procedures in the PRC-005-6 standard.
Among other activities, PRC-005-6 states that ohmic testing or capacity testing must be performed at specified intervals that vary depending on battery type.
What is capacity?
Capacity is the ability of the battery to supply a load for a certain duration. It is measured in Ahr. A battery with a certain capacity (Ahr) should be able to provide a certain current (A) for a certain duration (hr). Through a discharge test or capacity test, it is possible to measure the capacity of the battery. A capacity test can determine whether the battery will be able to perform its function well when an outage occurs.
What is a Capacity Test?
In a capacity test, the battery is subjected to a simulated outage. Current is drawn from the battery in a controlled manner, and the battery
discharge is monitored. As the test progresses, the battery voltage begins to gradually drop down to its end voltage. The time taken for the battery to reach the end voltage is used to determine the capacity of the battery. Figure 1 shows a typical battery discharge curve.
The capacity test can be done in various ways: constant current discharge, constant power discharge, constant resistance discharge, load profile, etc. The constant current discharge method is the most popular and is widely used. While doing the test using this method, the test current is kept constant throughout the test.
Why is Capacity Testing Not Preferred?
Although the discharge test is a true test of the battery and provides valuable information, people are generally reluctant to do discharge testing, primarily because it is labor-intensive and time-consuming. It is also one of those tests that needs to be done right the first time on that day. If a mistake is made while
starting the test, the test cannot be restarted immediately because the battery discharge data can be affected by the previous attempt. Proper planning and preparation will ensure that there are no hiccups and a discharge test can be carried out in the right manner and with ease.
Voltage/Current diagram at 35ºC (95ºF) and 50ºC (122ºF)
<35ºC (95ºF)
<50ºC (122ºF)
Figure 1: Battery Discharge Curve for a 48-V VRLA Battery String
FEATURE
Safety Is Essential
Before getting into the steps that can be taken to ensure a smooth discharge test, it is important to cover the safety aspect. The tester must be well-equipped to carry out the test in a safe manner (Figure 2). PPE includes safety glasses, face shields, acid-resistant gloves, and a protective apron. The presence of a water facility for rinsing eyes and skin after coming in contact with the electrolyte, a Class C fire extinguisher, and adequately insulated tools will ensure the safety of testing personnel.
STEPS TO ENSURE CORRECT DISCHARGE TESTING
It is important to have prior information on the battery string that is to be tested. Once the manufacturer and model are known, the
discharge specification sheet can be obtained online. The test parameters can be determined from the discharge specification sheet. Figure 3 shows a sample discharge specification table for a constant-current test.
From this table, the test current can be determined for a certain test duration. As can be seen, shorter duration tests require higher currents. It is preferrable to select a duration closest to the duty cycle of the battery. The duration must be kept constant during subsequent discharge tests on the battery string to ensure accurate trending of the battery capacity.
Once the test current is determined, the next step is to determine the capability of the test equipment. Discharge test equipment or load testers come in various shapes and sizes. The massive ones are capable of drawing high amounts of current and can work for a wide range of battery applications but aren’t portable. The portable ones may have limited power capability. Therefore, part of the planning involves running calculations to determine which testing equipment is required, or if the existing testing equipment will work for a discharge test at a certain current. Figure 4 shows the power capability of a battery discharge test system.
As seen from the curve, the maximum current drops with an increase in the string voltage. Hence, the string voltage is an important factor in deciding which instrument can be used for a specific test.
Figure 3: A test current of 19 A is required for a 5-hr constant-current discharge test to an end cell voltage of 1.75 Vpc. SOURCE: ENERSYS
Figure 2: Wearing the correct PPE ensures the safety of testing personnel.
Besides the load bank, additional equipment can be used to monitor individual cell voltages. Monitoring individual cell discharge is certainly valuable as it can help pinpoint bad cells in a string. This is helpful in determining whether the entire string needs to be replaced because of a bad test or if replacing a few cells in the string will fix the issue. Figure 5 shows a discharge test setup using a battery discharge test system along with accessories for individual cell voltage measurement.
Cell-voltage measurements must be done between posts of like polarity on adjacent cells so that the voltage drop along the inter-cell connection is included. The downside of this is that a cell connected to a longer inter-cell connection (an inter-tier cable for example) can seem to have lower cell voltage than others (Figure 6) because of the higher voltage drop along that longer connection.
Arrangement must be made for a backup battery string to power critical loads while the battery string is under test. Figure 7 shows a backup battery string being used during a discharge test.
Pre-testing the condition of the battery is also important. It must be on float for a certain duration (3 days for lead acid batteries) prior to testing.
Certain measurements can be done before starting a test. The continuity of the string can be verified by measuring impedance and strap resistance. This is a good practice because not only is the quality of the electrical path verified, but the impedance data obtained for individual cells can also be correlated with the individual cell discharge data obtained from the capacity test. High strap-resistance values might indicate loose connections that can be retorqued and tightened to avoid heating issues during the discharge test. Float current for the string needs to be measured, and individual cell-float voltages must be recorded. Record the temperature of about 10% of cells in the string.
Voltage/Current diagram at 35ºC (95ºF) and 50ºC (122ºF) ambient temperature
<35ºC (95ºF)
<50ºC (122ºF)
Figure 4: Power Capability Curve of a Battery Discharge Test System
Figure 5: Devices connected to all cells on the string provide individual cell-voltage values in real time.
Figure 6: Cell Voltage Measurement During Discharge Test
Battery temperature affects its performance. Hence, the battery temperature is noted and used to apply a correction factor during capacity calculation.
The cable connections between the load tester and the battery string must be of good quality to avoid heating problems during high-current discharges. The cables need to be short, but at the same time, the load tester should be at a safe distance from the battery string. Separate voltage sense leads can be connected on the battery terminals, as shown in Figure 8, for more accurate measurement by discounting the voltage drop along the current leads. The room needs to be well-ventilated so that the heat dissipated by the resistors in the load tester does not affect the ambient temperature.
Bypassing Bad Cells in Lead Acid Batteries
During the discharge test, cells can be bypassed if they are seen approaching polarity reversal (1 V or less). A maximum of one downtime period of either six minutes or 10% of test duration, whichever is shorter, is allowed, and the tester decides at what point to take it. The duration is kept short because the cells start to
Figure 7: DC System Fed from Backup Battery String During Discharge Test
Figure 8: Battery Terminal Voltage Measured Accurately Through Separate Voltage Sense Leads
recover as soon as they are disconnected from the load. Waiting too long before resuming the discharge can affect the battery discharge curve significantly and result in a much higher percent capacity being erroneously measured. Because of this short duration, it is important
to have the tools nearby to quickly bypass cells. The end battery voltage needs to be adjusted for the new number of cells in the string.
If all of the above measures are taken, the discharge test can be carried out smoothly. The test ends when the battery reaches the end voltage.
CAPACITY CALCULATION
The discharge duration is used to calculate the capacity at the end of the test. Capacity can be calculated using two methods.
Time Adjustment Method
This method is used for tests with a duration greater than an hour:
where:
t a – Actual discharge time
t s – Specified discharge time
K t – Temperature correction factor
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Rate Adjustment Method
This method is preferred if the test duration is less than an hour.
where:
X a – Actual discharge rate
X t – Specified discharge rate corresponding to the actual discharge time
K c – Temperature correction factor
Percent capacity thus obtained can be used to qualify the battery as bad or good.
Acceptance Test
A discharge test carried out immediately after installation or commissioning of the string is called an acceptance test. For lead acid batteries, the measured percent capacity must be at least 90% of the rated capacity for the battery to pass the test. The results obtained from this test can be used as the baseline for future measurements.
Performance tests can then be performed at regular intervals to track the health of the battery string. The battery string can be replaced once the percent capacity drops too low (80% of the rated capacity for lead-acid batteries).
Service tests or modified performance tests can also be performed to test the battery’s ability in specific applications.
In the lapsed time between consecutive discharge tests, online testing can be done in the form of impedance measurements at regular intervals. Any significant deviations observed in the impedance measurements can then be investigated by conducting a discharge test. Batteries are manufactured to last for hundreds of charge/discharge cycles, so a few discharge tests done as part of maintenance does not affect a battery’s service life. The discharge test provides a definitive answer and delivers the final verdict on the state of the battery.
CONCLUSION
A good battery maintenance program includes discharge testing among other maintenance activities. Discharge testing is the best tool for battery health assessment, and having a good understanding of the test procedure can result in the test being done in the correct manner, thus yielding accurate results.
More details regarding maintenance and testing on various types of batteries used in stationary applications are provided in the following documents:
• IEEE Std. 450–2020, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications.
• IEEE Std. 1188–2005, IEEE Recommended Practice for Maintenance, Testing, and Replacement of ValveRegulated Lead- Acid (VRLA) Batteries for Stationary Applications.
• IEEE Std. 1106–2015. IEEE Recommended Practice for Installation, Maintenance, Testing, and Replacement of Vented Nickel-Cadmium Batteries for Stationary Applications.
Sanket Bolar is a Substation Applications Engineer at Megger. From the beginning of his professional career, Sanket was directly involved with testing and condition assessment of power transformers working for Siemens Ltd (India). Sanket became part of Megger while working on his master’s degree as part of the internship educational program. Upon graduation, he joined Megger as an Applications Engineer covering a broad spectrum of substation products from transformer to power quality applications. Sanket graduated from Mumbai University, India, with a BS in electrical engineering and received his MS in electrical engineering specializing in power systems from North Carolina State University. He is a member of IEEE.
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WHAT IS THIS NERC?
BY KYLE HERON, Premier Power Maintenance
We find ourselves in a time where everyday life has become principally reliant on the uninterrupted supply of electricity. Powering our homes, sustaining mass transit infrastructure, and keeping the lights on at our healthcare facilities are prime examples of the importance reliable power holds to our way of life. But as our demand for electric power is evergrowing, our requirement for redundancy and reliability in our power system also scales.
Throughout the history of electrical generation and transmission, a number of devastating events have detrimentally impacted our electrical grid, but they have simultaneously spurred a growing awareness that voluntary guidelines for bulk electric system (BES) operation would simply not ensure reliability. The entity currently responsible for ensuring BES reliability is the North American Electric Reliability Corporation (NERC). But to better understand what NERC is, we’ll need to review the history of electrical generation and usage.
Electricity has been in use for roughly 130 years. In its infancy, it was primarily used in manufacturing, and generation took place onsite for immediate and localized consumption. Through the 1920s–1930s, electric usage began to scale, and generation shifted to a more centralized model that provided access for more Americans and extended it to rural areas. This shift relocated electrical generation farther from our communities, and electrical utilities began interconnecting their delivery systems as a
means of increased efficiency. This introduced the need for transmission lines to take electricity to where it would ultimately be used and began the early formation of the bulk electric system — the electrical grid.
The bulk electric system is often referred to as the largest machine in the world, consisting of over 164,000 miles of transmission lines that interconnect a network capable of moving over 750,000 megawatts of electricity throughout the United States and Canada. According to NERC, the BES is defined as all transmission elements operated at 100 kV or higher, and real power and reactive power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of electric energy.
The creation of the BES has allowed us to realize many benefits as the demand for electricity increased, such as increased redundancy of electrical circuits (improved reliability) and access to more sources of generation. But as is commonly the case, added
A traffic jam on First Avenue during a power blackout, November 9, 1965, in New York City. The largest power blackout in the history of the U.S. affected a large part of the northeastern United States and Canada.
benefits rarely come without compromise, and the bulk electric system’s compromise is the potential shared result of system failures.
HISTORY
One of the earliest examples of this drawback stems back to the Great Northeast Blackout of 1965. At the time, this was the largest power failure in United States history, affecting all of New York state, Connecticut, Massachusetts, New Hampshire, New Jersey, Pennsylvania, Rhode Island, and sections of Ontario, Canada. This catastrophic failure left over 800,000 commuters trapped in New York City’s subways and stranded many more in office buildings and elevators. The culprit of such a large-scale outage was the tripping of one 230-kilovolt
transmission line that forced additional load onto many nearby lines, causing them to also fail. This surge of power led to the cascading tripping of additional lines, which ultimately resulted in the collapse of the northeastern transmission network.
Following the Northeast Blackout, the U.S. Electric Power Reliability Act, through the Federal Power Commission (precursor to FERC), urged the development of a council of power coordination responsible for reviewing and publicizing all matters pertaining to electrical power coordination. Until 1968, The North American Power Systems Interconnection Committee (NAPSIC) was the entity that provided guidelines for
reliable operation, but the U.S. Electric Power Reliability Act would make way for the National Electric Reliability Council (NERC).
While NAPSIC was focused on reliable operation, NERC’s priority was to maintain regional planning coordination, which was accomplished by delegating through 12 regional organizations that effectively made up all of the power systems operating within the United States. Each region had its own representative on the NERC executive board. This was NERC’s early framework, but one important aspect is that the guidelines and criteria provided by NAPSIC and NERC were completely voluntary and unenforceable.
Over the next two decades, additional largescale power outages (New York City 1977, western United States 1992) prompted a gradual transition toward enforceable standards with NERC redefining their guidelines as operating policies, and some regional councils
agreeing to voluntarily pay fines if determined to be out of policy compliance. At this time, NERC still didn’t have the authority to enforce its policies; it was ultimately the Northeast Blackout of 2003, which saw fifty million people without power, that initiated NERC’s empowerment as a governing authority in electrical reliability.
In 2004, the US–Canada Power System Outage Task Force determined that the primary means to avoid future blackouts and diminish their impact was for the U.S. government to make reliability standards mandatory and enforceable and to upgrade equipment that was approaching its end of life.
VERSION 0 RELIABILITY STANDARDS
NERC’s response to this conclusion was to revise its planning standards and operating policies into a set of reliability standards titled Version 0 Reliability Standards that would be
widely embraced and adopted by the NERC Board of Trustees. In addition to implementing the Version 0 Reliability Standards, the Energy Policy Act of 2005 — now signed into law — declared that the Federal Energy Regulatory Commission (FERC) would oversee the creation of an electric reliability organization (ERO) as the authority responsible for enforcing reliability standards. NERC filed separately to be the ERO in the United States and Canada and was named as ERO for both countries by 2006. For the first time since its inception in 1968, NERC would finally have the means to enforce its reliability standards throughout North America.
NERC’s Version 0 Reliability Standards, and all subsequent revisions of NERC Reliability Standards, are developed through an ANSI-
accredited process focusing on reliability as well as market principles. The intent behind this foundation for NERC Reliability Standards is to ensure all existing and future standards are written in a way that preserves their objective of reliable planning and operation without negatively impacting competitive electric markets through an unfair competitive advantage. Reliability standards are proposed by NERC, approved by FERC, and ultimately enforced by NERC or the regional entity to which NERC has delegated authority. As of 2021, NERC has 14 mandatory standards subject to enforcement. Those in the electrical testing industry most commonly deal with the standards involving cybersecurity (Critical Infrastructure Protection — CIP), protection and controls testing/commissioning (PRC), and station battery testing and maintenance.
Figure 1: P&C Technicians Perform End-to-End Testing on a D60 Line Relay
FEATURE
CIP
To be able to work at a location where NERC Critical Infrastructure Protection (CIP) standards are in effect requires additional training to ensure workers do not inadvertently connect to an intelligent electronic device (IED), such as a microprocessor relay, in a
way that can potentially pass harmful code to the device and result in a CIP violation. This specialized training, usually provided or administered by the customer, is essential to help ensure testing and commissioning activities are CIP-compliant. In addition to training, workers encounter additional requirements including customer-issued laptops dedicated to CIP sites and audits of internal information technology (IT) policies and procedures for CIP compliance.
PRC
While it’s crucial to be mindful of the devices we plug our laptops into as it is pertinent to CIP compliance, we should also be aware of how testing and commissioning differs for NERC PRC compliance. NERC Standard PRC-005, Protection System Maintenance has specific requirements for the testing and commissioning of items like protective relays, instrument transformer circuits, trip paths, protective communication circuits, and alarm reporting.
Every test conducted is required to be properly documented for NERC compliance. Failure to perform required testing or properly complete the necessary documentation can result in the customer being faced with fines of up to $1,000,000 per day, depending on the severity level of the violation or the inability to proceed with system operation in the event of a failed NERC audit.
Additionally, NERC has specific requirements for installation, testing, and maintenance of station batteries that provide the DC control voltage for intelligent electronic devices (IEDs) and substation equipment associated with the bulk electric system. This standard also includes guidelines on how frequently each test must be performed to maintain the security and reliability of the BES.
CONCLUSION
Grid reliability improvement has been a constantly evolving practice that will continue to be updated as we meet new challenges capable of threatening the reliable delivery of electrical power to end-users.
Figure 2: P&C Technician Reviewing CT Isolations for an HV Transformer Replacement
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NERC’s standards and requirements are not an end-all-be-all answer to eradicating adverse system-wide events, but the goal is that we will avoid the recurrence of another 2003 Northeast Blackout, or an event of a similar scale, through our current protocol.
From a compliance standpoint, my hope is that, rather than approaching this challenge as avoidance of fines and potential system shutdown for non-compliance, operators view this as an opportunity to ensure their utility customers continue to do all in their power to keep the lights on for our homes, mass transit infrastructure, and healthcare facilities.
REFERENCES
(1) United States Environmental Protection Agency. Centralized Generation of Electricity and its Impacts on the Environment, January 4, 2021. Online: www.epa.gov/energy/ centralized-generation-electricity-and-itsimpacts-environment .
(2) History.com. “The Great Northeast Blackout,” March 4, 2010. Online: www.history.com/this-day-in-history/the-greatnortheast-blackout.
(3) Nevius, David. The History of the North American Electric Reliability Corporation. North American Electric Reliability Corporation, January 2020.
Kyle Heron joined Premier Power Maintenance in 2019 and is currently the Protection and Controls Sales Coordinator. He graduated from Indiana University Purdue University Indianapolis (IUPUI) with a degree in informatics.
Figure 3: Fiber-Optic Junction Cabinet Taking Signals from Regulator Controller Back to Remote Terminal Unit
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AN INTELLIGENT SYSTEM FOR
CONDITION ASSESSMENT OF POWER TRANSFORMERS
BY MOHAMED KHALIL, PhD , Doble Engineering Company
The health index (HI) approach has been adopted widely as a tool to help asset managers prioritize their plans and actions. However, the conventional computation of HI, which is based on scoring and ranking, has several drawbacks. In this work, the fuzzy logic approach is used to build up an intelligent HI system to assess the condition of power transformers based on oil quality and DGA results.
The continuous demand to optimize the lifetime cost of transformers through informed decisions has led to adopting condition monitoring tools in addition to traditional offline testing methods. Many utilities have migrated from conventional timebased to condition-based maintenance. The outcome of the current diagnostic methods — online and offline — is large volumes of accumulated data. As a result, the use of quantitative indicators such as HI is gaining
wide popularity, especially when it comes to prioritizing maintenance and replacement activities.
HI is an approach that combines all the information from a transformer to provide a single quantitative index that expresses overall condition based on measured data. The available data can be online, offline, operational, from condition monitoring systems, or from visual inspection, etc.
Despite the simplicity of weighting methods, determination of the weight factors for the diagnostic tests is based on the experience of experts, which differs from one person to another. In addition, setting a sharp threshold of diagnostic measurements for scoring is very difficult. In practice, scores can overlap. ISO/ IEC Guide 98-3:2008 notes that an exact measurand does not exist due to the unavoidable imperfection involved in the measurement process.[7]
Moreover, experience shows that the traditional weighting average method may omit the influence of a bad diagnostic test result on overall health condition.
To address these challenges, artificial intelligence (AI) has been applied as an alternative approach to calculate HI. For example, the artificial neural network (ANN) in[8] and the adaptive neuro-fuzzy inference system (ANFIS) in[9] are used to evaluate the HI of transformers. However, their practical application in electric utilities is scarce due to the challenges associated with symbolic reasoning and preparing large amounts of hand-crafted, structured training data.
FUZZY LOGIC IS BASED ON A NETWORK OF IF–THEN RULES THAT ARE CONSTRUCTED USING THE EXPERIENCE OF EXPERTS.
Several methods have been developed to convert existing diagnostic data into an HI. For instance, binary logistic regression is used in[1] for this purpose. The input data are classified into categories: healthy or unhealthy. Weights, assigned to each input, are calculated using the maximum likelihood criterion. Another approach is introduced in[2-5] to calculate the HI using the weighting average:
where:
n is the number of diagnostic tests
S is the score of each test measurement
W is the allocated weight given to each diagnostic test
In another work[6], the weighting sum is used instead to calculate the HI.
In this article, fuzzy logic is utilized to build up an intelligent model for evaluating the HI of power transformers. Contrary to ANN and ANFIS, fuzzy logic is based on a network of if-then rules that are constructed using the experience of experts. Fuzzy logic does not need to learn training data, and it has sophisticated capability to process the rules for all possible scenarios and form an accurate decision. Additionally, fuzzy logic does not apply sharp thresholds between the grades of the input data, since imprecision and fuzziness are the core of the fuzzy set theory.
USING OIL ANALYSIS TO ASSESSS POWER TRANSFORMER CONDITION
Conventionally, the primary areas of concern for electric utilities are oil quality and DGA results. Because oil sampling is the most practical way to diagnose the condition of
PHOTO:
INDUSTRY TOPICS
transformers while they are in service, the scope of this work is focused on oil quality and DGA results. However, the proposed fuzzy logic model can be similarly extended to include all the possible factors that impact transformer condition.
Disolved Gas Analysis
The analysis of dissolved gases in a transformer’s oil gives general information on the condition of the transformer and identifies unusual events such as incipient faults. Gases such as methane (CH4), ethane (C2H4), hydrogen (H2), ethylene (C2H6), acetylene (C2H2), carbon monoxide (CO), and carbon dioxide (CO2) are analysed to determine the types and severity of each fault.
Oil Quality
Oil quality tests focus on the condition of oil and paper insulation. Several parameters are usually monitored for oil, including break-down voltage (BDV), acidity, water content, interfacial tension (IFT), and furanic compounds such as 2-FAL.
FUZZY LOGIC APPROACH
Figure 1 shows the architecture of the fuzzy logic process, which consists of three stages.
Fuzzification
The truth of any statement in fuzzy logic is just a matter of degree. This degree of truth is determined by generating membership functions (MF). MF is a curve or straight line that defines how a given input is mapped to a degree of membership between 0 and 1 of the fuzzy sets. It can be triangular, trapezoidal, sigmoidal,
or Gaussian. The MF used in this work is trapezoidal, as shown in Figure 2, because of its simplicity. It is expressed as in (2): (2)
where:
x is the input parameter
If x lies between the centres of the trapezoidal c₁ and c₂, then the corresponding MF achieves the maximum degree of membership of 1. On the other hand, if the input is between a and c₁ or b and c₂, then the degree of membership is less than 1. This is the case when the measurand of a diagnostic test lies near the thresholds.
In this stage, the MFs convert the inputs from precise to fuzzy form between 0 and 1.
Fuzzy Rules and Fuzzy Inference Engine
This work uses the Mamdani fuzzy inference system. It is described in the XY−plane as: (3) where:
μa(x) is the membership function of fuzzy set a defined in universe X
μb(y) is the membership function of fuzzy set b defined in universe Y
μa→b(x, y) is the fuzzy implication in XY-plane
Figure 1: Block Diagram of the Fuzzy Logic Process
Figure 2: Trapezoidal Membership Function
The min (μa(x), μb(y)) takes the minimum of the two (or more) membership values when fuzzy rules are fired.
Meanwhile, fuzzy rules are a set of knowledgebased linguistic rules developed by the knowledge of test data interpretation and its impact on the condition of transformers. For instance, some of the implemented rules for arcing in the oil of transformers are:
1. If (C2H2 is very high) and (H2 is very high), then (arcing is very high).
2. If (C2H2 is very high) and (H2 is high), then (arcing is very high).
3. If (C2H2 is medium) and (H2 is high), then (arcing is high).
4. If (C2H2 is low) and (H2 is medium), then (arcing is medium).
In this stage, the results of the rules are combined to form the final value — a fuzzy value.
Defuzzification
In this work, defuzzification using the centroid method is performed. It determines the centre of gravity (Z0) of the area bound by the truncated output MFs, as in (4): (4) where:
z is the output variable μ(z) is the degree of membership of the truncated output MF.
ADOPTING FUZZY LOGIC TO ASSESS TRANSFORMER CONDITION
The proposed HI modelling based on the oil results is shown in Figure 3. In the proposed architecture, the HI of the transformer is divided into three main failure profiles: prognostic index (PI), oil quality index (OQI), and dissolved gas
analysis index (DGAI). The score of each failure profile is evaluated based on the scores of the associated failure modes.
DGA Index ( DGAI)
DGAI is based on the results of the levels of gases in the oil. The level of each gas is subsequently fuzzified into four fuzzy sets (MFs): low, medium, high, and very-high (VHigh), respectively. As an example, the MF of H2 is shown in Figure 4
The lower and upper limits and the two centres for each of the seven MFs for each input gas concentration are given in Table 1. The lower
and upper limits were selected in accordance with IEEE Std C57.10–2008[10]
The DGAI index is composed of two main modules: oil arcing and PD, and oil thermal ( Figure 5 ). Due to the thermal effect, the transformer’s oil decomposes and generates ethylene and ethane as principal gases. Therefore, one module was created for both ethylene and ethane to represent the oil thermal failure mode.
On one hand, the presence of hydrogen and acetylene in the oil may indicate arcing. Based on transformer diagnostic and test data interpretation
Figure 4: Membership Function of H2 Gas
Table 1: Limit Values of Gas Concentration MFs
techniques, fuzzy rules are developed for the oil arcing sub-module (Figure 6).
The three-dimensional curve plotted in Figure 7 shows the oil arcing output score (z-axis), which is based on the values of hydrogen, acetylene, their corresponding membership functions, and the predefined fuzzy rules of the oil arcing sub-module. The oil arcing output score is divided into four categories: very-high (yellow), high ( green), medium (light blue), and low (dark blue).
On the other hand, partial discharge (PD) activity in a transformer produces a high level of hydrogen and a considerable level of methane gases. An individual sub-module for oil PD is designed and combined with the submodule oil-arcing mode so the output score of
both sub-modules reflects the oil-arcing and PD failure module.
Prognostic Index (PI)
The inputs to the PI module, shown in Figure 8, are data that change with respect to time. The monotony increase of the input values gives an indication of the deterioration of the transformer’s condition. MFs are developed for the daily generated ppm of TDCG, hydrogen, and acetylene.
Figure 5: DGAI Module
Figure 6: Oil Arcing Sub-Module
Figure 7: Scoring of Oil Arcing Sub-Mode Based on H2 and C2H2
The fuzzy inference system of the inputs is indicated in Figure 9, which shows 29 of the 64 implemented fuzzy rules. These rules cover all possible scenarios of the input data and the associated output score. For example, when the daily rate of change (ROC) of C2H2 = 2.3, H2 = 2.3, and TDCG = 9.79, Rule 25 is fired, and the output score of the ROC DGA module shown in Figure 8 is 87.5.
In addition, MFs are created to include the ROC of 2FAL for thermally upgraded paper, in ppm per year, such that the output score of the ROC of DGA sub-module and the ROC of furfural are inputs to the PI profile.
Oil Quality Index (OQI)
OQI is a combination of three modules for moisture, oil characteristics, and solid insulation, as shown in Figure 10. MFs are developed for the input data: break down voltage (BDV), acidity, interfacial tension (IFT), water content, oil temperature, CO,
CO2, and the absolute value of 2FAL. Since the water content values (in ppm) are dependent on oil temperature, a separate module for moisture is used with its own implemented fuzzy rules, and the output of moisture module is the input to OQI.
The output score of the oil characteristics module is based on the three inputs of BDV, acidity, and IFT. The BDV test is one of the prominent diagnostic tests. This test gives an indication of contaminants, such as oil
Figure 8: Prognostic Index Profile
HUNDREDS OF FUZZY RULES HAVE BEEN DEVELOPED IN THE PROPOSED MODEL TO MIMIC THE BEHAVIOR OF AN OIL TRANSFORMER EXPERT AND GENERATE A RELIABLE HEALTH INDEX.
9: Fuzzy Inference Rules of ROC DGA Module
10: Fuzzy Logic — Oil Quality Index
degradation products and water. Acidity in the oil deteriorates the dielectric properties of paper insulation and accelerates the oxidation process in the oil. Increased oil acidity in a transformer indicates the rate of degradation of the oil with sludge. The output of the oil characteristics module is an input of the OQI module.
Similarly, the solid insulation module output depends on CO and CO2 gas levels in addition to the absolute value of 2FAL in the oil.
CONCLUSION
The fuzzy logic method is utilized to build up an intelligent system to evaluate the condition of power transformers based on oil data. Hundreds of fuzzy rules have been developed in the proposed model to mimic the behavior of an oil transformer expert and generate a reliable health index. The proposed model can be a useful tool to make decisions and prioritize power transformer maintenance plans.
This article was first published in Transformers Magazine, Special Edition, Digitalization , November 2020, www.transformers-magazine.com
REFERENCES
[1] W. Zuo, H. Yuan, Y. Shang, Y. Liu, T. Chen. “Calculation of a health index of oilpaper transformers insulation with binary logistic regression,” Mathematical Problems in Engineering, Vol. 2016, 2016.
[2] I. Hernanda, A. Mulyana, D. Asfani, I. Negara, D. Fahmi. “Application of health index method for transformer condition assessment,” Annual International TENCON Conference, Thailand, 2015.
[3] A. Naderian, S. Cress, R. Piercy, F. Wang, J. Service. “An Approach to determine the health index of power transformers,” Conference Record of the 2008 IEEE International Symposium on Electrical Insulation, pp. 192-196, 2008.
Figure
Figure
[4] F. Ortiz, I. Fernandez, A. Ortiz, C. J. Renedo, F. Delgado, C. Fernandez. “Health indexes for power transformers: A case study,” IEEE Electrical Insulation Magazine, Vol. 32, pp. 7-17, 2016.
[5] A. Jahromi, R. Piercy, S. Cress, J. Service, W. Fan. “An approach to power transformer asset management using health index,” IEEE Electrical Insulation Magazine, Vol. 25, no. 2, pp. 20-34, March-April 2009.
[6] R. J. Heywood, T. McGrail. “Clarifying the link between data, diagnosis and asset health indices,” IET Conference Publications, 2015.
[7] ISO/IEC Guide 98-3:2008, Uncertainty of measurement, Part 3: Guide to the expression of uncertainty in measurement, 2008.
[8] P. H. Mukti, F. A. Pamuji, B. S. Munir. “Implementation of artificial neural networks for determining power transfomer condition,” 5th International Symposium on Advanced Control of Industrial Processes (ADCONIP 2014), pp. 473477, 28–30 May, 2014.
[9] H. Zeinoddini-Meymand, B. Vahidi. “Health index calculation for power transformers using technical and economical parameters,” IET Science, Measurement & Technology, Vol. 10, no. 7, pp. 823-830, 10 2016.
[10] IEEE Std C57.104-2008, IEEE Guide for the Interpretation of gases generated in oilimmersed transformers, 2008.
Mohamed Khalil is a Technical Application Engineer at Doble Engineering, focusing on Doble’s enterprise asset management solutions. His fields of interests are reliability evaluation of electrical systems, failure modes, and criticality analysis. He was appointed to the IEEE Instrumentation and Measurement Administrative Committee and was a guest editor of IEEE Instrumentation and Measurement Magazine. Mohamed is currently an invited technical reviewer in a number of IEEE conferences. He received his M.Sc. in electrical engineering and his PhD in reliability engineering from Politecnico di Milano, Italy.
Along the extensive and complex electrical system infrastructure from generation to transmission and distribution, the wide variety of medium- and high-voltage circuit breakers (MV/HV CB) vary in size, interrupting medium, number of breaks per phase, and various other attributes. To help classify breakers and their attributes, they are all shipped with a nameplate stating the minimum information about specific mechanical, physical, and electrical characteristics that is required by IEEE Std. C37.04. Although manufacturers are only required to provide the minimum information, some provide more detailed information than others.
Viewing the nameplate will yield a variety of information concerning the CB’s function, electrical characteristics, and expected performance. For example, the same breaker may have different types of operating mechanisms, and this might not be apparent when first looking at the nameplate. Further investigation would be needed to fully understand the breaker’s mechanism specifications.
Understanding the information provided on the nameplate will provide a general description of the CB’s mechanism and operating conditions. Since there are many types of CBs, as well as numerous manufacturers, several questions can provide helpful information:
• Do all nameplates provide the same information?
• What is the minimum information that must be stated on the nameplate?
• One important specification on the nameplate is interrupting time. Does this correlate to operating times measured while testing?
• Will a quick glance at the nameplate tell you everything you need to test on the CB and what the expected values are?
This article focuses on the HV/MV CB nameplate information that is necessary for testing purposes. IEEE nameplate requirements and definitions are discussed. Parameters that are commonly tested in the field are described
along with whether the parameter is verified or measured during the design, factory, or field phase of the breaker’s life cycle, and additional testing of parameters not shown on the nameplate is recommended. In the end, the reader will have a basic understanding of the CB nameplate and how it relates to the application, operation, and maintenance of the CB.
NAMEPLATE REQUIREMENTS
At a minimum, the CB nameplate will indicate the attributes of the CB and its mechanism. The manufacturer can choose to combine these into a single nameplate or provide separate nameplates. This article focuses only on the nameplates containing the attributes of the CB and the mechanism. However, certain additional nameplates are also required:
• Nameplates must describe the operating characteristics of any current transformers (CT) or linear coupler transformers attached to the CB.
• A nameplate indicating dielectric withstand capability must be provided for any self-contained components, such as current transformers (CTs) or bushings; this information could also be included on the CB nameplate.
• Nameplates must be provided for any attached accessories indicating what they are, as well as any operating characteristics or relevant information.
Figure 1 and Figure 2 show examples of separate and combined CB nameplate configurations.
The information required on the CB nameplate can be divided into four categories:
1. Documentation provides general data identifying the CB manufacturer, CB type, serial number, and year of manufacture along with a parts list and the instruction book number.
2. Physical characteristics listed on the nameplate describe the CB’s weight,
Figure 1: Separate Nameplates for (a) CB, (b) Mechanism, and (c) CT
Figure 2: Combination CB and Mechanism Nameplate
Table 1: IEEE Std. C37.04 Minimum CB Nameplate Data
Documentation
• Manufacturer name
• Manufacturer type designation
• Manufacturer serial number
• Year of manufacture
• Parts list number
• Instruction book number
Physical Characteristics
• Normal operating pressure
• Minimum operating pressure
• Volume of oil per tank or weight of gas per circuit breaker
• Weight of circuit breaker with oil or gas
Electrical Characteristics
• Rated maximum voltage
• Rated power frequency
• Rated continuous current
• Rated full-wave lightning impulse withstand voltage
• Rated switching impulse withstand voltages
1) Terminal-to-ground CB closed
2) Terminal-to-terminal CB open
• Rated operating duty cycle
• Rated interrupting time
• Rated short-circuit current
• Percent DC component
• Short time current duration
• Ratings for capacitance current switching
1) Rated overhead line charging current
2) Rated isolated cable and isolated shunt capacitor bank switching current
3) Rated back-to-back cable and isolated shunt capacitor bank switching current
4) Rated transient inrush current peak
5) Rated transient inrush current frequency
• Rated out-of-phase switching current
operating pressure, and the volume of oil or weight of gas inside the tank.
3. Electrical characteristics provide the general operating conditions of the CB along with insulation levels and other protection information.
4. Operating characteristics refer to the minimum and/or maximum conditions for the mechanism to be able to operate and might include some electrical parameters related to the control of the breaker. In cases where the mechanism is hydraulic or pneumatic, the nameplate will show pressure rather than electrical parameters.
Table 1 and Table 2 provide the minimum CB and mechanism nameplate data required by IEEE Std. C37.04.
CB ELECTRICAL AND OPERATING CHARACTERISTICS
CB characteristics include documentation, physical characteristics, and electrical characteristics. and operating characteristics.
Rated Maximum Voltage
IEEE Std. 37.04–2018 states:
The rated maximum voltage of a circuit breaker is the highest rms phase-to-phase voltage for which the circuit breaker is designed, and is the upper limit for operation.
When the nameplate refers to continuous current and short-circuit current, it is the current at this rated maximum voltage.
A design test performing short-circuit current interruption and other current switching rating tests at the rated maximum voltage is used to verify this characteristic.
Rated Power Frequency
This is the frequency at which the CB is designed to operate. Typically, this frequency is 60 Hz or 50 Hz, but other frequencies exist (e.g., 25 Hz or 16-2/3 Hz). If the CB is operated at a higher frequency than its intended design, the CB will need to be de-rated, and the manufacturer should be contacted for consultation.
Table 2: IEEE Std. C37.04 Minimum Mechanism Nameplate Data
Documentation
• Manufacturer’s name
• Manufacturer’s type designation
• Manufacturer’s serial number
• Year of manufacture
• Wiring diagram number
• Instruction book number
• Parts list number
Operating Characteristics
• Closing control voltage range
• Tripping control voltage range
• Closing current
• Tripping current
• Compressor or hydraulic pump or spring charging motor control voltage range
• Compressor or hydraulic pump or spring charging motor current, and if applicable, limitations on mechanism operating frequency less than 30 close-opens (COs) per hour
• Compressor or hydraulic pump control switch closing and opening pressure (if applicable)
• Low-pressure alarm switch closing and opening pressure (if applicable)
• Low-pressure lockout switch closing and opening pressure (if applicable)
• Mechanism endurance class M1 or M2 shall be marked as applicable
Rated Continuous Current
The rated continuous current is the maximum RMS current at rated power frequency that the CB can transmit continuously during usual service conditions (see IEEE Std. C37.04–2018 Section 5.5). The current ratings are designed around the temperature limits of all the parts used to construct the CB. The CB is designed to carry this current at an ambient temperature of 40°C. For the maximum internal temperatures of the individual components, see IEEE Std. C37.04–2018 Section 5.5.2. The rated continuous current is applicable at or below the rated maximum voltage.
Rated Full-Wave Lightning Impulse Withstand Voltage
Although the CB is designed to operate at a rated maximum voltage, it may be subject to environmental conditions that exceed the maximum voltage. The dielectric withstand capability of a CB is demonstrated by subjecting it to a power frequency, a lightning impulse test, and where required, a choppedwave lightning impulse and switching impulse test at voltage levels equal to or greater than those specified in ANSI C37.06, Trial-Use Guide for High-Voltage Circuit Breakers Rated on a Symmetrical Current.
IEEE Std. 4–2013 Section 8 defines the standard lightning impulse as:
A full lightning impulse having a front time of (T1) of 1.2 and value (T2) of 50, and is described as a 1.2/50 impulse. The rated fullwave lightning impulse withstand voltage is the peak value of this wave. A new CB must have a 10% or less chance of external flashover when subjected to this wave.
Rated Switching-Impulse Withstand Voltages
In addition to the lightning impulse rating, CBs rated at 362 kV and above are assigned a switching-impulse withstand voltage rating. These CBs can be subjected to transient overvoltages when they are switching open or loaded, or when faulted lines and equipment are present. To help alleviate these overvoltages, the CB are often equipped with pre-insertion resistors (PIR) or synchronous closing devices.
Rated switching-impulse withstand voltage is the voltage value at the peak of a standard 250 x 2500 switching-impulse wave (IEEE Std. 4–1995 Section 8) where 250 is the time to peak value and 2500 is the time to reach half-peak value. At this voltage value, the CB has a 10% or less probability of external
flashover to ground in both wet and dry conditions.
Operating Duty Cycle
Also known as the rated operating sequence or rated standard operating duty, the operating duty cycle is a predefined sequence of operations in a specific period and interval. The sequence, period, and interval may be defined by industry standards, the manufacturer, or specific applications.
Per IEEE Std. C37.04, the standard operating duty of a CB is:
- t - CO - t’- CO
where:
O is Open CO is Close-Open t’ is 3 minutes t is the minimum reclosing time
For CBs not rated for rapid reclosing, t is 15 s and 0.3 s for CBs rated for rapid reclosing duty.
In generator CBs, IEEE Std. C37.013 specifies that the rated short-circuit duty cycle shall be two operations with a 30-min interval between operations (CO–30 min–CO). In circuit switchers (IEEE Std. C37.016), the rated operating sequence is Close-Open (CO).
The sequence of operations shown on the nameplate is the maximum number of operations in a specific period that the breaker was designed for. This should not be exceeded in the regular operation of the breaker or during field testing. It is also an indication of what type of application the breaker is designed to handle.
The minimum operation a breaker should be capable of performing is the CO, and it is the sequence the breaker should follow when the breaker is requested to close but there is already a trip command from a fault in the system. The breaker should close completely and then open immediately. This is also a basic sequence that any breaker is designed and built to perform.
The reclose sequence OC is the capability of the breaker to clear a fault and close after a delay. Some applications, e.g., generator breakers in which the breaker might not be mechanically designed for this sequence, do not require this. It should not be simulated during testing, as it may break or get jammed.
When a CB is designed for the reclose function, it should also be capable of opening immediately after a reclose to interrupt the fault if the fault is still present after the first clearing attempt. This sequence of operation is known as the OCO, although it is not commonly tested.
It is important to test the sequence defined in the nameplate to verify that the breaker will be capable of performing as per the design, especially if the sequence is being fully used in the system, for example, the reclose function instead of just an open and close operation.
Rated Interrupting Time
This is the manufacturer’s designated operating time limit for the opening of the contacts and interruption of the arc during the clearing of a fault. Rated interrupting time is measured from the energization of the trip circuit at rated voltage until the total interruption of current flow through the contacts. This interval includes the operation of the trip coil, actuation of the mechanism (travel), contact part separation, and extinguishing of the arc in all poles. This time depends on the speed of the breaker.
The standard rated interrupting time for CBs is 2, 3, or 5 cycles, but this might be exceeded under certain applications. In a CO operation, the interrupting time should not be more than 1 cycle for 5-cycle or higher CBs and ½ cycle for 3-cycle CBs. For out-of-phase switching, the time can be exceeded by 50% in 5-cycle CBs and 1 cycle in 3-cycle or faster CBs. In generator CBs, the typical values are between 60 ms and 90 ms.
This parameter is important during the design of the electrical network, especially when considering system stability and determining expected clearing times. The rated interrupting
time is the main component of the total time it takes to clear a fault from its initiation to relay pickup and eventually arc extinction.
Rated Short-Circuit Current
This is the highest symmetrical component of short-circuit rms current at the instant of arcing contact separation that a breaker should interrupt at rated maximum voltage and standard operating duty without suffering damage of any nature in any of its components. This current includes the DC component, and it also establishes by fixed ratios the highest currents that the CB can close and latch against to carry and to interrupt.
ANSI C37.06 defines the preferred shortcircuit current ratings for 123 kV and above CBs as ranging from 31.5 kA to 80 kA. The typical values for generator CBs range from 63 kA to 160 kA as per IEEE Std. C37.013. These types of CBs are required to close in on a fault, latch, and carry current for at least 0.25 s.
The peak making current should not exceed 2.74 times the rated short-circuit current. This parameter is tested only at the factory.
Percent DC Component
This defines the portion of the total DC current that the breaker is capable of interrupting during an asymmetrical fault. It is an important parameter for CB specification and relay setting calculations. This specification cannot be verified in the field.
Short-Time Current Duration
This is the maximum time a CB can carry the rated short-circuit current without any damage. It is the maximum permissible tripping time delay (Y) for CBs.
The standards indicate a duration of 1 s for HVCBs 123 kV and above, for circuit switchers above 72 kV, and for generator CBs. However, it is common to see breakers with a specification of 3 s.
INDUSTRY TOPICS
Ratings for Capacitance Current Switching
Capacitive currents are present during the switching of no-load overhead lines, noload cables, capacitor banks, or filter banks. Energization of parallel capacitor banks and no-load lines can generate overvoltages or high currents, whereas the interruption of capacitive currents can generate voltage breakdowns across contact separation, known as re-ignition (less than ¼ of a cycle) and restrike (greater than ¼ of a cycle). Re-ignition can generate power-quality problems, while restrike will cause overvoltages of up to three times the peak value of the phase-to-ground voltage across the capacitive load for each restrike.
Breakers are designed to handle a certain amount of capacitive current under different system conditions like overhead line switching, isolated cable and isolated shunt-capacitor-bank switching, back-to-back cable and isolated shunt-capacitorbank switching current, transient inrush current
peak, and transient inrush current frequency. IEEE Std. C37.06 shows the preferred capacitance current switching ratings for indoor and outdoor CBs. This characteristic is tested at the factory, and IEEE Std. C37.09 and IEEE Std. C37.012 specify the proper procedures for testing.
Each capacitive current switching rating assigned to the breaker must have an associated class from the following categories:
• Class C0: Unspecified probability of restrike during capacitive current breaking. Capability for one restrike per operation
• Class C1: Low probability of restrike while breaking capacitive current
• Class C2: Very-low probability of restrike while breaking capacitive current
Rated Out-of-Phase Switching Current
The out-of-phase condition is an abnormal situation in which the synchronism on either side
Reliable Power System Solutions
of the CB is lost, creating a difference of potential where the phase angle of the voltages exceeds the normal values. In some cases, the voltages can be 180° out of phase. During out-of-phase switching conditions, a very large short-circuit current occurs.
The rated out-of-phase switching current is the current that the breaker should be capable of handling during an operation under a lack of synchronism. This is an uncommon situation, so not all breakers are designed for this. Whenever a breaker is designed with this capability, the preferred rating is 25% of the rated (symmetrical) short-circuit current expressed in kA, and the interrupting time is allowed to be greater than the rated interrupting time by 50% for 5-cycle breakers and by 1 cycle for 3-cycle breakers.
CB MECHANISM CHARACTERISTICS
Mechanism characteristics include documentation and operating characteristics.
Control Voltage Range
This is the designated control voltage range required for operation of the mechanism at the connecting point of the control circuit. The high end of the range corresponds to the open-circuit voltage. The low end of the range corresponds to the voltage when the maximum operating current is flowing through the control circuit. The control circuit includes operating coils, auxiliary relays, and compressor, hydraulic pump, or spring charging motor.
IEEE Std. C37.06–2009 defines various ranges based on DC/AC signals, indoor or outdoor applications, and closing/tripping operations. For a DC voltage, various ranges are defined from 24 V to 250 V. Ranges below 48 V are not recommended for breakers that might experience a voltage drop during operation, such as being far from the source or where the cabling is not adequate.
Control Current
This is the maximum current at nominal voltage that should flow through the control circuit during the operation of the CB. Each element in the control circuit has its own nominal current and maximum current.
In some cases, e.g., in the tripping coil or the spring-charging motor, a characteristic current curve provides valuable information on the condition of the element or its associated part of the mechanism. For example, the tripping-coil current reveals information on the condition of the latching system, and the spring-charging motor current indicates the condition of the spring mechanism.
Rated Operating Pressures
CBs might require pressurized systems for hydraulic or pneumatically operated mechanisms and/or for interrupters that use a pressurized gas as the interrupting medium. Each of these has a rated pressure range as per the CB design and construction that should be guaranteed at any time for the breaker to be operated safely.
The pressure refers to the standard atmospheric air conditions of +20°C and 101.3 kPa (absolute)(or density), which may be expressed in relative or absolute terms, to which the mechanism or the interruption chamber should be filled before being operated.
CONCLUSION
CB nameplates contain basic information on how a breaker was designed and built, and it is useful to many different audiences. System engineers and operators use nameplate information for system calculations and to determine appropriate applications of the CB. System installers use it to verify conditions prior to installation. Testing and commissioning personnel use it to properly prepare testing procedures and evaluation criteria. Although the information displayed on the nameplate might not be complete for every audience’s need, especially for field testing purposes, most of the information is in the CB manual or instruction book, which is referenced on the nameplate.
For information on testing procedures that can confirm the expected performance of the CB, watch for Part 2 of this article in the Spring issue of NETA World.
REFERENCES
IEEE Std 4–2013, IEEE Standard Techniques for High-Voltage Testing.
IEEE Std 100–2000, The Authoritative Dictionary of IEEE Standard Terms - Seventh Edition.
IEEE C37.04–2018, IEEE Standard Rating Structure for AC High-Voltage Circuit Breakers
IEEE C37.06–2009, IEEE Standard for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis – Preferred Ratings and Related Required Capabilities for Voltages Above 1000 V
IEEE C37.09–1999, IEEE Standard Test Procedure for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis.
IEEE C37.010–1999, IEEE Application Guide for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis.
IEEE C37.012–2005, IEEE Application Guide for Capacitance Current Switching for AC High-Voltage Circuit Breakers.
IEEE C37.013–1997, IEEE Standard for AC High-Voltage Generator Circuit Breakers Rated on a Symmetrical Current Basis.
IEEE C37.016–2006, IEEE Standard for AC High-Voltage Circuit Switchers Rated 15.5 kV through 245 kV.
Volney Naranjo joined the Technical Support Group at Megger in 2011 as an Applications Engineer focusing on the products for transformer, low-voltage and high-voltage circuit breakers, batteries, and power quality testing. He participates in the IEEE Energy Storage and Stationary Battery committee and has published articles in conferences such as TechCon, PowerTest, TSDOS, BattCon, and EIC as well as technical magazines. Volney received his BSEE from Universidad del Valle in Cali, Colombia. After graduation, he worked in the areas of electrical design and testing and commissioning of power systems as a field engineer and project manager.
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TRAVELING WAVE RELAY APPLICATION, COMMISSIONING, AND INITIAL EXPERIENCE
BY SCOTT COOPER and FARI ELHAJ, OMICRON electronics, and ANTHONY SAVESIND and FRANCISCO J. SANCHEZ, Salt River Project
Traditional line protection incorporates elements in the phasor domain. Phasor-based line protection uses a full cycle of data and is subject to CT accuracy limitations, limiting operating speed and fault location accuracy.
However, new advances in protective relay technology have facilitated the introduction of relays that operate in the time domain. By detecting and time-stamping the arrival of traveling waves at each terminal, these devices employ peer-to-peer communication to make trip decisions and calculate fault location. These new devices are free of the inherent delay of phasor-based relay algorithms and the accuracy limitations of traditional fault current measurement, so trip times less than 1.5 ms and fault location to within one structure have been observed.
This article provides an overview of traveling wave and superimposed component distance protection and presents a trial project of the
technology on the Salt River Project (SRP) system.
SITE SELECTION
The SRP selected the line location to install, monitor, and evaluate this new technology on a trial basis. When testing any new system, the desire is to maximize the number of all possible types of operations during the trial period. SRP chose to deploy the new technology for this evaluation on an 8.49-mile, overhead 69-kilovolt sub-transmission line between the Dinosaur and Micromill One substations southeast of the Phoenix metropolitan area. Located in an area of undeveloped desert landscape, this line experiences persistent wildlife activity, and the lack of surrounding
structures increases the exposure to seasonal thunderstorm activity.
Equally important was choosing a transmission line constructed with optical ground wire (OPGW). Taking advantage of differential protection in the time domain requires a direct fiber link between relays to achieve communication data rates that approach the speed of light, which is a common basis for measuring traveling wave velocities. OPGW is available in the SRP service territory. However, the allocation of this medium is dominated by business purposes other than system protection. Therefore, acquiring a second pair of these fibers to use between the two ends of the line beyond the existing multiplexed pair that already carries all other station-to-station traffic required additional justification and approval.
DESIGN AND INSTALLATION
This trial relaying was designed systematically to operate in parallel with the line’s existing phasor-based protection using 11TD timedomain relays (Figure 1). This allows direct comparison with the behavior of the devices already deployed (87L — a pair of multifunction differential relays using multiplexed communications, and 21L — local impedancebased distance relays) during post-event analysis. Since this installation is for testing purposes, the time domain relay trip outputs were not connected to the circuit breakers’ trip circuitry. Not only does this prevent any unexpected operations from disturbing an inservice line, but it also allows settings changes to be made remotely without the need for test permitting or local device isolation.
Using a short-circuit program, a systemequivalent model was created for the protected line. Six elements were evaluated closely to allow optimal protection testing and fault locating. The first two settings — the phase and ground overcurrent supervision thresholds — were calculated by simulating different types of faults at the remote-end bus. These values were coordinated to be between the lowest possible fault and the maximum possible load expected
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on this transmission line. These elements establish a threshold to supervise the traveling wave relay elements to prevent mis-operation during non-fault related system events.
Next, the forward- and reverse-directional elements were scrutinized. These additional impedance thresholds will supervise the line distance and differential elements within the 11TD. Using the aforementioned systemequivalent model again, the forward setting was calculated as 30% of the minimum positivesequence impedance behind the local bus. The reverse setting was then simply calculated as 30% of the protected line’s positive-sequence impedance. These calculations provide torque control with a conservative safety margin for any system calculation errors.
The incremental distance element zone setpoints were set based on the utility’s standard convention. Accounting for maximum expected instrument transformer and line modeling errors, 80% for phase and 70% for ground faults were set. Although the source impedance ratio (SIR) at each end of the line was not used to determine the reach settings, it was calculated here for informational purposes. Based on classic SIR calculations, the line appears long from the transmission station end of Dinosaur Substation (SIR < 0.5) but is medium length from the distribution bus at the Micromill One Substation (0.5 < SIR < 4). This ultimately affects the operating time of the time domain distance function, but with both being relatively small, the relay is expected to operate faster.
Figure 1: Time Domain Relay Installation Single-Line Diagram
The final two settings have to do with line propagation velocity. Fault location using traveling waves (TWs) is determined by the equation:
(1)
where:
LL is the total line length local is the time the TW arrives at the local end t remote is the time the TW arrives at the remote end
v p is the propagation velocity
The static values that can be programmed into the device are LL (already known) and vp (to be determined experimentally). Additionally, at each end of the line, current transformers will translate the TW signal entering secondary cabling before finally arriving at the 11TD relay. This cabling is assigned a fractional value of the speed of light based on its physical attributes, representing the additional delay the TWs will be subjected to. Seemingly minor, this setting can account for substantial errors in fault location.
Once device installation was completed, a power system switching procedure was followed to allow capture of a high-speed traveling wave event that could be analyzed to determine the subject line’s specific vp. Initially assuming that it would be equivalent to 98% of the speed of light allowed for a calculated estimate of the anticipated time difference between the TW sent from closing one end of the line (t1local) and the reflection received from the open
opposite end of the line (t2local). Manipulating (1) provided: (2) where: c is the speed of light
The resulting value for our 8.49-mile line was 93 s, which is close to the time difference between the negative TW launching peak and the positive TW reflection peak seen in the Bewley diagram in Figure 2. Utilizing the actual time difference found experimentally and substituting it into (3) provided a final value for v p : (3)
It is interesting to note the polarities of the traveling waves launched by each phase of the breaker closing, as seen in Figure 3. A positive voltage waveform will result in a current signal’s TW having a positive polarity; a negative voltage waveform will likewise result in a negative-polarity TW. The reflection of the TW off the open end of the line results in a perfect inversion due to its infinite impedance. Similarly, a transformer located at the end of the line, which would have a higher characteristic impedance than the transmission line, would have also inverted the reflected TW. However, a line tap produces a minor reflection of the same polarity (not inverted) due to the parallel impedance reducing the line’s effective characteristic impedance. Although there is a line tap along the subject line, the reflections from it were not significant.
In all cases, the reflection coefficient seen at the end device can be expressed as in (4):
where:
(4)
Z0,eff is the effective characteristic of the object connected to the line causing the TW reflection
Z0 is the characteristic of the subject line itself
Figure 2: Bewley’s Lattice Diagram of Propagation Test Results
TESTING
Onsite field testing was desired and undertaken to establish in-zone fault detection performance, out-of-zone fault descrimination, and operation of the backup time domain distance protection. Specialized end-to-end testing was selected as the test method.
Of course, testing relays operating in the time domain presents a number of challenges:
• First, since testing without disturbing relay settings was desired, realistic traveling waves and 60 hz components must be applied to both relays simultaneously.
• Second, when transitioning from prefault conditions to fault conditions, source impedance must remain constant.
• Third, test signal injection timing at the local and remote ends must be extraordianarily precise, as each 1 nsec of timing errror results in a fault location error of roughly 1 foot.
• Finally, the simulated traveling waves must possess suitable rise times and amplitudes in order to pass through the relay’s traveling wave filter.
Test Software, Hardware, and Connections
The protected line was modeled in the test software by graphically describing the system under test (Figure 4) and then entering system voltage, system frequency, line impedances, source impedances, line length, CT polarity, and travelling wave propogation time.
From this infomation, the test software calcuates traditional 60 hz test quantities, traveling wave pulse polarity, and injection time for each test case. The desired commissioning test cases included in-zone phase-to-phase and phase-to-neutral faults, as well as out-of-zone phase-to-phase and phase-to-neutral faults.
At each end of the line, a test set and travelling wave injection hardware were connected to the relay test switches via standard test-switch adapters. A standard relay test set provided test
ADVANCEMENTS IN INDUSTRY
currents and voltages in the power frequency range. An accessory device was used to generate current and voltage channel traveling waves. The accessory device currents were connected in parallel with the relay test set currents providing a test input equal to the sum of the 60 Hz and traveling wave test signals. The voltage signals from the relay test set were connected in series with the traveling wave accesory voltage signals, providing a signal equal to the sum of power frequency and traveling wave voltages. Relay operations were measured by monitoring the relay output contacts with the relay test set. A separate IEEE 1588 grand-master clock provided time synchronization for the local and remote test sets.
Figure 3: Time Domain Plot of Propagation Time Test
Figure 4: System Model for Commissioning Test
ADVANCEMENTS IN INDUSTRY
Communication of test-case parameters and timesynchronization instructions between the local and remote terminals was conducted via a 4-G cellular modem.It should be noted that since the actual timing of the test signals is synchromized by a GPS at each end of the line, the communication speed of test parameters is not critical.
Once the test equipment was installed, communication and connections were verified by simulating normal line load flow and verifying the relay metering against the programmed inputs.
Fault Simulation of the Traveling Wave Differential
For the traveling wave differential element to operate during testing, several conditions must be met:
1. The relay communication channel and GPS clocks are healthy.
2. Protection is armed by simulating a normally energized line with no loss of potential, open pole, normal frequency, and no existing fault.
3. At simulated fault inception, incremental quantity overcurrent supervision condition is met by accurately simulating fault conditions in the power frequency range.
4. Current traveling waves meeting the waveshape criteria of the travelling wave filter are recieved at both ends within the programmed propogation time
Results
To test the operation of the installation, B-C-N, C-A-N, A-B-C-N, and C-A faults were simulated at various points on the protected line. The traveling wave differential protection operated in all cases. Traveling wave element trip times ranged from 1.0 ms to 2.3 ms. Fault location error, measured by comparing the simulated fault position and the reported fault location by the relay, was less than 20 meters in all test cases.
To test selectivity, faults were also simulated on the adjacent buses. This simulation causes the current traveling waves sent to the relay
adjacent to the fault and the relay on the opposite side of the line to have opposite polarities due to connected CT polarization. The resultant restraint quantity would be large, and the operate quantity would be small, resulting in no traveling wave differential element operation. As there are no parallel lines in this application, this would be sufficient to block the traveling wave differential. Note that additional supervisory logic is implemented for applications with parallel lines.
Tests simulating faults on either bus adacent to the line resulted in no traveling wave differential element operations.
Fault Simulation of the Incremental Quantity Distance Element
To test the operation of the traveling wave differential element, several conditions must be met:
1. Test signals must be consistent with line and system impedances.
2. Protection is armed by simulating a normally energized line with no loss of potential, open pole, normal frequency, and no existing fault.
3. Incremental quantity overcurrent supervision condition is met by accurately simulating fault conditions in the power frequency range.
4. Traveling wave protection is blocked.
5. Simulated fault impedance is inside the Zone-1 reach setting.
Procedure and Results
As the traveling wave differential is substantially faster than the incremental distance, the traveling wave differential must be blocked to test the incremental distance element. This was acomplished by changing the fault inception angle to the positive zero crossing, which results in no traveling waves generated by the simulation. The incremental element was tested with simulated phase-to-neutral and phase-to-phase faults around the programmed reach settings, 0.8 pu and 0.7 pu, respectively. The incremental distance protection operated
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ADVANCEMENTS
in 2.9 ms to 4.2 ms. As with other types of distance protection, some under-reaching was noted with higher source impedance ratios.
REAL WORLD EXPERIENCE
The Dinosaur-Queen Creek-Micromill One transmission line experienced a C-phase-toground fault in July 2018. The event was caused by multiple foil balloons bridging the C-phase insulator and the pole ground conductor. When the line was physically inspected later, field crews confirmed evidence of arcing at both of these locations on the transmission structure (Figure 5). This structure is located approximately 6.45 miles from the Dinosaur Substation end of the line.
The 11TD relay record correctly indicated a C-phase-to-ground fault for this incident. The travelling wave fault-locating feature calculated a distance of 6.47 miles from Dinosaur Substation. When compared to the actual location reported by crews, the relay’s number was within 100 feet of the actual event. Furthermore, closer manual examination of the waveforms captured within a Bewley’s lattice diagram provided a marginally closer distance (Figure 6).
In addition to reviewing the 11TD records, engineering personnel also extracted records from the paralleled tripping relays. The line differential relay (87L) reported a fault distance of 5.95 miles based on its traditional impedance-based calculations. Although we are dealing with a short line, this still represents a difference of eight transmission structures between the reported and the actual fault location. This clearly demonstrated the 11TD device’s superior fault-locating capabilities.
Figure 5: Actual Line Fault (07/18)
Figure 6: Bewley’s Lattice Diagram from 07/18 Relay Fault Record
ADVANCEMENTS IN INDUSTRY
under 1.5 ms. The operating speed of the 11TD relay was measured at approximately 0.9 ms on the Micromill One end (which was less than a third of the distance to the fault location at 2.04 miles) and 2.1 ms on the Dinosaur end. As seen in Figure 7, these times are calculated between the traveling wave disturbance detector and trip output assertion. The incremental quantity distance elements were slower and did not operate for this fault.
In contrast, the phasor-based 87L relay had considerably longer operating times. Zero- and negative-sequence directional elements picked up in just under 9 ms. The overall operating speed of the relay was again determined between its disturbance detection and the first trip output assertion. In this case, the impedance-based protection narrowly beat the differential on the Micromill One end, which was within the instantaneous Zone-1 ground operating region, set to 70% of the line impedance, operating in under 15 ms, as seen in Figure 8. The Dinosaur end called for a differential trip in under 18 ms, which would finally complete the line clearing.
Therefore, the 11TD dominated its relaying predecessor with significantly higher operating speeds, clocking in at 1/8th of a power-system cycle for total line tripping. The 87L allowed more than a cycle to elapse before calling for both ends to open.
CONCLUSION
In this application, the traveling wave line differential relay offered increased tripping speed and substantially more accurate fault location.
REFERENCES
E.O. Schweitzer III, A. Guzman, M.V. Mynam, V. Skendzic, and B. Kasztenny. “Locating Faults by the Traveling Waves They Launch,” 40th annual Western Protective Relaying Conference, Spokane, Washington, October 2013.
The 11TD and 87L operating speeds were also compared for the event. Traveling wave directional fault detection in the 11TD relay occurred in under 0.1 ms, with the incremental quantity directional element picking up in
R. James and S. Hayes. “Utility Experience with Traveling Wave Fault Locating on Lower Voltage Transmission Lines,” 45th annual Western Protective Relaying Conference, Spokane, Washington, October 2018.
Figure 7: Sequence of Events Plot for 7-18 Fault
Figure 8: Sequence of Events Plot #2 for 7-18 Fault
IEEE Std.C37.113, IEEE Guide for Pr otective Relay Applications to Transmission Lines.
Faris Elhaj joined OMICRON electronics in 2018 as a Training and Application Engineer based in Houston, Texas. His focus areas include protection and power utility communications (PUC). Faris started his career in protection and control (P&C) in 2012, working for GE in a variety of roles, delivering training on protection concepts and providing application support on Multilin relays and has executed many P&C service projects, conducting installation and commissioning activities for utilities and industrial plants. Faris received his BS and MS in electrical engineering from McMaster University in Hamilton, Ontario.
Scott Cooper is a Training and Application Engineer with OMICRON electronics. He has over 17 years of experience in a variety of high-intensity sales, application engineering, and training roles while working for Manta and Beckwith, mainly selling and supporting
ADVANCEMENTS IN INDUSTRY
P&C test equipment and systems. Scott is an active member of IEEE PES committee serving many PSRC working groups. While serving in the United States Navy, he was a qualified reactor operator and shutdown reactor operator, a qualification board member, a Reactor Plant Drill Team member, and a Reactor Training Division Instructor.
Anthony Sivesind has 18 years of experience in the utility industry and has worked in a variety of roles during his tenure at Salt River Project, including designer, engineer, and project manager of major substation construction and transmission jobs, new protection and control initiatives, and standards development and implementation. He is presently an Executive Engineer in the Protection, Automation, and Control Strategy Department, where he can focus on research and development initiatives to efficiently protect and control the grid in support of SRP grid modernization. Anthony received his BS and MS in electrical engineering with an emphasis in mechatronics and alternative energy from Arizona State University.
Francisco J. Sanchez is a Generation Engineer supporting Salt River Project generation facilities. He received his BS in electrical and computer engineering from New Mexico State University.
A-RENT: QUALITY EQUIPMENT AND RESPONSIVE SERVICE
NETA’s Corporate Alliance Partners (CAPs) are a group of industry-leading companies that have joined forces with NETA to work together toward a common aim: improving quality, safety, and electrical system reliability.
Our continuing CAP Spotlight series highlights some of their individual successes as NETA World interviews A-Rent CEO Paul Seppanen.
NWJ: Please briefly describe A-Rent
Seppanen: A-Rent specializes in electrical test equipment rental. We support customers nationwide, including NETA members, with our comprehensive fleet of the newest equipment in the sector. We’re now a 12-member team based in Burr Ridge, Illinois, outside Chicago.
NWJ: What is something NETA World readers don’t know about A-Rent Test Equipment?
Seppanen: We have four engineers on our staff. Our engineering depth lets us provide immediate first-line technical support for all of our equipment, with back-up from OEM partners as needed. Our engineers also develop functional test procedures (FTP) for every piece of equipment in our fleet. We rigorously test our rental equipment on specimen apparatus according to these FTPs
before every new rental to ensure equipment works smoothly in the field.
NWJ: What recent company achievement or milestone are you particularly proud of?
Seppanen: Since our launch a little more than two years ago, we’ve built a solid base of several hundred regular customers, including virtually every NETA Accredited Company in the United States. We’re proud that these customers gave us a chance and that our responsive service and the quality of our equipment have kept them coming back for continuing rentals.
NWJ: What change do you see on the horizon that will have a positive impact on your work?
Seppanen: We’re thankful to be part of a healthy and growing sector. Continued nationwide investments in grid resiliency programs, new datacenters, and wind/solar/
PAUL SEPPANEN
storage capacity expansions are requiring huge testing capacity among our clients, which we’re glad to support.
NWJ: What challenges do you see going forward for the industry?
Seppanen: Personnel shortages constrain every firm and the industry as a whole. We’re working to play a positive role by drawing newcomers from outside electrical testing into A-Rent. Our new team members then
WE’VE BUILT A SOLID BASE OF SEVERAL HUNDRED REGULAR CUSTOMERS, INCLUDING VIRTUALLY EVERY NETA ACCREDITED COMPANY IN THE UNITED STATES.
have a chance to become knowledgeable on equipment, testing procedures, logistics, and project expectations. We’ve been able to successfully grow our team and business with this approach, rather than trying to hire away people already in the sector.
A-Rent Team
Huge Selection of In-Stock Electrical Equipment
SPECIAL TEST EQUIPMENT FOR
• Protective Relays
• Transformers & Motor Analysis
• Partial Discharge/Corona
• Current Injection
• Cable Fault Location
OF RENTING
• Cost-Savings Versus Buying
• Available for Immediate Delivery
• Switchgear/Circuit Breakers
• Insulation Resistance
• Tan Delta/Power Factor
• Current Transformers
• Ground Grid
• Choose From a Variety of Manufacturer’s Top-of-the-Line Products
• Short-term Solutions for One-Off Tests
• Always Calibrated Equipment
ISO 17025 / NIST Cal / ANSI Z540
Twenty-nine members and four NETA staff attended the meeting.
NETA MEMBERSHIP MEETING CHARTS PROGRESS AND LOOKS AHEAD TO 50TH ANNIVERSARY CELEBRATION IN 2022
The NETA Board of Directors and NETA staff met face-to-face in midSeptember for the first time since March 2020. The NETA Membership Meeting took place at the San Antonio Marriott Riverwalk Hotel in San Antonio, Texas. The agenda included a comprehensive Board Report and strategy updates in specific areas such as membership growth and efforts to grow industry awareness.
A financial report showed the association on solid financial footing, while the Membership Committee focused on new applicant companies as well as other new-member possibilities.
After a mid-morning break, presentations focused on the PowerTest 2022 conference and trade show, including long-awaited plans for promoting NETA’s return to live events. “The PowerTest discussion has been particularly exciting because
we are celebrating NETA’s 50th anniversary next year during our biggest annual gathering of NETA Members and others allied to the field,” says Missy Richard, NETA’s Executive Director. “Everyone brought their best ideas on how to make this a memorable event to celebrate NETA’s accomplishments and its historical impact on the electrical power industry.”
The rest of the day’s agenda covered important updates on the Alliance Program, the Certification Exam and development of a practice exam, ANSI Standards, new training opportunities, NETA’s technical representation across the industry, and a demonstration of the newly launched NETA Nation Community platform. The NETA World Committee announced the addition of new content to the line-up, including an in-depth interview in
each issue with a stand-out performer from a NETA Accredited Company.
“It was inspiring to see how much our Board and committee volunteers have accomplished during the last 18 months without meeting in person and with the constraints of a world pandemic challenging them every step of the way,” says Eric Beckman, President of National Field Services, and President of the NETA Board of Directors. “We’ve grown existing programs and introduced new ones, embraced new media technologies, and forged ahead with plans for an in-person PowerTest Conference this spring. The resilience of our industry is reflected in the NETA leadership and volunteers present at this important meeting, and I look forward to celebrating our 50 th anniversary together in 2022.”
NETA Executive Director Missy Richard announces the return of in-person member meetings and the 2022 dates for the annual PowerTest conference.
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ANSI/NETA STANDARDS UPDATE
REVISION SCHEDULED
ANSI/NETA ETT–2018 REVISION SCHEDULED FOR 2022
ANSI/NETA ETT, Standard for Certification of Electrical Testing Technicians , 2018 Edition is in the process of revision. The initial ballot was completed July 2021. Suggested comments and revisions will be reviewed by the Standards Review Council in fall 2021. A second ballot is scheduled for late 2021. The revised edition of NETA ETT is scheduled to debut at PowerTest 2022.
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.
SPECIFICATIONS AND STANDARDS
ANSI/NETA ATS–2021
LATEST EDITION
ANSI/NETA ATS, Standard for Acceptance Testing Specifications for Electrical Power Equipment & Systems, 2021 Edition, has completed an American National Standard revision process. ANSI administrative approval was granted September 18, 2020. The new edition was released in March 2021 and supersedes the 2017 edition.
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 ATS-2021 new content includes arc energy reduction system testing and an update to the partial discharge survey for switchgear. ANSI/NETA ATS-2021 is available for purchase at the NETA Bookstore at www.netaworld.org.
ANSI/NETA ECS–2020
LATEST EDITION
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
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.
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.
The 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.
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)
ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Equipment & Systems, 2019 Edition, completed an American National Standard revision process and received ANSI approval on February 4, 2019. The revised edition of ANSI/NETA MTS was released in March 2019 and supersedes the 2015 Edition.
ANSI/NETA MTS contains specifications for suggested field 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.
ANSWERS
ANSWERS
1. c. Fall 2002. Jim’s first Tech Quiz was featured again in the Fall 2021 issue of NETA World
2. a. Jim wrote 76 Tech Quizzes from Fall 2002 to Winter 2020.
3. b. At the age of 19, Jim enlisted in the Air Force, where he served as a jet mechanic in Korea during the Vietnam War.
4. b. During his interview for the 2013 NETA Outstanding Achievement Award, Jim reminisced that in 1986, “There was a core group of guys who had a vision. I could see
that vision,” he said. “I wanted to be a part of making it happen. The industry needed stability and quality companies that had a set of standards. I saw NETA as the path.”
5. e. All of the above. Jim was also a regular contributor to NETA World for well over two decades and was an active presenter/ lecturer at NETA’s PowerTest conferences.
6. a. 2011. The Electrical Safety Excellence Award was established in 1999 for “outstanding dedication and contributions to advance and accelerate the dispersion of information and knowledge impacting electrical safety through activities within the PCIC.”
NETA ACCREDITED COMPANIES Setting
249th Engineer Battalion
249th EN BN S3 NCOIC 9450 Jackson Loop. Bldg. 1418 Fort Belvoir, VA 22060 (703) 805-9981
249th Engineer Battalion, Bravo Company Bldg 3-2631 Butner Rd Fort Bragg, NC 28310-0001 (703) 853-3958
john.w.crosby.mil@mail.mil SFC John Crosby
249th Engineer Battalion, Charlie Company
9410 Jackson Loop Bldg 1416 Fort Belvoir, VA 22060-5116 (703) 806-1078
william.s.maddox13.mil@mail.mil
SSG William Maddox
249th Engineer Battalion, HHC 9450 Jackson Loop Bldg 1416 Fort Belvoir, VA 22060-5147
SSG Michael Hamilton
A&F Electrical Testing, Inc.
80 Lake Ave S Ste 10 Nesconset, NY 11767-1017 (631) 584-5625 kchilton@afelectricaltesting.com www.afelectricaltesting.com
A&F Electrical Testing, Inc.
80 Broad St Fl 5 New York, NY 10004-2257 (631) 584-5625 afelectricaltesting@afelectricaltesting.com www.afelectricaltesting.com Florence Chilton
ABM Electrical Power Services, LLC
720 S Rochester Ste A Ontario, CA 91761-8177 (301) 397-3500 abm.com/Electrical abm.com/Electrical
ABM Electrical Power Services, LLC 6541 Meridien Dr Suite 113 Raleigh, NC 27616 (919) 877-1008 brandon.davis@abm.com abm.com/Electrical Brandon Davis
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.com/Electrical
ABM Electrical Power Services, LLC 4221 Freidrich Lane Suite 170 Austin, TX 78744 (210) 347-9481
ABM Electrical Power Services, LLC 11719 NE 95th St. Ste H Vancouver, WA 98682 (360) 713-9513
Paul.McKinley@abm.com www.ABM.com/Electrical Paul McKinley
ABM Electrical Power Solutions 4390 Parliament Place Suite S Lanham, MD 20706 (240) 487-1900
ABM Electrical Power Solutions 3700 Commerce Dr # 901-903 Baltimore, MD 21227-1642 (410) 247-3300 www.abm.com
ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 christopher.smith@abm.com Chris Smith - General Manager
ABM Electrical Power Solutions 814 Greenbrier Cir Ste E Chesapeake, VA 23320-2643 (757) 364-6145 keone.castleberry@abm.com www.abm.com Keone Castleberry
Electrical Energy Experts, LLC W129N10818 Washington Dr Germantown, WI 53022-4446 (262) 255-5222 tim@electricalenergyexperts.com www.electricalenergyexperts.com
Tim Casey
Electrical Energy Experts, LLC 815 Commerce Dr. Oak Brook, IL 60523 (847) 875-5611
Michael Hanek
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
Giga Electrical & Technical Services, Inc. 5926 E. Washington Boulevard Commerce, CA 90040 (323) 255-5894 gigaelectrical@gmail.com www.gigaelectrical-ca.com/ Hermin Machacon
Grubb Engineering, Inc.
2727 North Saint Mary’s St. San Antonio, TX 78212 (210) 658-7250
Hood Patterson & Dewar, Inc. 4511 Daly Dr. Suite 1 Chantilly, VA 20151 (571) 299-6773 info@hoodpd.com https://hoodpd.com/
Hood Patterson & Dewar, Inc. 1531 Hunt Club Blvd Ste 200 Gallatin, TN 37066 (615) 527-7084 info@hoodpd.com https://hoodpd.com/
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 gbenzenberg@bellsouth.net www.industrialelectrictesting.com Gary Benzenberg
Industrial Tests, Inc. 4021 Alvis Ct Ste 1 Rocklin, CA 95677-4031 (916) 296-1200 greg@indtest.com www.industrialtests.com Greg Poole
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
100 Lenox Drive Suite 100 Lawrenceville, NJ 08648 (609) 285-2800 jvasta@jetelectricaltesting.com jetelectricaltesting.com Joe Vasta
KT Industries, Inc. 3203 Fletcher Drive Los Angeles, CA 90065 (323) 255-7143 eric@kti.la ktiengineering.com Eric Vaca
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 info@magnaiv.com 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
NETA ACCREDITED COMPANIES Setting the Standard
Magna IV Engineering
Avenida del Condor sur #590 Oficina 601 Huechuraba, 8580676 +(56) -2-26552600 info.santiago@magnaiv.com
Harvey Mendoza
Magna IV Engineering
Unit 110, 19188 94th Avenue Surrey, BC V4N 4X8 (604) 421-8020 info.vancouver@magnaiv.com
Rob Caya
Magna IV Engineering
Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 (403) 723-0575 info.calgary@magnaiv.com
Morgan MacDonnell
Magna IV Engineering 4407 Halik Street Building E Suite 300 Pearland, TX 77581 (346) 221-2165 info.houston@magnaiv.com www.magnaiv.com Aric Proskurniak
Magna IV Engineering 10947 92 Ave Grande Prairie, AB T8V 3J3
1.800.462.3157 info.grandeprairie@magnaiv.com
Matthew Britton
Magna IV Engineering 531 Coster St. Bronx, NY 10474 (800) 462-3157 Info.newyork@magnaiv.com
Power Engineering Services, Inc. 9179 Shadow Creek Ln Converse, TX 78109-2041 (210) 590-6214 pes@pe-svcs.com www.pe-svcs.com
Power Engineering Services, Inc. 4041 Ellis Road Suite 100 Friendswood, TX 77546 (210) 590-4936 pes@pe-svcs.com www.pe-svcs.com
Power Engineering Services, Inc. 1001 Doris Lane Suite E Cedar Park, TX 78613 (210) 590-4936 pes@pe-svcs.com www.pe-svcs.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 www.powerproducts.biz Raymond Pesaturo
Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz www.powerproducts.biz
Power Solutions Group, Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 bwilloughby@powersolutionsgroup. com www.powersolutionsgroup.com Barry Willoughby
NETA ACCREDITED COMPANIES Setting the
Power Solutions Group, Ltd.
251 Outerbelt St. Columbus, OH 43213 (614) 310-8018
Shermco Industries 6551 S Revere Parkway Suite 275 Centennial, CO 80111 (877) 456-1342 www.shermco.com www.shermco.com
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
NETA ACCREDITED COMPANIES Setting
Southern New England Electrical Testing, LLC 3 Buel St Ste 4 Wallingford, CT 06492-2395 (203) 269-8778
www.sneet.org www.sneet.org
John Stratton
Star Electrical Services & General Supplies, Inc. PO Box 814 Las Piedras, PR 00771 (787) 716-0925 ahernandez@starelectricalpr.com www.starelectricalpr.com Aberlardo Hernandez
Taifa Engineering Ltd. 9734-27 Ave NW Edmonton, AB T6N 1B2 (780) 405-4608 fsteyn@taifaengineering.com
Taurus Power & Controls, Inc. 9999 SW Avery St Tualatin, OR 97062-9517 (503) 692-9004 powertest@tauruspower.com www.tauruspower.com
Rob Bulfinch
Taurus Power & Controls, Inc. 8714 South 222nd St. STE A Kent, WA 98031 (425) 656-4170
powertest@tauruspower.com www.taruspower.com
TAW Technical Field Services, Inc. 5070 Swindell Rd Lakeland, FL 33810-7804 (863) 686-5667 www.tawinc.com
Tidal Power Services, LLC 8184 Highway 44 Ste 105 Gonzales, LA 70737-8183 (225) 644-8170 darryn.kimbroug@tpsgse.com www.tidalpowerservices.com Darryn Kimbrough
Tidal Power Services, LLC 1056 Mosswood Dr Sulphur, LA 70665-9508 (337) 558-5457 rich.mcbride@tidalpowerservices.com www.tidalpowerservices.com Rich McBride
Tidal Power Services, LLC 1806 Delmar Drive Victoria, TX 77901 (281) 710-9150 kelly.grahmann@tps03.com Kelly Grahmann
Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com www.titanqps.com
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
US Army Prime Power School Bldg 12630, Flw 28 Fort Leonard Wood, MO 65473 (253) 380-0194 brandon.s.sheppard.mil@mail.mil SSG Brandon Sheppard
Utilities Instrumentation Service - Ohio, LLC 998 Dimco Way Centerville, OH 45458 (937) 439-9660 www.uiscorp.com 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 Walls
Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 apeterson@utilserv.com www.utilserv.com
Alan D. Peterson
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addition in the Raytech line of testing equipment. See our ad in the PowerTest 2022 Preview Guide to learn more about our mini model.
To learn more about our product lines, request a quote, schedule a demonstration, for sales or service, contact us 24/7.
Current transformer testing, calibration, and assessment with the push of a button
Our CT Analyzer assesses the accuracy of both metering and protection current transformers (CTs) via secondary injection. For added safety, it uses only low test signals of up to 120 V. From production to maintenance inspections, it tests, calibrates, and assesses CTs up to 0.1 accuracy class in less than one minute.
longer need bulky machinery to test your CTs in accordance with IEEE / IEC or customized standards. For these reasons, customers in more than 120 countries already use CT Analyzer to test their CTs. www.omicronenergy.com/ct-analyzer
