MEASURING PARTIAL DISCHARGE ON MEDIUMVOLTAGE CABLES
ON-LINE CABLE PD TESTING PAGE 56 ACCEPTANCE AND MAINTENANCE TESTING FOR MEDIUM-VOLTAGE ELECTRICAL POWER CABLES PAGE 64
DETECTING PARTIAL DISCHARGE ON MEDIUM-VOLTAGE CABLE ACCESSORIES PAGE 76
46 Measuring Partial Discharge on Medium-Voltage Cables
Jason Aaron and Joseph Aguirre, Megger
Measuring partial discharge (PD) activity is a diagnostic method used to evaluate insulation quality. Paired with other cable tests, it can identify defects before a fault occurs, reducing maintenance, repair, and replacement costs.
56 On-Line Cable PD Testing
William G. Higinbotham, EA Technology, LLC
This article explores the theory, benefits, and pitfalls of on-line PD testing and shows the value of the methodology as a proven and practical method to reduce the impact of future cable failures.
64
Detecting Partial Discharge on Medium-Voltage Cable Accessories
Michel Trepanier and Claude Tremblay, Hydro-Quebec; Lionel Reynaud, Hydro-Quebec Research Institute; and Mathieu Lachance, OMICRON electronics Canada
In-service failures lead to loss of revenue, increased expenditures for repairs, and potential damage to other power apparatus due to increased stress during a fault. Learn how Hydro-Quebec implemented a multi-level evaluation system to achieve safety, economic, and service goals.
76 Acceptance and Maintenance Testing for Medium-Voltage Electrical Power Cables – Part 1
Tom Sandri, Protec Equipment Resources
Part 1 of 3 describes the evolution of testing methods and philosophies over the past 30-plus years and explains the use, advantages, and limitations of each technique.
TABLE OF CONTENTS
INSIGHTS AND INSPIRATION
8 Wyatt Hamrick: Curiosity and Commitment
IN EVERY ISSUE
7 President’s Desk
Recognizing Your Dedication
Eric Beckman, National Field Services NETA President
14 NFPA 70E and NETA
A Game of Inches: Understanding Dimensions in NFPA 70E
Ron Widup, Shermco Industries
20 Relay Column
Condition Monitoring: Generator Stator
Ground Capacitance
Steven Turner, Arizona Public Service Company
26 In the Field
Medium-Voltage Cable Installation Issues
Mose Ramieh, CBS Field Services
33 Safety Corner
Programs, Policies, Manuals, Procedures, and Training
Paul Chamberlain, American Electrical Testing Co. LLC
38 Tech Quiz
Off-Line Partial Discharge Cable Testing
Virginia Balitski, Magna IV Engineering
40 Tech Tips
Ground Enhancements: An Answer to Difficult
Grounding Situations
Jeff Jowett, Megger
INDUSTRY TOPICS
86 Microgrids in Practice
Mayfield Renewables
94 Photovoltaic Power Systems and Ground-Fault
Protection on the Service Entrance Disconnect
John Wiles, Retired
100 Using the Three Rs to Reduce the Environmental Impact of SF6 Gas
Lina Encinias and Corey Ratza, DILO Company, Inc.
CAP CORNER
108 Advancements in the Industry Operational Technology Cyber Threats Are on the Rise
Bryan J. Gwyn and Sagar S. Singam, Doble Engineering Company
114 CAP Spotlight Group CBS: People, Technology, and Uptime NETA NEWS
NETA Welcomes New Accredited Company — Electro Test LLC
NETA Activities Update
70B Update
David Huffman, Power Systems Testing Company IMPORTANT LISTS
Accredited Companies
NFPA 70E Training
Get Your Workers Certified to the 2021 Standard!
Electrical Safety for the Qualified Worker training is aimed at qualified electrical workers to help them build capabilities, knowledge and safe work practices when working around energized electrical systems. Protec Equipment Resources now offers a live online instructor-led 2.5 day course that meets the NFPA 70E ® 2021 standard for electrical safety in the workplace!
Live Instructor-Led
People taking this class for the first time are required by the 70E 2021 standard to take it “live”. Whether online or in-person, to be compliant, there must be interaction and engagement with an instructor.
Great Price
Less expensive than in-person programs, with more curriculum and volume discounts!
Strongest Content Offering
20 hours (2.5 days) of practical tutorial that includes grounding as a topic!
Conveniently Consistent and Flexible
Virtual live online classes at a known date and time every month! Enroll 1 or 30.
Reduces Travel Time and Costs
Minimize workers’ time away from the office; eliminate the cost of travel and per-diems.
High Level of Instruction
Train with Tom Sandri, well-known in the electrical testing industry with over 30 years of experience. Tom was certified by a committee member and writer for the 70E certification.
FOR MORE INFORMATION
Scan the QR Code below with your phone’s camera and click the link that appears
Tom Sandri Director of Technical Services
3050 Old Centre Road, Suite 101
Portage, MI 49024
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: Bob Sheppard, Premier Power Maintenance
second vice president: Dan Hook, CBS Field Services
Scott Blizard (American Electrical Testing Co., Inc.)
Jim Cialdea (CE Power Engineered Services, LLC)
Leif Hoegberg (Electrical Reliability Services)
Dan Hook (CBS Field Services)
David Huffman (Power Systems Testing)
Chasen Tedder, Hampton Tedder Technical Services
Ron Widup (Shermco Industries)
non-voting board member
Lorne Gara (Shermco Industries)
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
design and production: Moon Design
NETA Committee Chairs
conference: Ron Widup; membership: Ken Bassett; promotions/marketing: Scott Blizard; safety: Scott Blizard; technical: Lorne Gara; technical exam: Dan Hook; continuing technical development: David Huffman; training: Bob Sheppard; finance: John White; nominations: Dave Huffman; alliance program: Jim Cialdea; association development: Ken Bassett
NETA World is published quarterly by the InterNational Electrical Testing Association. Opinions, views and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees or agents (herein “NETA”).
All technical data in this publication reflects the experience of individuals using specific tools, products, equipment and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA.
NETA MAKES NO ENDORSEMENT, REPRESENTATION OR WARRANTY AS TO ANY OPINION, PRODUCT OR SERVICE REFERENCED OR ADVERTISED IN THIS PUBLICATION. NETA EXPRESSLY DISCLAIMS ANY AND ALL LIABILITY TO ANY CONSUMER, PURCHASER OR ANY OTHER PERSON USING ANY PRODUCT OR SERVICE REFERENCED OR ADVERTISED HEREIN FOR ANY INJURIES OR DAMAGES OF ANY KIND WHATSOEVER, INCLUDING, BUT NOT LIMITED TO ANY CONSEQUENTIAL, PUNITIVE, SPECIAL, INCIDENTAL, DIRECT OR INDIRECT DAMAGES. NETA FURTHER DISCLAIMS ANY AND ALL WARRANTIES, EXPRESS OF IMPLIED, INCLUDING, BUT NOT LIMITED TO, ANY IMPLIED WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE.
ELECTRICAL TESTING SHALL BE PERFORMED ONLY BY TRAINED ELECTRICAL PERSONNEL AND SHALL BE SUPERVISED BY NETA CERTIFIED TECHNICIANS/ LEVEL III OR IV OR BY NICET CERTIFIED TECHNICIANS IN ELECTRICAL TESTING TECHNOLOGY/LEVEL III OR IV. FAILURE TO ADHERE TO ADEQUATE TRAINING, SAFETY REQUIREMENTS, AND APPLICABLE PROCEDURES MAY RESULT IN LOSS OF PRODUCTION, CATASTROPHIC EQUIPMENT FAILURE, SERIOUS INJURY OR DEATH.
ISSN 2167-3594 NETA WORLD JOURNAL PRINT
ISSN 2167-3586 NETA WORLD JOURNAL ONLINE
RECOGNIZING YOUR DEDICATION
As so many parts of the world face challenges due to extreme weather and geological events, I want to take a moment to recognize electrical workers and their families. As we all have learned, the electrical infrastructure is quite possibly the most essential part of our life these days. We tend to forget that we can’t accomplish many of the things we are accustomed to doing — or even the basic activities of life — without safe and reliable power.
Our technicians, electricians, and engineers put themselves in potential harm’s way every day to restore essential services. Adhering to various state, agency, and government regulations while maintaining safe work practices has and continues to be a challenge, and I commend the perseverance and dedication of all of those involved. It is truly a testament to how diligent and generous the people in our critical industry really are.
In this issue of NETA World, we take a look at some of the specific requirements for safely and effectively commissioning, testing, and maintaining cables, especially at a time when testing methods are under constant pressure to keep up with technology.
PowerTest 2023 will be at the Rosen Shingle Creek in Orlando, Florida, on March 8–12, 2023. You can still take advantage of early bird pricing, so don’t delay.
Plan ahead and always put safety first.
Eric Beckman, PE, President InterNational Electrical Testing Association
WYATT HAMRICK: CURIOSITY AND COMMITMENT
Thirty-one years into his career, Potomac Testing Project Manager Wyatt Hamrick says he is humbled by the lessons he has learned, but also proud of the many achievements and fond memories his career has provided.
With 10 years of service in the U.S. Army and 21 years of electrical testing experience under his belt, Hamrick says his own deep curiosity — which led his younger self to disassemble countless gifts to learn more about electricity — was the beginning of his approach to his work as a NETA Level 4 Technician. From there, his mentors, his efforts to gain as much knowledge as possible, and a very positive employment experience at Potomac Testing eventually led to a transition to his current position as a project manager and a love for his profession. Hamrick also holds a BS in management of technology from Athens State University and is a Master Electrician.
Here, Hamrick describes his journey and shares his focus on how we must continuously adapt our safety practices for fast-paced multiphase projects.
NWJ: What attracted you to electrical testing?
Hamrick: For as long as my memory serves, I have always had a deep curiosity and amazement about electricity. If you were anything like me as a child, you should immediately call to thank and/or apologize to all those who nurtured your inquisitive nature. All through my early years, I disassembled
countless birthday and Christmas gifts in an effort to learn more about electricity. I realize now that those early days of destruction ultimately led to building the foundation for my career in electrical testing. For me, electrical testing provides a dynamic space to understand and test many of the truths and mysteries of electricity.
NWJ: How long have you been in the field, and how did you get started?
Hamrick: I have been in the field for as long as I can remember, starting as an electrician’s helper for my dad. This early insight into
WYATT HAMRICK
the trade encouraged me to pursue various courses in electricity and electronics during high school, then trade schools and colleges, followed by extensive military training. To date, my professional career totals approximately 31 years. My first 10 years was spent with the U.S. Army as a HAWK Missile System Radar Technician, then as a Prime Power Technician. I am fortunate that my last 21 years have been spent with my current employer, Potomac Testing.
NWJ: How did you get to your current position?
Hamrick: Clearly, I must have lingered too long near the management side of too many projects. Project management was definitely a long-term consideration and a goal I set along with Potomac Testing leadership before transitioning to the office, but my formative years helped create a strong belief in me that my place was in the field. This belief allowed me to focus my efforts on gaining as much knowledge as possible, similar to those experienced senior technicians who blazed the trail before me. Although I tried like hell, I was never able to surpass my greatest mentors because as I grew, they did, as well. Somewhere along the way, my growth and development narrowed the gap between my roles as a field technician and project manager and eventually led to a natural transition to my current position as a project manager.
NWJ: Who has influenced or mentored you along the way?
Hamrick: This is a very abbreviated list! Most importantly, my parents, for seeing and supporting my pursuits and interests. Next, several military instructors, but one in particular comes to mind as an important influencer. While I have long since forgotten his name, this instructor’s motivational words continue to impact my life, and remain with me to this day:
“This is your job. Know your job. No one should ever have to do your job for you.”
That may seem simple, but it has stuck with me for almost three decades. The list of NETA technicians who have mentored and influenced me is too long to list here, but I want to give a special shout out to Bryan Hunter, Craig Biggs, and Steve Meader. Thank you! I am also extremely grateful that Ken Bassett took a chance on me and created an environment that to this day provides positive, never-ending challenges and puzzles to solve.
INSIGHTS & INSPIRATION
NWJ: What about this work keeps you committed to the profession?
Hamrick: I have a healthy fascination with all the ways electricity can be used and misused. Most of all, and I’m speaking NETA-wide, I love doing good work with smart people who give a damn. Our skills, experience, and training allow us to perform meaningful work.
NWJ: Describe one of your best workdays…what happened?
Hamrick: It was a one-day outage to troubleshoot and repair a defective transfer scheme. The customer had no historical knowledge nor associated drawings of the equipment. A highly respected senior technician and I were tasked to investigate, test, reverse engineer, repair, and sketch an old and somewhat complicated system. By understanding and trusting each other’s technical abilities, we were able to divide the problem and attack it from multiple directions. We poured ourselves into this effort, and as a result, found and successfully corrected several mis-wired and defective components.
Although the customer was happy, only the two us knew and could fully appreciate the level of achievement we experienced. In short, the best workdays include teamwork with people you like and respect, taking on difficult tasks, and achieving desired goals.
NWJ: Share the story of a day that didn’t go as planned. How did you respond and what did you learn?
Hamrick: Many days have not gone as planned, but the project that stands out for me was an assessment of an industrial complex after a hurricane decimated a community. This task was originally slated for 10 days of assessment but quickly developed into a six-week recovery and repair project.
Our team was not prepared for many aspects of this project, especially for the physical and
mental suffering of those we were working for. To start the project, our only available lodging was an RV that was not equipped with electricity, running water, or laundry appliances. The client’s site had sustained flood waters in the lower levels of the facility and significant rainwater intrusion in the upper levels. The various products in this facility — plus God knows what from the streets — had mixed and infiltrated much of the electrical distribution. The situation was tragic, and the working conditions were abysmal.
On Day 11, I took a long drive out of the disaster area searching for an open store that could provide me with fresh underwear and other normal creature comforts. With those essentials obtained, I returned to finish project. How did I respond? I followed the advice of my beautiful wife, who was at home with our infant and toddler. Paula’s advice was, “Suck it up, Buttercup. Do what you do best, and hurry home.” We not only achieved, but far surpassed the expectations of our customer. What I learned about planning for disaster recovery assignments was to over-plan for your provisions and build and support your home team.
NWJ: What energy trend do you think will affect your work in the future?
Hamrick: The increased need to expand our nation’s power grids and generation plants will have a huge effect on our future work. Additionally, the ever-expanding interconnectivity of devices and systems will continue to affect everything we do. NETA technicians will continue to be an essential piece of the security and reliability requirements surrounding these delicate systems.
NWJ: As an industry, what do you think should be our No. 1 priority over the next year?
Hamrick: Our No. 1 priority must always be legitimate safety practices. Of increasing concern to me is how we must continuously adapt our safety practices for
fast-paced multiphase projects. Our electrical testing industry has definitely made great advancements in safety over the last couple of decades, but we are not alone in this overall industry. Project timelines and milestones remain constant, regardless of growing supplychain shortages and associated delays. These delays invariably lead to schedule compression while simultaneously introducing hazardous conditions to our job sites that were not previously a concern.
To continue safely, we must demand proper communications from those working around us, as well as strict enforcement of hazard analysis and lockout/tagout procedures. Additionally, we must constantly verify and test our means of protection. Perhaps the most vital key to maintaining safety on these types of projects is a vigilant site leader who is in constant communication with all parties at all times. Finally, all team members must know that they are fully empowered and expected
to stop work if these communications are not occurring or our safety protocols are being infringed upon.
NWJ: If you were talking to a young person interested in knowing more about being an electrical testing technician, how would you describe the job, and what advice would you give them?
Hamrick: Our profession is a great career choice with excellent pay and benefits. You will need to continually assess your current understanding of our craft and test what you know to be true. Ask many questions; learn new and old products, software, and methods; and study literature written by those who have explored those gaps before you.
We are in high demand due to our professionalism, specialized training, and experience. In our lifetime, I see no end for the need for our services. Our work has meaning,
and you should never be bored working in this every-changing industry.
At first, most new technicians will be rightfully fearful. They typically will not do anything without proper instruction and confirmation of their safety. Eventually, after many years in the field, technicians will have learned or experienced enough near-misses for safety to be deeply impressed upon their consciousness. Be extra concerned during the in-between years. Although you should never trust your safety to anyone, a second set of eyes is always encouraged. They may save your life one day.
NWJ: Is there anything else you’d like to share?
Hamrick: I hope that all NETA techs enjoy their profession. I have truly enjoyed this career and time has flown by. I am humbled by the
lessons I have learned, but also very proud of the many achievements and fond memories this career has provided.
The motto I took from the US Army Corp of Engineers was “Essayons!” This explanation of that motto (with just a few word swaps) explains the drive of the best NETA Technicians and the wider NETA team.
“The U.S. Army Engineer Regimental motto is ‘Essayons!’ It is French for ‘Let us try.’ This isn’t a sympathetic, half-hearted try. It’s a statement of confidence, almost as if to say, ‘Where others failed, we will succeed.’”
I wanted to be an engineer because I wanted to succeed where others hadn’t yet. I wanted a diverse mission set that required me to be physically fit and mentally sharp. Now, I’m just trying to make a difference.
BURLINGTON ELECTRICAL TESTING CO., LLC
For scheduling call 215-826-9400 or email sales@betest.com Visit us at www.betest.com
AROUND THE CLOCK RESPONSE SERVING THE POWER INDUSTRY
BET is an independent third-party testing firm with more than 50 years of experience serving industrial, commercial, and institutional facilities’ low- to high-voltage electrical testing and maintenance needs, including:
• Acceptance Testing & Commissioning
• Switchgear Reliability Testing
• Protective Relay Setting
• Transformer Repair
• Transformer Oil Analysis
• Circuit Breaker Retrofits
• Battery Bank Testing
• Cable Fault Locating
• Meter Calibration
• Motor Testing & Surge Analysis
• Infrared & Ultrasonic Inspections
• Load Survey & Analysis
• Coordination & Short Circuit Studies
• Arc Flash Hazard Analysis
NFPA 70E, 2024 EDITION: SECOND DRAFT MEETING
BY RON WIDUP, Shermco Industries
In late August 2022, the NFPA 70E Technical Committee met for the Second Draft meeting related to the revision of what will be the 2024 edition of NFPA 70E, Standard for Electrical Safety in the Workplace.
This was the step in the revision process where the 70E Technical Committee meets to review Public Comments as well as NFPA Correlating Committee comments related to proposed changes to the standard. The NFPA consensus process is very thorough, allowing full public input and comment on committee actions.
As a reminder, the standards revision process is generally a four-step process, and NFPA provides a summary.
Step One: Public Input
Following the publication of the current edition of an NFPA standard, the development of the next edition begins, starting with the acceptance of Public Input for changes to the document.
After receiving input from the public, a First Draft meeting of the Technical Committee is held, and the committee considers the input and provides a response. The responses are balloted, and a report of the ballot and any committee comments is published in the form
Figure 1: NFPA Standards Process COURTESY OF NFPA
of a First Draft report. This is the beginning of change to what will become the newly formed standard content.
Step Two: Public Comment
After the first draft report is published, anyone may submit a Public Comment in the form of suggested text on the First Draft. From here, the Technical Committee calls a Second Draft meeting to review any suggested comments from the public. These actions are recorded and balloted by the Technical Committee, and a Second Draft report is generated for review by the public.
*Note: This is where we currently are in the NFPA 70E, 2024 Edition, revision process.
Step Three: NFPA Technical Meeting
Following completion of the Public Input and Public Comment stages, there is further opportunity for debate and discussion of any unresolved issues at the NFPA Technical Meeting held during the NFPA Conference & Expo each June. The next meeting will be held in Las Vegas, June 19–23, 2023.
Prior to the meeting, if someone still has an issue they want to bring forth, they must file a notice of intent to make a motion or NITMAM.
A NITMAM is a proposed amending motion for NFPA membership consideration and debate at
THE NFPA 70E AND NETA
the NFPA Technical Meeting. These motions are attempts to amend the committee’s recommended text published as the Second Draft.
Allowable motions include:
• Motions to accept Public Comments in whole or in part
• Motions to reject a Second Revision (change accepted by the committee) in whole or part
• Motions to accept committee comments in whole or in part
• Motions to reject a Second Revision (change accepted by the committee) in whole or part and can include the related portions of First Revisions
In addition, under certain specified instances, motions can be made to return an entire NFPA Standard to the committee. If successful, the Standard will not be issued and will be returned to the committee to continue its work.
Step Four: Council Appeals and Issuance of Standard
One of the primary responsibilities of the NFPA Standards Council, as the overseer of the NFPA standards development process, is to act as the issuer of NFPA standards.
The Standards Council considers any appeals that have been made, and after deciding all appeals related to a standard, the Standards Council, if appropriate, proceeds to issue the document as an official NFPA standard.
The new NFPA standard becomes effective 20 days after the Standards Council’s action of issuance. In the case of NFPA 70E, that most likely will be in July 2023.
An important note: When NFPA 70E is issued and an effective date is determined, this is the date at which the standard is applicable and will supersede all previous editions. Because it is a work practices document, the effective date of the new standard constitutes the rules and requirements going forward, so it’s important to understand any changes that were made to the new standard.
HIGHLIGHTS OF THE SECOND DRAFT MEETING
Several hundred Public Comments were processed during the recent Second Draft meeting. Some were technical; some were related to structure in accordance with NFPA’s Style Manual; some were directed to the Technical Committee by NFPA’s Correlating Committee.
All of them received thorough review, analysis, and discussion, which reinforces the effectiveness of the consensus process, ultimately leading to the production of the revised standard.
Global Change: Electric Shock
To ensure consistent use of the term and as a global change, any time* the word “shock” was used, we added the word “electric” in front of it.
* There are two terms — “hearing protection boundary” and “lung protection boundary” — where the definitions use “shock” in a
Figure 2: Electric Shock
different context, i.e., “shock wave.” These were not changed.
Section No. 90.5(C) Explanatory Material
A sentence was added to 90.5(C) to clarify the use of other standards as a reference:
Unless the standard reference includes a date, the reference is to be considered as the latest edition of the standard.
Point being, unless indicated otherwise, always consider the latest edition of any referenced standard when using the 70E!
Article 100 Definitions: Electrically Safe Work Condition
In one of the most important definitions in the standard, a slight change was made with regard to terminology around testing for the absence of voltage. The words “to verify” were replaced with “for” to be consistent with how the process of establishing and verifying an electrical safe work condition is described in120.6(7). It is a small, but important, change!
Electrically Safe Work Condition.
A state in which an electrical conductor or circuit part has been disconnected from energized parts, locked/tagged in accordance with established standards, tested to verify for the absence of voltage, and, if necessary, temporarily grounded for personnel protection.
Article 100 Definitions: Boundaries Abound
There are five boundary definitions to be aware of:
1. Arc flash boundary
2. Hearing protection boundary*
3. Limited approach boundary
4. Lung protection boundary*
5. Restricted approach boundary
*The hearing and lung protection boundaries are referenced in Article 360, Safety-Related Requirements for Capacitors.
Article 105 Application of SafetyRelated Work Practices and Procedures
Besides adding the words “Application of” to the title, the purpose of Section 105 was updated to the following:
105.2 Purpose.
These practices and procedures are intended to provide for employee safety reduce the risk for employees relative to electrical hazards in the workplace.
Figure 3: Absence of Voltage
THE NFPA 70E AND NETA
This update was made so that describing the purpose of the standard in terms of risk reduction is consistent with the risk assessment and control requirements of the document.
Section
110.4(A) Electrical Safety
Training (1) Qualified Person
Text was deleted in this section as the wording was redundant.
(b) A person shall be permitted to be qualified for some equipment or tasks and not others.
Section 250.2 Maintenance Requirements for Personal Safety and Protective Equipment
The term “hot sticks,” which arguably is a slang term, was clarified, and the term “live line tools” is used throughout the standard.
(2) Hot sticks (live line tools)
The addition of “live line tools” was added to include the correct technical term.
NEC STYLE MANUAL COMPLIANCE
There were many revisions to the standard to correct wording and terminology so that it complies with 2020 NEC Style Manual. It is important that sentence structure and organization is consistent between NFPA standards, and many editorial corrections were made to the 2024 edition to comply with the Style Manual.
SUMMARY: WHY DO WE CARE ABOUT NFPA 70E?
Many subject matter experts and volunteers work to develop consensus standards, and the rules, procedures, and guidance outlined in NFPA 70E are very purposeful and structured, allowing for public input and change. But why do we care?
Simply put — to save lives and avoid injury! NFPA 70E is a resource to help companies and employees reduce exposure to risks and reduce occupational injuries and fatalities. It was created to provide a document that meets Occupational Safety and Health Administration (OSHA) requirements and is entirely consistent with the NEC and other applicable publications.
NFPA 70E is a great resource to keep your employees safe as we deal with the hazards of electricity. So buy the new edition when it comes out and familiarize yourself with the words and terms, new and existing, of this very important safety standard.
And before you work on it — turn it off!
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 Principal member of the Technical Committee on 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 ThirdParty 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).
The
the industry, that never compromises
As North America’s largest independent electrical testing company, our most important Company core value should come as no surprise: assuring the safety of our people and our customer’s people. First and foremost.
Our service technicians are NETA-certified and trained to comply and understand electrical safety standards and regulations such as OSHA, NFPA 70E, CSA Z462, and other international guidelines. Our entire staff including technicians, engineers, administrators and management is involved and responsible for the safety of our co-workers, our customers, our contractors as well as our friends and families.
Our expertise goes well beyond that of most service companies. From new construction to maintenance services, acceptance testing and commissioning to power studies and rotating machinery service and repair, if it’s in the electrical power system, up and down the line, Shermco does it.
This article demonstrates how to use numerical generator protection relay profile capability to measure the stator ground capacitance of a large combustion turbine generator. The measurements are taken when the generator is on-line and running at full speed while the generator breaker is open (no load), and again during startup as the exported power increases.
The stator capacitance-to-ground (Figure 1) is indicative of conductive moisture and dirt in and around the stator insulation system. The apparent conductive surface area of winding insulation grows as contaminants build up.
The value of the variable plate can be measured and trended over time as the change in stator capacitance-to-ground (Cg).
Compare the initial (baseline) measurement to future recorded values. A significant rise in magnitude may indicate one of the following conditions:
• Internal contamination
• Moisture infiltration
• Problem with the circuit cables connected to the machine
THIRD HARMONIC VOLTAGE
Generators produce varying amounts of third harmonic voltage in addition to the fundamental. The stator winding pitch — the distance between the two sides of each loop relative to the distance between the rotor poles — influences the amount of third harmonic voltage produced. The amount of third harmonic voltage generated by the machine also varies with loading. Changes in both real and reactive power alter the amount of third harmonic voltage produced.
Figure 1: Stator Winding Capacitance-to-Ground
Figure 2 illustrates the third harmonic circuit for a large unit connected generator that is high-impedance grounded. The generator stepup (GSU) transformer low-side delta winding provides third harmonic isolation from the transmission system. Note that it is assumed the low-side generator breaker is open and the machine is running at full speed (that is, no load) for the purpose of the calculations.
The distributed C g is represented as an equivalent pi-section divided between the system and neutral sides of the stator windings. The system side has additional external capacitance (C x) from the surge capacitor, isophase bus, and auxiliary transformer. Note that only the capacitance of the surge capacitor is considered on the system side for the following calculations since it is assumed that the low-side generator breaker is open. The neutral resistor (RN) is reflected to the primary.
3V03 and VN3 are measured by the generator relay, while VG3 is calculated using those two
2: Stator Winding Capacitance-to-Ground
values. Note that the terms 3V03 and 3V0Z3 are used interchangeably.
VG3 ≡ Total third harmonic voltage (source)
3V03 ≡ Third harmonic voltage drop across terminal capacitance
VN3 ≡ Third harmonic voltage drop across ZN
Third Harmonic Voltage Profile
Figure 3 shows the third harmonic voltage profile captured by the generator protection relay during startup.
Figure 3: Third Harmonic Voltage Profile Captured During Startup
Table 1: Third Harmonic Voltage Profile
Figure
RELAY COLUMN
Table 1 shows the third harmonic voltage profile captured by the generator protection relay during a startup.
CALCULATIONS
Figure 4 represents the total third harmonic current flow through the neutral impedance ZN, which is the parallel combination of the neutral resistor RN and stator capacitance-toground (Cg/2). IT is the total current while IR is the resistive component and IC is the capacitive component.
3RNpri
Figure 4: Third Harmonic Neutral Circuit IR IC
First, calculate the circuit impedance to solve for C g : (neutral side reactance)
(third harmonic frequency)
(system side reactance)
Next, calculate the third harmonic neutral voltage VN3 dropped across the neutral grounding resistor (NGR) and stator capacitance-to-ground:
(surge capacitance) RNpri = NG2•RN NG = Grounding transformer turns ratio (66.67)
VN3
RN = Neutral grounding resistor (0.25 W)
RNpri = (66.67)2•(0.25 Ω) = 1111.222 Ω primary
Set equations [1] and [2] equal and solve for ZCg.
Equation [3] solves for Cg, the stator capacitance-to-ground.
RELAY COLUMN
CONCLUSION
This article demonstrates how to use a numerical generator protection relay profile capability to measure the stator ground capacitance of a large combustion turbine generator. Increases in the measurement over time are indicative of contamination buildup that provide guidance on when maintenance should be performed.
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.
Newest Circuit Breaker Test Set: PI-5000 Gen2
The most rugged & reliable portable high-current circuit breaker tester available
BUILT FOR FIELD SERVICE
Modular design provides unparalleled output capabilities in a portable unit.
MAXIMIZING TESTING FLEXIBILITY
Two-piece modular design provides unequaled portability in environments that are difficult to access, such as rooftops or basements.
INTUITIVE & EASY TO USE
Simple user interface of the proven MAC-21 controller, detachable interconnect pieces, and Cam-Lok mains connections make the PI-5000 Gen2 easy to set up, use, and transport to the next job.
Trusted by professionals nationwide and shipping now. Contact ETI Precision for a PI-5000 Gen2 quote today.
NEW SAFETY ENHANCEMENTS
Upgrades and improvements include protecting your equipment and technicians from accidental mains over-voltage situations.
ACHIEVE PEAK OUTPUT OF 60,000A
Continuous output of 4,000A and peak output of 60,000A allows efficient testing for a wide variety of circuit breakers including draw-out and molded-case.
MEDIUMVOLTAGE CABLE INSTALLATION ISSUES
BY MOSE RAMIEH, CBS Field Services
Properly installed and maintained medium-voltage cable is highly reliable, and when properly installed, there is little or no maintenance to be performed. Yes, you should keep the terminations clean, and yes, you can perform a periodic VLF with tan delta or partial discharge test to trend degradation over the years. However, in my experience, the No. 1 reason cables fail is poor installation practices. Many factors that can impact the quality of cable installation come into play.
WORKING AROUND DESIGN OF THE GEAR
I still remember one of the first medium-voltage cable faults I cleaned up. It was at a hospital that had recently modified the system to add a new medium-voltage air switch lineup. The installation was in an existing room and required that the conductors enter the switches from the top of the gear. While top-entry gear is nothing new, in this situation, the switchgear as built and delivered to the site was designed to be bottom-fed.
Now, who was to blame for this design issue isn’t relevant to the story, but what happened next was that a well-intentioned electrical contractor found a way around (or should I say through) the switchgear design issue. They decided to route the medium-voltage cables between the switchgear bus to the termination point at the bottom of the switch (see my wonderful sketch in Figure 1).
Figure 1: Sketch of Bottom-Fed Switch
The problem with this solution is that it places a grounded plane (the cable’s shield) near the energized bus work. To further illustrate the contractor’s misconception, when I asked why he thought it was acceptable to route the cable in this manner, his response was, “Well, isn’t that insulated cable rated for the voltage?” Where was the NETA testing company in this situation, you might be asking.
A couple of things to consider:
1. Technicians commonly show up to test cables and nothing else. If this is the task, their vision of the remainder of the power system might not be in focus. They have a blind spot to other portions of the system.
2. Were the cables routed through the bus before or after the test? If they were routed in that manner at the time of testing, then we could argue that the technician should have caught this glaring issue. Of course, that assumes the
technician knows enough about cable construction and that he or she notifies the contractor of the issue and stands firm against energizing the system.
3. Finally, there is the all-too-human factor of “doing the best we can to make it work.” It’s well-intentioned, tragically flawed, and easier than suffering the consequences of stopping the job to find a better solution — at least until the cable causes a switchgear failure.
Another equipment design issue that can create challenges in making proper terminations is pad-mounted equipment that limits the distance between the concrete floor and the connection point. This leads to a choice of working in an uncomfortable, hunched-over body position or pulling the cable outside the enclosure where additional length (slack) then must be routed and wrapped back into the gear. This creates problems with bend radius and ensuring that the slack remains clear of
Figure 2: Metering Cabinet
IN THE FIELD
energized components as noted in the previous example.
The pad-mounted utility metering cabinet in Figure 2 is an example of a challenging situation I faced in Florida. While there seemed to be plenty of room to make the cables up, it proved very difficult to route the 750 MCM
cable to the various termination points from the conduit entries. Had the designer of the installation been aware of this challenge, a trough could have been built/formed under the switch (Figure 3) allowing more movement and easier sweeps of this very stiff cable.
Figure 4 is another example of a poorly designed plan for how cables would be terminated. Note that there is literally zero room to make the Pfister terminations required on this piece of gear. I wish I knew how this cable was finally terminated, but I left this project long before the cables were completed.
MANAGING EXTRA CABLE LENGTH
There is also the “let’s leave some slack in case I make a mistake in my cable cutbacks” issue. While cable terminators are human and do make mistakes, they should be skilled (if not certified) craftsmen in this specialized talent. This craftmanship extends to being able to plan their work and foresee and manage the challenges in varied installation situations. To be clear, leaving some slack is a fine plan, so long as it doesn’t create issues with managing the extra cable. The pad mount transformer in Figure 5 is a perfect example of extra slack gone horribly wrong.
INSTALLATION PRACTICES
One of the worst installations I’ve even seen was at a chemical plant that was adding additional capacity. Our team was hired by the electrical contractor to test the new cable installations. Our initial test of the cables indicated a termination issue. The issue was sufficiently bad to trip the VLF test set before getting to the withstand voltage. This was followed by an uncomfortable conversation with the contractor that they were going to need to pull new cable to correct the issue.
As with any failed cable test, the first thing to check is the cutbacks of the cable made during the process of installing terminations. Removing terminations costs money and time, and if you are wrong, you can expect you will be asked to pay for those losses. In this case,
Figure 3: Trough Offering Additional Space to Turn and Route Cables
Figure 4: No Room for Terminations
we were not wrong. Figure 6 clearly shows the poor installation made by an inexperienced and rushed electrician.
Note that this photo was taken after surgically removing the terminations to avoid any alteration of what we discovered. The defects were numerous and included:
• Poor cutbacks
• Deep cuts into the cable installation at the semi-con cutback
• Failure to install the constant tension spring, which allowed the braided shield to be pulled out of place toward the cable lug when the core was removed from the stress cone
Admittedly, it is rare to find a cable this poorly constructed, but I assure you that it can and does happen.
WATER INTRUSION IN THE CONDUCTOR
Another rare installation issue technicians need to be aware of involves outdoor terminations, which are typically connected to pole-mounted cutout switches with mechanical lugs. An inexperienced terminator who is not provided with all the proper materials may leave bare conductors exposed for installation into the lug (Figure 7). On the surface, you may not see an issue with this practice, but consider that this
Figure 5: Excessive Slack
Figure 6: Exceptionally Poor Cutbacks
outdoor installation is exposed to rain. Over the course of time, rain will migrate into the cable conductor.
The water will build up and create a water column going up the pole, and this water column is capable of building up enough pressure to push loadbreak elbows off their bushings at the pad-mounted equipment that is often located at the other end.
Another situation I encountered was on a deadbreak connection. A similar bare conductor installation at the pole pushed water into the deadbreak. When the water froze, it expanded the deadbreak to the point that it failed catastrophically.
ADDING NEW CABLES TO AN EXISTING INSTALLATION
In a recent situation, new cables were added to connect an existing switch to a new switch being installed in an expansion. The old termination required a longer cutback to the cable shield than the new termination. On the surface, it didn’t seem like a big issue. However, this mismatch of the ground shield (Figure 8) placed a grounded point adjacent to the unshielded portion of the existing cable.
Over time, the ground shield on the new cables will create electrical stresses that could eventually cause a failure of the existing cable. The solution to this issue is to modify the new cable cutbacks so that the shield grounds are at the same position (red arrow). The additional exposed insulation this change creates in the new cable can then be wrapped with silicon splicing tape (blue arrow) to complete the moisture barrier at the end of the cable.
CONCLUSION
If you want to create reliable medium-voltage cable systems, learn from these life lessons:
• Never allow medium-voltage cable to be adjacent to energized components.
• Avoid excessive slack in cable systems.
Figure 7: Cable Allowing Water Intrusion
Figure 8: Mismatched Ground Shields
• Plan ahead for cable sweep and bend radius management.
• Trust your test equipment.
• Properly install terminations in accordance with the manufacturer’s instructions.
And as Dad always said, “Keep it clean, read the instructions, measure twice, and keep it clean.”
Mose Ramieh is Vice President, Business Development at CBS Field Services. A former Navy man, Texas Longhorn, Vlogger, CrossFit enthusiast, and slow-cigar-smoking champion, Mose has been in the electrical testing industry for 24 years. He is a Level IV NETA Technician with an eye for simplicity and utilizing the KISS principle in the execution of acceptance and maintenance testing. Over the years, he has held positions at four companies ranging from field service technician, operations, sales, business development, and company owner. To this day, he claims he is on call 24/7/365 to assist anyone with an electrical challenge. That includes you, so be sure to connect with him on the socials.
BECOME A NETA ALLIANCE PARTNER
If your company is focused on problem-solving and innovating for the betterment of the electrical power services industry, become a NETA Alliance Partner. The NETA Alliance Program is designed for those that work in the electrical testing industry and share in our mission of setting the highest safety standards in the world.
Annual Member + Alliance Meeting
Annual Member + Alliance Luncheon
Meeting of the Minds
Ability to apply to participate in the Technical Working Committee Activities
Discounted PowerTest Registration
50% off one ANSI/NETA Standard ($138 value)
30% off NETA Bookstore Purchases
30% off NETA Training and SPTS Courses
NETA World Journal ($40 value)
Post press releases
Share information about your services through our distribution channels
PROGRAMS, POLICIES, MANUALS, PROCEDURES, AND TRAINING
BY PAUL CHAMBERLAIN, American Electrical Testing Co.
Several regulatory agencies direct which documents are required when performing a company’s tasks. In some cases, federal and state requirements must be adhered to for the same task or hazard. For example, in the United States, the U.S. Environmental Protection Agency (US EPA) and state environmental agencies such as the Massachusetts Department of Environmental Protection (MA DEP) regulate potential environmental impacts that can occur during performance of a task. For workplace safety, requirements are handed down from the U.S. Department of Labor (DOL) and its subdepartment, the Occupational Safety and Health Administration (OSHA). Canada has its own version of OSHA — the Canadian Centre for Occupational Health and Safety, or CCOHS.
Currently, 22 U.S. states have their own stateapproved occupational safety agency with regulatory oversight over private business:
• Alaska
• Arizona
• California
• Hawaii
• Indiana
• Iowa
• Kentucky
• Maryland
• Michigan
• Minnesota
• Nevada
• New Mexico
• North Carolina
• Oregon
• Puerto Rico
• South Carolina
• Tennessee
• Utah
• Vermont
• Virginia
• Washington
• Wyoming
This article explores the typical safety documents required to comply with U.S. federal OSHA standards. Every company should familiarize itself with these requirements and comply with any other regulations that apply to their business.
GUIDELINES
OSHA provides guides for developing safety programs. The format depends on whether the requirement is applicable to the specific work being performed. These guides can be found on the OSHA.gov website: https://www.osha. gov/employers Canadian employers regulated by CCOHS can find guidelines and samples at https://www.ccohs.ca/topics/legislation/programs/.
Before developing a program, policy, plan, or procedure — and the training that goes with them — it is important for a company to know the scope of work and where the work will occur, as the requirements change depending on work location. For example, U.S. work performed in a construction setting might not have the same requirements as work performed in a general industry setting. Additionally, not all OSHA requirements are applicable to a specific setting. For example, if the company performs entry into enclosed
spaces only, but does not enter into confined spaces that require a permit, the program should indicate that and training must include that information. The program would not need to cover entry into permit-requiring confined spaces, even though enclosed and confined spaces are found in the same OSHA regulation.
JOB HAZARD ANALYSIS
A job hazard analysis (JHA) is an important tool to analyze the work to be performed and the hazards associated with each step in performing the work. Companies should take the time to create JHAs to better understand which hazards their employees will encounter. In some instances, such as in construction, a JHA is required per OSHA. JHAs can be known by other names, such as a job safety analysis (JSA) or even just a hazard analysis (HA), but they all have essentially the same outcome: identification of known hazards associated with completion of a task. Pre-job briefs, if detailed enough, can be a suitable substitute for a JHA. To view a sample OSHA JHA, visit https://bit.ly/3fuz7Vf
Once a JHA has been completed, known hazards will be identified. The completed JHA should be reviewed with all personnel performing the work. Once a hazard is identified, the appropriate OSHA or CCOHS regulation can aid in creating a program, policy, procedure, or training.
POLICIES
Policies can be short, sweet, and to the point. Think of these as a description sheet for a task or hazard. They are a position statement on how a company will address an issue, whether it is safety, environmental, procedural, or even human resource-related. It is usually not heavily detailed, but can be if the topic can be covered succinctly, and it references other pertinent information. For example, a policy for respiratory protection might only state when wearing a respirator would be necessary and that the company provides the respirator and training. If a topic requires greater detail, it is usually fully documented in a procedure or
SAFETY CORNER
program. Policies outline who and when but are not detailed when it comes to how the work is accomplished. Policies may also refer to what can occur should a task not be completed as required.
PROGRAMS
Programs are designed for extensive detail. Think of a program as a detailed instruction sheet, including all components necessary for the work. A program highlights the requirements as set forth by the regulatory agency and reviews the training necessary prior to beginning the task. It gets into the specifics of who, what, where, when, why, and how. The program references the documents (i.e., inspection forms) required to comply with the regulations.
Programs are fairly extensive, and often mimic a regulation line for line to ensure compliance. For example, a program states what employees are required to do, where they can find information on performing the task, and how to remain in compliance with requirements. It also reviews what the company is required to perform to maintain compliance with the regulation. Each applicable hazard usually has its own program. To continue the example, a respiratory protection program details the training, which areas require a respirator, how to determine whether a respirator is required, how to select the type of respirator, how to maintain a respirator, medical clearances necessary for use, and even how an employee is issued a respirator.
PROCEDURES
Procedures are very task-oriented. Think of a procedure as a detailed step within a set of instructions that is very specific for each task performed. It references requirements as stated in programs, and give physical direction on how a task is to be performed line for line. It also generally discusses the hazards associated with each step of performing the task. Continuing the example again, a procedure would detail how to maintain a respirator. The program will state that a respirator is to be cleaned daily, but the procedure will tell
SAFETY CORNER
the employee in specific detail how to properly clean the respirator.
MANUALS
Think of these as a general overview. A manual is usually designed as a reference for a program. A manual contains only the information pertinent to how an employee is to comply with all of the company’s requirements. In some cases, a company may replace individual programs with a manual, essentially making the manual a collection of programs — each chapter becoming its own program. This depends on how much information is being relayed. If the chapter is extensive, or the regulation the company is attempting to comply with contains requirements that do not apply to all of the company’s tasks, then it would make sense to summarize only the information critical to how the company will comply. A separate program would be created detailing the specifics of what is required for compliance, what is not, and why. Continuing the previous example, if the employee is required to use a new respirator, a manual may just tell them where to obtain one. Details as far as types used or any requirements for type used would be contained in the program.
TRAINING
Training must cover all information the employee needs to know to reduce or mitigate the hazard while performing the task. The employee is not required to review the applicable program, but some companies choose to perform training in this manner. Since a program is written to reflect the relevant regulation, this can be pretty boring. Because of this, some companies choose to train using other methods, such as presentations, videos, or even just on-the-job (OJT) training.
However, the company must ensure the employee is competent to perform the task before they perform the task. In some cases, competency must be observed and refreshed on a regular basis, depending on the regulatory requirement. To document competency, a company can use quizzes or tests or even simple sign-off sheets indicating that the employee reviewed and understood the information. No matter how training is conducted, this documentation must be completed and maintained on file so long as the employee works at that company.
CONCLUSION
Companies must comply with many requirements, and there are many ways to go about complying with those regulations. But no matter how a company chooses to comply, it cannot avoid the eventual paperwork and documents that must be created to reach and maintain compliance. A JHA is a good starting point for determining which hazards are present when performing a job. Once you have identified the hazard, you can more easily identify the regulation created to mitigate the hazard. Once a company fully complies with the regulation and informs the employee of those requirements, it will go a long way to preventing injuries. After all, knowledge is power, and the more an employee knows about a hazard and how to mitigate it, the less likely it is for an employee to be injured by that hazard.
Paul Chamberlain has been the Safety Manager for American Electrical Testing Co. LLC since 2009. He has been in the safety field since 1998, working for various companies and in various industries. Paul received a BS from the Massachusetts Maritime Academy.
138
OFF-LINE PARTIAL DISCHARGE CABLE TESTING
BY VIRGINIA BALITSKI, Magna IV Engineering
NETA Certified Technicians must continually adjust to advancing technology and diagnostic testing techniques. Over the years, cable testing has advanced to where multiple testing methods can be selected.
After careful consideration of system requirements, a site owner may choose off-line partial discharge (PD) testing as one of their cable testing methods. This quiz looks at some details on partial discharge testing of cables.
1. What is partial discharge?
a. A localized electrical discharge that only partially bridges the insulation
b. Complete loss of a voltage signal
c. A low-frequency (0.1Hz) failure
d. Severe arcing that exists inside insulators that is usually detected by IR scanning
2. Which of the following cables are suitable for off-line PD testing?
a. 3-conductor tape-shielded cable
b. 1-conductor concentric neutral cable
c. Non-shielded cable
d. a & b
3. What other limitations might make offline PD testing of a cable not feasible?
a. Cable length
b. Electrical noise on site
c. Resistive shield connections at the termination
d. All of the above
4. What are the typical test set components of an off-line PD test set?
a. PD measuring instrument, 60Hz hipot, and series capacitor
b. PD measuring instrument only
c. PD measuring instrument, VLF hipot, and a parallel coupling capacitor
d. PD measuring instrument, DC hipot, and a parallel resistor
See answers on page 123.
No.
5. What units are usually used to quantify PD activity?
a. Micro-amps
b. Pico-coulombs
c. Giga-ohms
d. Ampere-hour
6. Do all data points from off-line testing indicate PD activity?
a. Yes. The analyzer is filtered for highfrequency signals, so any data is concerning.
b. No. High-frequency signals are recorded, including electrical noise and corona discharges.
c. No. You will almost always receive mostly corona discharge signals, and only major issues will make it through.
d. Yes. Any concerning PD will produce a vast number of data points.
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 has achieved NETA level 4 Senior Technician Certification. She has since dedicated her time to the advancement of training and safety in the electrical industry. Virginia is a Certified Engineering Technologist through ASET – The Association of Science & Engineering Technology Professionals of Alberta. She serves on NETA’s Board of Directors, is the current Vice-Chair of CSA Z462, Workplace Electrical Safety, and is a member of the NFPA 70E, Electrical Safety in the Workplace Technical Committee.
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.
GROUND ENHANCEMENTS: AN ANSWER TO DIFFICULT GROUNDING SITUATIONS
BY JEFF JOWETT, Megger
As part of the electrification of a facility, it is commonly thought that merely connecting the system to a driven ground rod means that the building is grounded. It’s not that simple. By pure luck, such an approach may indeed work. But the considerable value of the building, the efficiency of operation, the wealth of information and knowledge that is stored and transferred, and most of all the safety of personnel should not be left to luck.
Considerable variables are involved in establishing a good ground — that is to say, a ground of sufficiently low resistance so that the electrical system will operate at desirable or specified levels of efficiency and safety. To put it into perspective, the majority of electrical work is done on copper, a well-known quantity in terms of specifications and properties. Even
Table 1: Typical Soil Resistivity
– 10,000
insulating materials, though much more varied than copper, are composed of well-known formulae.
By contrast, soil resistivities (Table 1) can range in value from a few hundred to a million ohmcentimeters (Ω-cm). Indeed, on the low end of this scale, simply driving an 8- or 10-foot rod may be sufficient. But for more difficult soil types and local conditions, reaching specification may be a real challenge.
GROUNDING MATERIALS
The first line of defense is the grounding electrode — the metal that is installed in the earth to which the grounding conductor or conductors are attached. Fault current, it is hoped, will find this the path of least resistance in going to ground and back to the utility that generated it or, in the case of lightning, equilibrium with the clouds. This is obviously preferable to traveling through equipment — or worse, people. Putting more metal in the earth is the most common remedy. The more contact the electrode has with
the surrounding soil, the lower the resistance. Imagine a mob of people escaping a building fire; two doors are better than one.
Two general methods of getting more metal into the earth are to a) go deeper or b) laterally expand the size of the grid. There are practical arguments on both sides, but overall, going deeper is preferable…especially if you hit water table. Of course, water is a good conductor, and water table can provide a constant lowresistance path. The water table can drop over time, however, so periodic maintenance checks of the rod’s resistance must be taken (Figure 1).
The major disadvantage to deep-driven rods is that they are comparatively expensive. They can be installed by coupling additional rods and driving the electrode deeper, but in more difficult hard-ground terrain, it may be necessary to drill a bore hole and backfill it with a conductive material around the rod.
An alternative to a deep-driven rod is to expand the electrode laterally. The easiest way to do this is to add more rods, not coupled on top of each other as in deep-driven, but expanded into an interconnected parallel grid. Additional rods should always be spaced at least as far apart as they are deep. This is so their electrical fields do not overlap and cause the two to begin performing as a single rod. This defeats the purpose of the added rod.
Generally, a second rod will decrease the resistance by about 40%. After that, though, it’s not so easy. Additional rods yield progressively smaller decrements until the exercise becomes counterproductive. Nonetheless, it is common practice to continually drive and test until spec is achieved.
Metallic grounding meshes or horizontal bars welded into a grid can also be used. These may be useful in areas of shallow bedrock where extensive excavation is prohibitive. But in cold climates, be sure any such structures can be buried below the frost line. Freezing immobilizes the dissipation of fault currents just as it does in a car battery.
OTHER MATERIALS
Thus far we’ve examined making the electrode larger or driving it deeper. These are the most common methods of grounding an electrical system to meet an imposed specification. But with the enormous variability of soil resistivity and local conditions, these methods can be challenged and may not be adequate. A number of specializations have been devised to meet the worst of conditions. One has already been mentioned: drilling a bore hole
Figure 1: Maintenance Testing a Ground Rod
for a deep-driven rod and backfilling it with conductive material.
One of the most widely used materials is bentonite. Named for its discovery near Ft. Benton, Montana, bentonite is a mined material formed by the weathering of volcanic ash in seawater. It has the useful property of holding water molecules in a lattice structure that retards desiccation (unlike moisture in soil), which thereby maintains the grounding electrode in a steady and favorable environment for passage of current. Under severe conditions, bentonite may develop cracks and recede from the electrode, so synthetic variants are also available.
Ground enhancement material composed of Portland cement and a carbon-based conductive material (commonly known as GEM) is also widely used.
Improved materials for surrounding or encasing a ground electrode have more recently been developed. These appear on the market under various trade names, each with its own formulation aimed at promoting conductivity while retarding desiccation, cracking, and reduced contact with the electrode.
A representative formulation is based on natural clay, not carbon-based, and with neutral pH so as not to corrode the electrode even
under prolonged contact. These materials can be hygroscopic, capturing moisture from the surrounding soil and holding it in a conductive lattice. A resistivity of 0.6 Ω/m is characteristic. Such materials can exhibit a capacitive effect in absorbing the high rise time of lightning strikes. A representative specification is 1,682 V/688 A for 500 ms. An NSF Standard 60 rating indicates to inspectors that the material is in conformance with environmental protection regulations. Systems have been known to remain effective for 50 years. Theft reduction is an added benefit, as the hardened conductive material makes extraction difficult.
CHEMICAL TREATMENTS
The soil itself can be chemically treated. Lowering the resistivity around the ground rod will promote current flow and lower the resistance of the rod to surrounding soil, possibly bringing it within the desired specification. Common materials are magnesium sulfate, copper sulfate, and rock salt. They can be applied in a trench dug around the electrode (Figure 2).
But there are caveats. Rain and other weather conditions will slowly leach away the applied materials, so they must be regularly assessed and replenished. Depending on the porosity of the soil and amount of rainfall, it could be years before the treatment needs to be replaced.
Figure 2: Application of Grounding Materials
Chemical treatments can also attack the electrode; magnesium sulfate is the least corrosive. Soluble sulfates can also attack concrete, so it must be kept away from building foundations. This poses a potential problem with lightning protection, where a short, straight path directly into the earth is most effective. EPA and local environmental regulations must also be considered. Industry standard parameters are covered in IEC Standard 62561-7, Part 7: Regulations for Earthing Enhancing Compounds.
ELECTROLYTIC GROUNDING SYSTEMS
Also in use are electrolytic grounding systems, where the rod itself is an active part of its environment. Hollow rods with breather holes extract moisture from the environment, convert it to salt water to provide greater conductivity, and gradually leach it into the surrounding environment to create a constant low-resistance path into the soil (Figure 3). More than replenishing soil moisture, the system creates electrolytic roots that further
enhance the capability of the electrode to dissipate dangerous fault currents safely.
These systems are available as vertical rods for deep-driven electrodes and L-shaped rods for shallow bedrock where deep-driven electrodes would be cost prohibitive.
SOFTWARE SOLUTIONS
A more efficient and less time-consuming method is to design the system beforehand using dedicated software. Some are available at no charge from companies offering grounding materials such as rods and meshes. A fourterminal ground tester is needed to measure the resistivity of the local soil. The data will be entered in the software, along with the resistance value the grid must meet, plus a few qualifying questions. The software will then design and display an appropriate system: x number of rods laid out in a pattern.
CONCLUSION
With the enormous range of earth types and soil resistivities alluded to in the beginning
Figure 3: Specialized Rods Extract Moisture from the Environment
of this article, any given site may or may not require heroic efforts to install an effective ground. However, such instances are not uncommon.
Many common soil conditions preclude simply driving a rod. For example, coastal loams such as those found along the Atlantic seaboard tend to be forgiving, but rocky and mountainous soils often call for more elaborate systems. Sandy soils such as in deserts and along seashores are also difficult. Grains of sand tend to have microscopic air pockets that do not conduct well. Sand does not retain water well and, in the passage to greater depths, electrolytic minerals that aid current flow get washed away.
Therefore, poor grounding conditions are not at all uncommon and may call for special
accommodations in designing and installing the electrode. Don’t just drive a rod and walk away. Take a resistivity measurement first, and hope that it’s low.
REFERENCE
XIT Grounding. Product Catalog, Version 2022V1, 2022. Accessed at https://vfclp.com/ lyncole/.
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.
First released over 15 years ago, the Schneider MasterPact NW low voltage circuit breaker has a large global install base. When the Micrologic trip unit or sensors fail, start thinking AC-PRO-NW™.
AC-PRO-NW™ brings all of the safety and reliability features you trust from URC to the MasterPact NW family of circuit breakers, such as QUICK-TRIP® arc flash reduction and Sluggish Breaker® We also included some new features as well, such as delayed open/close and wireless communications.
Visit to receive your early adopter discount!
* For a limited time
MEASURING PARTIAL DISCHARGE ON MEDIUM-VOLTAGE CABLES
BY JASON AARON and JOSEPH AGUIRRE, Megger
Partial discharge (PD) testing is a form of diagnostic testing for power cable systems. PD testing of medium- and high-voltage cable applications is beneficial when paired with other cable tests including very-low frequency (VLF) and tan delta (TD) tests. Partial discharge testing is another way to judge a cable’s insulation vitality or ability to endure electrical stress. Utilizing PD as an off-line testing technique can identify problematic defects long before a fault situation would create an in-service outage.
In addition to using partial discharge testing for condition-based maintenance testing for aged cables, it can be used for acceptance testing and commissioning. It is possible to considerably reduce the costs of maintenance and network renewal with the help of cable diagnostic techniques. More informed decisions eliminate unnecessary cable repairs or renewals, which leads to an increase in a cable’s life expectancy.
Conducting a PD test during commissioning and acceptance can help find defects before the cable is placed in service, which will also increase reliability and verify the workmanship of the cable installation.
Another means of locating PD is continuous on-line monitoring, which can be established to provide advanced warning that a cable’s
insulation is deteriorating while in service. Off-line PD resolves many of on-line PD’s limitations; however, this method requires the cable to be de-energized and removed from service during a scheduled outage. It can also be used as a quality check in a forced outage situation after repairs are performed and before the cable is placed back into service.
OFF-LINE PD TESTING
When using off-line PD testing, a separate power supply is coupled to the cable under test. Thus, the PD test can be accomplished at various levels of rated voltage (Uo) from 0.5 to 1.7 times on aged cables and up to 2 times on new cables. Uo refers to the voltage magnitude as a multiple of the rated operating voltage in reference to the phase to ground voltage. PD should not occur below the operating voltage of the cable. Before testing can commence, a calibration measurement must be conducted using a known apparent charge, typically starting at 1 nC (nanocoulomb). The coulomb magnitude can be adjusted to determine a suitable bandwidth, which is dependent on the overall length of the cable. This ensures reproducible measurements and a reliable evaluation of comparable data.
A disturbance level or background noise measurement should also be taken to give a baseline of the PD measuring circuit. The
partial discharge testing procedure should start at 0.5 times Uo and rise by 0.1 to 0.2 until PD is discovered. This is referred to as the partial discharge inception voltage (PDIV). If the PDIV is close to operating voltage or Uo, this would cause immediate concern for replacement or repair, as necessary. Once the PDIV is achieved, the voltage should be decreased until the partial discharge has been extinguished, known as PDEV. The measurement of PDEV is critical as it will determine whether partial discharge will occur on the cable under normal operating conditions if an over-voltage condition arises, thus leading to the situation where PD activity is continuously working to degrade the cable’s insulation. The effects can only be reversed if the cable is de-energized and returned to service.
In contrast, if the cables do not display PD up to the maximum applied voltage, the testing can be increased to ensure no partial discharges occur. If PD has begun at a lower interval of 1.1 or 1.2 Uo, the specimen can be placed in service, but the critical state must be noted for future replacement or repairs.
PD testing requires an AC waveform to function, for example, power frequency (60 Hz, 50 Hz) or very-low-frequency (VLF). Various VLF waveforms are used in cable testing, including VLF sinusoidal, VLF cosine rectangular (CR), and damped ac (DAC). VLF sinusoidal and cosine rectangular are continuous waveforms, while DAC is a decaying waveform consisting of discreet pulses that may have significant time between pulses on longer cables due to the increased capacitive load.
PARTIAL DISCHARGE IN CABLES
The measurement of partial discharge (PD) activity is a diagnostic method used to evaluate insulation quality. These measurements can be performed on cables, switchgear, transformers, or other types of electrical power equipment. Partial discharges are localized electrical discharges or sparks that can occur between
Figure 1: Typical Shielded Cable Construction
conductors, such as the conductor and metallic sheath of a typical power cable (Figure 1), when the electrical insulation begins to deteriorate. However, these defects are not severe enough to bridge the insulation material to cause a short circuit condition to fail the cable.
PD activity is typically the first indicator of insulation deterioration within an insulation system. This is especially true for cables and cable joints (splices) where 89% and 91% of failures, respectively, are attributed to breakdown of the insulation per IEEE Gold Book , Table 36. The measurement of this activity can be analyzed to determine the type, magnitude, location, and applied voltage. These results can be used to “predict with a high level of confidence that a given cable is in very poor condition and is likely to fail in the near future.” (IEEE 400.3)
CABLE DEFECTS
Three types of defects are typically found in power cables: void, surface, and corona discharges.
Void discharges (Figure 2) occur when a cavity is present in solid insulation.
Surface discharges (Figure 3) are seen when PD events occur on the surface or interfaces of surfaces where there is physical damage. While there are many sources of surface PD, some examples are deep cuts where two layers of a cable meet due to poor workmanship such as on the semiconducting and insulating layers or improper positioning of stress relief at a termination or splice.
Corona discharges (Figure 4) occur when the electrical field of an energized conductor exceeds the dielectric strength of a gas creating a partial discharge. These types of discharges can be seen in a cable where sharp edges exist due to workmanship errors while installing a termination or splice. Another instance where a cable may experience corona discharges is in an air-filled void. In this case, the electrical stress will cause partial discharges across the air within the void.
These deformities can exist for many reasons (Figure 5). However, they usually form when existing water trees convert to conductive electrical trees and begin to destroy a cable’s insulation.
Figure 2: Equivalent Circuit of Dielectric with Void
Figure 3: Surface Discharge
Figure 4: Corona Discharge Model
The difference of potential within the void causes a point of concentrated electrical stress (Figure 6) that will continually deteriorate the dielectric strength of the insulation until it reaches total failure.
APPLIED WAVEFORMS FOR PD MEASUREMENTS
Utilizing these off-line PD wave shapes for testing the VLF sinusoidal waveform can also be used as an initial wave shape for finding PD.
VLF Sinusoidal
VLF sinusoidal imitates the same wave shape as line frequency (50 Hz, 60 Hz), having rms
and peak voltages; however, it is slowed down to 0.1 Hz. This waveform is recognized for VLF withstand testing per IEEE 400.2. VLF sinusoidal is a prolonged changing wave that takes 10,000 ms or 10 seconds to produce one entire cycle or a polarity crossover every 5,000 ms (about 5 seconds).
VLF Cosine Rectangular
A more advanced form of PD testing requires VLF cosine rectangular (CR) to be comparable to VLF sinusoidal. However, it does not have a rms voltage; instead, it only uses peak voltage. It may look identical to a square wave, but it is not a simple square wave. CR maintains a 5-second DC hold followed by a sinusoidal transition into a 5-second hold of the opposite DC polarity. These back-and-forth transitions continue for the entirety of the test. The DC holds for a very short time and does not damage the cable’s insulation as continuous DC testing does because the polarity interval is brief, thus emulating an AC sinewave with only 5 seconds +/- peak voltages.
During PD testing, the CR transition uses the cable’s capacitance and a fixed inductor within the test equipment to create a resonance circuit. When the polarity transitions occur,
Figure 5: Common Cable Defects
Figure 6: Electrical Field Distribution
the circuit resonates one-half cycle applying a diode to stop the polarity switch. VLF cosine rectangular polarity reversal is in the range of 16 ms to 1.6 ms, being similar to the polarity crossover of 60 Hz at 8.3 ms or 50 Hz at 10 ms. It therefore produces a considerably closer transition to line frequency than 5,000 ms (about 5 seconds) VLF sinusoidal waveform that is 1,000 times slower.
Damped AC
Another advanced technique is damped AC, which sets up a resonance circuit similar to CR. However, DAC allows the voltage to exponentially decay through resistive losses of the circuit. It gives DAC a frequency closer to that of line frequency range (30 to 300 hz). The greater the frequency, the greater the probability that PD could be measured and the lower the PDIV can be. The voltage that is produced is only on the cable for a very short duration and uses a fluctuating waveform for only a few hundred milliseconds, making DAC the gentlest
waveform for off-line PD testing of cables. VLF cosine rectangular and damped AC have polarity changes closer to line frequency than VLF sinusoidal. This increases the likelihood of finding PD in the cable. Solely utilizing VLF sinusoidal for PD testing may not represent the actual condition of the cable when testing.
PDIV and PDEV
Partial discharge inception voltage (PDIV) is the voltage at which partial discharge activity begins to occur within a defect. PDIV is found by slowly raising the test voltage until PD activity is seen at any point along the cable, whether it be mid-span, a termination, or a splice point. This information is critical to understanding the quality of a cable’s insulation. As of this article, the PDIV thresholds established by U.S. standards do not provide criteria for partial discharge field measurements of in-service cables. Despite the absence of this criteria, this value should be measured and recorded to compare to
future field measurements. Reduced PDIV in comparison to previous tests should be followed by further investigation to determine the insulation quality of a cable.
Partial discharge extinguish voltage (PDEV) is the voltage level at which PD activity is no longer active in the test specimen. This is determined by gradually lowering the applied voltage once PDIV is discovered to a voltage magnitude
where partial discharges are not measured. As with PDIV, field testing criteria has not been established per U.S. standards; however, it is important to note the applied voltage at the point of PDEV. Although established thresholds are not provided for field testing, the PDEV values set forth for factory testing can be used to make general decisions regarding the condition of power cables. For separable connectors (IEEE 386), partial discharge activity should extinguish at 1.3 times above the rated voltage of the cable. Respectively, for cable joints (IEEE 404) and terminations (IEEE 48), the PDEV threshold is 1.5 times the cable’s rated voltage.
PARTIAL DISCHARGE ACTIVITY CHARACTERISTICS
Localization
Localization (Figure 7) is a valuable benefit to partial discharge testing. This can help determine the distance and location to a source of partial discharge in a cable.
PD Localization Mapping
PD localization mapping (Figure 8) gives the engineer or technician a visual indication of the distance to a defect and the discharge magnitude. These results can be compared to the physical layout of the cable to help pinpoint weak areas of a cable.
The test set-up prior to taking any measurements is a key component to ensuring the distance found in the test results is accurate. The velocity factor or propagation of velocity must be properly selected for the type of cable being tested.
PD Activity Magnitude
Partial discharge magnitude is measured in coulombs. This is typically found in the range of picocoulombs (pC) or nanocoulombs (nC). Generally, any measurement seen above 100 pC is considered a cause for concern. However, this is dependent upon other factors, such as the insulation type of the cable being tested, the service age of the cable, and environmental conditions at the time of the test. Results of elevated partial discharge levels should be followed by further investigation to
determine the source of the PD activity. The benefit of partial discharge testing is maximized when included with other types of cable tests as a part of a cable maintenance program.
Benefits and Limitations
One of the greatest benefits of measuring partial discharge on cables is the ability to make maintenance decisions based on the actual condition of the cable. The presence of PD activity will be the first indication of deterioration of the insulation system within a cable. This allows the end user to address these
defects are located through generated highfrequency pulses that are propagated in both directions. During the measurement, the system uses the incoming signals to identify the directly incoming PD pulses and the respective reflections, as was seen in Figure 7.
Cable age and neutral conductor condition are two characteristics that may significantly affect the ability to localize PD activity on a cable. Damaged or corroded neutral conductors could make it exceedingly difficult or impossible to properly localize PD activity within a cable.
THE
March 8 - 12, 2023
Rosen Shingle Creek | Orlando, Florida
Secure your place at the premier electrical maintenance and safety conference and save $100 on your trip to Orlando when you register before December 31, 2022.
PREMIER ELECTRICAL MAINTENANCE AND SAFETY CONFERENCE
that interferes with the high-frequency pulses applied to localize the PD activity.
CONCLUSION
There are numerous choices for the frequency and waveform that is applied during an offline partial discharge test. Testing at a power frequency of 50 or 60 Hz matches operating conditions, but this requires an exceptionally large power supply and is not practical for most field conditions. Testing at lower frequencies such as 0.1 Hz reduces the need for using a large power supply and allows the use of a much smaller, field-friendly unit. Testing can be accomplished utilizing sinusoidal, cosinerectangular, or damped AC waveforms. The choice of cosine-rectangular or damped AC more closely replicates testing at power frequency. These frequencies are experienced during the polarity changes that take place throughout the test where the change in voltage with respect to time occurs at a rate similar to power frequency. Therefore, testing with cosinerectangular or damped AC provides the benefit of a smaller test unit while still sustaining the means for an effective measurement.
REFERENCES
[1] IEEE. IEEE Std. 493-1997, IEEE Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems (Gold Book), pp.1464, 31 August 1998, doi: 10.1109/ IEEESTD.1998.89291.
[2] D. Gowda and A. Desai. “Modeling of Partial Discharge (PD) for Solid Insulation with Void and Building a Hardware Setup to Measure Partial Discharge,” Biennial International Conference on Power and Energy Systems: Towards Sustainable Energy, 2016.
[3] “Guidelines to Perform On-Line Partial Discharge Measurements in Underground Power Cable,” Rugged Monitoring. Accessed 22-Sep-2022 at: https://www. ruggedmonitoring.com/blog/guidelinesto-perform-on-line-partial-dischargemeasurements-in-underground-power-cable/5 e58add9cde096000141a77e.
[4] J. Perkel and J. C. Hernandez-Mejia. NEETRAC, Atlanta, GA, 2016.
[5] D. Götz, F. Petzold, H. Putter, S. Markalous, and M. Stephan. “Localized PRPD Pattern for Defect Recognition on MV and HV Cables,” 2016 IEEE/PES Transmission and Distribution Conference and Exposition (T&D), 2016, pp. 1-4, doi: 10.1109/TDC.2016.752005.
Jason Aaron has been an Applications Engineer with Megger’s Technical Support Group since 2020. He enlisted in the US Marine Corp right after high school and was trained as an Aircraft Technician. After 10 years of service, he worked for Shermco for 8 years performing start-up, maintenance, and commissioning of electrical power systems and substations while earning Level 4 NETA certification. He is an IEEE member focusing in the areas of circuit breaker primary current injection techniques and cable testing, diagnostics, and fault location.
Joseph Aguirre is an Application Engineer at Megger. He specializes in cable testing, diagnostics, and fault location techniques as well as testing of all substation apparatus. Joseph trains end users on the theory and proper use of various pieces of high-voltage testing equipment. He has worked as a maintenance technician, a crew foreman for utility substation maintenance and construction, and as a NETA Certified Technician providing commissioning and maintenance on all substation apparatus and industrial electrical equipment before joining Megger. Joseph earned a BS in industrial technology at the University of Texas Permian Basin and is working toward a graduate degree in energy business and an MBA.
ON-LINE CABLE PD TESTING
BY WILLIAM G. HIGINBOTHAM, EA Technology
Imagine this: A new hyper-scale data center is built in rural New Jersey. It has more than 100 25 KV cables. Six months into operation, a cable termination fails catastrophically, and the forensic investigation determines that termination workmanship was lacking. Partial discharge caused tracking, and the cable flashed over. But that’s not the nightmare scenario. The nightmare scenario is that the same team of jointers terminated all 100 cables, and the owner has no idea if they are all on the edge of failing or if this was the only bad cable.
The owner is left with three options of how they might respond to the crisis:
1. Shut the data center down for weeks or longer and test every cable.
2. Bury their heads in the sand and hope they have no more failures.
3. Test all the cables on-line to identify any suspect cables for further study.
By examining the theory behind on-line testing, this article will show that the third option is the only solution that is both proven and practical at reducing the impact of additional bad terminations down the road.
HISTORY
In previous articles, we have covered how medium-voltage cables — and specifically MV cable terminations — are one of the least reliable parts of any power system. Any time you introduce the possibility of human error into a closed system, you increase the risk of detrimental outcomes.
Cable failures are caused by subpar workmanship at the terminations twothirds of the time. This is due to a variety of reasons, including the fact that doing a field termination is a technically challenging job in a less-than-ideal situation. Minor mistakes can result in hidden problems that may not manifest themselves until years later.
Traditionally, cable testing occurs in two different forms over the life of the cable: precommissioning testing and maintenance testing.
1. Pre-commissioning tests include conductor resistance, insulation resistance, dielectric withstand, tan-delta, and shield continuity. Occasionally, offline VLF-based partial discharge testing is done.
2. Maintenance testing is performed to find problems that can occur or worsen over time. In highly critical applications
where cables can be temporarily removed from service, the same tests performed at commissioning are performed again at slightly reduced values to avoid stressing the cables. While this testing does identify concerns, it is disruptive.
As technology has developed, on-line maintenance testing has emerged as the ideal first line of defense in cable maintenance. On-line maintenance testing is ideal because it does not impact operations and is therefore much less disruptive and less expensive. Clearly, not all pre-commissioning tests can be done online, so there is a tradeoff, but on-line testing can provide information that allows further investigation to be more strategic. On-line testing is typically limited to:
• Conductor resistance is an incredibly important piece of information to have. High resistance can result in failure quite quickly. High resistance is usually a result of poor termination crimping or shear-bolt installation and can worsen over time. This is easily detected on-line using infrared (IR). Using IR to inspect terminations can detect temperature rise due to high resistance. This type of testing is widely used at all voltages.
• On-line partial discharge (PD) testing can find insulation problems that exist upon initial energization as well as those that have developed or worsened over time. This article takes a closer look at on-line PD testing.
Using a Parabolic Ultrasonic Setector on Pad-Mount Cable Terminations
THEORY
Although not widely known, PD in cables is a well-understood phenomenon that can lead to failure at any time. In a power system, if the voltage applied (KV/mm) exceeds a section of the insulation’s ability to withstand it, a discharge occurs. If the problem is the entire insulation system, a total catastrophic discharge occurs. If it’s only part of the insulation, a much smaller, short-duration, low-energy discharge occurs. This discharge damages the insulation further and will lead to a full discharge if left untreated. Detecting partial discharge can allow the asset to be repaired before it fails completely causing loss of load.
If the insulation system is completely homogeneous, the voltage field distribution is perfectly even and the only discharge that can occur is a total flashover. If the insulation is not homogeneous — by that, I mean part of it has higher or lower permittivity — the voltage distribution will not be even. This can occur due to inclusion in the insulation, damage to the insulation during installation, or improper use/construction of terminations to control the electrical field as it transitions out of the cable insulation at connection points on the
equipment. A higher concentration of voltage stress can occur on a smaller, and potentially weaker, part of the insulation. This section with higher stress can then discharge and be damaged.
An example of this can be seen in Figure 1, which shows the distribution of voltage across an insulator with an air-filled void. This void is exposed to a higher-voltage gradient due to the air having lower relative permittivity than the XLPE insulation. If the high-voltage gradient exceeds the withstand of air, partial discharge will occur across the void. The problem is compounded by air having a lower dielectric strength than XPLE.
TOOLS
Thankfully, partial discharge occurring within the insulation or termination of a cable can be detected with a variety of on-line tests:
• Ultrasonic testing. PD near the surface of a cable termination causes air- and structure-borne ultrasonic energy to be released.
• High-frequency current transformer (HFCT) testing. Partial discharge can
Figure 1: Field Distribution with a Void
induce currents down the shield and the cable conductor at higher frequency than the power signals. By attaching an HFCT to the ground shield of a cable, these signals can be identified and monitored.
• Transient earth voltage (TEV) testing. PD currents cause transient voltage spikes on grounded surfaces such as cable compartment doors and cable sheaths. These can be picked up by measuring for voltage transients on the cabinet doors.
• UHF radio detection. PD causes cable terminations to emit broadband UHF spikes. Outdoor terminations are unshielded, and these emissions can be detected.
Any tool used for cable testing should be capable of multiple techniques and must also be synchronized to the power system frequency for higher selectivity. It must include algorithms to filter and discriminate PD in the presence of noise.
PRACTICAL ISSUES
A variety of issues can limit the ability to find PD in cables, but the two most prominent are access to shield ground straps and conducted noise.
In European-type switchgear, cables are terminated such that the ground straps from the shields are outside the HV compartment.
In U.S. ANSI-style switchgear, the straps are entirely inside the HV compartment. This makes application of the HFCT difficult. Permanently installing the HFCT inside the compartment or bringing the grounds straps outside are the most practical solutions. Cables on riser poles are easier since they tend to have exposed grounds.
Noise can play a major role in PD detectability. Highly noisy cables like those attached to inverters or electric arc furnaces can be difficult to test. Temporarily removing the noise source may be necessary. Test equipment has a variety of tools to reduce the impact of noise but there are practical limitations.
LIMITATIONS AND PITFALLS
Additional limitations and potential pitfalls must be considered when running on-line tests.
• The best on-line HFCT test can see only as far as the next point where the shield is grounded. If you have a cable where every splice or manhole location is grounded, you will have to test at each ground location.
• Ideally, you want to test on every ground of each phase conductor separately. Physically, ground connections may make that impossible. A test on the combined ground is possible but it typically has reduced sensitivity. Figure 2 shows a test on a single phase.
Figure 2: Single-Phase Ground Test — No Filter
Figure 3 shows the same test on combined grounds with no filtering. The noise is much greater and hides the PD on the combined ground.
Figure 4 shows the same combined test with some noise filtering applied. The PD is visible, but still not as clean as Figure 2.
TEV testing directly on the sheath of the cable near the termination is a great way to find PD but armored or buried cables can limit the ability to do that test.
Ultrasonic testing of terminations is very useful but well-sealed compartments or outdoor terminations can be a challenge. Contact sensors and ultrasonic dishes can solve these problems.
HFCT testing works well on concentric neutral and tape-shielded cables in good condition. However, if a cable has corrosion in the tape shield overlap, the shield goes from being a continuous, low-impedance path to a long helical coil. This will present higher resistance and much higher impedance to the PD current pulses. This can dramatically shorten the PD detection distance.
Figure 3: Combined Ground Test — No Filter
Figure 4: Combined Ground Test with Filtering
A cable in Saudi Arabia was scanned using an HFCT. Not only was PD present, but the results were so clean the tester could determine the distance to the source. A buried splice was found and confirmed with TEV testing. Once the joint was replaced, the TEV reading showed no PD, confirming the fix. Figure 5 shows the phase-resolved plot and the waveforms that allowed the location to be mapped.
CASE STUDY
A cable that was only 12 months old was scanned using HFCT and TEV. Where there should have been no PD, there were massive readings. The termination was disassembled and a shield and spring were found to be missing. Once corrected and re-energized, the TEV showed a significant drop in level but the PD was not completely gone. Time to look for more damage! Figure 6 shows HFCT and TEV readings.
Figure 5: HFCT Results from Defective Buried Joint
Figure 6: A) HFCT and B) TEV Readings of Bad Termination
A high-voltage asset owner in central Canada has numerous terminations on substation structures. Contamination is building up unevenly on the terminations. This operator is very proactive and periodically does PD surveys of indoor and outdoor assets as part of their regular preventative maintenance.
One of the scanned terminations returned very-high levels of ultrasonic energy. The phaseresolved plots show typical PD results. The source is frequency locked to the power system, and the impulses are occurring twice a cycle, half a cycle apart. The levels are approaching 40 dBuV, which is very high. ANSI/NETA MTS 2019 calls for immediate action on levels greater than 6 dBuV. Figure 7 shows the phase-resolved plot and the contaminated termination.
During the next scheduled outage, the insulators were cleaned and then rescanned. The ultrasonic energy was gone, proving that the discharge was a result of the contamination. Figure 8 shows the phase-resolved plot and termination after thorough cleaning.
Figure 7: A) Phase-Resolved Plot and B) Contaminated Termination
Figure 8: A) Phase-Resolved Plot and B) Termination After Cleaning
William G. Higinbotham has been president of EA Technology LLC since 2013. His responsibilities involve general management of the company, including EA Technology activities in North and South America. William is also responsible for sales, service, support, and training on partial discharge instruments and condition-based asset management. He is the author or co-author of several industry papers. Previously, William was Vice President of RFL Electronics Inc.’s Research and Development Engineering
Group, where his responsibilities included new product development, manufacturing engineering, and technical support. He is an IEEE Senior Member and is active in the IEEE Power Systems Relaying Committee. He has co-authored a number of IEEE standards in the field of power system protection and communication and holds one patent in this area. William received a BS in computer/electrical engineering from Rutgers, the State University of New Jersey’s School of Engineering, and worked in the biomedical engineering field for five years prior to joining RFL.
• Cables
• LV/MV Circuit Breakers
• Rotating Machiner y
• Meters
• Automatic Transfer Switches
• Switchgear and Switchboard Assemblies
LV/MV Switches • Relays - All Types
Motor Control Centers • Grounding Systems
Transformers • Insulating Fluids • Thermographic Sur veys
Reclosers
Surge Arresters
Capacitors • Batteries • Ground Fault Systems • Equipotential Ground Testing • Load Studies • Transient Voltage Recording and Analysis • Electromagnetic Field (EMF) Testing • Harmonic Investigation • Replacement of Insulating Fluids
Power Factor Studies
DETECTING PARTIAL DISCHARGE ON MEDIUM-VOLTAGE CABLE ACCESSORIES
BY MICHEL TRÉPANIER and CLAUDE TREMBLAY, Hydro-Quebec; LIONEL REYNAUD, Hydro-Quebec Research Institute; and MATHIEU LACHANCE, OMICRON electronics Canada
Hydro-Quebec (HQ) is a major Canadian utility that manages the generation, transmission, and distribution of electricity to more than 3.8 million customers. Its distribution network includes over 12,000 km (7,456 miles) of medium-voltage underground distribution cables and more than 600,000 accessories — each with potential for failure.
Medium-voltage (MV) underground cable systems are a critical part of the distribution network of many electric utilities. Like any other power apparatus, insulation in underground MV cable systems ages over time. In North America, a large number of underground cross-linked polyethylene (XLPE) cables were installed in the 1970s and 1980s with a reported design life in the range of 30 to 40 years.[1] Today, utilities are faced with underground distribution systems that are theoretically either at the end of or past their design life.
RELIABILITY CHALLENGES
The reliability of the electric grid has always been a topic of interest. In-service failures lead to loss of revenue, increase in expenditures for repairs, and potential damage to other power apparatus due to increased stress during the fault. Furthermore, public and personal safety
can be compromised, especially when these failures occur in underground vaults and manholes in densely populated urban areas.
Replacing every piece of equipment and accessory that has reached its theoretical design service life is not an option for economical and practical reasons:
1. Newly introduced technologies can lead to higher risk of infant failures.
2. Each specimen ages at a different rate depending on the operating and environmental conditions.
Therefore, maintenance and diagnostic tests are common practice to assess the health of power system critical assets. This can rapidly become challenging for utilities where available manpower and/or funding might not be available to periodically test every electrical component.
The costs and constraints associated with replacing a network accessory are significant. The planning, work preparation, maneuvers to isolate the problematic equipment, execution of the work, and restoration can easily generate costs of tens of thousands of dollars — and this for an accessory worth only a few hundred dollars.
This situation becomes all the more significant when the problem is associated with a complete set of accessories, or worse, when the quality, precision, or methodology of the tests carried out by the manufacturer is not adequate. A utility can quickly face a major problem when several hundred or thousands of faulty accessories are installed in the network before noticing the problem and determining its source and nature.
In 2005, Hydro-Quebec reported that most of the in-service failures in its underground
distribution network occurred at cable joints. A common cause of deterioration in those cable accessories was partial discharges.[2]
This article shows how HQ has implemented a thorough inspection procedure to decrease the rate of failure in their underground distribution network. Among other tools, a multi-level PD detection approach was adopted to minimize the expertise required onsite. Several case studies are used to show the advantage of such an inspection procedure for an underground system.
PARTIAL DISCHARGE THEORY
The theory of partial discharges is very complex, and a complete description is beyond the scope of this article. However, a basic understanding of the phenomenon is helpful from this point onward.
A partial discharge (PD) is a localized dielectric breakdown of a small portion of an insulation system under electrical stress. PD can occur when the local electric field exceeds the local dielectric strength at a given location within or on the surface of an energized object. Each PD event will generate a current pulse. At its origin, if the discharge occurs in atmospheric air, this pulse has a rise time of just a few nanoseconds. It contains a theoretical constant broad frequency spectrum from DC to up to
several hundred megahertz (MHz). Therefore, PD can be detected using various technologies.
IEC 60270[3] is a normative document that defines the broad lines of PD measurements in many electrical devices. It specifies the test circuit, type of sensors, and measured frequency range and designates apparent charge (in picocoulombs) as the unit to quantify PD activity. Figure 1 shows an example of a typical PD measurement circuit according to IEC 60270.
IEC 60270 is primarily applicable for PD measurement performed in controlled environments, such as a factory or laboratory, where interferences can be easily mitigated. PD measurements that comply with IEC 60270 are commonly referred to as conventional PD measurements.
When measuring PD in the field, it can be challenging to comply with every IEC 60270 requirement. Space restrictions, a high level of interference, and the difficulty of performing a valid calibration are among the most common reasons other techniques are used. These are often defined as unconventional PD measurements and are described in IEC 62478.[4]
One example of such a measurement is the use of an antenna as a sensor. The antenna is installed on the surface or near the equipment and captures part of the energy from the electromagnetic wave generated by the discharge activity. In this case, many factors influence the measured quantity; therefore, the assessment usually focuses on whether PD activity is detected rather than quantification of the discharges. A simplified schematic of unconventional PD measurement performed using an antenna is shown in Figure 2.
INSPECTION AT HYDRO-QUEBEC UNDERGROUND SYSTEM
Over the years, HQ has become a leader in online problem detection. Predictive maintenance to ensure safe access to underground facilities was introduced in 1996
Figure 1: PD Measurement Circuit
According to IEC 60270
Figure 2: UHF PD Detection Using an Antenna-Type Sensor
Gases detection
• Harmful and combustible gases
Thermography
• Low-voltage equipment
• Medium-voltage equipment
• Medium-voltage equipment
360º Imaging PD Measurement
• Civil infrastructure
• Projects evaluation
in an exploratory manner. Now, 25 years later, HQ has a mature and sophisticated preventive inspection program that makes it possible to target any potential anomaly of an accessory before an in-service failure occurs. It also provides workers with safe access to underground facilities.
Every vault or manhole should be inspected once every six years, and 30 HQ teams are dedicated to this inspection program, which represents an annual inspection of more than 100,000 accessories in 12,000 vaults or manholes. Every manhole inspected with no anomaly is given an access validity period of one year. In addition to these inspections, several hundred repairs per year must be made in manholes that do not earn this validity period and therefore require emergency inspection.
A manhole inspection has four phases (Figure 3):
1. Measure potentially harmful and combustible gases.
2. Use thermographic measurement of low- and medium-voltage components to identify hot spots.
3. Measure PD on medium-voltage accessories.
4. Integrate a 360-degree photo into an interactive 3D experience tool to help to plan, visualize, and evaluate events such as a virtual tour of underground installations, optimization of work preparation, evaluation of the degradation of the vault, and new line routing with fewer field visits.
Depending on the test to be performed (infrared or 360-degree imaging), the device is fixed at the end of a pole, which is lowered inside the structure. The cameras are connected by cable to a computer in the thermograph truck. An operator handles the cameras, views the infrared images, and detects hot spots.
Hydro-Quebec has developed diagnostic software to evaluate the performance of splice connection, i.e., the internal temperature of each accessory and the current at which the maximum temperature will be reached given the type of splice, cable size, and ambient temperature (Figure 4).
PD measurements are complementary to the thermographic inspection. If no anomaly is
Figure 3: Inspection Program Phases
Dielectric losses Interfacial issues
Overheating connections
detected by thermography, PD measurement is completed on all medium-voltage components present inside the underground vault. Online PD measurements made during HQ’s maintenance program are non-conventional PD measurements, which means that only the presence of PD in an accessory is measured, not its charge in picoCoulombs.[4]
A PD sniffer[5][6][7] has been specifically designed for use by non-expert workers as a first-level
safety tool. It can recognize a PD signal in a fully automatic manner without any interpretation. Currently, the PD sniffer is being gradually replaced by a PD alarm,[8][9] a new, lighter, less expensive tool (Figure 5).
The PD alarm is able to detect the inversion of polarity of a PD (Figure 6) produced between the two antennas at an operating range below 30 MHz and centered around 18 MHz.[10] This low band frequency allows the use of standard
Accessibility
component
Figure 4: Automatic Evaluation of a Splice Performance
Figure 5: PD Alarm Mobile Unit
Green light indicating absence of a PD between the 2 probes
Figure 6: PD Detection Performed with the PD Alarm Tool and cheaper electronics for all necessary treatments. The development of antennas is also one of the keys to success.
light indicating presence of a PD between the 2 probes
When potential partial discharge is detected by a thermographer, he leaves the manhole and calls the technical team of engineers for validation.
FEATURE
An engineer then uses the advanced partial discharge analyzer (PDA)[2][11] to confirm or deny the presence of PD.
CASE STUDIES
Over the years, PD measurements have enabled Hydro-Quebec to detect dielectric anomalies on underground accessories that were aging as well as on accessories newly installed in the network. This helped avoid worker exposure to imminent risk as well as breakdowns and
associated costs by removing these problematic accessories before an in-service failure occurred.
Most cases are caused by improper assembly; a minority are caused by manufacturing issues. However, manufacturing issues can have greater negative impact on the network. Although factory tests are carried out by manufacturers of electrical distribution products, a dielectric fault is sometimes detected on the accessory installed in the network. These cases are the most interesting because they are the subject of a more in-depth analysis. Here are several examples of problematic accessories that had passed manufacturers’ tests and had been installed in a network.
Case Study I: 600 A Molded Busbars
600 A molded busbars were installed by HQ linemen in vaults to interconnect molded fuses and transformers (Figure 7). They are also part of a multi-channel solid dielectric switchgear deployed on Hydro-Quebec’s network.
Figure 7: Molded Busbar in Vault
Using the PD sniffer tool, HQ thermographers noticed probable PD on molded busbars recently installed in vaults, and an expert engineer confirmed the presence of PD with the PDA system. He also used the new PD alarm tool, which indicated the presence of PD. After removal, phase-resolved partial discharge (PRPD) analysis done on the defective units (Figure 8) clearly shows the presence of PD.
At almost the same time, the test engineer in charge of testing all new equipment prior to being installed in the field measured and confirmed PD on a multi-channel dielectric switchgear. During some open-close operations on the switchgear, the test engineer was able to determine that the PD was coming from the bus work of the apparatus, but he could not determine which component of the bus work was defective. To finalize his analysis, the test engineer used the new PD alarm tool to locate the defective part of the bus work: a 600 A molded busbar.
Following this event, Hydro-Quebec measured PD on new accessories from this manufacturer and confirmed the presence of PD activity on a high percentage of the analyzed accessories.
Based on the PRPD analysis of the tested molded busbars, the test engineer suspected that the PD was created by porosity in the
insulation material. X-ray images were taken on three defective molded busbars, and the verdict was the same: There were porosities in the insulation at one end of the molded busbar (Figure 9). The manufacturer analyzed and dissected the returned units and came to the same conclusion. Corrective actions in the molding and PD testing process were then taken by the manufacturer.
Additional Case Studies
The sequence of events in the following cases is the same as in the previous section:
• Workers detected the presence of PD on an accessory installed in the field using the PD sniffer or PD alarm.
• The presence of PD was confirmed by the technical support team using the PDA.
• The defective accessory was removed from the underground system and replaced.
Figure 8: PRPD Analysis on Molded Busbar
Figure 9: X-ray images showed porosities in the insulation material at one end of the molded busbar.
• When several identical cases were detected, PRPD analysis was done in a laboratory.
• Sometimes an X-ray scan of the accessory was done.
Capacitive Plug of a Separable Cable Joint
In 2011, we observed the presence of PD activity on more than 15 newly installed accessories. Hydro-Quebec has more than 55,000 units of this type of accessory distributed in more than 3,500 underground structures.
• A report on the origin of PD was written.
• If it was a manufacturing problem, the conclusions were sent to the manufacturer so corrective actions could be taken.
Problems A faulty area of the molding was located at the capacitive socket. X-ray images showed that some space was not filled by the insulating material (Figure 10). The manufacturer had changed some molds, and its factory test procedure did not detect the problematic components.
Corrective Actions
Hydro-Quebec informed the manufacturer of the problem associated with the molding of this type of accessory and returned all its separable cable joints from the same lot to the manufacturer. The manufacturer corrected the molding issue and testing procedures for these components.
Submersible Epoxy Isolated Fuse
This electrical device is used to provide protection for a submersible transformer in the event of an overload or internal failure. HQ has approximately 2,000 fuses of this type installed in over 500 underground structures.
Problems PD was caused by air gaps (Figure 11) inside the silicone filling, which is used to fill the void at the interface of three materials: brass, fiberglass, and epoxy.
Corrective Actions
Hydro-Quebec replaced the fuses with the highest levels of PD. Several tests were performed to determine whether it was safe for workers to be near these components. It was concluded that, due to its location, PD activity does not deteriorate the epoxy insulation.
Figure 10: Cavity in a Separable Cable Joint
Cavity Cavities
Figure 11: Air Gaps in Submersible Epoxy Isolated Fuse
CASE 1
CASE 2
Air gaps in silicone filling
Cap for Grounding Device
This component is installed on pad-mounted switches and is used to isolate the grounding device.
Problems PD was caused by porosity in the insulation material and poor bonding between the semiconductor and the insulation material (Figure 12).
Corrective Actions
During PD factory tests, the grounding cap was temporally installed and maintained using a hydraulic press. The test-bench assembly applied non-uniform pressure to the components and did not reflect the in-service condition. When the manufacturer was informed, the test bench was adjusted to properly detect anomalies.
T-Elbow on Medium-Voltage Switches
This connection accessory called deadbreak elbow is mainly used to connect an underground cable to a switchgear.
Problems Several components of this type installed on the network showed PD activity. The problematic components were removed and investigated. It was found that the PD was caused by bad contact between the semiconductor and the lug (Figure 13).
Corrective Actions Manufacturing tests were made with a connector bigger than the actual connector used in service. The connector used in-service did not make proper contact and generated PD activity. The manufacturer adjusted his test bench and was able to detect accessories that were out of tolerance.
Figure 12: Cap for Grounding Device, Porosity, and Bounding
Figure 13: Surface Contact Problem with a T-Elbow
CASE 4
14: Number of Anomalies vs. Years
CONCLUSION
Hydro-Quebec’s maintenance program achieves several targets. The first of these targets is the health and safety of employees and the public. By removing potentially dangerous accessories from the network prior to their failure, HQ raises its safety criteria to a high level. It is a priority for the company.
The second target is economic. The maintenance program reduces in-service failures. Performing a repair after an in-service failure is at least two and a half times more expensive than replacing an accessory after an inspection. In addition, when corrective actions are planned, there is little or no service interruption.
The third target is to ensure quality service and continue monitoring best practices. This quality assurance has repercussions on manufacturers since they are notified on certain issues, allowing them to improve their processes.
Approximately 500 anomalies are detected each year by thermography and 100 anomalies by detection of PD. Since the beginning of the maintenance program, the number of anomalies has greatly decreased (Figure 14).
REFERENCES
[1] “Diagnostic Testing of Underground Cable Systems,” Cable Diagnostic Focused Initiative, DOE Award No. DE-FC0204CH11237, Dec. 2010.
[2] D. Fournier et al. “Detection, Localization and Interpretation of Partial Discharge in the Underground Distribution Network at Hydro-Quebec,” CIRED 2005 — 18th International Conference and Exhibition on Electricity Distribution, Turin, Italy, 2005, pp. 1-4, doi: 10.1049/cp:20050961.
[3] International Electrotechnical Commission. IEC 60270, High-Voltage Test Techniques —Partial Discharge Measurements, Edition 3.1.
[4] International Electrotechnical Commission. IEC TS 62478-2016, HighVoltage Test Techniques — Measurement of Partial Discharges by Electromagnetic and Acoustic Methods, Edition 1.0.
[5] F. Léonard et al. “Partial Discharge (PD) Sniffer for Worker Safety in Underground Vaults,” Acts of the CIRED Conference, 2011.
[6] L. Reynaud, D. Pineau, M. Charette. “Partial Discharge (PD) Automatic Diagnosis Tool for Worker Safety in Underground Vaults, Jicable’11 Conference, Versailles, France, 2011.
[7] F. Léonard. “Dynamic Clustering of Transient Signals,” United States Patent Application Publication, US 2014/0100821 A1.
[8] L. Reynaud, D. Pineau, M. Charette, M. Trépanier. “PD Alarm — Lightweight Automated Diagnostic Device for Online Detection and Location of Partial Discharges on Non-Shielded Accessories of a MediumVoltage Distribution Network,” Jicable’19 Conference, Versailles, France, 2019.
[9] L. Reynaud, M. Trépanier, D. Pineau, M. Charette. “PD Alarm Tool for Online Detection of Partial Discharges in Medium-Voltage Accessories: Technology and Case Studies,” Acts of the DOBLE Conference, Boston, MA, USA, 2020.
[10] D. Pineau, L. Reynaud, M. Charrette. “Détecteur de Décharge Partielle et Méthode Associée,”United States Patent 0297-PCT-US ; Canada Patent Pending 0297-PCT-CA, 2019.
[11] D. Fournier et al. “Detection, Localization and Interpretation of Partial Discharge,” United States Patent US 8,126,664 B2, 2012.
Figure
Michel Trépanier worked in the Underground Distribution Division of Hydro-Quebec (HQ) in Montréal, Canada, from 2006–2009 as a Technical Support Engineer for the inspection teams in predictive maintenance, location, and analysis of underground faults. In 2010, he joined the Underground Distribution Standards Department, where he specializes in thermal inspection, partial discharge analysis, and characterization of medium-voltage electrical accessories. He contributed to several expertise and innovation projects at the Hydro-Quebec Research Institute. Michel obtained his engineering degree in electrical energy and electrical networks at École de Technologie Supérieure de Montréal in 2005.
graduated from Sherbrooke University and is a licensed member of the Ordre des ingénieurs du Quebec.
Lionel Reynaud has been involved in research and development of numerous control and monitoring systems at the Hydro-Quebec Research Institute (IREQ) in Varennes, Canada, since 1998. Since 2003, Lionel has specialized in problems related to cables and accessories at HydroQuebec’s underground medium-voltage distribution network. As Project Manager, he led the deployment of tools for fault location and partial discharge detection. Lionel obtained a University Technological Diploma in electrical engineering and industrial computing and an MS in computer systems at the Higher Institute of Aeronautics and Space in Toulouse, France.
E
Marc h 8 – 12, 2023
Rosen Shingle Creek | Or lando, Flor ida
ACCEPTANCE AND MAINTENANCE TESTING FOR MEDIUM-VOLTAGE ELECTRICAL POWER CABLES — PART 1 OF 3
BY THOMAS SANDRI, Protec Equipment Resources
As time progresses and a cable system ages, the system’s bulk dielectric strength degrades. During this aging process, artifacts such as water trees, delamination, voids, and shield corrosion raise the local stress placed on the cable during normal operation. The exact way in which the strength of a device degrades will depend upon many factors including voltage, thermal stresses, maintenance practices, system age, cable system technology and materials, and environment.
For years, high-voltage direct current (DC) testing had been the traditionally accepted method for judging the serviceability of medium-voltage cables. DC high-potential tests have worked well for conducting dielectric strength and condition assessment tests on paper insulated lead covered (PILC) cable. When cable materials began to change and plastic insulated cables were first introduced in the 1960s, little was known about the overall aging characteristics of the new materials, and DC therefore continued to be the preferred method of testing.
As time moved on, plastic insulated cables became more abundant, and as they aged, they began showing effects of service age. DC continued to be the dominant test, but concerns began to grow over the effectiveness of this test. In the early 1990s, reports began to surface indicating that DC high-potential testing could be to blame for latent damage experienced by extruded medium-voltage cable insulation.
As insulation materials continue to change and improve and as reliability demands grow, testing
methods have been developed that provide a better indication of the integrity of cables, splices, and terminations. To use these methods effectively, the operator must understand the mechanisms of aging and failure in cable systems. It is also important to understand testing techniques and have the ability to diagnose test results. It is equally important for trained personnel to be thoroughly familiar with the fundamentals of power cable design, operation, and maintenance.
This article reviews the evolution of testing methods and philosophies over the past 30plus years. The intended application of each technique along with the advantages and limitations of the technique will be reviewed providing the knowledge necessary to develop an effective cable testing program.
SIX BASIC LAYERS OF MV CABLE CONSTRUCTION
In a typical medium-voltage cable, copper or aluminum wires (either stranded or solid) are used as conductors (Figure 1). These conductors are
covered with an extruded polymeric stress-control layer made of semi-conductive compounds, often referred to as the conductor shield. The insulation layer immediately surrounds and is fully bonded with the conductor shield. An insulation shield encases the insulation and, in some cases, may be composed of the same semi-conductive material as the conductor shield. The copper neutral wires or tape are wound around the insulation shield and are usually covered with a thermoplastic polyethylene jacket for mechanical protection from the external environment and to reduce moisture intrusion into the cable, all of which can cause premature cable failure.
PHOTO:
Figure 1: Medium-Voltage Cable Layers
Conductor Strand Types
Various conductor strand types are commonly used in cable construction. The various types provide advantages in certain applications by either reducing the diameter of the cable or by lowering total AC resistance for a given crosssectional area of conducting material.
• Concentric strand. A concentric stranded conductor (Figure 2) consists of a central wire or core surrounded by one or more layers of helically laid wires. Each layer after the first has six more wires than the preceding layer. In compact stranding, each layer is usually applied in a direction opposite to that of the layer under it.
Figure 2: Concentric Strand
• Sector conductor. A sector conductor (Figure 3) is a stranded conductor with a cross-section in approximately the shape of a sector of a circle. A multiple-conductor insulated cable with sector conductors has a smaller diameter than the corresponding cable with round conductors.
Figure 3: Sector Conductor
• Segmental conductor. A segmental conductor (Figure 4) is a round, stranded conductor composed of three or four sectors slightly insulated from one another. This construction has the advantage of lower AC resistance due to increased surface area and skin effect.
Figure 4: Segmental Conductor
• Compact strand. A compact stranded conductor (Figure 5) is a round or sector conductor having all layers stranded in the same direction and rolled to a predetermined ideal shape. The finished conductor is smooth on the surface and contains practically no interstices or air spaces. This results in a smaller diameter.
Figure 5: Compact Strand
Conductor Shield
The cable conductors are covered with an extruded polymeric stress-control layer made of semi-conductive compounds, often referred to as the conductor shield (Figure 6). The conductor shield isolates the cable insulation from any air surrounding the conductor strands. This is very important since air gaps will lead to ionization and partial discharge activity that will prematurely fail the insulation.
Insulation Materials
Comparing the dielectric losses of various insulation types (Table 1), we can see that polyethylene (PE) and cross-linked polyethylene (XLPE) offer the lowest dielectric losses. Paper/oil (PILC) has low to medium dielectric losses and ethylene propylene rubber (EPR) offers the highest dielectric losses. This comparison of materials also shows that PE and XLPE have sensitivity to water contamination
(treeing) while EPR offers relatively low sensitivity to water contamination.
An understanding of the insulation material plays a key factor in the testing of cable and analysis of test results. When testing hybrid or mixed circuits, insulation with higher dielectric loss may mask the true condition of the cable section with lower dielectric losses.
Insulation Shield
The insulation shield encases the insulation and, in some cases, may be composed of the same semi-conductive material as the conductor shield (Figure 7). It serves a similar purpose as the conductor shield and shields the insulation from air that might cause ionization and partial discharge activity.
The purposes of the insulation shield are to:
• Obtain symmetrical radial stress distribution within the insulation.
• Eliminate tangential and longitudinal stresses on the surface of the insulation.
• Exclude from the dielectric field those materials such as braids, tapes, and fillers that are not intended as insulation.
• Protect the cables from induced or direct over-voltages. Shields do this by making the surge impedance uniform along the length of the cable and by helping to attenuate surge potentials.
Material
Polyethylene (PE)
Cross-linked Polyethylene (XLPE)
Ethylene Propylene Rubber (EPR)
Paper / Oil (PILC)
Advantages
• Lowest dielectric losses
Cable Shielding
Medium- and high-voltage power cables in circuits over 2,000 volts usually have a shield layer of copper or aluminum tape or conducting polymer. If an unshielded insulated cable is in contact with earth or a grounded object, the electrostatic field around the conductor will be concentrated at the contact point, resulting in corona discharge and eventual destruction of the insulation. Leakage
• High initial dielectric strength
• Low dielectric losses
• Improved material properties at high temperatures
• Does not melt but thermal expansion occurs
• Increased flexibility
• Reduced thermal expansion (relative to XLPE)
• Low sensitivity to water treeing
• Low to medium dielectric losses
• Not harmed by high potential DC testing
• Known history of reliability
Disadvantages
• Highly sensitive to water treeing
• Material breaks down at high temperatures
• Medium sensitivity to water treeing (although some XLPE polymers are water tree resistant)
• Medium–high dielectric losses
• Requires inorganic filler/additive
• High weight
• High cost
• Requires hydraulic pressure/pumps for insulating fluid
• Difficult to repair
• Degrades with moisture
Table 1: Insulation Materials Insulation Shield
Figure 6: Conductor Shield
Figure 7: Insulation Shield
current and capacitive current through the insulation present a danger of electrical shock. The grounded shield equalizes electrical stress around the conductor and diverts any leakage current to ground. Stress-relief cones should be applied at the shield ends, especially for cables operating at more than 2 kV to earth.
Several different types of shields are commonly used for medium-voltage cable applications. These shielding styles include:
• Tape-shielded (also called ribbonshielded). Tape shields (Figure 8) over ethylene propylene rubber (EPR) insulation have been a favored power cable construction for years. The way the tape is wrapped can deliver significant reliability and performance benefits. The overlap of the tape windings is a key design feature in helical-tape construction. The Insulated Cable Engineers Association (ICEA) recommends a minimum tape overlap of 10%. However, extra overlap delivers increased short-circuit capacity and better mechanical reliability.
Figure 8: Tape-Shielded Cable
Caution should be taken during installation of this style cable. If a tapeshielded cable is bent too sharply or pulled around bends with too much tension, the tape windings may separate, and the tape can buckle when the cable straightens out. The buckling can damage the underlying insulation shield. In a conduit, the damage is invisible, and even in a cable tray, the cable jacket may conceal the condition. What’s worse, most electrical proof tests performed in the field will not reveal this kind of damage.
• Wire-shielded (also called concentric neutral). This cable offers the same construction as tape-shielded cable
except for the different metallic shield layer (Figure 9). It is often considered interchangeable with tape-shielded cable and is very common in utility applications. When concentric neutral cables are specified, the concentric neutrals must be manufactured in accordance with the Insulated Cable Engineers Association (ICEA) standards. These wires must meet ASTM B3 for uncoated wires or ASTM B33 for coated wires.
These wires are applied directly over the nonmetallic insulation shield with a layer of not less than six or more than ten times the diameter of the concentric wires.
Figure 9: Wire-Shielded Cable
• UniShield® (a registered trademark of BICC Cables). Note the “Uni” in the name, which refers to the outer three layers being combined into a single layer: insulation shield, which also functions as a jacket, with metallic drain wires imbedded into the jacket to form a single functional layer (Figure 10).
Figure 10: UniShield Cable
• PILC, paper-insulated, leadcovered cable. The paper insulation is impregnated with oil which must be kept contained within the cable by use of a lead jacket (Figure 11).
Figure 11: Paper-Insulated LeadCovered Cable
CABLE AGING
A power cable fails when local electrical stresses are greater than the local dielectric strength of the dielectric material(s). Reliability and the rate of failure of the whole cabling system depend on the difference between the local stress at any given point in the system and the local strength at that point. Failure of the dielectric results in an electrical puncture or flashover at the location of the degraded dielectric. This flashover can occur between two dielectric surfaces, such as cable insulation and joint insulation, or it can occur as an external flashover at the cable terminations. A cable failure can occur because of the normally applied 50/60 Hz voltage or during a transient voltage such as lightning or switching surges.
As time progresses and the cable system ages, the bulk dielectric strength degrades. The main aging factor of extruded dielectric cable is electrical, although under abnormal situations, thermal aging can be significant. The electrical aging mechanisms — partial discharge, electrical treeing, water treeing, and charge injection — occur at contaminants, defects, protrusions, and voids and thus tend to be localized.
Looking at specific mechanisms, excessive electrical stress or bulk deterioration of the insulation can occur because of:
Manufacturing Imperfections
• Voids
• Contaminants in insulations
• Poor application of shield material
• Protrusions on the shields
• Poor application of jackets
Poor Workmanship
• Cuts
• Contamination
• Missing applied components or connections
• Misalignment of accessories
Aggressive Environment
• Chemical attack
• Transformer oil leaks
• Floods
• Petrochemical spills
• Neutral corrosion
Wet Environment
• Bowtie trees
• Vented water trees
• High rates of corrosion
• Can reduce dielectric properties
Overheating
• Excessive conductor current for a given environment and operating condition (global)
• Proximity to other cable circuits for short distances (local)
Mechanical
• Damage during transportation, typically localized
• Excessive pulling tensions or sidewall bearing pressures, either localized or global
• Damage from dig-ins, typically localized
Water Ingress
• Normal migration through polymeric materials
• Breaks in seals or metallic sheaths
Water Trees
Water trees, sometimes called electrochemical trees, have basic characteristics different than electrical trees. Electrical trees are characterized by the occurrence of partial discharge and require high electric stress to initiate, then rapidly lead to catastrophic dielectric failure. Water trees can be initiated at much lower dielectric stress and grow very slowly. These trees are associated with no measurable partial discharge and can completely bridge the insulation from conductor to shield without dielectric breakdown. Although breakdown does not occur, dielectric strength is greatly reduced. This is particularly true with regards to the direct current (DC) breakdown value.
Water tree degradation is a major problem for medium-voltage extruded dielectric cables, particularly service-aged XLPE cables. It is
perhaps the worst degradation process of the polymeric insulation that contributes to the failure of the cable.
Water trees are formed and grow in the presence of moisture, impurities or contamination and the electric field over time. There are generally two types of water trees (Figure 12): bow-tie trees and vented trees.
Bow-tie trees are water trees that grow from the insulation outwards towards the surfaces of the insulation. These trees grow in the direction of the electric field in both directions, towards the two electrodes. Bow-tie trees have faster initial growth rate compared to vented trees. Bowtie trees are, however, not capable of growing to large sizes and usually do not grow to a size significant enough to cause failure of the insulation.
Vented trees are water trees that grow from the surface of the polymer inwards into the insulation system. These trees will also grow in the direction of the electric field. Vented trees have a lower initial growth rate compared to bow-tie trees; however, vented trees can grow right through the entire insulation thickness.
Electrical Trees
The cumulative effect of partial discharges within solid dielectrics is the formation of numerous, branching partially conducting discharge channels, a process called electrical treeing (Figure 13). Repetitive discharge events
cause irreversible mechanical and chemical deterioration of the insulating material. Damage is caused by the energy dissipated by high-energy electrons or ions, ultraviolet light from the discharges, ozone attacking the void walls, and cracking as the chemical breakdown processes liberate gases at high pressure.
The chemical transformation of the dielectric also tends to increase the electrical conductivity of the dielectric material surrounding the voids. This increases electrical stress in the unaffected gap region, accelerating the breakdown process.
CABLE TESTING OPTIONS
The Insulated Conductor Committee of the IEEE Power & Energy Society has divided test methods or philosophies into two fundamental categories: Type 1 field tests and Type 2 field tests.
Type 1 tests are intended to detect defects in the insulation of the cable system to improve service reliability after the defective part is removed and appropriate repairs are performed. The following tests are usually achieved by applying moderately increased voltages across the insulation for a prescribed duration of time. Such tests are categorized as pass/fail.
• Insulation resistance (under voltage)
• DC high potential: IEEE Std. 400.1, Guide for Field Testing of Laminated Dielectric, Shielded Power Cable Systems rated 5 KV and Above with High Direct Current Voltage and IEEE Std. 400.5, IEEE Guide for Field Testing of DC Shielded Power Cable Systems Rated 5 kV
Figure 12: Types of Water Trees
Figure 13: Electrical Tree
and Above with High Direct Current Test Voltages
• VLF high potential: IEEE Std. 400.2, Guide for Field Testing of Shielded Power Cable Systems Using Very Low Frequency
• High potential power frequency: typically considered a factory test and not a field test
Type 2 tests are intended to provide indications that the insulation system has deteriorated, hence, termed diagnostic tests:
• Dissipation factor (tan delta) testing: IEEE Std. 400.2, Guide for Field Testing of Shielded Power Cable Systems Using Very Low Frequency (VLF)
• Partial Discharge: IEEE Std. 400.3, Guide for Partial Discharge Testing of Shielded Power Cable Systems in a Field Environment
• Damped alternating current: IEEE Std. 400.4, IEEE Guide for Field Testing of Shielded Power Cable Systems Rated 5 kV and Above with Damped Alternating Current (DAC) Voltage
• Isothermal relaxation current test
• Return voltage
IEEE further categorizes cable testing into three areas:
1. Installation tests. Field tests conducted after cable installation is complete, but before splicing or terminating occurs. The test is intended to detect shipping, storage, or installation damage.
2. Acceptance tests. Field tests made after cable system installation, splicing, and terminations are completed, but before the cable system is placed in normal service. The tests are intended to further detect installation damage and to show any gross defects or errors in installation of the various system components.
3. Maintenance tests. Field tests made during the operating life of a cable system. They are intended to detect deterioration of the system and to check the serviceability so that suitable maintenance procedures can be initiated.
UNDER VOLTAGE TESTING WITH DIRECT CURRENT
Under voltage tests performed with direct current (DC) are typically performed with a test set referred to as a megohmmeter. Since these tests use voltages under the rating of the insulation being tested, the test is a nondestructive test and does not produce any of the ill effects associated with high-voltage DC testing that we will discuss later in this article.
The traditional insulation resistance test is the simplest way to gain an overall indication of the condition of the insulation. Although the insulation resistance (IR) test can be applied as a simple Type 1 or go/no-go test, it can also be used to give more extensive diagnostic information. Type 2 or diagnostic insulation tests electrically stimulate the insulation and measure the response of the insulation to that stimulus. Depending on that response, we can draw some conclusions about the condition or heath of the insulation.
The test current in the body of the cable insulation can be split into three components:
• Capacitive current is initially large but goes to zero as the test piece is charged.
• Polarization current is caused by charges in the insulation material moving under the effect of the electric field or by molecular di-poles lining themselves up with the applied field (orientation polarization). It is greatly affected by moisture or contamination in the insulation, as the water molecule has additional orientation polarization. This process takes much longer than capacitive charging.
• Steady leakage current through the insulation, which is usually represented by a very-high resistor in parallel with the capacitance of the insulation.
Spot Test
The spot reading test is the simplest of all insulation tests. Test voltage is applied for a short but specific period of time (typically 1–2 minutes) as any capacitive charging
current will usually have decayed by this time. A reading is then taken. On longer cables offering increased capacitance, the time for the capacitive charging current may be significantly increased. The reading can then be compared to the minimum installation specifications. Spot readings can be performed as part of an inspection or as part of troubleshooting and can be used as a simple good/bad indicator.
Spot test readings can also be trended against previously obtained values. However, insulation resistance is highly temperature dependent, and thus the results should be corrected to a standard temperature.
If the insulation resistance reading is high and the reading increases or remains steady during the test, the insulation is in good condition. As the capacitance current and absorption current decreases, insulation resistance increases. If the insulation resistance reading decreases during the test, the cable insulation is probably wet or otherwise in bad condition. If the final value of resistance is low (or the current is high), the cable insulation is in poor condition.
Time Resistance Test (Polarization Index/Dielectric Absorption)
A valuable property of insulation is that insulation charges during a test. The polar DC field applied by the megohmmeter causes realignment of the insulating material on the molecular level, as dipoles orient themselves with the field. This movement of charge constitutes a current. Its value as a diagnostic indicator is based on two opposing factors: The current dies away as the structure reaches its final orientation, while leakage promoted by deterioration passes a comparatively large, constant current. The net result is that leakage current is relatively small in good insulation, and resistance rises dramatically as charging goes to completion. This changing resistance provides diagnostic information related to the degree of degradation of the insulation (Figure 14). Deteriorated insulation will pass relatively large amounts of leakage current at a constant rate for the applied voltage. This will flood out the charging effect and will
Insulation probably OK (A)
Moisture and dirt may be present (B)
Time 0 10 min.
show little-to-no change in resistance value. Time-resistance test methods take advantage of this charging effect. Graphing the resistance reading at time intervals from initiation of the test yields a smooth rising curve for good insulation, but a flat graph for deteriorated insulation. The ultimate simplification of this technique is represented by the polarization index (PI) and dielectric absorption (DA) tests, which requires only two readings and a simple division. When performing the PI test, the one-minute reading is divided into the tenminute reading to provide a ratio. In DA, the time values are typically 30 seconds and 60 seconds. Obviously, a low ratio indicates little change, hence poor insulation, while a high ratio indicates the opposite.
Discharge-Based Insulation Tests
A range of techniques that look at the response of the insulation during its discharge have emerged. These tests all target the polarization behavior of the insulation because, as mentioned earlier in this article, this property is sensitive to moisture in the insulation. Since all three components of current are present during the charging phase of an insulation test, the determination of polarization or absorption current is hampered by the presence of the capacitive and leakage currents. The discharge phase of the test, however, can more rapidly remove
Figure 14: Polarization Index Test
these effects, providing the possibility of interpreting the degree of polarization of the insulation and relating this to moisture and other polarization effects.
Isothermal Relaxation Current Test (IRC Test)
This test was developed for testing service-aged medium-voltage cables and grew as a response to problems associated with DC high potential testing of plastic cables. The early installed base of these cables from the 1960s and early 1980s is particularly problematic.
The IRC test uses a 1 kV test voltage for 30 minutes to polarize the dielectric. The polymer polarization traps charge at specific discrete energy levels, and during the discharge process, these energy levels give rise to different time constants in the discharge current. The major use of the effect in the IRC test is to look for the time constant associated with water trees in degraded cross-linked polyethylene (XLPE) cable material. The relaxation current occurring after the capacitance has been discharged is digitized for processing in PC-based software.
The software processing is based on a modelling technique that converts the current into charge and plots this charge against time. The total charge plot is then treated as a composite of standard shapes whose time constants are fitted to the composite curve by iteration. Cable aging is identified by the relative values of the time constants. The test was initially developed using artificially aged cable and has now been applied to operational XLPE cables.
SUMMARY
In Part 1 of our three-part series on acceptance and maintenance testing for medium-voltage electrical power cables, we reviewed cable construction and cable aging characteristics and started our discussion on cable testing options and philosophies. In Part 2 of this article, we will move away from under voltage testing and explore high potential testing techniques.
Thomas Sandri is Director of Technical Services at Protec Equipment Resources, where his responsibilities include the design and development of learning courses. He has been active in the field of electrical power and telecommunications for over 35 years. During his career, Tom has developed numerous training aids and training courses, has been published in various industry guides, and has conducted seminars domestically and internationally. Thomas supports a wide range of electrical and telecommunication maintenance application disciplines. He has been directly involved with and supported test and measurement applications for over 25 years and is considered an authority in application disciplines including insulation system analysis, medium- and high-voltage cable, and partial discharge analysis, as well as battery and DC systems testing and maintenance. Tom received a BSEE from Thomas Edison University in Trenton, New Jersey.
ELECTRICAL TESTING LEADING EDGE on
ELECTRICAL TESTING LEADING EDGE on
the
the
ELEMCO SERVICES
offers a comprehensive array of state-of-the-art electrical testing ser vices and expertise.
HIGH, MEDIUM AND LOW VOLTAGE REPAIR AND MAINTENANCE OF:
Switchgear / Circuit Breakers / Transformers / ATS Switches / Cables TESTING, CALIBRATION AND REPAIR OF METERS AND REL AYS
FIELD SERVICES:
Acceptance Testing and Commissioning / Infrared Sur veys Motor and Cable Testing Load and Power Quality Recording and Analysis
MICROGRIDS IN PRACTICE
BY MAYFIELD RENEWABLES
The majority of the U.S. electric grid was built in the early 20th century. It was initially designed for the one-way transfer of electricity from large fossil-fuel power plants directly to consumers. The grid of that era delivered power from rural areas, where power was generated, to cities, where much of it was consumed.
Much has changed in the energy landscape, especially over the last 10–15 years, with the accelerated adoption of variable renewable energy sources (VREs) and distributed energy resources (DERs) such as rooftop solar and electric vehicles. These newfound energy flows are much more complex than the existing grid was designed to handle, and redesigning our electric infrastructure will require significant innovation and investment.
As we shift toward rapid, widespread expansion of VREs, the grid is evolving to become more responsive. Integrated advanced control systems and other digital technologies work with
existing equipment to respond more quickly and accurately to electricity supply and demand changes. But the scale of these solutions has not met the scale of the problem — yet.
Alternatively, some of the world’s electrical systems are pivoting to decentralize, decarbonize, and democratize driven by the need to lower electricity costs, improve resiliency and reliability, reduce CO2 emissions, and expand access to electricity. Microgrids, in particular, have emerged as flexible, scalable solutions that can integrate and manage the many distributed VREs required to meet many of the world’s climate goals.
WHAT IS A MICROGRID?
The term “microgrid” is not well understood. If you ask five people to describe a microgrid, you will likely get five different answers. For
our purposes, we will use the Department of Energy’s definition:
A group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid. A microgrid can connect and disconnect from the grid to enable it to operate in grid-connected and island mode.
This definition specifies three distinct differences from a standard macrogrid:
1. An easily identifiable boundary from the rest of the grid
2. Resources within the microgrid controlled together
3. Microgrid function whether connected to the larger grid or not
HOW IS A MICROGRID BUILT?
A microgrid can be broken down into three key components: generation, load (demand), and storage, all within the same controlled network (Figure 1).
The microgrid must have at least one generation source to meet onsite electrical demand. Historically, fast-starting, robust diesel generators have been the dominant power generation sources
Figure 1: Microgrid Components
SOURCE: MAYFIELD RENEWABLES
for most microgrids. But with the falling cost of solar PV and energy storage, many microgrid developers are either skipping the diesel generator entirely or reducing its fuel burn by installing a solar-plus-storage system. An energy storage system (ESS), like a fossil-fuel generator, can respond quickly to changes in demand. Unlike a generator, the ESS does not need to burn costly, dirty fuel while idling around the clock.
Beyond generation and storage components, sophisticated control systems act as the brains of a microgrid. A typical control system includes many distributed controllers and sensors and a central supervisory control and data acquisition (SCADA) system to collect data and distribute instructions. The software behind the controls can balance the load by increasing generation or decreasing demand elsewhere on the microgrid, maximizing renewable energy usage and minimizing other electricity costs. Microgrids also contain many of the same critical components required for the standard grid, such as transformers, inverters, switchgear, and protective devices, but scaled down to the appropriate size for the system.
WHAT ARE SOME MICROGRID APPLICATIONS?
Microgrid development is a force multiplier for grid reliability, resiliency, security, and control. As more microgrids go online, the existing grid gets broken into smaller components that can be added together or isolated on demand.
The existing grid connects homes, businesses, and other buildings to central power sources. This interconnectedness has one major downside: Everyone is affected when part of the grid goes down. A microgrid generally operates while connected to the grid, but more importantly, it can also decouple itself and operate on its own using local energy generation in times of crisis like storms, power outages, or even peak-rate periods. This ability to become an energy island is useful for many applications, including:
• Emergency backup. Microgrids can become electrically isolated from the rest
of the grid in the event of an outage while continuing to produce and use electricity onsite.
• Energy independence. A microgrid can connect to a local resource that is too small or unreliable for traditional grid use, allowing communities to be more energy independent and, in some cases, more environmentally friendly.
• Extended islanding. A microgrid can be powered by distributed generators, batteries, or renewable generation resources like solar modules. Depending on how it’s fueled and how the connected load controls are managed, a microgrid may be able to run on its own for weeks at a time or even indefinitely. The system can be designed with any specific period of autonomy.
As microgrid deployment becomes more common, understanding what they are, how they are built, and how they can be used will become increasingly important.
BENEFITS OF MICROGRIDS
In addition to being flexible and scalable, microgrids provide additional benefits.
Ease of Connection for Efficient, Low-Cost, Clean Energy
The microgrid manager (e.g., local energy management system) can balance generation from non-controllable renewable power sources, such as solar, with distributed controllable generation, such as natural-gas-fueled combustion turbines. They can also use stationary energy storage and the batteries in electric vehicles to balance production and usage within the microgrid.
Improved Operational Efficiency and Stability of Regional Grid
When sited strategically within the electricity system, microgrids help reduce or manage electricity demand and alleviate grid congestion, thereby lowering electricity prices and reducing peak power requirements. In this manner, microgrids may support system reliability, improve system efficiency, and help delay or avoid investment in new electric capacity.
Provide Ancillary Grid Services: Energy Storage or Spare Capacity
A microgrid in grid-connected operation can provide frequency control support, voltage control support, congestion management, reduced grid losses, and improved power quality. Usually, some kind of energy storage system is used to provide these services to the regional grid, but the microgrid can be used as either a load or a generator, if needed, and in some places can actually be financially compensated for ancillary services.
CHALLENGES FACING MICROGRIDS
The evolution of microgrid technology presents new challenges.
Lack of Geographical Diversity, Inertia to Compensate for Variability in Generation
Microgrids lack geographical diversity, so relative variability, like increased demand or reduced generation from weather, will have a much larger impact on the system’s performance. Most microgrid generating sources also lack the inertia used by large synchronous generators on the macrogrid for frequency and demand response. Energy storage in the microgrid can help alleviate the effects of variability, but this is also part of the reason for staying connected to the larger regional grid.
Increased Equipment Costs, Energy Losses
Extra protective devices can add up to as much as 50% of the total microgrid cost, depending heavily on local regulations and the microgrid design. Microgrids give up the economy of scale that is so advantageous to the macrogrid. Additionally, DC-AC conversion can waste more than 15% of total energy produced, depending on the number of inverters in the design. Some of this energy loss is compensated for by the lack of transmission distance required, but should still be taken into consideration in any microgrid.
Remaining Legal and Regulatory Questions
Microgrids face three types of legal hurdles:
1. Laws that prohibit or limit specific activities
2. Laws that increase the cost of doing business
3. Uncertainty, including the risk that new laws will be implemented to regulate microgrids and impose restrictions or costs not anticipated at the time of development or construction
Finally, a number of regulatory questions remain before the widespread adoption of microgrids is even possible:
• Should microgrids count as “utilities” and be subject to state/federal regulation?
• Will microgrids be subject to consumer protection laws like utilities?
• If not a utility, what are the laws for buying/selling excess electricity and other ancillary services?
• Who determines minimum, maximum, and appropriate size for microgrids?
• Who is responsible for operating and maintaining a microgrid?
REAL-WORLD EXAMPLES
The benefits often greatly outweigh any potential risks involved with the microgrid, so what are some real-world examples where microgrids have proven to be beneficial?
• During wildfire season, many of the power outages in California are planned outages. A microgrid is a solution to many homeowners’ power problems by enabling them to produce and store their own power via solar panels and batteries and disconnect from the main grid, staying totally selfsufficient until the main grid is back online.
• When Hurricane Maria tore through Puerto Rico in 2017 causing the longest power outage in U.S. history, microgrids would have been much easier to restore, especially to hospitals and emergency responders. In fact, one of the major benefits of a microgrid is that it can extend beyond a single house or building and create a tiny electricity-isolated island within a community. A perfect example of this would be a microgrid between a fire
department, a school, and a senior center for emergencies, or even between multiple resorts on an island community.
• The University of California San Diego (UCSD) microgrid now powers a campus that covers 1,200 acres and serves a community of about 45,000 faculty and students living and working in 450 buildings. Two high-efficiency 13 MW natural gas turbines, a 3 MW network of solar resources, a 2.8 MW fuel cell, and a 2.5 MW advanced energy storage system allow the university to generate about 85% of its own energy at about half the price utility power would cost. The microgrid earns money for USCD by helping the utility meet peak demand by reducing campus loads upon request. They also generate a high excess of electricity from the PV array, so that local energy costs go negative to around minus 2¢/kWh during midday.
• A heat wave and storms led to power outages that affected hundreds of thousands of New York and New Jersey electricity customers during June 2019. Through it all, Home Depot stores in the New York area remained open thanks to microgrids that provided all of the critical power needs for each store during their
outages and eliminated the need for any back-up generators. With a combination of solar PV, fuel cells, and other energy storage on their microgrids, Home Depot has been able to meet sustainability initiatives in New York and elsewhere. This supports the retailer’s goal to ensure that stores remain available to the communities they serve in the event of a natural disaster or grid power failure.
There are pros and cons for microgrids, but a microgrid can be a great solution for many applications. The next section discusses the stages of a microgrid design, how to make it a successful project, and some of the challenges of developing a microgrid.
MICROGRID MODELING SOFTWARE
Many variables affect the overall results of the microgrid, including site-specific weather and infrastructure data that will determine the total output potential. From that data, estimated total output, along with local utility rates and available incentives, can be used to help calculate the economic benefits. Finally, economic feasibility, along with any other standards for the microgrid’s performance (load response, resiliency, energy arbitrage, etc.) can be used to calculate a more comprehensive picture of the microgrid’s potential benefits (Figure 2).
Resiliency Studies
Peak-Shaving/Load-Response
Reliability/Coverage Probability
Energy Arbitrage Modeling
P50/P90 Analysis
Easy, Complete Reporting
Site-Specific Weather Data
System Optimization
Web-Based Software
Free/Open-Source
Utility Rates/Incentive Included
Traditional Generation (diesel, gas, coal, etc.)
Residential & Commercial (behind-the-meter)
Residential & Commercial (front-of-meter)
Power Purchase Agreements (PPAs)
Solar PV
Battery Storage
Thermal Storage
Wind
Hydropower
Solar Water Heating
Fuel Cells
Geothermal Power
EV Charging
A number of microgrid modeling software packages to simulate the success of a microgrid in a given location are available. They range from free online academic tools to paid downloads, and they offer a variety of different features.
KEY SOFTWARE FEATURES
Obviously, there are many options out there for microgrid modeling. So how can you
differentiate these software solutions and find the best one for your business? Several key features can be used to distinguish them from each other based on the needs of your business and your clients.
• Price. Price will always be something to keep in mind for your business, but it shouldn’t be the first or only thing you consider. While paid licenses like
Table 1: Microgrid Modeling Software Comparison
HOMER or XENDEE definitely have more advanced user interfaces, others still yield the same quality of results for free, but may be less intuitive to use or contain fewer reporting features. Cost will vary greatly depending on the number of users in your organization, and a single license for your resident microgrid expert could more than pay for itself.
• Modeling capabilities. There are a number of different performance measures and reports that can be used to define the feasibility of a microgrid, so you will need to ensure your software can handle the analyses your clients are most interested in. Some of the available reports in microgrid software include system resiliency studies, energy arbitrage modeling, peak-shaving or load-response analyses, probability of exceedance analysis (P50/P90), and reliability/coverage probability reports. The reports generated by some programs are good enough to send straight to the client, but others will require you to take some tables and figures and create your own customer-facing report.
• Utility tariffs/complex rate analysis. Presumably, the most important part of any microgrid modeling for your clients will be the economic analysis, including total system cost and potential savings after construction. In most modeling software packages, you can at least manually enter utility tariffs/rates and incentives, but this information isn’t always readily available. The paid programs typically include this information in the software, making it much easier to accurately model the financial side of the microgrid, beyond just upfront system costs, especially for those with less experience with utility rules and regulations.
• Ease of use. Finally, ease of use could be the biggest priority to your business,
especially if your team has limited experience or expertise with microgrids. Some programs focus more on the technical side, some more on the user experience, but at the end of the day, your team members need to be able to use it accurately and efficiently. While all the programs above offer user manuals and video tutorials, paid software often offers training sessions or one-on-one consultations to help you get the most out of the software.
Microgrids are definitely an up-and-coming technology, and some more advanced training in microgrid modeling and design could help prepare your team for the future of renewables.
CONCLUSION
As you can see, there are plenty of free and paid options for modeling microgrids. The user interfaces and features vary greatly between the various platforms, but for most businesses, it comes down to a combination of four factors:
1. Price
2. Modeling capabilities
3. Rates/tariffs/incentives
4. Ease of use
Beginning designers may find the paid software easier to get the hang of, but some of the less complicated microgrid designs and reports can be done just as effectively and efficiently with free software. Ultimately, all of these modeling software programs can elevate your business and help sell projects to current and future clients. It will be up to you to decide between price and performance.
Mayfield Renewables is a team of solar + storage experts that offers many microgrid development services, including feasibility studies, component selection and sizing, and full permit set development.
Freedom isn’t usually a requirement when searching for a power system testing company. But it should be! Our relationally-focused freedom powers everything we do. As a locallybased, independently owned, third-party testing organization, we answer only to you.
PHOTOVOLTAIC POWER SYSTEMS AND GROUND-FAULT PROTECTION ON THE SERVICE ENTRANCE DISCONNECT
BY JOHN WILES, Retired
There are no one-size-fits-all solutions to the ground fault-protected main circuit breaker issue. Diligent attention to the requirements in the NEC — NFPA 70 and the equipment in the existing installation is required.
The 2020 National Electrical Code (NEC –NFPA 70) in Section 230.95 Ground-Fault Protection of Equipment requires groundfault protection of equipment for solidly grounded wye services of more than 150
COURTESY JOHN WILES
volts but not exceeding 1,000 volts phase to phase. While this type of service is not common in residential/dwelling services, it is quite common in medium-size commercial electrical installations such as schools, big-box stores, and supermarkets. Load-side PV system connections (705.12) are attractive in these situations because the large panelboards/load centers offer a relatively easy method of making the connection (Photo 1).
However, Section 705.32 must be addressed, and other factors should be investigated before the decision is made to make a load-side PV connection.
THE BASICS
A major consideration revolves around the common use of a main circuit breaker that is equipped with a GFP accessory. Circuit breakers are manufactured with numerous optional accessories, including (depending on manufacturer and model) shunt trips, auxiliary switches, remote indicators, power operation, adjustable trips, and ground-fault protection (GFP) trip mechanisms (Photo 2).
Photo 1: Large Panelboard in a Commercial Building Providing Several Potential Load-Side Connection Points
While UL Standard 489 requires tests to evaluate the backfeeding of the basic circuit breaker, most of the accessories are not evaluated for backfeeding. In fact, backfeeding may have no effect on many of these accessories, and specific testing for backfeeding may be unnecessary.
However, older and possibly some current ground-fault trip mechanisms may be damaged if the circuit breaker has voltages on both line and load terminals after the circuit breaker has been opened by a ground-fault trip. UL Safety Standard 489 for molded-case circuit breaker testing does not evaluate the GFP accessory on backfed GFP main circuit breakers in a manner that subjects the ground-fault device to the conditions it would experience in a utility-interactive PV system or possibly even in a parallel-connected generator installation where line and load terminals are both energized during and after a ground-fault trip. PV inverters responding to internal antiislanding software may have energized outputs up to two seconds after the AC utility power is removed from the inverter output. These
PV inverter-energized load-side terminals on the main circuit breaker may cause the GFP trip mechanism to be destroyed if that trip mechanism is connected to and receives power from the main circuit breaker load-side output terminals. In normal operation with no PV, when a ground-fault event occurs, the opening
COURTESY JOHN WILES
Photo 2: 1,200-Amp Circuit Breaker with Ground Fault Protection COURTESY
Typical School Carport
circuit breaker immediately removes the power source for that GFP trip mechanism, and no damage will occur.
Circuit breaker manufacturers should be evaluating all accessories supplied with their circuit breakers for operation under all possible application configurations. However, utilityinteractive inverter installations are a relatively new application, and PV inverters are being applied to electrical installations that may be decades old.
Discussions with technical support personnel at circuit breaker manufacturers indicate that most new designs use a current transformer to power the GFP device and that the current transformer does not respond to any potential voltages on the load terminals of a trippedopen main circuit breaker. The GFP device, powered by the current transformer, should not be damaged by backfeeding or by inverter
supplied voltages on the output terminals of a tripped open main circuit breaker.
However, there is some confusion and uncertainty about older GFP/circuit breaker designs that have been installed widely and may still be found in older buildings.
LOOKING DEEPER Load-Side Connections Where a GFP-Protected Main Circuit Breaker Is Involved
Section 705.32 requires a supply-side connection of a PV system where a Section 230.95 ground-fault protected main service disconnect is involved, but the exception allows load-side PV connections with requirements for ground-fault protection of the loads from all ground-fault sources.
If the circuit breaker manufacturer (design engineer) will sign a statement that the specific
• AC, DC, or hand-cranked powered
• Analog, digital, and graphical displays
• Accurate, reliable, and built to perform
• Perform insulation resistance tests into the GΩ and TΩ ranges
• 50 V to 15 kV models
main circuit breaker with GFP accessory by part number and model number will not be damaged under PV inverter backfed conditions (line and load terminals energized at the same time during and after the GFP device trips the circuit breaker), then it appears that backfeeding that circuit breaker may be acceptable and a load-side PV connection may be possible. Bulletins and information from sales departments are sometimes insufficient to make a safe determination.
After determining that the main circuit breaker/GFP is suitable, the issue of protecting the load circuits or feeders during groundfault conditions from all sources, utility, and PV must be addressed (705.32 EX). An engineering analysis would be required that shows how and where ground-fault currents are sourced. What impedances are involved in the utility source and the PV source, and how much current can each supply under varying types of ground faults? Ground faults are not always hard, low-resistance faults and may be arcing faults of varying impedances. Suppose
the PV system provides enough ground-fault current to prevent the main circuit breaker GFP from tripping. How is the ground fault contained or interrupted?
Some manufacturers and installers are wary of connecting some sort of GFP device to the inverter output because this is a non-standard connection, and any ground faults detected might only be those originating between the device (usually a backfed circuit breaker) and the inverter, not ground faults occurring in load circuits. This would occur if a GFPE circuit breaker were to be used in an AC inverter combining panel since that circuit breaker would normally sense ground-fault currents only toward the inverter from the circuit breaker location.
Several manufacturers offer a main circuit breaker GFP that can take inputs from multiple ground-fault sources like a dual-utility feeder system. But these would be found in limited, special instances where there are multiple utility sources, and they may not be useable to meet NEC requirements in the PV applications.
Photo 3: PV System Mounted on School Carport
COURTESY JOHN WILES
Other Considerations
The NEC requirements in 705.32 and 705.12(B) might appear to restrict the PV to always be 20% or less of the main circuit breaker rating, and the main GFP circuit breaker will always trip on a ground fault, but what was the GFP trip setting? On a 1,200amp GFP circuit breaker, the GFP adjustable trip setting might be from about 200 amps to 1,200 amps of fault current. For a load with multiple ground-fault current sources (at least one from the utility and one or more from current-limited utility-interactive PV inverters), what would the proper trip settings be for each ground-fault device?
Under the 2017 NEC and 2020 NEC, the 120% allowance in 705.12(B)(2) may apply to the installation. But it may not. A relatively large PV system with a small main circuit breaker on a large busbar could meet either the 120% or the 100% allowance.
The 2020 NEC still has the basic requirement for ground fault protection in 705.32. If a supply-side PV connection is elected, the new Section 705.11(E) will apply. This section has been interpreted as requiring ground-fault protection for PV circuits and PV equipment when they are connected to services rated at 1,000 amps or more. This requirement would mean that a properly rated backfed circuit breaker with a ground-fault accessory be used as the PV system disconnect at the point of connection to the service conductors.
Historical Perspective
About 15 years ago, two PV-progressive electric utilities headquartered in Phoenix, Arizona, (Arizona Public Service and Salt River Project) decided to put medium-size PV systems (18–60 kW) on numerous schools in their respective service territories (see opening photo and Photo 3).
These schools typically had services that met the NEC 230.95 requirements and were equipped with ground-fault protected main circuit breakers. Some were brand-new schools, while many were quite old. Getting data on
old, discontinued main circuit breakers with GFP accessories was difficult, if not impossible. As previously mentioned, the large 1,000-ampplus panelboard/load centers in these schools presented an attractive location to make a load-side PV connection. However, exhaustive investigations on the numerous existing school electrical systems by two separate professional engineers experienced in the NEC requirements and installations of PV systems of this size on the large GFP protected services resulted in both utilities opting for supply-side connection of the PV system on every school. And in more than a few cases, a transformer was required to match the PV inverter output voltage to the higher service voltage.
Before connecting a PV system that will backfeed a GFP main service disconnect or circuit breaker, the following steps should be followed. There may be others.
1. Accurately determine that any and all ground-fault protection devices installed where they may be exposed to backfeed currents are suitable for operation in a backfed manner with a utility-interactive PV inverter.
2. Select an appropriate GFP device(s) that can be connected to the inverter(s) outputs to control ground-fault currents flowing in load circuits from those sources.
3. Make an engineering assessment of the magnitudes of the potential and available fault currents from both utility and PV sources to the load circuits being protected. Circuit impedance calculations under fault-current levels for all sources and the load impedance should be made.
4. Determine the proper setting for all adjustable-trip ground-fault protection devices that will ensure that the load circuits and feeders are protected from all ground-fault current sources.
5. The installed system should be tested while the GFP circuit breaker is being backfed with a PV inverter by activating the internal ground-fault trip circuit test. That test should be conducted twice to ensure
that the ground fault mechanism or device was not damaged during the first test.
Supply Side Connection
In many cases, it may be easier and safer to implement a supply-side (of the main GFP circuit breaker) PV connection as allowed by 705.12(A) (2017 NEC) or 705.11 (2020 NEC).
SUMMARY
The requirements of the NEC are stringent but can be met. There are no one-size-fits-all solutions to the ground fault-protected main circuit breaker issue. Diligent attention to the requirements in the NEC and the equipment in the existing installation is required.
The NEC requirements continue to evolve as new subsystems and equipment bring increased safety to PV installations while reducing or eliminating the requirements of the recent past.
John Wiles is retired from the Southwest Technology Development Institute at New Mexico State University, but as a temporary employee in his previous position, he devotes 25 percent of his time to PV activities.
Reprinted with permission from IAEI News Magazine, July/August 2022. An online version is available at https://wp.me/pa0pa5-66o
USING THE THREE Rs TO REDUCE THE ENVIRONMENTAL IMPACT OF SF6 GAS
BY LINA ENCINIAS and COREY RATZA, DILO Company, Inc.
The ability of SF₆ to recombine after arcing events — combined with the fact that it is chemically inert, non-toxic in its pure state, nonflammable, and very-high density — makes it an excellent di-electric gas, and sulfur hexafluoride has been used as an insulating medium in the electrical industry since the 1950s.
SF 6 GAS ENVIRONMENTAL IMPACT
SF₆ is a man-made gas that does not naturally occur in large quantities. In 1997, the Kyoto Protocol (Global Warming Treaty) listed SF₆ gas as one of the six greenhouse gases that should be controlled by reducing emissions or eliminating its use. The Global Warming Potential (GWP) of a gas measures the amount of energy the emissions of 1 ton of that gas will absorb relative to 1 ton of carbon dioxide (CO2). Gases with a higher GWP contribute more significantly to climate change.
SF₆ gas has been identified as the most potent greenhouse gas, surpassing others such as carbon dioxide and methane. Over the span of a 100-year period, SF₆ is 22,800 times more effective at trapping infrared radiation than an equivalent amount of CO₂. SF₆ gas is also very
stable, and it accumulates in the atmosphere in an essentially undegraded state, thus having an atmospheric lifetime of 3,200 years. Therefore, even a small amount of SF₆ emitted into the atmosphere can have a significant impact on global climate change.
Despite regulations and efforts to decrease SF₆ emissions, the amount of SF₆ in the atmosphere steadily increased worldwide since 1998. There are several uses for sulfur hexafluoride, but it is most used as an insulating gas for electrical switchgear in the transmission and distribution of power industry. The industry is seeking alternatives to SF₆ due to its high GWP. However, federal regulations do not currently prohibit the purchase of new SF₆ switchgear, and most states do not have their own regulations restricting SF₆ gas.
The market for SF₆ gas is expected to grow to USD 309.8 million1 and the global installed base of SF₆ equipment is expected to grow by 75% by 20302 despite the availability of alternative solutions and data on how harmful SF₆ emissions are to the environment. The transmission and distribution industry is responsible for about 80% of SF₆ emissions, but utilizing the Three Rs of responsible SF₆ gas handling in addition to SF₆ reconditioning can help significantly reduce the industry’s environmental footprint.
THREE R s : RE-USE, RECOVER, RECYCLE
Ideally, SF₆ should be used in a closed-loop cycle and never be emitted into the atmosphere.
Unfortunately, we know this is not always the case. The most common causes of emissions in the T&D industry are production of virgin SF₆ gas, faulty or leaking gas insulated equipment (GIE), and improper gas handling methods and human error. The Three Rs address these common emission causes and help to prevent SF₆ from entering the atmosphere.
RE-USE (AND CHOOSE TO DITCH) VIRGIN SF 6 GAS
The benefits of re-using SF₆ gas instead of purchasing virgin SF₆ gas include reduced environmental impact, cost savings, and increased reliability of product sourcing. Any contaminants that occur while SF₆ gas is in use due to the intrusion of air, moisture, or
Table 1: Comparison of Emission Rates for Virgin, Reconditioned, and Recycled SF₆ Gas
45.36 kg (~100 lbs) Virgin SF6 Gas 3.6 kg (30lbs) to 36.3 kg (80 lbs)
45.36 kg (~100 lbs) Reconditioned (95% to =/>99.0% Purity) =/<0.29 kg (0.64 lbs)
45.36 kg (~1,000 lbs) Recycled (97% Purity) =/<0.12kg (0.05 lbs)*
*It is possible to achieve an emission rate below 0.12 kg (0.05 lbs) as it is dependent on equipment, handling processes, and practices. Recycled gas is defined as SF6 gas that has been filtered on-site via an SF6 gas cart
generation of arc byproducts can be removed with the proper filtration and separation process. SF₆ gas can be reconditioned to a likenew state that meets or exceeds IEC standards even after being exposed to an arcing event, moisture, and/or other contaminants and is approved for use within the T&D industry.
Environmental Impact of Virgin Gas
The production of virgin SF₆ gas is a major source of emissions. The International Panel on Climate Change’s 2019 Guidelines for National Greenhouse Gas Inventories estimates that 0.03 kg to 0.08 kg of SF₆ gas is emitted to the atmosphere per every 1 kg (2.2 lbs) of SF₆ gas produced.3 In fact, producing virgin SF₆ gas can create 12.5 or more times the emissions than reconditioning or recycling SF₆ gas for re-use.
One way to curb emissions while using SF₆ gas is to switch from purchas ing virgin gas to using reconditioned gas. A large and growing stockpile of SF₆ gas is already in circulation in North America. From an environmental perspective, reconditioning gas helps us lower the carbon footprint by removing the need to produce more SF₆ gas Additionally, utilizing SF₆ gas already in the United States helps reduce emissions created by the manufacturing and shipping of virgin gas from overseas.
Increased Reliability and Decreased Cost
It is important to recognize that the major shareholders of manufacturing virgin SF₆ gas come from industrial gas production plants outside of North America. Virgin SF₆ gas
production was ceased in the United States with the greenhouse gas emission reduction targets instituted by the Environmental Protection Agency. Therefore, any virgin SF₆ gas purchased in the United States is imported from Eastern Europe, Russia, or Asia where the gas is produced. Given current supply chain issues and increased demand, virgin SF₆ gas has never been more expensive or difficult to source.
Reconditioned SF₆ gas can be sourced from vendors within the United States, decreasing shipping costs and delays. The SF₆ reconditioning practice ensures a readily available supply for the power and utility sectors and eliminates the need and environmental impact of importing virgin product from other continents.
An additional advantage for sourcing reconditioned SF₆ is cost savings. Virgin gas typically costs double what reconditioned SF₆ gas costs. Technological advances in the filtration and separation process make it possible for reconditioned SF₆ to meet or exceed federal and international industry standards, all at a lower cost, and this cost savings does not compromise the quality of the gas.
From a technological view, there are no significant differences in the makeup of engineered virgin SF₆ and reconditioned SF₆ that has undergone a cryogenic process to remove by-products. Furthermore, reconditioned SF₆ gas can be purchased at significantly lower cost than virgin gas while simultaneously supporting American businesses.
RECOVER CORRECTLY
SF₆ gas recovery (Figure 1) refers to the process of capturing or removing gas from GIE via a recovery system. In addition to removing the gas from the GIE, the recovery system provides basic filtration of contaminants like moisture, SF₆ gas by-products, and sometimes oil.
Three important things to keep in mind for SF₆ gas recovery:
• Determine the volume of SF₆ gas. It’s critical to determine the volume of SF₆ gas to be recovered to select the correct tools and equipment and avoid emissions. The following formula can be used to determine the volume of SF₆ gas:
Volume (ft3) / density = lbs
An SF₆ density curve like the one in Figure 2 can help determine the density using the size of the GIE compartment and the ambient temperature. Next, the density along with the volume of the GIE are used to determine the approximate pounds of SF₆ gas to be recovered.
Figure 1: Recovery of SF₆ Gas from GIE Using a SF₆ Gas Cart
Figure 2: SF₆ Density Curve
• Recover to blank-off pressure. When completing SF₆ recovery using a gas cart, it is imperative to reach the lowest level of vacuum possible — blank-off pressure. Generally, reducing the amount of gas in a breaker to atmospheric pressure alone leaves a startling 14–18% of residual gas within the GIE. Starting additional maintenance while residual gas is still present can cause an emission.
For volumes under 100 lbs. of SF₆ gas, the minimum blank-off pressure is <5 mbar. For volumes over 100 lbs. of SF₆ gas, the minimum blank-off pressure is <1 mbar. Recovering to blank-off pressure removes virtually all the gas from the GIE and reduces emissions caused by residual gas being emitted into the atmosphere when the GIE is opened for maintenance.
• Use the correct size recovery equipment It is extremely important to use an
adequately sized recovery system for the volume of SF₆ gas that needs to be recovered. Hose length should also be considered. Utilizing an undersized recovery system for the volume of SF₆ to be recovered will leave residual gas in the GIE that can lead to an emission.
Figure 3: Particle Filter Used to Trap Solid Contaminants in SF₆ Gas
RECYCLE VIA ON-SITE FILTRATION
Contamination of SF₆ gas can occur naturally over time through leaks and arcing events.
Common contaminants found in SF₆ gas include decomposition by-products, oil, and moisture. It’s important to test the quality of SF₆ gas via a zero-emission analyzer prior to beginning any gas handling as certain contaminants like SF₆ byproducts can be hazardous to human health and damage equipment.
Depending on the quality and purity of SF₆ gas, the gas can be recycled on-site. Except for air, nitrogen, carbon tetrafluoride (CF4), and other vapors, most contaminants can also be removed on-site using a recovery system and external pre-filters. This recycling allows contaminated SF₆ gas to be processed onsite and quickly returned to your company’s inventory and/or be filled back into GIE.
Four main types of filtration can be performed on-site to allow for SF₆ recycling (Figure 3):
• Aluminum oxide (AL₂O₃). Aluminum oxide absorbs moisture and SF₆ byproducts from SF₆ gas by attracting and trapping the particles as the vapor passes through the filter.
• Molecular sieve desiccant. The desiccant traps water molecules and removes them from the SF₆ gas as it passes through the filter.
• Particle filter. The particle filter traps any solid particles in the SF₆ gas as it passes through the filter. These particles may include solid decomposition material from SF₆ gas by-products that would damage the GIE and gas handling equipment. Particle filters have a 100% capture rate of particles ≥1.0 µm.
• Activated charcoal. The high surface area of activated charcoal along with high bulk density and particle size distribution allow it to remove organic compounds such as oil
from SF₆ gas. The activated charcoal filter is not a standard part of a recovery system but can be used externally if gas analysis shows that oil is present as a contaminant.
Most recovery systems include aluminum oxide, molecular sieve desiccant, and particle filters. Using a pre-filter provides extra filtration to protect the recovery system from any contaminants present in the gas and makes the recycling process more efficient by providing extra filtration.
It may take multiple passes through the recovery system and pre-filter to recycle the gas to meet IEC standards for re-use. If you do not see a significant improvement in gas quality after filtration, your filters could be saturated and will likely need to be cleaned or replaced. Please note that cleaning may require PPE and special handling processes that require specific training or certifications (i.e., a respirator program). If the IEC standard for re-use cannot be met or exceeded, the SF₆ gas will have to be sent for reconditioning.
Reconditioning SF6 Gas
In some cases, SF₆ gas may need to be reconditioned to remove vapors prior to being re-introduced into the supply stream. Reconditioning is a process that occurs after the Three Rs are used to separate SF₆ gas from other vapors (N2, O2, CF4). The reconditioning process requires special equipment and handling procedures that ensure as close to zero emissions as possible.
An SF₆ gas separator uses a three-stage cryogenic process to recondition SF₆ gas to a guaranteed 99% purity and less than 99.5 ppmV moisture. In short, reconditioning is a cryogenic process that is combined with filtration and high pressure through an emission-free process. The end goal is to meet or exceed the standards set by CIGRE, IEEE, ASTME, and IEC. When the process is followed correctly, the standards can easily be exceeded and the gas can be returned to the market for re-use.
CONCLUSION
SF₆ gas is an extremely effective di-electric gas that contributes significantly to global
Marc h 8 – 12, 2023
Rosen Shingle Creek | Or lando, Flor ida
Saber Knows Power
Saber Power Field Services is a NETA Accredited Company serving the electric utility, petrochemical, municipal, industrial/commercial, renewable and oil and gas industries.
Quality, customer satisfaction and electrical safety set us apart from our competitors.
NETA Acceptance Testing
SF6 Gas Services
SF6 Service Cart for maintenance of gas components.
Oil Processing Services
NETA Maintenance Testing
Regular testing, inspection and corrective services minimizing costly interruptions.
Commissioning & Startup
Start-up testing, commissioning, acceptance testing, breaker repair and maintenance, and 24-hour
Breaker Shop Services
Electrical experts in circuit breaker repair, upgrades and replacement, with a large inventory.
Mobile Breaker Shop
Mobile unit brings our vital shop services directly to our customer’s locations for onsite repairs, upgrades and maintenance.
Electrical Training
Live webinar, on-demand, in-person and custom safety and technical skills training.
Emergency Response municipalities, hospitals, data centers, and more.
Natural Disaster Recovery
Servicing the Gulf Coast and beyond to repair equipment and systems damaged by hurricanes and storms.
OPERATIONAL TECHNOLOGY CYBER THREATS ARE ON THE RISE
BY BRYAN J. GWYN and SAGAR S. SINGAM, Doble Engineering Company
Critical infrastructure security is in the national spotlight.[1] According to the 2022 State of Operational Technology and Cybersecurity Report, organizations throughout the world’s OT security initiatives are making inadequate progress toward comprehensive protection of ICS and SCADA systems in the relatively new world of connected OT.[2] The Biden administration recently issued a national security memorandum that sets baseline cybersecurity goals and practices to protect the grid. The order also encourages the deployment of advanced technology for threat visibility, detection, monitoring, and response.
Power and utility companies play a starring role in safeguarding the nation’s infrastructure. As organizations double down on compliance and technology, there are several things to consider amidst a rapidly evolving cybersecurity landscape.
The CIA Triad is a data security concept. It directs a company’s data security efforts and helps lay out a strong security foundation. In fact, including these ideas in any security
ADVANCEMENTS IN
program is ideal. The three pillars of security architecture are:
Confidentiality
In today’s world, it is critical for people to protect their sensitive private information from unauthorized access. Protecting confidentiality necessitates the ability to define and enforce specific levels of access to information. In some cases, this entails categorizing information into different collections based on who needs access to the information and how sensitive the data is — the amount of damage suffered if confidentiality is breached. Access control lists, volume and file encryption, and Unix file permissions are some of the most used methods for managing confidentiality.
Integrity
The “I” in the CIA triad represents data integrity. This critical component of the CIA Triad is intended to prevent data from being deleted or modified by unauthorized parties. For example, online buyers demand accurate product and pricing information and assurances that the quantity, cost, availability, and other information will not change after they make their order. Data integrity safeguards include encryption, hashing, digital signatures, and digital certificates.
Availability
The availability of your data is the focus of this stage — the third in the CIA Triad. High-availability systems are computing resources with architectures specifically designed to increase availability. The most well-known attack that jeopardizes availability is called a denial-of-service attack, in which a system, website, or web-based application’s performance is purposely and maliciously compromised or the system is rendered inaccessible. The breakdown of hardware or software, power outages, natural catastrophes, and human error are other possible risks to availability. The information must be protected and made available when needed, which requires that authentication procedures, access routes, and systems all function effectively.
ADVANCEMENTS IN INDUSTRY
OT SECURITY GOVERNANCE [3]
The federal government has issued many executive orders in the past to strengthen the cybersecurity posture of vital infrastructure. President Biden most recently signed Executive Order 14028 Improving the Nation’s Cybersecurity in May 2021 to protect critical infrastructure. [4] This directive focuses on modernizing cybersecurity requirements such as data encryption at rest and in transit, a zero-trust architecture, and the deployment of multifactor authentication and data encryption within a certain timeframe.
The CIA Triad is all about information and data security. But the first thing to note in Figure 1 is that, in general, IT and OT risk management priorities differ. IT prioritizes confidentiality, while OT prioritizes availability, followed by integrity and confidentiality (A-I-C). It is critical for every business to identify these priorities since they determine the overall security defensive systems of the organization.
This demonstrates that even today, having a basic security foundation such as the NIST Cybersecurity Framework (CSF), which went into force nearly a decade ago, is vital for critical infrastructure organizations. The NIST CSF consists of a framework core, profiles, and implementation tiers. While the core functions of the NIST CSF include categories, subcategories, and informative references, we will focus on the first two core components shown in Figure 2 of this framework from a 1,000-foot perspective.
Asset management, a comprehensive inventory of all OT assets, is one of the essential core components of an OT asset database — not only hardware, but also a comprehensive view of the data, personnel, devices, systems, and facilities that enable the organization to meet its objectives. They must be identified, and their importance in business objectives and risk management must be clearly established. Database management software can bridge the divide between competing IT and OT priorities. Look for a relational database architecture that will support a central data warehouse structured for universal interfacing to external systems. Bringing such a system on-line will integrate OT data into a hub where asset management and work management will intersect.
Connecting dataflows emanating from different sources enables OT teams to have the data integrity, availability, and confidentiality they prioritize while critical elements related to human performance and network security remain intact for IT intents and purposes. The
Figure 1: CIA Triad Priorities
Figure 2: NIST Cybersecurity Framework
ideal OT database management system will accept user authentications developed in the IT domain, which complements the corporate cybersecurity measures put in place for user (and device) password management. This assures data security and integrity as well.
After identifying and categorizing your assets, you should take proactive measures to safeguard them from internal and external cyber threats. Security maintenance rules and practices, including software patch management and whitelisting, must be created and implemented for the NIST CSF’s Protect component.
INVEST IN TRANSIENT CYBER ASSET SECURITY AND PATCH MANAGEMENT
Remote field devices can present major security risks. Transient cyber assets (TCAs) such as tablets, asset testing laptops, and protective relays are often disconnected from the main network, making them a prime channel for
CALISTO® R9
ADVANCEMENTS IN
spreading malware. Given that TCAs regularly contact critical assets, they’re a top security threat if not secured properly. Speed is of the essence when it comes to cybersecurity.
However, securing your assets shouldn’t hold productivity back. Look for systems you can tailor to secure the work processes that need defenses the most and streamline procedures from the field to the office. Tapping patch management software that easily shows the patch updates available to TCAs enables you to quickly select the updates you want and automatically downloads those installers to TCAs to be installed during remote updates. Patch management systems should also monitor, send alerts, and report on security risks, keeping you in a constant state of vigilance.
STAY PREPARED AND PROACTIVE
Cyber threats are fast moving and unpredictable. Utilities need to be armed and ready with the right tools and processes. While advanced
ADVANCEMENTS IN INDUSTRY
technology for threat identification and management is currently strongly encouraged by the Biden administration, it could soon become a requirement.
REFERENCES
1. Fortinet. 2022 State of Operational Technology and Cybersecurity Report. Accessed at https://www.fortinet.com/content/ dam/fortinet/assets/analyst-reports/report2022-ot-cybersecurity.pdf.
2. Whitehouse.gov. National Security Memorandum on Improving Cybersecurity for Critical Infrastructure Control Systems, 2021. Accessed at https://www. whitehouse.gov/briefing-room/statementsreleases/2021/07/28/national-securitymemorandum-on-improving-cybersecurityfor-critical-infrastructure-control-systems/
3. G. Meghan. What is the NIST Cybersecurity Framework? Verve Blog, 2022. Accessed at https://verveindustrial.com/resources/blog/ what-is-the-nist-cybersecurity-framework/.
4. Whitehouse.gov. Executive Order on Improving the Nation’s Cybersecurity, 2021. Accessed at https://www.whitehouse.gov/briefingroom/presidential-actions/2021/05/12/executiveorder-on-improving-the-nations-cybersecurity/
Bryan J. Gwyn is Senior Director of Solutions at Doble, with over 30 years of international experience in electric utility transmission and distribution protection and control and telecommunication engineering, operations and management. Leading a team of global subject matter experts, he is responsible for the development of protection, asset management, monitoring, and security solutions. Bryan received his BEng (Hons) in electrical and electronic engineering and his PhD at City University, London. He is a Chartered Engineer and a Senior Member of IEEE.
Sagar S. Singam is a Senior Cyber Security Engineer at Doble with more than 8 years of expertise in industrial and IT cybersecurity architecture. He obtained his MS in information assurance and cybersecurity from Regis University.
Introducing NETA Series III Handbooks
We’ve got answers. Discover page after page of comprehensive, component-specific, technical resources for training and reference purposes. Over 200 of the very best articles from NETA World Journal and technical presentations from NETA’s PowerTest conferences. To order, please visit netaworld.org or call 888.300.6382
GROUP CBS: PEOPLE, TECHNOLOGY, AND UPTIME
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.
Here, our continuing CAP Spotlight series talks to President Ashley Ledbetter about the thought leadership and subject-matter expertise of Group CBS.
NW: What are the biggest challenges facing your company right now?
Ledbetter: The most important assets we have are human assets. We can’t be successful without good people. Fortunately, we’ve always excelled at retaining our talent, but to produce, repair, or service the best electrical power distribution equipment for the world, we need to continue to grow. Our employees will be key to achieving that goal because, while we have many great ideas and plans, we’ll need fresh perspectives and creative approaches to move those innovative ideas forward.
NW: What are the biggest challenges facing your customers?
Ledbetter: Maximizing uptime is a continual goal for our customers. The challenge is building effective and efficient maintenance programs that align with their values and vision while keeping their workers and customers safe. Coupled with that, our customers must be able to find the critical equipment they need
to keep operations going. These are the areas where Group CBS excels. In today’s supply chain, Group CBS is one of the few vendors an electrical customer can call in the middle of the night for essential equipment and service. We are proud to serve as that dependable resource for our customers.
NW: Which industry trends are you keeping an eye on?
Ledbetter: One of the trends we’re watching closely is the evolving relationship between companies and employees. It is changing, and the key to navigating it will be finding the balance between achieving our corporate goals and simultaneously supporting the individual growth of each employee.
NW: Which new technologies affecting the industry are changing the way you work?
Ledbetter: Technology is advancing at a breakneck pace, and it’s exciting — from the internet and video meetings changing our
ASHLEY LEDBETTER
day-to-day work environment to advanced electronics and testing systems revolutionizing work in the field, such as using portable magnetrons to test a vacuum interrupter on site.
NW: What do you predict will impact your business most in the near future?
Ledbetter: One thing that is likely to impact our business is the workforce — attracting and retaining stellar talent. It is the most important aspect of our business — and that of our customers — today and tomorrow. To help support our customers in that endeavor as power distribution equipment in the field continues to age, we’re dedicated to developing and providing life extension solutions and other innovations to help customers keep the power flowing while preparing for future growth.
NW: Is this a good time to be in the electrical power testing business?
Ledbetter: Absolutely. Electric power is an essential resource. However, as we are all aware, the average age of installed equipment continues to increase. Testing is the only way to monitor the health of power distribution systems. With that in mind, electrical testing is and will remain an essential need for today’s world.
NW: If you could change one thing about how your business operates, what would it be?
Ledbetter: Helping our customers to be safer, more efficient, and more successful is our number-one goal, but sometimes the inherent silos in our industry stand in the way. If we can break down the walls between Group CBS and its customers, we can truly be a trusted partner, not just a vendor. Our mutual success depends on it.
NW: What advice do you have for young people entering the field?
Ledbetter: My recommendation for new entrants into the field is to be ready for change. It doesn’t happen overnight, but it’s coming.
New opportunities, disciplines, and specialties are on the horizon. For example, while test data improves every year, the expertise necessary to put the data into perspective is still evolving. Prepare for these eventualities and be ready for tomorrow’s opportunity.
NW: How important is mentoring in the electrical testing field and why?
Ledbetter: The value of mentoring cannot be overstated. Tribal expertise passed down person to person fills the gaps between theoretical knowledge and real-world experience. Technology and empirical data are important, but they can’t take the place of relationships.
NW: What strategies will keep professionals growing and learning?
Ledbetter: After many years or even decades in a particular industry, one must never be complacent. Resist the urge to rest on your laurels, and never think you know it all. There is always something new to learn, experience, or do — even if it’s outside your comfort zone.
Group CBS Team Dinner
NETA WELCOMES NEW ACCREDITED COMPANY — ELECTRO TEST
Electro Test LLC was founded in 2018 when Brad Helminen decided there were enough opportunities and an open market for NETA testing in Oahu and the surrounding Hawaiian Islands. Younger brother Jared decided he would also try his hand at running a business, and he and his family followed
Brad to the North Shore of Oahu to start the new testing company.
Brad and Jared were immediately involved in several projects that required NETA Certified Technicians and engineers because the complexity of some control systems was beyond the skill level of most electricians living in Hawaii. Jared and Brad built a reputation at several facilities on Oahu and the Outer Islands when people had electrical issues needing work and acceptance testing on new facilities. The Army Corps added Electro Test to a list of approved vendors, and all of the military installations began communicating with Electro Test when they had testing or troubleshooting needs. Since 2018, Brad, Jared, and the Electro Test crew have been involved in the start-up of new wind-farm substations, pumping stations, and several military installations.
Electro Test now has a permanent home in the center of the Island of Oahu in Wahiawa, Hawaii, that includes a large industrial shop with space to test off-site breakers and electrical devices.
“Electrical safety and testing standards in Hawaii have lagged behind mainland standards for decades,” notes Brad Helminen. “We are confident that Electro Test’s presence in Hawaii will help these industries keep pace with the modern world in the years to come.”
Brad and Jared Helminen are Electrical Engineers with degrees from Michigan Technological University. Jared is a licensed Professional Engineer in Michigan and Hawaii and has been a Level 3 NETA Technician since 2011. Brad holds a Master Electrician License and has been a Level 3 Certified NETA
Jesse, Jared, and Brad Helminen and Clifford Fa
Technician since 2009. Clifford Fa, a former car mechanic who worked with mechanical and electrical systems, was brought on board in October 2020 for his skills with everything mechanical. Jesse Helminen, the youngest brother, joined the team full-time after a six-month internship in May 2021. Jesse also holds a BS in electrical engineering from Michigan Technological University.
“NETA welcomes Electro Test LLC as a NETA Accredited Company,” says Eric Beckman, PE, President of National Field Services Inc. and current NETA President. “NETA Accredited Companies help advance the electrical power systems industry and ensure the safety and
reliability of the electrical power system. Achieving NETA accreditation requires dedication and persistence, and we congratulate Electro Test on achieving this milestone event.”
NETA ACTIVITIES UPDATE
NAMO COMMITTEE — U.S. ARMY PRIME POWER SCHOOL GRADUATION
August 25, 2022
Fort Leonard Wood, Missouri
Dave Kreger, member of the NETA NAMO Committee, attended the Prime Power School graduation in August. While there, Dave handed out certificates to the graduates and facilitated discussions regarding the NETA NAMO Program.
NETA BOARD AND MEMBER MEETINGS
September 15–16, 2022
Louisville, Kentucky
NETA’s fall board and member meetings held in Louisville, Kentucky, focused on association development, membership, PowerTest updates, certification, and standards development. The board meeting focused on budget and program initiatives for the upcoming fiscal year. A representative from the Kentucky Department of Labor facilitated a discussion regarding apprenticeship programs and fielded questions as to the concept of a NETA apprenticeship program.
ANSI/NETA STANDARDS UPDATE
ANSI/NETA MTS–2019 REVISION IN PROCESS
A standards revision is in process for ANSI/NETA–2019, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems to be released in March 2023. The initial ballot and public comment period ended on August 29, 2022. The Standards Review Council will review all comments for consideration by the end of October. A second ballot is scheduled for issue on November 11, 2022. The revised edition of ANSI/NETA MTS is scheduled to debut at PowerTest 2023 in Orlando, Florida.
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
SPECIFICATIONS AND STANDARDS
systems. The purpose of these specifications is to assure that tested electrical equipment and systems are operational and within applicable standards and manufacturers’ tolerances, and that the equipment and systems are suitable for continued service. ANSI/NETA MTS–2019 revisions include online partial discharge survey for switchgear, frequency of power systems studies, frequency of maintenance matrix, and more. ANSI/NETA MTS–2019 is available for purchase at the NETA Bookstore at www.netaworld.org.
ANSI/NETA ECS–2020 NEXT REVISION SCHEDULED
ANSI/NETA ECS, Standard for Electrical Commissioning of Electrical Power Equipment & Systems , will be revised following the American National Standard process. The next edition of the standard is scheduled to begin the American National Standard revision process in 2023, with a scheduled release in 2024. ANSI/NETA ECS–2020 supersedes the 2015 Edition.
ANSI/NETA ECS describes the systematic process of documenting and placing into service newly installed or retrofitted electrical power equipment and systems. This document shall be used in conjunction with the most recent edition of ANSI/NETA ATS, Standard for Acceptance Testing Specifications for Electrical Power Equipment & Systems The individual electrical components shall be subjected to factory and field tests, as required, to validate the individual components. It is not the intent of these specifications to provide comprehensive details on the commissioning of mechanical equipment, mechanical instrumentation systems, and related components.
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.
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.
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 ATS, Standard for Acceptance Testing Specifications for Electrical Power Equipment & Systems , 2021 Edition, completed an American National Standard revision process and was published in the spring of 2021.
ANSI/NETA ATS covers suggested field tests and inspections for assessing the suitability for initial energization of electrical power equipment and systems. The purpose of these specifications is to assure that tested electrical equipment and systems are operational, are within applicable standards and manufacturers’ tolerances, and are installed in accordance with design specifications.
ANSI/NETA 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 ETT–2022
LATEST EDITION
ANSI/NETA ETT, Standard for Certification of Electrical Testing Technicians , completed the American National Standard revision process. ANSI administrative approval was granted January 7, 2022. The new edition was released at PowerTest in March 2022 and supersedes the 2018 edition.
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.
NFPA 70B UPDATE
BY DAVID HUFFMAN, Power Systems Testing Company
The NFPA 70B Committee met via online video calls to review the public inputs on the Second Draft. This meeting was held between April 25–29 2022. Several task groups held side meetings — some late at night and others very early in the morning — to complete the proposed responses to each input.
Balloting for the Second Draft 70B closed on August 16, 2022. The report on balloting will be issued November 2, 2022. The committee will be scheduling meetings after this time.
The Motions Committee Report (NITMAM) will close on November 30, 2022. A report on
this will be posted January 11, 2023. Although there are no scheduled meetings at this time, I anticipate a meeting sometime in the spring or summer of 2023.
David Huffman has been with Power Systems Testing, a NETA Accredited Company, since January 1988 and is currently CEO. He graduated from California State University, Fresno, and is a licensed Professional Electrical Engineer in the state of California as well as a NETA Level IV Certified Technician. David is a member of the NETA Board of Directors, NETA’s Principal Representative to the NFPA 70B Committee, and serves as a member of various NETA committees.
ANSWERS
1. a. A localized electrical discharge that only partially bridges the insulation. These PD events generate a current pulse. During off-line PD cable testing, the current pulses are sensed and plotted by the PD measuring instrument. These measurements are then analyzed to determine issues within the cable.
EASTERN
2. d. a & b. PD testing requires a shielded cable for proper uniform voltage application across the cable insulation.
3. d. All of the above. All of these may be reasons the cable is not suitable for off-line PD testing. The cable might be too long for the PD signal to travel the length of the cable; excessive electrical noise may interfere with the ability to detect PD; and resistive shield connections might result in attenuation.
PREVENTATIVE ELECTRICAL MAINTENANCE PROGRAMS
DATA CENTERS, COMMERICAL HIGH RISES, CRITICAL ENVIRONMENTS & FINANCIAL INSTITUTIONS
DEVELOPMENT & UPDATES OF ELECTRICAL SINGLE LINE DIAGRAMS
SITE SPECIFIC SAFETY & TECHNICAL TRAINING 24HR EMERGENCY SERVICE
INFRARED SCANNING
ACCEPTANCE TESTING
ENGINEERING STUDIES · ARC FLASH, SHORT CIRCUIT & COORDINATION
4. c. PD measuring instrument, VLF hipot, and a parallel coupling capacitor. The VLF hipot is used to apply the AC waveform. Then, partial discharge is recorded as high-frequency signals through the coupling capacitor circuit into the PD measuring instrument.
5. b. Pico-coulombs (pC). The apparent charge of a PD event is typically measured in Picocoulombs.
6. b. No. The PD measuring instrument will record high-frequency signals, which could also include electrical noise or corona discharges. Once the data recording has been completed, the data must be reviewed to categorize it and determine whether there are any concerning PD data points. Upper and lower recording limits can be set during calibration to record the most advantageous spectrum to capture concerning PD data.
ABM Electrical Power Services, LLC
720 S Rochester Suite A Ontario, CA 91761-8177 (301) 397-3500 www.abmpowerservice.abm.com
ABM Electrical Power Services, LLC 6541 Meridien Dr Suite 113 Raleigh, NC 27616 (919) 877-1008 brandon.davis@abm.com www.abmpowerservice.abm.com 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 www.abmpowerservice.abm.com
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.abmpowerservice.abm.com
Paul McKinley
ABM Electrical Power Solutions 4390 Parliament Place Suite S Lanham, MD 20706 (240) 487-1900 www.abmpowersolution.abm.com
ABM Electrical Power Solutions 3700 Commerce Dr # 901-903 Baltimore, MD 21227-1642 (410) 247-3300 www.abmpowersolution.abm.com
NETA ACCREDITED COMPANIES
ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638
ABM Electrical Power Solutions 814 Greenbrier Cir Ste E Chesapeake, VA 23320-2643 (757) 364-6145
Advanced Testing Systems 15 Trowbridge Dr Bethel, CT 06801-2858 (203) 743-2001 pmaccarthy@advtest.com www.advtest.com
Pat McCarthy
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
Alpha Relay and Protection Testing, LLC 2625 Overland Ave Unit A Billings, MT 59102 (406) 671-7227
zfettig@arptco.com www.arptco.com
Zeb Fettig
American Electrical Testing Co., LLC 25 Forbes Boulevard Suite 1 Foxboro, MA 02035 (781) 821-0121 www.aetco.us
Jason Briggs
American Electrical Testing Co., LLC 5540 Memorial Rd Allentown, PA 18104 (484) 538-2272 jmunley@aetco.us www.aetco.us
American Electrical Testing Co., LLC 34 Clover Dr South Windsor, CT 06074-2931 (860) 648-1013 jpoulin@aetco.us www.aetco.us
Gerald Poulin
American Electrical Testing Co., LLC 76 Cain Dr Brentwood, NY 11717-1265 (631) 617-5330 bfernandez@aetco.us www.aetco.us
Billy Fernandez
American Electrical Testing Co., LLC 91 Fulton St., Unit 4 Boonton, NJ 07005-1060 (973) 316-1180 jsomol@aetco.us www.aetco.us
Jeff Somol
AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 brian@ampqes.com
Brian Rodgers
AMP Quality Energy Services, LLC 41 Peabody Street Nashville, TN 37210 (629) 213-4855
Nick Tunstill
Apparatus Testing and Engineering 11300 Sanders Dr Suite 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 jcarr@apparatustesting.com www.apparatustesting.com
Jerry Carr
Apparatus Testing and Engineering
7083 Commerce Cir Ste H Pleasanton, CA 94588-8017 (916) 853-6280
jcarr@apparatustesting.com
www.apparatustesting.com
Jerry Carr
Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108
michel.c@aec-us.com
www.aec-us.com
Michel Castonguay
Applied Engineering Concepts 9235 Activity Road San Diego, CA 92126 (619) 822-1106 michel.c@aec-us.com www.aec-us.com
Michel Castonguay
ARM CAMCO, LLC
667 Industrial Park Road Ebensburg, PA 15931 (814) 472-7980
acct@armcamco.net
Sam Morello
BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800
ddevlin@banaelectric.com www.bectesting.com
Blue Runner Switchgear Testing, LLC 924 Highway 98 East Suite C-200 Destin, FL 32541 (270) 590-4974
Tony Demaria Electric, Inc. 131 W F St Wilmington, CA 90744-5533 (310) 816-3130
neno@tdeinc.com www.tdeinc.com
Neno Pasic
Utilities Instrumentation Service, Inc. 2290 Bishop Cir E Dexter, MI 48130-1564 (734) 424-1200
gary.walls@UIScorp.com www.uiscorp.com
Gary Walls
Utilities Instrumentation Service - Ohio, LLC 998 Dimco Way Centerville, OH 45458 (937) 439-9660 www.uiscorp.com
Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 accounting@utilserv.com www.utilserv.com Accounts Payable
VISTAM, Inc. 2375 Walnut Ave Signal Hill, CA 90755 (562) 912-7779 ulyses@vistam.com
E L E C T R I C A L EQUIPMENT?
h e
Ta p i n t o t h e p ow er o f N a t i o n a l Sw i t c h gea r
a t na t iona lswi t c h gea r. com o r
c a l l u s t od ay at ( 8 00) 322-0149 .
A quality leap through system-based protection testing
System-based protection testing – something new again? Yes, absolutely. This innovative approach makes it possible to check that the entire protection system works correctly, thus increasing the testing quality. Instead of validating individual relay settings, RelaySimTest simulates realistic scenarios in the energy system to reveal errors in the settings, the logic and the design of the protection system.
