INVESTIGATING AN ELECTROMECHANICAL DIFFERENTIAL RELAY MISOPERATION PAGE 52
TESTING TECHNIQUES FOR PROTECTION-CLASS CURRENT TRANSFORMERS PAGE 62
TESTING AND COMMISSIONING A DISTRIBUTION RECLOSER IN GRID-TIE SOLAR FARMS PAGE 72
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COVER STORY
Challenges in Transformer Protection Testing
While the basic premise of transformer differential protection is straightforward, features found in relay algorithms compensate for challenges presented by the transformer differential application. This article describes typical functional differential tests and their challenges and presents a system-based alternative that reduces challenges and ensures settings are adequate. Instructions for setup and execution are accompanied by test cases, and the benefits and drawbacks of systembased testing are compared.
Scott Cooper, OMICRON electronics
FEATURES
52 Investigating an Electromechanical Differential Relay Misoperation
Alex Rangel, Saber Power Services, LLC
62 Testing Techniques for Protection-Class Current Transformers
Dinesh Chhajer and Sughosh Kuber, Megger USA
72 Testing and Commissioning a Distribution Recloser in Grid-Tie Solar Farms
Mohit Sharma, Megger, and Luis Montoya, PE, FlexGen Power Systems formerly ABM
Scott Blizard, American Electrical Testing Co., LLC
NFPA 70E and NETA
Looking at NFPA 70E 2021 — Part 1
Ron Widup and James R. White, Shermco Industries
Combustion Turbine Generator Trip Analysis
Steve Turner, Arizona Public Service Company
Basic Fall Protection
Paul Chamberlain, American Electrical Testing Co., LLC 30 Tech Quiz
Ground Testing Procedures
Jeff Jowett, Megger
84 Impact of SFRA Setup Issues on Transformer Frequency Response
Michael D. Wolf, PE, Doble Engineering Co.
92 Understanding and Avoiding Battery Failure
Rodrick J. Van Wart, AVO Training Institute, Inc.
98 Advancements in the Industry
PF Measurements on Complete Stator Windings
Mathieu Lachance, OMICRON electronics Canada
108 Insights & Observations — CAP Spotlight
AEMC Instruments: Over 125 Years of Technical Heritage and Innovation in Test Instrumentation SPECIFICATIONS
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NETA Officers
pResiDent: Scott Blizard, American Electrical Testing Co., Inc.
fiRst vice pResiDent: Eric Beckman, National Field Services
secOnD vice pResiDent: Scott Dude, Dude Electrical Testing, LLC
secRetaRy: Dan Hook, Western Electrical Services, Inc.
tReasuReR: John White, Sigma Six Solutions, Inc.
NETA Board of Directors
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Eric Beckman (National Field Services)
Scott Blizard (American Electrical Testing Co., Inc.)
Jim Cialdea (CE Power Engineered Services, LLC)
Scott Dude (Dude Electrical Testing LLC)
Dan Hook (Western Electrical Services, Inc.)
David Huffman (Power Systems Testing)
Alan Peterson (Utility Service Corporation)
Chasen Tedder, Hampton Tedder Technical Services
John White (Sigma Six Solutions)
Ron Widup (Shermco Industries)
nOn-vOting bOaRD membeR
Lorne Gara (Shermco Industries)
NETA World Staff
technicaL eDitORs: Roderic L. Hageman, Tim Cotter
assistant technicaL eDitORs: Jim Cialdea, Dan Hook, Dave Huffman, Bob Sheppard
assOciate eDitOR: Resa Pickel
managing eDitOR: Carla Kalogeridis
cOpy eDitOR: Beverly Sturtevant
aDveRtising manageR: Laura McDonald
Design anD pRODuctiOn: Moon Design
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cOnfeRence: Ron Widup; membeRship: Ken Bassett; pROmOtiOns/maRketing: Scott Blizard; safety: Scott Blizard and Jim White; technicaL: Alan Peterson; technicaL exam: Dan Hook; cOntinuing technicaL DeveLOpment: David Huffman; tRaining: Eric Beckman; finance: John White; nOminatiOns: Alan Peterson; aLLiance pROgRam: Jim Cialdea; assOciatiOn DeveLOpment: Ken Bassett and John White
NETA World is published quarterly by the InterNational Electrical Testing Association. Opinions, views and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees or agents (herein “NETA”).
All technical data in this publication reflects the experience of individuals using specific tools, products, equipment and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA.
NETA MAKES NO ENDORSEMENT, REPRESENTATION OR WARRANTY AS TO ANY OPINION, PRODUCT OR SERVICE REFERENCED OR ADVERTISED IN THIS PUBLICATION. NETA EXPRESSLY DISCLAIMS ANY AND ALL LIABILITY TO ANY CONSUMER, PURCHASER OR ANY OTHER PERSON USING ANY PRODUCT OR SERVICE REFERENCED OR ADVERTISED HEREIN FOR ANY INJURIES OR DAMAGES OF ANY KIND WHATSOEVER, INCLUDING, BUT NOT LIMITED TO ANY CONSEQUENTIAL, PUNITIVE, SPECIAL, INCIDENTAL, DIRECT OR INDIRECT DAMAGES. NETA FURTHER DISCLAIMS ANY AND ALL WARRANTIES, EXPRESS OF IMPLIED, INCLUDING, BUT NOT LIMITED TO, ANY IMPLIED WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE.
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WELCOME TO THE WINTER EDITION
This edition of NETA World features articles on electrical power system protection. Protection schemes covering feeder, generation, transmission, and transformers may have many similarities, but they often contain specific functions or schemes unique to that type of equipment.
Be sure you check out this edition’s four feature articles:
• “Challenges in Transformer Protection Testing,” by Scott Cooper of OMICRON electronics
• “Testing Techniques for Protection-Class Current Transformers,” by Dinesh Chhajer and Sughosh Kuber, Megger USA
• “Testing and Commissioning a Distribution Recloser in Grid-Tie Solar Farms,” by Mohit Sharma of Megger and Luis Montoya, PE, of FlexGen Power Systems, formerly ABM
• “Investigating an Electromechanical Differential Relay Misoperation,” by Alex Rangel of Saber Power Services, LLC
It is presently October 2020, and the country is in the middle of a COVID-19 virus resurgence. NETA Member Companies and their technicians throughout the United States and in Canada have been identified as essential workers as they help support and maintain our nation’s critical infrastructure. Be sure to follow your company’s and customers’ safety policies for the COVID-19 pandemic. The policy should include many of the preventative measures to limit the spread of the COVID-19 virus that have been communicated by the CDC in the United States and by the Public Health Agency of Canada. Be safe, and err on the side of caution.
Mark your calendars for PowerTest 2021, the premier electrical maintenance and safety conference on March 8–12, 2021. This will be the first hybrid conference in NETA’s history! If you are unable to attend PowerTest 2021 in person, NETA will provide an opportunity to attend virtually. This portion of the event will allow people to interact on a web-based platform rather than meeting in a physical location. Online sessions will include feature webinars and webcasts as well as opportunity for NETA Certified Technicians to receive CTDs for attending virtually. Call the NETA office for details on CTD and CEU credits offered for attending the virtual portion of PowerTest 2021. Be sure you register to ensure a spot among the leaders in the electrical testing industry.
Coach safe behavior….Live injury and disease free every day!
Scott A. Blizard, President International Electrical Testing Association
Safety First…No One Gets Hurt!
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LOOKING AT NFPA 70E 2021: PART 1
BY RON WIDUP and JAMES R. WHITE, Shermco Industries
In this issue of NETA World, we begin to explain some of the major changes in the 2021 edition of NFPA 70E. So whether you love the 70E, or find it a challenge and don’t want to deal with it…because your life at work is mandated by it, and you know what that means: Do it or else!
So familiarize yourself with the latest changes to the 2021 edition of the 70E. Here are a few of the changes.
ARTICLE 100
There are very few revisions in Article 100, Definitions. Let’s start with a definition that has not changed: Arc Rating. The important portion of the definition is in Informational Note No. 1:
But that is not the case. NFPA 70E is a standard and is not mandatory. However, your company has the option of making parts of it their policy, which would then be mandatory for you. Companies often adopt all or part of the 70E because the 70E Committee includes representatives from 26 companies, including NETA, in the formation of the content for the standard, and it contains the latest thinking and information available concerning electrical safety and safe work practice. Your company wants you to go home to your family uninjured. NFPA 70E only covers electrical safety and nothing else.
• Informational Note No. 1: Arc-rated clothing or equipment indicates that it has been tested for exposure to an electric arc. Flame resistant clothing without an arc rating has not been tested for exposure to an electric arc. All arc-rated clothing is also flame-resistant
Some technicians or purchasing agents have purchased the incorrect clothing, thinking it was arc rated, only to find out it is for flash fires (refineries and pipelines). Clothing and PPE rated for an arc flash has a tag on the inside of the clothing similar to Figure 1, which is from Oberon, a major supplier of arc-rated clothing and PPE.
The familiar tag in Figure 2 causes some confusion, since it seems to be for arcrated clothing; it even shows an arc thermal performance value (ATPV). The tag references NFPA 2112, which is a valid standard, but not for arc-rated clothing or PPE. NFPA 2112 is for flash fires, and that type of clothing is required for petrochemical facilities. This clothing, if properly marked, could be dualrated as arc-rated and for flash fires, but both would need to be shown on the label.
Look for these numbers when purchasing clothing or PPE:
• NFPA 70E, of course
• NFPA 2112: flash fires only
• ASTM F1506: arc-rated clothing always marked with ASTM F1506, may also be marked ASTM F1509/F1509M, and be dual-rated with NFPA 2112 if properly marked
• ASTM F2178/2178M: arc-rated face shields, balaclavas, and hoods
• ASTM F1891: arc-rated rainwear
• ASTM F2675/2675M: arc-rated hand protection
• CSA Z462: Canada’s NFPA 70E-equivalent standard
THE NFPA 70E AND NETA
ASTM F1506-10a Performance Standard
PPE Selection
Advice: If the garment states compliance with ASTM F1506-10a but the label is not correct, buyer beware!
Definition Revisions
Revisions to NFPA 70E are shown in legislative text: Deleted language is shown in red and crossed through, and added text is shown underlined. All definitions are in Article 100, Definitions.
Deleted. The definitions for Accessible, Readily Accessible, and Branch Circuit were deleted. None were used in NFPA 70E.
Arc Rating. Although the definition for arc rating did not change, revisions were made to the Informational Notes to make them consistent with ASTM language and to provide clarity:
ASTM F1506-10a
6.3 Garments shall be labeled with the following information:
6.3.1 Tracking identification code system,
6.3.2 Meets requirement of Performance
Specification F1506,
6.3.3 Manufacturer’s name,
6.4.4 Size and other associated standard labeling,
6.3.5 Care instructions and fiber contents, and
6.3.6 Arc rating (ATPV) or arc rating (Ebt)
Figure 1: ASTM F1506-Required Label
Figure 2: Confusing Label — Not Arc-Rated
THE NFPA 70E AND NETA
• The previous content in Informational Note No. 2 was moved to Informational Note No. 3: Breakopen is a material response evidenced by the formation of one or more holes in the innermost layer of arc-rated material that would allow flame to pass through the material.
• Informational Note No. 2: ATPV is defined in ASTM F1959/F1959M, Standard Test Method for Determining the Arc Rating of Materials for Clothing, as the incident energy (cal/cm2) on a material or a multilayer system of materials that results in a 50% probability that sufficient heat transfer through the tested specimen is predicted to cause the onset of a second degree skin burn injury based on the Stoll curve.
• Informational Note No. 3: EBT is defined in ASTM F1959/F1959M, Standard Test Method for Determining the Arc Rating of Materials for Clothing, as the incident energy (cal/cm2) on a material or a material system that results in a 50 percent probability of breakopen. Breakopen is defined as a hole with a material response evidenced by the formation of one or more holes of a defined size [an area of 1.6 cm2 (0.5 in.2) or an opening of 2.5 cm (1.0 in.) in any dimension] in the innermost layer of arcrated material that would allow thermal energy to pass through the material.
Balaclava. (Sock Hood): An arc-rated hood head-protective fabric that protects the neck and head except for a small portion of the facial area of the eyes and nose
Informational Note: Some balaclava designs protect the neck and head area except for the eyes while others leave the eyes and nose area unprotected.
Figure 3 shows a typical balaclava. Note that a properly fitted balaclava will not be tight, but will fit loosely, as shown. A tight-fitting balaclava will reduce the arc rating. Many companies we’ve visited had only one balaclava for all their qualified persons. This is incorrect and places their workers at risk.
Not all balaclavas are arc-rated. A balaclava is any type of head covering that has an opening for the face and/or eyes. A ski mask is considered a type of balaclava. A visit to any of the Internet providers will show a wide variety of balaclavas that are not arc-rated, but wool. Wool would be fuel for the fire.
Barrier. A physical obstruction that is intended to prevent contact with equipment or energized electrical conductors and circuit parts or to prevent unauthorized access to a work area. The Committee believed the last portion of the definition was unnecessary.
Electrically Safe Work Condition.
An Informational Note was added for Electrically Safe Work Condition.
• Informational Note: An electrically safe work condition is not a procedure, it is a state wherein all hazardous electrical conductors or circuit parts to which a worker might be exposed are maintained in a de-
Figure 3: Balaclava and Arc-Rated Face Shield
energized state for the purpose of temporarily eliminating electrical hazards for the period of time for which the state is maintained.
Informational Notes are not mandatory but contain information directly related to whatever it may be part of. This Informational Note states that putting equipment into an electrically safe work condition is not a procedure; it is a process, which is ongoing. The purpose is to maintain a deenergized state to protect the worker. The word “temporary ” and the phrase “ for the period of time for which the state is maintained” were added to emphasize that this is not a permanent change; it is only in effect during the task being performed and will be returned to its normal, energized state.
This is Second Revision language. In the First Revision, the language was somewhat different. This type of revision happens often during the meetings. A change will be made during the First Revision; then, a Public Comment will come in and a change will be voted to make further revisions in the Second Revision.
Fault Current Available. An additional Informational Note No. 3 was added to the definition for Fault Current, Available:
• Informational Note No. 3: The available fault current varies at different locations within the system due to the location of sources and system impedances.
Of course, any impedances in the path of the fault current will reduce it, sometimes by quite a bit. It depends on the impedance.
Receptacle. A receptacle is a contact device installed at the outlet for the connection of an attachment plug, or for the direct connection of electrical utilization equipment designed to mate with the corresponding contact device. A single receptacle is a single contact device with no other contact device on the same yoke. A multiple receptacle is two or more contact devices on the same yoke. [70:100]
THE NFPA 70E AND NETA
When a definition is used in the NEC (NFPA 70), it will be noted at the end of that definition as [70:100] where 100 is the NEC Article it will appear in.
Switchgear Equipment , Arc-Resistant. Equipment designed to withstand the effects of an internal arcing fault and that directs the internally released energy away from the employee.
A number of revisions were made to this definition. First, the name was changed to acknowledge that more types of arc-rated equipment are being manufactured.
Two new Informational Notes provide where to obtain more information.
• Informational Note No. 1: An example of a standard that provides information for arc-resistant equipment is IEEE C37.20.7, Guide for Testing Switchgear Rated Up to 52 kV for Internal Arcing Faults.
• Informational Note No. 2: See O.2.4 (9) for information on arc-resistant equipment.
Voltage, Nominal. A new Informational Note was added to this definition.
• Informational Note No. 3: Certain battery units are rated at nominal 48 volts dc but have a charging float voltage up to 58 volts. In dc applications, 60 volts is used to cover the entire range of float voltages.
Pretty self-explanatory, although note that OSHA considers 50 volts and above as an electrical hazard. OSHA has stated they will not accept higher voltages, even if they are in a standard.
Working on Electrical Conductors or Circuit Parts.
Intentionally coming in contact with energized electrical conductors or circuit parts with the hands, feet, or other body parts, with tools, probes, or with test equipment, regardless of the personal protective equipment (PPE) a person is wearing. There are two categories of “working on”: Diagnostic (testing) is taking readings or measurements of electrical equipment, conductors,
THE NFPA 70E AND NETA
USE THIS SIMPLE METHOD TO SEPARATE DIAGNOSTICS FROM REPAIR: IF ONLY A TEST INSTRUMENT IS USED, IT IS DIAGNOSTIC. IF A TOOL IS BEING USED, IT IS REPAIR.
or circuit parts with approved test equipment that does not require making any physical change to the electrical equipment, conductors, or circuit parts. repair Repair is any physical alteration of electrical equipment, conductors, or circuit parts (such as making or tightening connections, removing or replacing components, etc.).
There are no major revisions to this definition, except to separate the two categories of “working on” — diagnostic (testing) and repair — to clarify their differences. It is worthwhile to mention that any change to a piece of equipment, even tightening screws on a terminal block, would be considered repair. This is brought up because some supervisors and technicians don’t believe that tightening screws is repair. Use this simple method to separate diagnostics from repair; If only a test instrument is used, it is diagnostic. If a tool is being used, it is repair.
Figure 4a and Figure 4b show an event caused by this misunderstanding of the definition. The supervisor had to leave for another part of the job. The apprentice technician was told only to tighten things “that were not hot.” The apprentice mistakenly used a 1,000-volt-rated tester to test a 4,160-volt potential transformer (PT) to see if it was energized. Things did not go well, and the apprentice suffered serious burns.
A LITTLE REORGANIZATION,
AGAIN
NFPA 70E again reorganized to make 70E easier to use and to place information in its proper place.
Article 110 includes some major changes:
• 110.1 Priority (used to be 105.4)
• 110.2 General [used to be 120.2(A)]
• 110.3 (used to be 130.2) Electrically Safe Work Condition
• 110.4 [used to be 130.2(A)] Energized Work
• 110.5(A) (used to be 110.1) Electrical Safety Program
• 110.6 (used to be 110.2) Training Requirements
• 110.7 (used to be 110.3) Host and Contract Employer’s Responsibilities
• 110.8 [used to be 110.4(A)] Testing Instruments and Equipment
• 110.9 (used to be 110.5) Portable Cordand Plug-Connected Equipment
Figure 4a: What He Tested
Figure 4b: What He Should Have Tested
• 110.10 (used to be 110.6) Ground-Fault Circuit-Interrupter (GFCI) Protection
• 110.11 (used to be 110.7) Overcurrent Protection Modification.
• 110.12 (new) Equipment Use
Article 130 also saw some major reorganizational changes:
• 130.1 General
• 130.2 Energized Electrical Work Permit
• 130.3 Open
• 130.4 Shock Risk Assessment
• 130.5 Arc Flash Risk Assessment
• 130.6 Open
• 130.7 Personal and Other Protective Equipment
• 130.8 Other Precautions for Personnel Activities
• 130.9 Work Within the Limited Approach Boundary or Arc Flash Boundary of Overhead Lines
• 130.10 Underground Electrical Lines and Equipment
• 130.11 Cutting and Drilling
• 130.12 Cutting, Removing or Rerouting of Conductors
At this point, NFPA staff could leave 130.3 and 130.6 open, or they could decide to renumber the entire article(s). The NFPA Manual of Style allows articles to be left open for future use. The only way to be sure is to view the actual 2021 70E. Readers will have to do what everyone else will do: Wait and see.
Deep Dive. Section 110.1 Priority was moved from Article 105 to bring more prevalence to it. The Committee believed it was a better fit in 110, as we did with the other changes in section order. Some changes were made to its Informational Note:
0 Section 110.1 Priority
Hazard elimination shall be the first priority in the implementation of safety-related work practices.
0 Informational Note No. 2: An electrically safe work condition is a state wherein all hazardous electrical conductors or circuit parts to which a worker might be exposed are placed and maintained in a zeroenergy de-energized state, for the purpose of temporarily eliminating electrical hazards. See Article 120 for requirements to establish an electrically safe work condition for the period of time for which the state is maintained. See Informative Annex F for information regarding the hierarchy of risk control and hazard elimination.
Committee Statement
An example of a Committee statement is shown below. This is not done for every revision; it is only shown as an example of how the Committee justifies the revisions made.
This second revision improves clarity in the informational note by replacing the undefined term “zero energy” with the defined term “deenergized.” In addition, language is added to clarify that elimination is achieved by disconnecting and isolating from energy sources all electrical conductors or circuit parts to which a worker might be exposed in the area where work is to take place. Additionally, it is clarified that this de-energization is a temporary state and exists only during the period for which the electrically safe work condition state is maintained. This informational note correlates with the purpose of NFPA 70E which is to provide a “practical” safe working area for employees relative to the hazards arising from the use of electricity.
Some of the revisions being made are from the First Revision based on Public Comments or Committee discussions. This is a fairly common occurrence and demonstrates the thought (and discussions) that go into all Public Inputs and Public Comments. We always have a reason for
THE NFPA 70E AND NETA
a revision. It isn’t done on a whim or without thought and discussion.
The Second Revision version of NFPA 70E and all Committee Statements are available on www.NFPA.org/70E/nextedition . The First Revision is only available during the Public Comment period. People ask why the Committee takes some action, and the comments are there to answer that question.
CONCLUSION
This column has tried to explain some of the workings of the NFPA 70E Committee. The work is certainly not taken lightly by the Committee members. We make all efforts to ensure the 70E is easier to use, clearer on its intent, and contains the most effective safety requirements.
The changes made to the 2021 edition on NFPA 70E are not as far-reaching as those in the 2015 and 2018 editions. The above
revisions and their explanations are only the beginning of this series of columns explaining the revisions made for the 2021 edition. Some of the changes are covered in this article. Part 2 in the Spring 2021 issue will cover additional detail, and more information will be presented in this ongoing series of 70E & NETA columns. We hope this is helpful to all our readers, many of whom depend on NFPA 70E for their jobs.
We hope it helps the field technicians, owners, and supervisors of both NETA accredited companies and non-NETA entities understand and interpret NFPA 70E better. Following the requirements of the 70E, whether mandated or not, will prevent injuries and possible fatalities.
REFERENCES
Joseph J. Andrews, PE. “Case History — Who’s at Fault?” Electrical Safety Resources, Inc. IEEE Electrical Safety Workshop 2002.
Ron Widup and Jim White are NETA’s representatives to NFPA Technical Committee 70E, Electrical Safety Requirements for Employee Workplaces. Both gentlemen are employed by Shermco Industries in Dallas, Texas, a NETA Accredited Company.
Ron Widup, Senior Advisor, Technical Services and Vice Chairman of the Board of Directors, has been with Shermco Industries since 1983. He is a member of Technical Committee on NFPA 70E, Electrical Safety in the Workplace; a Principal Member of National Electrical Code (NFPA 70) Code Panel 11; a Principal Member of the Technical Committee on NFPA 790, Standard for Competency of Third-Party Evaluation Bodies; a Principal Member of the Technical Committee on NFPA 791, Recommended Practice and Procedures for Unlabeled Electrical Equipment Evaluation; a member of the Technical Committee on NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, and Vice Chair for IEEE Std. 3007.3, Recommended Practice for Electrical Safety in Industrial and Commercial Power Systems. Ron also serves on NETA’s board of directors and Standards Review Council. He is a NETA Certified Level 4 Senior Test Technician, a State of Texas Journeyman Electrician, an IEEE Standards Association member, an Inspector Member of the International Association of Electrical Inspectors, and an NFPA Certified Electrical Safety Compliance Professional (CESCP).
James (Jim) R. White, Vice President of Training Services, has worked for Shermco Industries since 2001. He is a NFPA Certified Electrical Safety Compliance Professional and a NETA Level 4 Senior Technician. Jim is NETA’s principal member on NFPA Technical Committee NFPA 70E®, Electrical Safety in the Workplace; NETA’s principal representative on National Electrical Code® Code-Making Panel (CMP) 13; and represents NETA on ASTM International Technical Committee F18, Electrical Protective Equipment for Workers. Jim is Shermco Industries’ principal member on NFPA Technical Committee for NFPA 70B, Recommended Practice for Electrical Equipment Maintenance and represents AWEA on the ANSI/ISEA Standard 203, Secondary Single-Use Flame Resistant Protective Clothing for Use Over Primary Flame Resistant Protective Clothing. An IEEE Senior Member, Jim was Chairman of the IEEE Electrical Safety Workshop in 2008 and is currently Vice Chair for the IEEE IAS/PCIC Safety Subcommittee.
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.
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COMBUSTION TURBINE GENERATOR TRIP ANALYSIS
BY STEVE TURNER, Arizona Public Service Company
Relay personnel responsible for testing protective relays are often called upon to troubleshoot and gather system data such as settings and event recordings when a major event occurs (for this example, a large generator trip). If only electromechanical relays are installed and no digital fault recorder is available, it can be difficult to determine the root cause of the trip event. This article demonstrates how to analyze a generator trip with limited information on hand.
ANALYSIS
The initial investigation determined there was a three-phase bus fault on the low side of the generator step-up transformer (GSU). Follow-up investigation through data analysis determined there were four individual events.
Figure 1 shows the sequence of events captured by the numerical line current differential relays located at the high side of the generator GSU and switchyard breaker. The first event occurred at 19:02:56 and was due to a three-phase bus fault. The
Figure 1: Sequence of Events Compiled from Numerical Line Current Differential Relays
RELAY COLUMN
second and third events occurred at 19:09:17 and 19:20:32, respectively. The fourth event occurred at 19:24:56. This time, the switchyard breaker was successfully closed, energizing the adjacent GSU.
SEQUENCE OF EVENTS
Figure 2 shows the overall one-line diagram for the power system.
Figure 3a through Figure 3e illustrate the sequence of events leading up to the restoration of the adjacent generator.
The adjacent generator was brought back on gear at time equal to 19:28:35.
Figure 4 shows the inrush current measured by the numerical line current differential relays following closing the switchyard breaker.
Figure 2: One Line Diagram
Figure 3c: Disconnect on High Side of Adjacent GSU Opened
Figure 3a: Three-Phase Bus Fault on GSU Low Side
Figure 3d: Lockout Relay Reset
Figure 3b: Direct Transfer Trip to Switchyard Breaker via Numerical Line Current Differential Relays
Figure 3e: Switchyard Breaker Closed
CONCLUSION
Advantages offered by numerical protection relays include:
• Event reporting
• Event summary reports
• Event history reports
• Event reports
• Sequential events recorder report
This article demonstrates how the event recording taken from the numerical line current differential relays protecting the line to the faulted GSU can be used to verify that the overall system protection operated properly.
Steve Turner is in charge of system protection for the Fossil Generation Department at Arizona Public Service Company in Phoenix. After working with Beckwith Electric Company, Inc. for 10 years, Steve spent two years as a consultant in San Diego. His previous experience includes positions as an Application Engineer at GEC Alstom and in the international market for SEL focusing on transmission line protection applications. Steve also worked for Duke Energy (formerly Progress Energy), where he developed the first patent for double-ended fault location on overhead high-voltage transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has BSEE and MSEE degrees from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and a member of the IEEE PSRC.
Figure 4: Inrush Current Following Closing Switchyard Breaker
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BASIC FALL PROTECTION
BY PAUL CHAMBERLAIN, American Electrical Testing Co. LLC
Fall protection requirements and equipment varies depending upon where the work is being performed. The regulations can be confusing for some employees, so it is up to the manager or safety professional to understand the work, the environment the work is being performed in, and the equipment needed to mitigate the hazard of falling from height.
WHEN IS PROTECTION REQUIRED?
In general industry, which the Occupational Safety and Health Administration (OSHA) defines as all industries not included in agriculture, construction, or maritime, fall protection is required anytime there is a fall of 4 feet or more from an unprotected edge or side. In summary:
1910.28(b)(1)(i)
Except as provided elsewhere in this section, the employer must ensure that each employee on a walking-working surface with an unprotected side or edge that is 4 feet (1.2 m) or more above a lower level is protected from falling by one or more of the following:
(a) Guardrail systems;
(b) Safety net systems; or
(c) Personal fall protection systems, such as personal fall arrest, travel restraint, or positioning systems.
In most cases, since general industry is NOT a construction environment, fall protection is provided using guardrails that are required as part of building code. OHSA and building codes are very specific about how these
guardrails are constructed. They must consist of a top rail, mid-rail, or balusters, and a toe-board. Code requires they be a certain height, withstand a certain weight load, and be constructed in a specific manner. Since the building you are working in is not under construction, guardrails are likely in place. If there are no guardrails, then a safety net or personal fall protection system (i.e. anchorage, lanyard, or harness) is required.
In construction, which OSHA defines as construction work, alteration, and/or repair, including painting and decorating, the requirements for fall protection are slightly different.
191026.501(b)(1)
Each employee on a walking/working surface (horizontal and vertical surface) with an unprotected side or edge which is 6 feet or more above a lower level shall be protected from falling by the use of guardrail systems, safety net systems, or personal fall arrest systems.
Unlike in general industry, the construction standard for OSHA requires protection of a side 6 feet or more above a lower level. The means and methods of protection have not
changed; you can still use guardrails, personal fall protection, or safety nets. However, the height at which height protection becomes required has changed. It is worthwhile to mention that OSHA 1910.269, Power Generation, Transmission and Distribution generally follows the construction standard for fall protection (1926 Subpart M) with some slight differences. These differences usually pertain to working on transmission towers, poles, and protection from falls due to electrical shock and flash.
WHAT IS REQUIRED?
OSHA and building codes present very specific requirements for guardrails to properly protect employees from falls. Per OSHA’s general industry standard, guardrails must adhere to the following:
1910.29(b)
(1) The top edge height of top rails, or equivalent guardrail system members, are 42 inches, plus or minus 3 inches, above the walking-working surface. The top edge height may exceed 45 inches, provided the guardrail system meets all other required criteria.
(2) Midrails, screens, mesh, intermediate vertical members, solid panels, or equivalent intermediate members are installed between the walking-working surface and the top edge of the guardrail system as follows when there is not a wall or parapet that is at least 21 inches high:
(i) Midrails are installed at a height midway between the top edge of the guardrail system and the walking-working surface;
(ii) Screens and mesh extend from the walking-working surface to the top rail and along the entire opening between top rails supports;
(iii) Intermediate vertical members (such as balusters) are installed no more than 19 inches apart; and (iv) Other equivalent intermediate members (such as additional midrails and architectural panels) are installed so that the openings are not more than 19 inches wide.
(3) Guardrail systems are capable of withstanding, without failure, a force of at least 200 pounds applied in a downward or outward direction within 2 inches of the top edge, at any point along the top rail.
(4) When the 200-pound test load is applied in a downward direction, the top rail of the guardrail system must not deflect to a height of less than 39 inches above the walkingworking surface;
(5) Midrails, screens, mesh, intermediate vertical members, solid panels, and other equivalent intermediate members are capable of withstanding, without failure, a force of at least 150 pounds applied in any downward or outward direction at any point along the intermediate member.
(6) Guardrail systems are smooth-surfaced to protect employees from injury, such as punctures or lacerations, and to prevent catching or snagging of clothing.
(7) The ends of top rails and midrails do not overhang the terminal posts, except where the overhang does not pose a projection hazard for employees.
(8) Steel banding and plastic banding are not used for top rails or midrails.
(9) Top rails and midrails are at least 0.25 inches in diameter or in thickness.
There are a few differences for temporary guardrails in the construction standard from the requirements set forth in the general Industry standard, but they are negligible. Many of these requirements for the construction of guardrails are used as part of building codes.
If a guardrail is infeasible, personal fall protection or a safety net must be used, and OSHA has very specific requirements for guardrail use and construction.
Personal fall protection must consist and adhere to the following, which is summarized from the construction standard:
1926.502(d)
(1) Connectors shall be drop forged, pressed or formed steel, or made of equivalent materials.
(2) Connectors shall have a corrosion-resistant finish, and all surfaces and edges shall be smooth to prevent damage to interfacing parts of the system.
(3) Dee-rings and snaphooks shall have a minimum tensile strength of 5,000 pounds.
(4) Dee-rings and snaphooks shall be prooftested to a minimum tensile load of 3,600 pounds without cracking, breaking, or taking permanent deformation.
(5) Snaphooks shall be sized to be compatible with the member to which they are connected to prevent unintentional disengagement of the snaphook by depression of the snaphook keeper by the connected member, or shall be a locking type snaphook designed and used to prevent disengagement of the snaphook by the contact of the snaphook keeper by the connected member. Effective January 1, 1998, only locking type snaphooks shall be used.
(6) Unless the snaphook is a locking type and designed for the following connections, snaphooks shall not be engaged:
(i) directly to webbing, rope or wire rope; (ii) to each other;
(iii) to a dee-ring to which another snaphook or other connector is attached; (iv) to a horizontal lifeline; or (v) to any object which is incompatibly shaped or dimensioned in relation to the snaphook such that unintentional disengagement could occur by the connected object being able to depress the snaphook keeper and release itself.
(7) On suspended scaffolds or similar work platforms with horizontal lifelines which may become vertical lifelines, the devices used to connect to a horizontal lifeline shall be capable of locking in both directions on the lifeline.
(8) Horizontal lifelines shall be designed, installed, and used, under the supervision of a qualified person, as part of a complete personal fall arrest system, which maintains a safety factor of at least two.
(9) Lanyards and vertical lifelines shall have a minimum breaking strength of 5,000 pounds.
(10) When vertical lifelines are used, each employee shall be attached to a separate lifeline.
(11) Lifelines shall be protected against being cut or abraded.
(12) Self-retracting lifelines and lanyards which automatically limit free fall distance to 2 feet or less shall be capable of sustaining a minimum tensile load of 3,000 pounds applied to the device with the lifeline or lanyard in the fully extended position.
(13) Self-retracting lifelines and lanyards which do not limit free fall distance to 2 feet (0.61 m) or less, ripstitch lanyards, and tearing and deforming lanyards shall be capable of sustaining a minimum tensile load of 5,000 pounds (22.2 kN) applied to the device with the lifeline or lanyard in the fully extended position.
(14) Ropes and straps (webbing) used in lanyards, lifelines, and strength components of body belts and body harnesses shall be made from synthetic fibers.
(i) When work is to be performed near electrical power lines or equipment it must be Arc Rated.
(15) Anchorages used for attachment of personal fall arrest equipment shall be independent of any anchorage being used to support or suspend platforms and capable of supporting at least 5,000 pounds per employee attached, or shall be designed, installed, and used as follows:
(i) as part of a complete personal fall arrest system which maintains a safety factor of at least two; and (ii) under the supervision of a qualified person.
(16) Personal fall arrest systems, when stopping a fall, shall:
(i) limit maximum arresting force on an employee to 900 pounds when used with a body belt;
(ii) limit maximum arresting force on an employee to 1,800 pounds when used with a body harness;
(iii) be rigged such that an employee can neither free fall more than 6 feet, nor contact any lower level; i. This is 4 feet in the General Industry standard, as discussed previously (iv) bring an employee to a complete stop and limit maximum deceleration distance an employee travels to 3.5 feet; and,
(v) have sufficient strength to withstand twice the potential impact energy of an employee free falling a distance of 6 feet, or the free fall distance permitted by the system, whichever is less.
(17) The attachment point of the body belt shall be located in the center of the wearer’s back. The attachment point of the body harness shall be located in the center of the wearer’s back near shoulder level, or above the wearer’s head.
(18) Body belts, harnesses, and components shall be used only for employee protection (as part of a personal fall arrest system or positioning device system) and not to hoist materials.
(19) Personal fall arrest systems and components subjected to impact loading shall be immediately removed from service and shall not be used again for employee protection until inspected and determined by a competent person to be undamaged and suitable for reuse.
(20) The employer shall provide for prompt rescue of employees in the event of a fall or shall assure that employees are able to rescue themselves.
(21) Personal fall arrest systems shall be inspected prior to each use for wear, damage and other deterioration, and defective components shall be removed from service.
(22) Body belts shall be at least one and fiveeighths (1 5/8) inches (4.1 cm) wide.
(23) Personal fall arrest systems shall not be attached to guardrail systems, nor shall they be attached to hoists with few exceptions.
SAFETY CORNER
(24) When a personal fall arrest system is used at hoist areas, it shall be rigged to allow the movement of the employee only as far as the edge of the walking/working surface.
CONCLUSION
Falls are the number-one cause of injury and death in industry. Understanding when it is needed and how to employ it correctly, which includes providing the right equipment to prevent an employee fall, is important to mitigate that potential injury. More information and other specifics regarding fall protection can be found under OSHA
29 CFR 1910, General Industry Standards and Regulations in Subpart D – Walking and Working Surfaces and Subpart R – Special Industries, and in OSHA 1926, Construction Industry Regulations under Subpart M – Fall Protection.
Paul Chamberlain has been the Safety Manager for American Electrical Testing Co., LLC since 2009. He has been in the safety field for the past 21 years, working for various companies and in various industries. He received a Bachelor of Science in safety and environmental protection from Massachusetts Maritime Academy.
James (Jim) R. White, Vice President of Training Services, has worked for Shermco Industries Inc. since 2001. He is a NFPA Certified Electrical Safety Compliance Professional and a NETA Level 4 Senior Technician. Jim is NETA’s principal member on NFPA Technical Committee NFPA 70E®, Electrical Safety in the Workplace®, NETA’s principal representative on National Electrical Code® Code-Making Panel (CMP) 13, and represents NETA on ASTM International Technical Committee F18, Electrical Protective Equipment for Workers. Jim is Shermco Industries’ principal member on NFPA Technical Committee for NFPA 70B, Recommended Practice for Electrical Equipment Maintenance and represents AWEA on the ANSI/ISEA Standard 203 Secondary Single-Use Flame Resistant Protective Clothing for Use Over Primary Flame Resistant Protective Clothing. An IEEE Senior Member, Jim received the IEEE/IAS/PCIC Electrical Safety Excellence Award in 2011 and NETA’s Outstanding Achievement Award in 2013. Jim was Chairman of the IEEE Electrical Safety Workshop in 2008 and is currently Vice-Chair for the IEEE IAS/ PCIC Safety Subcommittee.
PROTECTIVE RELAYING
BY JAMES R. WHITE, Shermco Industries
This edition of Tech Quiz covers protective relays. Many years ago, as I was teaching a protective relay class, a student asked, “What are these things?” I replied, “Relays,” to which he answered, “No, relays are those little black plastic things that go click-click.” I made sure to call them protective relays from then on. Things in the protective relaying field have progressed rapidly over the years, and digital protective relays are now the norm as is digital test equipment.
1. One question always seen on the NETA exams is about protective relay ANSI numbering. What is the protective relay number for a synchronizing relay?
a. 25
b. 32
c. 52
d. 86
2. Which protective relay looks inside a generator?
a. Distance relaying
b. Mho relays
c. Ohm relays
d. Loss-of-excitation relays
3. What does Figure 1 illustrate?
a. Mho relay characteristic
b. Ohm relay characteristic
c. Reactance relay characteristic
d. Offset relay characteristic
Figure 1: Which Relay?
No. 132
4. Looking at the internal schematic in Figure 2, identify the following components:
Figure 2: Internal Schematic
GROUND TESTING PROCEDURES
BY JEFF JOWETT, Megger
Effective ground testing is an informed combination of instrumentation and procedure. Accuracy, resolution, safety, noise suppression, graphics, clamp features, and general reliability are all critical, as they are with any electrical testing. But effective and accurate ground testing depends as much on adherence to procedure as it does on quality of instrumentation. If the operator does not understand and diligently apply correct procedure, the highest quality instrument will be little more than a waste of money. Some relatively common electrical tests basically amount to connecting a pair of leads and pressing a test button, but not so ground testing!
Random hookup and intuitive operation get the operator nowhere.
FALL OF POTENTIAL
The basis for ground testing is found in the fundamental procedure known as fall of potential (FOP). A long test lead — often as long as the operator can provide or manage — is stretched out with a metal rod or probe clipped to the end. When the tester is energized, a current circuit is established by an alternating square wave through the soil to the
electrode being tested. The unique frequency of the square wave provides a test signal against which the tester can measure.
Measurement is accomplished by means of the second test circuit: potential. A long lead is similarly strung out, and a metal probe is driven into the soil. This is normally in the direction of the current probe but need not be
if obstructions impede. This circuit measures voltage drop caused by soil resistance, and the two measured parameters — current and potential — calculate resistance through Ohm’s Law. The tester displays resistance to the location point of the potential probe.
This may sound simple, but it isn’t. The problem lies in determining just what is being measured. Move the potential probe, and the tester will calculate a new resistance to the new location. Even if the distance to the probe is maintained constant but in a different direction, the reading may differ. This is due to local soil anomalies from one probe placement to another. This is where correct procedure defines a reliable test. Indeed, if no study is done by the operator and the leads are merely stretched out for their lengths and a reading taken, a correct measurement may be achieved. Unfortunately, this is often done in the field, but it is pure luck.
The correct procedure is to take an arbitrary number of measurements in a line and graph the distance at which the reading was taken versus resistance at that point (Figure 1).
What is hoped for is a level graph line at a satisfactorily low value. This accomplishes two things: It identifies the steadily rising graph where the measured ground resistance runs directly into the extraneous resistance of the current probe, and it reveals local soil inconsistencies that could severely distort a single reading (Figure 2).
SIMPLIFIED FALL OF POTENTIAL
Fall of potential is the best overall method, but it requires considerable work and possibly too much room to stretch leads. What then? Other methods have been derived, some for the purpose of saving time and others for dealing with difficult test conditions. The first of these, called simplified fall of potential, requires only three measurements rather than enough
Figure 2: Comparison of Failed and successful FOP Graphs. The continuously rising graph line (top) may include correct resistance reading, but it is unrecognizable. The extended horizontal line in the correct test (bottom) clearly identifies ground resistance.
Figure 1: Successful FOP Test with Instrument Setup
feet. A simple and easy mathematical proof substitutes for drawing the graph. The most atypical of the readings is mathematically compared to the average and then calculated as a percentage accuracy. The operator makes a decision as to whether this is an acceptable accuracy. If so, the average is submitted as the test result. If all three readings were the same, then this would provide added assurance. But non-homogeneity of soil, especially around graded construction sites, often precludes this.
An obvious spinoff here is to dispense with any math and merely move the potential probe back and forth a few times and decide whether the readings fall reasonably well together. This could be referred to as the eyeball method. It lacks genuine method but is probably the most widely used procedure, at least for less demanding locations. An experienced operator may indeed have sufficiently keen powers of discernment, but if third parties are involved (i.e. inspectors, clients, insurance, lawyers), it may be more practical to do the math and submit the report.
62% RULE
Finally, the 62% rule brings simplicity down to its base level. Mathematics tracing back to the ancient Greek scholars supports the 62% rule. But none of that is necessary to apply to ground testing. All the ground test operator needs to know is that the 62% position on an FOP graph is the one that will give the most accurate reading.
So why aren’t all ground test readings taken at that position and be done with it? The answer is because the mathematics is based on an ideal model, and few construction sites, industrial sites, or anywhere else are likely to conform to ideality. Grading mixes topsoils from different locations. The soil may be naturally stony. There may be a large subterranean rock, power cable, water main, ground water, or other nonuniformity to contend with. Put simply, the
is accepted at the operator’s risk unless the site has previously been proven by more rigorous prospecting. The rule is a quick and handy backup test on sites where distances and directions have been established by rigorous testing. But a new test runs the risk of a gamble.
Slope
The other reason for established test procedures is to effectively address difficult situations. The main challenge is insufficient space in which to extend test leads far enough to separate the resistance field around the current probe from that of the electrode being measured. A coherent FOP graph cannot be constructed, and the graph line continues to rise as more resistance is added with each move of the potential probe. By far the most popular means of dealing with this issue is the slope method (Figure 3).
If the graphed resistance line continues to rise, most likely the correct value is there somewhere — it just can’t be discerned from viewing the graph. Still, even a partial FOP graph can come in handy. Only three measurements are necessary for the proof. These are at 20%, 40%, and 60% of the distance to the current probe. From these three numbers, a slope coefficient, typically referenced by the Greek letter μ, is calculated and referenced to a table commonly available in the ground testing literature. As the slope coefficient represents the distance to the potential probe over the distance to the current probe and the latter is known, the distance at which the correct ground resistance reading should be taken is calculated by solving this simple equation: d p /d c = μ for dp.
The actual ground resistance reading can then be determined by either reading the graph line or physically placing a potential probe at that distance and taking the reading. But suppose the calculated μ value cannot be found on the table? That would indicate the resistance field of the current probe is contained completely
successfully determined. What then?
Intersecting Curves
The fallback is intersecting curves. This is a difficult and tedious procedure to be avoided if possible, but it works when nothing else will. Two sets of graphs are constructed. One set is of three portions of FOP graphs working from an edge of the grid. These will keep rising. If they did not, they would be complete FOP graphs and intersecting curves wouldn’t be necessary. But since these are not readable FOP graphs, where is the 62% distance? For that, a second set of graphs is constructed by selecting arbitrary points for the electrical center of the grid at a distance x from the connection on the edge of the grid and then locating the 62% accordingly. The arbitrary values of x are plotted against the 62% resistances on each of the curves. These three graph lines will coincide at one point (Figure 4) for the correct distance of x from the true electrical center of the grid to the point of attachment of the test lead(s) at the edge. All other values for x are wrong (not the true electrical center), and so the resistances will scatter, with only the correct resistance being common to all three graphs.
Four Potential
Another problem associated with applying FOP to large grids is that their shapes can become more and more asymmetrical, rendering it increasingly difficult to apply even a fair guess as to the electrical center. Since these grids can also have very low resistances, it is easy to fall into incoherent results if a proven method isn’t followed. A means of addressing this is the four potential method, but unlike slope and intersecting curves, it can require prohibitively long leads. The tester is connected to an arbitrary point on the edge of the grid. Leads are stretched in a straight line, and six critical values are taken at 0.2, 0.4, 0.5, 0.6, 0.7, and 0.8 of the distance to the current probe (Figure 5). These results are processed through four simple + and – formulae
Figure 3: Typical Slope Method Layout
Figure 4: Center of Triangle Formed by Graph Lines is Ground Resistance
Figure 5: Typical Layout for Four Potential Method
that yield the correct ground resistance. The four results should substantially agree, imparting confidence to the calculation.
Star Delta
Two methods remain for confines so tight that even minimal extension of current and potential leads is prohibitive. One of these is star delta. The tester is shunted into a two–terminal configuration, either X – PC or C1P1 – P2C2. Modern testers have selector
not necessary. Three test probes are placed in a triangle around the ground electrode being tested, and six two-point resistance measurements are taken between each pair of probes and between each probe and the ground under test (Figure 6). Similar to four potential, these six test results are processed through four simple equations for resistance of the test ground, and agreement provides assurance.
Dead Earth
Finally, under the worst of urban conditions, with virtually no room for leads or place to drive probes, the two-point star delta test becomes the only option. The second test lead is attached to any convenient low-resistance return: a metal fence post, building structure, or best of all, the water pipe system. Test current circulates through the earth to the water pipe system or other connection and back to the tester through a lead (Figure 7). A series loop is measured, and its success counts on the return element being of negligible resistance. This is commonly called the dead earth method because the return is not part of an electrical system. It’s not especially accurate or reliable, but sometimes it’s all that remains.
CONCLUSION
A ground test performed by random hookup will likely yield some result, but it’s no more reliable than rolling dice. Because the earth is so vast, adherence to established procedure is mandatory. Know the procedures, where and why they apply, and results will be trustworthy and effective.
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.
Figure 6: Star Delta Test Configuration
Figure 7: Dead Earth Test Setup
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CHALLENGES IN TRANSFORMER PROTECTION TESTING
BY SCOTT COOPER, OMICRON electronics
While the basic premise of transformer differential protection is straightforward, numerous features are employed in modern relay algorithms to compensate for challenges presented by the transformer differential application. As a result, developing appropriate test quantities and properly quantifying results can be challenging with traditional functional differential testing.
CHALLENGES IN TRADITIONAL FUNCTIONAL TESTING
A traditional functional test assures that all measurements and derived quantities are measured and calculated accurately, and that the overall relay hardware — including inputs and outputs — function properly. Therefore, the test quantities of a traditional functional test are defined as a sequence of steadystate or phasor values. This type of testing is
frequently performed throughout the life cycle of a relay. During commissioning, this type of test can further assure whether threshold and time elements are set according to the settings specified by engineering. The following sections describe typical tests and their challenges.
Pickup Testing
Even the simple differential element pickup test, when performed manually, requires the test designer to calculate the nominal operating current amplitude, or tap, for each winding. The currents on the winding are simply increased from zero until the relay trips. The pickup current value is then converted back to per-unit and compared to the setpoint.
Slope Testing
For differential characteristic tests in the slope region, the proper phase shift is determined from the transformer three-line diagram. For three-phase tests, balanced quantities of a given multiple of tap and phase shift matching the application are applied to two or more current windings, which simulates a balanced load. Currents on one side are then incrementally increased until the differential element operates. For tests of a single differential element phase, realistic through-fault current phasors must be calculated. Evaluating the results of slope characteristic tests is not straightforward as there is significant variation in the restraint current calculation between differential relay manufacturers such as the maximum per-unit phase current, minimum per-unit phase current, average per-unit phase current, sum of the per-unit phase currents, or other calculations. In addition, some differential relays incorporate a reference winding in the restraint calculation that can be fixed or calculated automatically.
If the simulation of single-phase faults is desired, calculation of test values is more complex, and the relay’s method of zerosequence elimination must be considered. To simplify this process, dedicated software tools exist that calculate the required steady state
Incorporating a Cubic Spline in the Differential Operating Characteristic
quantities by using an internal transformer model. The software module can then directly inject the quantities, measure back the pickup or trip signals, and assess the steady state accuracy. These tools have limitations when the relay applies adaptive characteristics or works in the time domain instead of the frequency domain.
To further complicate testing, modern relays incorporate several additional characteristic features. For example, some relays incorporate cubic splines to smooth the transition between slope 1 and slope 2 (Figure 1). Testing in the cubic spline region requires additional calculations.
Another feature that can complicate testing is an adaptive slope characteristic (Figure 2). These schemes are applied to restrain operation of the differential elements for external faults that might cause current transformer (CT) saturation, unbalancing the differential, and cause a mis-operation.
When functional testing a differential characteristic incorporating an adaptive slope, the applied slope is determined by pre-fault current. To test slope 2 on these devices, prefault state duration and pre-fault current amplitude are coordinated with the relay settings, which causes the relay to shift to a high
Figure 2: Adaptive Slope Characteristic and Supervisory Relay Word Bits Used by SEL-487E Transformer Differential Relay
security mode. Of course, traditional ramping tests cannot be used in these cases. Instead, the characteristic is verified by applying a series of tests incorporating rest, pre-fault, and fault states.
Inrush and Overexcitation Blocking
To restrain the differential element during magnetizing inrush, most relays use both the 2nd and 4th harmonic content of the calculated phase differential currents (Figure 3).
During inrush, 2nd harmonic content of the resultant current varies with closing angle. To prevent mis-operations of the differential
Figure 3: COMTRADE Recording of Transformer Inrush Showing Time Domain Plot (left) and Calculated Harmonic Content at the Time Indicated by the Yellow Marker (right)
element due to closing angle, modern digital relays incorporate a variety of special schemes. The most common uses the highest measured harmonic in any phase to restrain all phases. However, other devices use cross-phase averaging, where the average even harmonic content in all phases is used to restrain the differential in all phases, which can substantially complicate testing. In these cases, test operators frequently use only three-phase tests, leaving these features untested. To test these elements, composite waveforms containing fundamental frequency and the harmonic under test are used. One test method consists of increasing fundamental current until the relay operates, then increasing only the harmonic content until the relay restrains, then calculating the harmonic percentage and comparing to the relay settings.
A completely different inrush blocking algorithm analyses the current signals in the time domain. If the current dwells close to zero and is unipolar, it is considered an inrush condition. This method has better sensitivity on new core materials that generate very low 2nd harmonic content on inrush. This type of algorithm cannot be tested with traditional functional testing methods.
In addition to inrush conditions, transformer magnetizing current can also increase during transformer overexcitation, possibly resulting in an improper differential element trip. To mitigate this possibility, the 5 th harmonic content of the differential current is measured, and if a preset threshold is reached, the differential element is either desensitized or completely restrained (Figure 4).
Restricted Earth Fault
Restricted earth fault, or ground differential elements are gaining popularity. Related to the transformer differential element, restricted earth fault elements protect against faults occurring near the neutral end of wye-connected transformer windings. In these schemes, the calculated zero sequence current from the wye winding phase currents is compared to the measured ground current (Figure 5).
Region
Figure 4: Differential Characteristic Illustrating Operation of the 5th Harmonic Restraint in a Beckwith Transformer Relay. When the 5th harmonic threshold of the differential current is reached, the differential element pickup setting is increased to prevent mis-operation. As with inrush, testing is performed using a composite waveform consisting of the fundamental and 5th harmonic frequencies.
Functional testing of these schemes requires the test designer to properly calculate phasecurrent phasors for internal and external faults to check proper operation. Additional logic is also incorporated to create operating windows and provide protection when the transformer is energized from one side only.
Figure
Is This Testing Adequate?
Even after surmounting the challenges of functional testing, the fundamental question of setting adequacy remains mostly unanswered. If the relay does not operate quickly, securely, and dependably during a power system event, the goal of the protection system has not been met. There may be a better way.
SYSTEM-BASED TESTING OF TRANSFORMER DIFFERENTIAL PROTECTION
A system-based testing approach can reduce testing challenges and ensure the settings are adequate. The idea is simple:
• To ensure the relay trips for an internal fault, simulate realistic internal faults to test the response of the relay.
• To ensure the relay is secure against tripping for through-faults, simulate realistic through-faults and verify the relay does not operate. Thus, a system-based testing solution calculates the testing quantities within a subtransient power system simulation, directly outputs the signals with an amplifier, measures the response, and assesses the result.
Transformer Simulation
When defining a system-based test case, do not think about the element or algorithm under test; instead, consider the power system incidents this element is supposed to act on, for example:
• Faults external to the protected zone
• Faults internal to the protected zone
0 Turn-to-turn faults
0 Turn-to-ground faults
• Inrush during energization
• Transformer overexcitation due to overvoltage
• CTs saturation and ratio errors
The electromagnetic transient (EMT) simulation of these incidents is one of the cornerstones for
a system-based testing solution. The reliability of a simulation result depends on accurate input data. To make the testing tool practical for technicians and engineers in the field, we must find a solution that yields numerically stable and reliable results and apply heuristics where data is not available.
Transformer Model
Relevant power system scenarios include lowfrequency transient events such as faults as well as low-frequency non-linear phenomena such as inrushes and overexcitation. High-frequency phenomena in the power system are not relevant to the transformer protection relay due to internal algorithms and the cut-off frequency of anti-aliasing hardware filters. Therefore lowfrequency transformer models are suitable for system-based transformer protection testing.
The more physical, geometrically based, and detailed the transformer model is, the more accurate simulation results will be. However, parameter availability imposes the major constraint on the accuracy of the simulation results in the field. From a field technician perspective, the main source of information is the transformer nameplate. Information about core material and dimensions, number of winding turns, and geometry of the winding is not normally available. Thus, it is important that the model can be parametrized from nameplate data using reasonable heuristics that are based on guidelines provided in international standards and by expert working groups.
The mutually coupled coils model that is used in the described solution was proposed by Brandwajn and Dommel and offers a reasonable compromise between precision and parameter detail. The same principle is utilized in various free and commercial EMT simulation tools.
External Faults
The fault current contribution to an external phase fault mainly depends on the positive sequence impedance of the transformer, which
6a Positive-Sequence Equivalent Circuit
6c Influence of Grounding Impedance
6e Influence of Delta Winding
Influence of Three-Limb Core
6d Influence of Wye-Winding with Isolated Neutral
6f Influence of Compensation Winding
Figure 6: Influence of Various Factors on Two-Winding Transformer Zero-Sequence Equivalent Circuit
can be derived from the short-circuit voltage on the nameplate. However, the simulation of ground faults requires reasonable zero-sequence short-circuit impedances for the transformer that are not always available on the nameplate. The zero-sequence impedance is influenced by the core type, vector group, presence of a
compensation winding, and neutral grounding. Figure 6a – Figure 6f show how these factors affect the zero-sequence equivalent circuit of a two-winding transformer. P, S, M, N, and C in the figure subscripts denote primary, secondary, magnetizing, neutral, and compensation, respectively.
6b
The effect of core type and compensation winding on transformer zero-sequence impedance can be estimated using heuristics, based on the guidelines in ISO/IEC 60076-8:1997. Accordingly, a system-based testing solution heuristically estimates unknown impedances: and based on a transformer positive-sequence, short-circuit impedance where:
Internal Faults
For the simulation of internal transformer faults, the system-based testing solution relies on a widely accepted method described in Bastard et al. The method extends an original, mutually-coupled-coils transformer model, splitting the faulted coil into two sub-coils in
Figure 7: Splitting Faulted Coil of Wye Winding into Two Parts (left) and Faulted Coil of Delta Winding into Three Parts (right).
Figure 8: Switching from Series to Parallel R-L Circuit
the case of turn-to-ground faults and into three sub-coils in case of turn-to-turn faults, therefore allowing a branch with a fault resistance RF to be inserted in the newly introduced terminals between the sub-coils (Figure 7).
Determining the short-circuit impedance of the split sub-coils requires knowledge of the inductive leakage factors, which again are not specified by a transformer nameplate. To estimate inductive leakage factors, detailed transformer geometrical data would be required. Since the data is not commonly accessible for relay protection engineers, we are left to rely on heuristic estimations of inductive leakage factors.
Different heuristics were proposed in M. Kezunovic et al, Darwish et al, and PalmerBuckle et al. Keeping our use case in mind, the most challenging scenario for the sensitivity of a restricted earth fault protection function is faults close to the neutral with just a few shortcircuited turns and high fault resistance. In such a scenario, the principle of proportionality plays a higher role than the principle of leakage. In other words, a contribution of fault and winding resistance to the equivalent shortcircuit impedance is higher than a contribution of leakage inductance. Therefore, different inductive leakage factor heuristics yield similar simulation results for many test scenarios.
Saturating Core
All differential relays must incorporate features to provide security during magnetizing inrush and transformer overexcitation, both sources of significant differential current during these events. To achieve realistic simulated waveforms for these phenomena, the non-linear saturation characteristic of the transformer core must be simulated. Therefore, an iterative approach for inclusion of non-linear inductors into the solution is utilized.
To simulate the non-linear transformer core, the system-based testing solution takes winding resistances and the magnetizing branch out of the mutually-coupled transformer coils model
and transforms the magnetizing branches from series R-L circuits to parallel R-L circuits with non-linear inductor (Figure 8).
For a core-type transformer with concentric windings, Cigre Working Group 33.02 recommends placing the non-linear inductor across a coil closest to the core. The saturation of yokes and unwound limbs (for a five-limb transformer) in the transformer model are neglected, as a reasonable estimation of their saturation characteristics requires detailed knowledge of transformer design parameters or results of non-standard transformer tests. The advantage of using only three nonlinear inductances per transformer includes a better simulation performance and simpler parametrization compared to more sophisticated non-linear transformer models.
For scenarios with residual flux (or remanence), the testing solution uses a non-linear hysteretic inductor model based on the principles of EMTP Type-96, which is widely accepted in power system simulations.
SETTING UP AND EXECUTING A SYSTEM-BASED TEST
While all these details of the simulation are daunting, they are taken care of by the modelling in the software. Compared to functional testing, the test setup is much simpler. Starting from a standard power transformer topology (Figure 9), only the CT ratios and the transformer nameplate data must be entered:
• Vector group
• Rated voltages
• Rated power
• Short circuit voltage / impedance
• No-load current
• Core type
The parameters for the saturating core are set automatically to typical values according to heuristic estimation of magnetization characteristic parameters outlined in Cigre and
Colombo and Santagostino and usually do not have to be adapted.
Test Cases
Defining a system-based test document requires some rethinking of existing testing procedures. For example, instead of defining a 2nd harmonic content, we simulate the energization of the power transformer at various closing angles. Instead of defining a differential and restraining current, we simulate through faults and internal differential zone faults. All these scenarios can be defined within a single-line diagram of the transformer and the surrounding power system.
From a systematic standpoint, a test document starts with a metering check, followed by test cases for stability. The differential relay is not supposed to trip for normal load current or faults on the buses outside of the differential zone. It may happen that the overcurrent element trips with some time delay for outside faults. The fault can be dragged from a toolbar in the software and dropped on the bus.
To test the differential trip, the fault can also be dropped on the power transformer. For a turnto-ground fault close to the star-point (<5%) a differential element might not be sensitive enough; therefore, a REF element, if applied, will pick up the fault. Similarly, for turn-toturn faults with both terminals close to each
CB
Figure 9: Single-Line Diagram and Transformer Parameterization for System-Based Testing
a) Fault incident during energization
b) Sympathetic inrush due to energization of parallel transformer
c) CT Saturation during external fault
Figure 10: Time Domain Plot from a System-Based Testing Case Illustrating Inrush and Resultant CT Saturation
other, the differential element might not be sensitive enough; a negative sequence element might pick up this type of fault.
To test stability during inrush, both breakers are in an open state. Within the test case, an event will close the breaker, causing an inrush condition. By changing the closing angle, the amount of inrush in each phase can be altered.
Apart from these major test cases, additional real-world scenarios can be tested, including sympathetic inrush, fault during inrush, external faults with CT saturation, and overexcitation due to overvoltage (Figure 10).
Since a system-based testing solution can control multiple test sets from one PC’s software, three-winding transformers or REF protection can be tested without rewiring the test setup. Protection schemes for phase shifting transformers can be tested the exact same way
without adding complexity. Line protection systems where the transformer is within the protected zone can also be easily tested.
BENEFITS & DRAWBACKS
The biggest benefits of the system-based test approach are simplicity and the ability to ensure the protection system is working under real-world conditions. As it is relay independent, the test document for the same type of transformer is identical, independent of the relay manufacturer. And because it only simulates realistic incidents, it will work for every relay algorithm improvement in the future.
On the downside, system-based testing requires some rethinking of existing testing procedures. The harmonic content of the test signal during an inrush is realistic for the type of transformer, but it cannot be set exactly below or above a
certain threshold. Therefore, functional testing still has its place.
CONCLUSION
So where do we invest our precious testing time and resources? If a differential relay is accurate when set to a certain threshold and has been tested several times throughout its lifecycle — for example during prequalification — functional testing is sufficient. But if the goal of commissioning is to ensure that a differential relay and its engineering adequately protect the power system and transformer, system-based testing is the right tool.
REFERENCES
V. Brandwajn, H. W. Dommel, and I. I. Dommel. “Matrix Representation of Three-phase N-Winding Transformer for Steady-State and Transient Studies,” IEEE Transactions on Power Apparatus and Systems, Vols. PAS-101, No. 6, pp. 1369-1378, 1982.
ISO/IEC 60076-8:1997, Power Transformers — Application Guide.
P. Bastard, P. Bertrand, and M. Meunir. “A Transformer Model for Winding Fault Studies,” IEEE Transactions on Power Delivery, Vol. 9, No. 2, pp. 690-699, 1994.
M. Kezunovic, B. Kasztenny, and Z. Galijasevic. “A New ATP Add-On for Modeling Internal Faults in Power Transformers,” American Power Conference, Chicago, 2000.
H. A. Darwish, A. I. Taalab, and H. E. Labana. “Step-by-Step Simulation of Transformer Winding Faults for Electromagnetic Transient Programs,” 2005/2006 IEEE/PES Transmission and Distribution Conference and Exhibition, Dallas, TX, 2006.
P. Palmer-Buckle, K. Butler, N. Sarma, and A. Kopp. “Simulation of Incipient Transformer Faults,” 1998 Midwest Symposium on Circuits and Systems (Cat. No. 98CB36268), Notre Dame, IN, USA, 1998.
CIGRE Working Group 33.02 Internal Overvoltages. TB 039, Guidelines for Representation of Network Elements When Calculating Transients, https://e-cigre.org/ publication/039-guidelines-for-representationof-network-elements-when-calculatingtransients.
E. Colombo and G. Santagostino. “Results of the Enquiries on Actural Network Conditions when Switching Magnetizing and Small Inductive Currents and on Transformer and Shunt Reactor Saturation Characteristics,” Electra, Vol. 94, pp. 35-53, 1984.
J. G. Frame, N. Mohan, and T. Liu. “Hysteresis Modeling in an Electromagnetic Transient Program,” IEEE Transactions on Power Apparatus and Systems, Vols. PAS-101, No. 9, pp. 3404-3412, 1982.
George Alexander, David Costello, Brad Heilman, and Jason Young. “Testing the SEL487E Relay Differential Elements,” SEL Application Guide, Vol IV AG2010-07, p 11.
Scott Cooper is the Application and Training Engineer for OMICRON in St. Petersburg, Florida. He has thirty years of experience in a variety of roles including substation commissioning, application engineering, power plant operations, and technical training. He is active in the IEEE PSRC and has written numerous papers and magazine articles. Scott is a graduate of the United States Navy Nuclear Propulsion program.
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INVESTIGATING AN ELECTROMECHANICAL DIFFERENTIAL RELAY MISOPERATION
BY ALEX RANGEL, Saber Power Services, LLC
Transformer differential protection based on ANSI 87 is one of the most common protection methods for large power transformers due to its outstanding speed and accuracy. However, given the complexity of this method when applied on delta-wye grounded transformers, mistakes made during the design and/or installation phases might not be detected promptly and can eventually cause an undesired operation — it could take months or years! This article analyzes the transformer differential protection schemes of two 25 MVA, 138/12.47 kV transformers feeding a main–tie–main scheme and investigates how improper installation and commissioning of a tie breaker caused a full outage at an industrial facility.
DIFFERENTIAL PROTECTION
Discussing differential protection starts with one of the most basic electrical laws: Kirchhoff’s Current Law (KCL). The KCL law states: “The algebraic sum of the currents entering a node (or a closed boundary) is zero.” In other words, the amount of current that enters an electrical node must equal the amount of current that exits the node. If these currents are unequal, an unintended path for current flow is present. Figure 1 shows a basic KCL representation.
Differential relays apply KCL to protect electrical equipment (e.g. bus, transformer, line) by using current transformers (CTs), which must be installed at each connection point to obtain the total current summation. To perform the summation, each set of CTs must be brought into a protective device. A more modern approach allows the current values to be transmitted between relays using fiber optics (outside of the scope of this article).
Figure 1: Kirchhoff’s Current Law
polarity and their resulting currents into the relay are 180 degrees out of phase. For a more thorough explanation of current flow and CT polarity, refer to “What is so Negative About Negative Sequence? Part 2,” NETA World , Summer 2018. Figure 2 shows a typical bus differential protection scheme.
TRANSFORMER DIFFERENTIAL PROTECTION USING ELECTROMECHANICAL RELAYS
Transformer differential protection was originally performed using electromechanical relays. Many of these devices are still in service today and are now available with digital relays as well. These electromechanical relays require a set of currents at each side of the transformer (restraint currents) to undergo physical summation (operate current) to determine the fault location (internal or external) using a percentage characteristic method. For a detailed explanation of this method, refer to the ABB Type HU and HU-1 Transformer Differential Relays Instruction Manual. Figure 3 shows the restraint and operate currents in a differential electromechanical relay.
It is important to note that CT polarity in these systems plays an important role: The CTs must be installed and wired so that the total current summation adds up to zero on load and external faults. This is only possible if the CTs at each end of the apparatus have opposite
One of the biggest challenges in transformer differential protection is the delta-wye grounded transformer configuration, which is widely applied. In this configuration, the delta-side windings connect one side of a given winding (i.e. the polarity side) to the opposite side of an adjacent winding (i.e. non-polarity
Figure 2: Bus Differential Protection Scheme
Figure 3: Differential Protection Using an Electromechanical Relay (Simplified)
Figure 4: 30-Degree Shift on a Delta-Wye Grounded Transformer
Figure 5: Delta-Connected Secondary CTs
side). With this connection type, currents entering the delta side of the transformer are considered to be phase-to-phase, while currents exiting the wye-grounded side of the transformer are considered to be phase-toground with all three of the latter windings grounded on one side. This configuration creates a 30-degree phase shift between the low- and high-voltage currents, which must be considered to properly apply transformer differential protection. Figure 4 shows the phase-angle relationship between the deltaand wye-grounded primary currents (A phase shown only). For a more detailed analysis, refer to Amberg and Rangel’s Tutorial on Symmetrical Components
CURRENT COMPENSATION AND ELECTROMECHANICAL RELAYS
The previous section described a 30-degree phase shift between both sides of a transformer. To cancel out the CT secondary currents (and satisfy KCL), this shift must be addressed by wye-ground connecting the CTs on the delta side while delta connecting the CTs on the wyegrounded side. This CT delta configuration creates phase-to-phase secondary currents and therefore rotates the phase angles by 30 degrees. With this final shift, both sets of secondary currents have a phase angle difference of 180 degrees.
Note: Proper tap selection must be considered in transformer differential protection. However, in the misoperation being analyzed here, TAP1 and TAP2 were properly selected and did not contribute to the issue. Therefore, they will not be discussed further.
Figure 5 shows the proper CT configuration to be used for transformer differential protection with electromechanical relays. Due to the opposing CT polarity, the restraint currents entering the relay are 180 degrees apart.
EXISTING SYSTEM
The system discussed in this paper consists of two incoming 138 kV transmission lines; each line feeds a 138 kV breaker. Each breaker then feeds a 25 MVA, 138 kV/12.47 kV transformer. On the low-voltage side, each transformer feeds a 12.47 kV breaker, which then feeds a 12.47 kV bus (identified as bus A and bus B). Each bus provides power to three different feeders (identified as 1, 2, and 3 on bus A and 4, 5, and 6 on bus B). A connection between bus A and bus B exists through a tie breaker connected to both buses.
CTs on the high-voltage side of the transformer are wye-ground connected (CT ratio of 100:5), while CTs on the low-voltage side of the transformer are delta connected (CT ratio of 1200:5). Since the 12.47 kV
buses are part of the differential scheme by design, the CTs at the load side of each feeder, as well as one set of CTs from the tie breaker, must be connected to the 87T relays (every set connected in delta and paralleled). Figure 6 shows a simplified one-line diagram of the system.
PHASE-TO-GROUND FAULT
On 11/29/2017, a C-phase-to-ground fault occurred downstream of feeder 5. A digital relay had recently been installed to protect feeder 5, and an event report was generated during the fault. The event report shows that the fault in the system lasted approximately three cycles and had a maximum current value of approximately 2,400 ARMS. During this fault, differential protection relays 87T1 and 87T2 tripped, and a full blackout was experienced at this facility (both 138 kV breakers opened). Figure 7 shows the oscillography generated by the feeder 5 relay during the ground fault.
TROUBLESHOOTING
Site personnel identified the ground fault downstream of feeder 5, determined that both 87 relays had misoperated, and requested assistance from a third-party testing company to investigate the reason for the misoperations. The relay flags had been cleared, the lockout relays had been reset, the 138 kV breaker on the A side was closed (the system became
Figure 6: One-Line Diagram of Existing System (Simplified)
Figure 7: C-Phase to Ground Fault on Feeder 5
partially energized), and loading was kept to a minimum until the root cause was determined.
The half of the system that was re-energized had a very low load; therefore, performing troubleshooting and commissioning was difficult. Additionally, because the 87T1 relay was electromechanical, it was not possible to obtain all restraint currents at once (a digital relay is able to capture these currents through a triggered event report). It was decided to troubleshoot the other half of the system that was still de-energized and isolated.
To verify the restraint currents flowing into 87T2, current was injected from the feeder breaker CT terminal blocks back into the relay. Given that the CT burden is much higher than the wiring and the relay inputs, it was not necessary to lift the wires prior to testing. A single balanced Amp was injected at each polarity connection point at the feeder 5 breaker CT terminal blocks (ST2X-1, ST4X1, ST6X-1), and current measurements were taken with a digital clamp meter at a) the field
wiring exiting the breaker and b) the restraint channel at 87T2. The measured currents were a) 1.0 Amp (expected) and b) 0.6 Amps (unexpected). Figure 8 shows a simplified schematic of the current testing performed at feeder 5 and the 87T2 relay (A-phase measured values only).
According to KCL, 0.4 Amps are flowing in an unknown path. Site personnel mentioned that the tie breaker had been replaced months ago due to aging. It was not put in service (i.e. the breaker and the isolating switches remained opened). However, connections were made to put it in service if needed. It was also mentioned that the 87T relays had nuisance tripped in the past and that these events began to happen shortly after this breaker’s installation. A visual inspection performed at the tie breaker’s wiring cabinet revealed that shorting screws had been installed at the CT shorting blocks connected to the 87T relays (Figure 9). Using a digital clamp meter verified that the missing 0.4 Amps were flowing into this unintended path. Since the
Figure 8: Current Testing at Feeder 5 Breaker (Simplified)
Figure 9: Tie Breaker CT Terminal Blocks, Shorting Screws Inserted
CTs are delta-connected, their windings were shorted and a current path through this short was created (refer to Figure 8), which then created an outstanding operate current. This operate current would become high enough during an external fault to cause the 87T relays to erroneously declare an internal fault and trip.
LESSONS LEARNED
Several lessons were learned from these misoperations:
• When replacing substation apparatus, individual components that are part of the specific apparatus might affect the system. In the case of outdoor breakers, current transformers must be fully tested and commissioned prior to re-energizing the system to ensure proper operation.
• The use of electromechanical differential relays on a delta-wye grounded transformer adds complexity due to the CT delta connection on the wye-grounded side of the power transformer. These deltaconnected CTs must never be shorted because the non-polarity side of one phase is always connected to the polarity side of another phase.
• Whenever CTs are introduced into a system but are not to be used, they can be connected wye-grounded and shorted out (they must never be left open).
• Protection systems (in this case, the differential relays) must be recommissioned anytime they are modified. One simple check is to meter the operate current upon loading the power transformer. A digital clamp meter can be used for electromechanical relays; for digital relays, a meter command should suffice. The
mismatch between operate and restraint currents must be low and according to relay manufacturer specifications.
CONCLUSION
The process of replacing substation apparatus due to aging and/or limitations is very common, and all new instrumentation devices introduced into the system (i.e. CTs) must be fully tested and commissioned to ensure proper operation. Without proper testing and commissioning, mistakes can go undetected and eventually cause misoperations.
REFERENCES
Alexander, C. and Sadiki, M. Fundamentals of Electric Circuits, 3rd Edition. The McGrawHill Companies, Inc., 2007.
Rangel, A. “What Is So Negative about Negative Sequence? Part 2.” NETA World, Summer 2018.
ABB, Inc. Type HU and HU-1 Transformer Differential Relays Instruction Manual, 1999.
Amberg, A. and Rangel, A. Tutorial on Symmetrical Components, 1st Edition (ebook). Schweitzer Engineering Laboratories, Inc. Accessed March 7, 2016 at https://cdn.selinc.com/assets/Literature/ Publications/White%20Papers/LWP0010-01_ TutorialSymmetrical-Pt1_AR_20130422.pdf
Alex Rangel is a Protection and Controls Engineer for Saber Power Services, LLC. Alex is NETA Level 4 certified, has been an IEEE member for 11 years, and has been a registered Professional Engineer (PE) in the state of Texas since 2014. He received a BSEE and an MSE from the University of Texas at Austin in 2009 and 2011, respectively.
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TESTING TECHNIQUES FOR PROTECTION-CLASS CURRENT TRANSFORMERS
Relaying current transformers serve as critical components in the design of a protection scheme. CT performance under fault conditions should be within its operating characteristics for a true representation of fault magnitudes and reliable operation of the protection scheme. To ensure proper installation and operation, CTs are often subjected to one or more tests performed in accordance with standards including IEEE C57.13.1, IEC 60044–1, and IEC 60044–6.
IEEE C57.13.1, Guide for Field Testing of Relaying Current Transformers describes field test methods that assure CTs are connected properly, are of marked ratio and polarity, and are in a condition to perform as designed both initially and after being in service for a period of time. Performing the recommended ratio, polarity, winding resistance, and excitation tests on each tap of a multiple-tap CT can be a labor- and time-intensive job. Combined with substation assets such as transformers and circuit breakers with multiple CTs per phase, it is a complex task to obtain reliable and accurate results.
An excitation test performed using the secondary voltage injection method could
require high levels of AC voltage to plot the saturation characteristics and determine the knee point. Special application CTs such as TPY, TPZ, or generator CTs may require thousands of volts to perform this test. This requirement not only makes it a challenging situation in the field environment, but also poses safety concerns for operating personnel.
This conventional method of testing CTs in the field has been used for years with some limitations and drawbacks. With modern advancement in digital processing and solidstate technology, efforts have been made to perform those same tests quickly, safely, and with a high degree of accuracy and reliability.
DINESH CHHAJER and SUGHOSH KUBER, Megger USA
ALTERNATIVE TESTING TECHNIQUES
An excitation test on protection class CTs utilizing nominal frequency 50/60 Hz sinusoidal voltage signal is one of the most challenging tests to perform, as it requires a high voltage/wattage source to drive the CT into saturation to measure its core characteristics. When testing a C800 class CT, test voltage can typically be around 800 V RMS, and for some special cases, 1,300 V may be required to achieve 1 A excitation current for saturation. For some IEC-class CTs, test voltage can easily reach 4,000 V RMS to achieve 1 A saturation.
Many field-portable instruments are unable to deliver that level of AC voltage and wattage. This makes the test difficult to perform for some applications and requires significant safety precautions that must be taken before performing the test. The DC voltage technique can be employed to achieve core saturation and overcome these limitations. IEC 600446 Annex B-3 explains the alternate way to perform a CT excitation test.
The flux generated in the core can be represented by
saturation can then be mathematically converted back to an equivalent 50 Hz/60 Hz saturation. This will then achieve the same result as the conventional AC excitation test technique.
The integral of voltage over a period of time would be a measure of flux (Φ) produced as shown in equation (1). It can be generated by using AC or DC excitation voltage. The area under the curve reflects the flux produced as shown in Figure 1.
Flux can be increased by utilizing either of the two methods. Either the time period can be kept constant as the voltage is increased, or the voltage can be kept constant with an increase in time. The conventional method used by the industry over the years has been to keep the time period constant (or fixed frequency at 50/60Hz) as the voltage is increased. Alternatively, the DC voltage can be kept the same and the time can be prolonged until the core is saturated. By integrating the constant DC voltage over time, the core saturation can be determined. This
Figure 2 shows an excitation test result with a knee-point voltage of around 14 kV. The advantage of the DC method is to eliminate the need for higher levels of AC voltage and achieve the same results by utilizing a DC voltage at or below the available line voltage. The technique allows testing CTs with higher knee-point voltages using the same concept with a slightly longer test duration. Additionally, lower levels of DC test voltage allow safer testing conditions and a portable, lightweight instrument ideal for field conditions.
CT demagnetization is an important step to ensure that the core has no residual magnetism. This can be achieved by reducing the hysteresis loops starting from saturation through a series of similar DC excitation reoccurring cycles in opposite directions with progressively reduced magnitudes.
CONCURRENT TESTING TECHNIQUE
The conventional testing method works on the concept of keeping the primary circuit open, applying an AC voltage to the secondary winding, and measuring secondary voltage/ current along with primary voltage values to obtain test parameters such as ratio, polarity, winding resistance, and excitation characteristics curve. For a multi-tap CT, these tests are repeated for each tap either through a manual operation or by utilizing an automatic switching technique.
The concurrent testing technique uses the transformer’s ampere-turn principle to obtain the recommended test results for all the taps and any inter-tap combination simultaneously. (2)
The turns ratio (N2/N1) of a CT is a ratio of the applied voltage on the secondary side to the
Figure 1: The area under the curve is flux generated using the AC and DC method.
Figure 2: Saturation Test with Knee-Point Voltage around 14 kV
measured voltage on the primary side as shown in equation (2). The concurrent technique applies the test voltage across the complete secondary winding and measures the voltage across each secondary tap position in addition to the primary winding induced voltage. Concurrent testing test connections to a multitap CT can be made as shown in Figure 3.
With those measurement values, the ratio for each tap position can be calculated simultaneously as shown in equation 3.
(3)
The excitation characteristics can also be obtained for all the taps by performing an excitation test across the complete secondary winding and measuring voltages across all the taps throughout the test duration. Measured tap voltages along with calculated turns ratios and secondary current can be utilized to plot the excitation curves for all the tap combinations concurrently.
A DC winding resistance test for a CT secondary winding is performed to detect any shorted turns or high-resistance connection point(s) in the CT secondary circuit. The same concurrent technique can be employed to measure the winding resistance of each tap combination by applying a DC current through the entire secondary winding and measuring the voltage drop across each tap position.
COMPARATIVE ANALYSIS
This section focuses on the performance characteristics of a CT using two techniques discussed in the previous sections: the DC excitation method and the concurrent test technique. A comparative analysis of test results from excitation tests performed using the AC method and DC method is discussed. The accuracy of testing a multi-tap CT in AC concurrent method is examined by comparing the test results obtained from testing the same CT on a tap-by-tap basis (AC method).
Furthermore, the test results from AC concurrent method are compared with the DC concurrent method for accuracy.
AC Excitation vs DC Excitation Test
Four types of protection CTs (C400 and C800) with varying saturation characteristics were tested in the field using the AC and DC methods explained in the previous section. The excitation test was conducted between the X1–X5 taps of the CT. Their characteristics are shown in Figure 4 a, b, c, and d.
From Figure 4, the saturation curves for two C400 and two C800 CTs obtained from AC and DC excitation methods provided similar excitation characteristics and knee-point values. The difference in knee point measured using the ANSI 45 method (tangent at 45° angle) for the two methods (AC and DC) was found to be negligible.
Excitation Tests. Performing an excitation test using the non-concurrent method involves measuring voltage/current across individual taps. The concurrent method measures the voltage drop across all the taps simultaneously and calculates the secondary current using the
ampere-turns principle as given in equation (2). The field results from the AC excitation test across different taps using concurrent and non-concurrent measurement methods are provided in Figure 5. The field results show that the excitation curves using the concurrent measurement method follow the non-concurrent measurements. The results also confirm that the concurrent method could
Figure 4: Comparison of AC and DC Test Method Results
Table 1: Ratio Test Comparison
improve testing efficiency by reducing the test time considerably without compromising the accuracy of test results.
Ratio Test. For concurrent tests, equation (3) can be used to calculate the ratio of each tap by simultaneously measuring the voltage drop across each tap (V12, V23, V34, V45) and the voltage induced on the primary (Vh). Table 1 provides field results of both a non-concurrent and concurrent test across the same taps of a CT. From Table 1, it can be observed that the differences in results between the two methods are negligible.
Winding Resistance Test. A DC current is applied to the secondary winding of a CT and the voltage drop across each tap is measured individually. The connections for this test are the same as the ratio test. The winding resistance of different tap positions measured using nonconcurrent and concurrent methods is provided in Table 2. The field results show that the resistance values do not differ much between the two methods.
Concurrent DC vs Concurrent AC Test. The concurrent DC method follows the same connection and working procedures of a concurrent AC method. DC voltage is applied across the CT secondary, and the voltage across individual taps is measured simultaneously. The excitation characteristics of a C800-type CT using AC and DC concurrent methods is shown in Figure 6.
The linear portions of the AC and DC method excitation curves are observed to be following each other closely. The knee point for CT saturation using the DC method is similar to that for the AC method. The minor differences in the lower part of the curves could be attributed to the non-linear characteristics of CT excitation response in that region and the low-voltage range selection (<5 V) of the instrument during the measurement.
The DC method can be used to test CTs with high saturation points, such as TPY and TPZ that are used in locations where high transient and sub-transient currents are expected. Figure 7 shows the result of a CT with a high kneepoint value of close to 14,000 V.
Testing CTs such as TPY and TPZ is very difficult when only the AC method is employed, as the voltage required to saturate the core is high. On the other hand, the DC method only requires a voltage below
Figure 5: Comparison of Non-Concurrent AC and Concurrent AC Test Method Results
Figure 6: Comparison of Concurrent AC and DC Test Method Results
Table 2: Comparison of Winding Resistance Test Results
Figure 7: Testing CT with High Knee-Point
Using the DC Method
line power value to achieve core saturation characteristics for these types of CTs.
CONCLUSION
It is vitally important to test protection class CTs during installation and periodically thereafter to ensure they work as intended for power system protection applications. The tests recommended for CT testing in the industry standards are well established. However, methods used to perform those tests are evolving.
Efforts are being made to create safer operating conditions, test special-application CTs, and improve the efficiency and productivity of the test system through automation, intelligent data processing, and developing smart algorithms utilizing basic principles of transformer operation and electromagnetics.
New measurement techniques proposed in this article, although unique, utilize the concepts well-described in electrical textbooks. DC excitation and the concurrent method of testing offer an alternative approach for testing CTs that provides the same measurements and results as conventional techniques recommended in various international standards. The comparative analysis between different methods indicates that DC excitation and the concurrent method of testing can
be utilized in place of AC excitation and individual tap-by-tap testing techniques without compromising the accuracy and reliability of the results. Demagnetization is highly recommended after a DC excitation test to minimize any residual magnetism in the core of the CT.
REFERENCES
IEC 60044-6, Instrument Transformers Part 6: Requirements for Protective Current Transformers for Transient Performance.
IEEE C57.13.1-2006, Guide for Field Testing of Relaying Current Transformers.
United States Patent: Concurrent Transformer Test System and Method. Patent No. US 9,128,134 B2, Date of Patent: Sep. 8, 2015.
Dinesh Chhajer manages Megger USA’s Technical Support Group. His responsibilities include providing engineering consultation and recommendations in relation to testing of transformers, batteries, circuit breakers, and other substation assets. Dinesh has presented numerous white papers related to asset maintenance and testing at various conferences within power industry. Dinesh previously worked as an Application Engineer at Megger and a substation and design Engineer at Power Engineers Inc. He is an IEEE member and a licensed Professional Engineer in Texas. Dinesh received his MS in electrical engineering from the University of Texas at Arlington.
Sughosh Kuber is a Relay and Protection Applications Engineer at Megger North America, where he provides technical support to service companies and utilities responsible for reliable operation of electrical networks. Sughosh brings over 9 years of field experience and academic research in power systems from protection schemes and testing to data analysis for energy efficiency and sustainability. Sughosh received his MS in electrical engineering from New Mexico State University.
Exhibit to an audience of 500+ electrical testing professionals including leading decision-makers looking for new products and services.
MARCH 8 – 12, 2021 ROSEN
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TESTING AND COMMISSIONING A DISTRIBUTION RECLOSER IN GRID-TIE SOLAR FARMS
BY MOHIT SHARMA, Megger, and LUIS MONTOYA, PE, FlexGen Power Systems, formerly ABM
Rapid photovoltaic (PV) penetration into the electric grid has mandated deeper operational and technical understanding of protection schemes in PV farms. An effective protection scheme ensures a grid-connected system functions reliably and securely, and testing and commissioning the entire protection scheme to prove its operational success is of paramount importance. This article presents a standard grid-tie photovoltaic farm architecture and discusses how to restore the system to regular operation using reclosing schemes.
Distributed generation (DG) is increasingly widespread across the nation’s utility landscape, but uniform policies that allow renewable energy generators to connect to the utility grid were missing until recently. This significantly complicates renewable energy installations and has likely deterred the adoption of customer-sited DG. To address these complications, IEEE introduced interconnection standard IEEE Std. 1547 in 2003 to facilitate deployment of renewables and other forms of DG by specifying technical and institutional requirements and the terms by which utilities and DG system owners must abide.
IEEE and North American Reliability Corporation (NERC) standards exist to address the reliability needs of interconnected electricity systems. These standards apply to the bulk electrical system (BES) specified by the BES definition adopted by the Federal Energy Regulatory Commission (FERC) in March 2014.
In some cases, norms apply to devices and needs beyond the BES. As more distributed energy resources are connected to the grid, their impact on the bulk power system is becoming substantial. At higher penetration levels, issues may develop in transmission line loading, grid voltage, and system frequency during regular or disturbed operation. Therefore, extensive testing and commissioning of devices that are part of distributed generation and their interconnection have gained careful consideration. This article looks at protection testing of recloser controllers that are a crucial part of many grid-tied renewable energy systems.
SYSTEM DESCRIPTION
A typical utility-scale solar photovoltaic system is shown in Figure 1. The system is divided into three subsystems: direct current system, alternate current collector system, and distribution-level system.
• The direct current system consists of solar arrays, combiner boxes, fuses, and disconnects all operating on DC power. Each subsystem’s specific overcurrent protection needs are based
on the requirements of array-combiner boxes.
• The alternate current collector system is located on the AC side of the inverter and typically consists of a 480 V AC common bus.
• The distribution-level system appears at the output of the collector system. Power from the solar farm is injected via a stepup transformer, which transforms system voltage from 480 V AC to 12.5 KV AC allowing interconnection to distribution line voltages. This subsystem consists of potential transformers (PTs), current transformers (CTs), medium-voltage underground and overhead cable, a revenue meter, and a medium-voltage recloser switch equipped with an electronic relay.
Inverters in the solar farm transform energy from DC to AC. Each inverter has overcurrent and overvoltage protection. The DC protection side is isolated from the AC side, including isolated ground fault systems. Indeed, individual protection schemes apply to each subsystem. However, this paper focuses on protection requirements for the distributionlevel system.
INTERCONNECTION AND PROTECTION
IEEE Std. 1547-2018 describes the requirements for interconnecting solar PV farms. A photovoltaic solar farm classifies as a distributed energy resource (DER) and therefore must comply with operational requirements to respond to abnormal voltages and frequency events in the utility line.
Conditions for interconnection include active and reactive power capability and voltage/ power requirements. The three-phase inverters are responsible for adjusting these in the system. The inverters act as a link between the DC system and the AC collector system as shown in Figure 1.
Figure 2, a detailed view of the distribution level system, indicates the location of the recloser switch and relay.
The MV recloser and its relay system should respond to utility EPS disturbances. IEEE Std. 1547 establishes response-time requirements for mandatory disconnection due to loss of phase, area EPS fault conditions, and out of limit voltage or frequency. Table 1 and Table 2
Figure 1: One-Line Diagram for Utility-Scale Solar Farm Main Zones
indicate boundaries for voltage and frequency, respectively.
During fault conditions, grid voltage (line side of the recloser switch) could experience excursions outside of normal operating values resulting in power fluctuations. Therefore, the standard recommends two levels of undervoltage and overvoltage. To comply, system voltage on the utility side of the recloser must be monitored. The MV recloser switch controller chosen for this article is capable of receiving six voltage inputs. Three inputs are from the utility side, sourced from three 0.5 kVA distribution transformers; three inputs are from the generating side, sourced from three low-energy capacitive voltage sensors located in the bushings of the solid dielectric recloser.
The standard also proposes underfrequency and overfrequency levels that directly address the system’s protection stability and are indirectly responsible for unintentional islanding.
When an MV recloser switch operates and isolates a PV farm from the grid, a relay mechanism must guarantee reconnection once grid conditions are normal and healthy voltage is established. Schemes involving automatic reclosing (Figure 3) can ensure proper
Table 1: Response Requirements to Abnormal Voltages
SOURCE: IEEE STD. 1547-2018
Table 2: Response Requirements to Abnormal Frequency
SOURCE: IEEE STD. 1547-2018
disconnection and reconnection of the solar PV farm to maintain production while the solar PV injects the maximum power available. The recloser sequence should be coordinated with the local area EPS since automatic reclosing onto a circuit needs approval from the affected utility. Abnormal conditions should result
Over voltage (59)
Under voltage (27) Over frequency (81O) Under frequency (81U)
Phase and Ground Overcurrent (51P, 51G, 50P, 50G)
Figure 2: Distribution Level System for Solar PV Interconnection
in momentary cessation of operating mode, and restoration of connection behavior must be coordinated for proper reclosing time characteristics.
External conditions such as battery failure, manual push-button trip, yellow-handle operation, and relay sleep mode must be considered in the MV reclosing sequence.
TESTING AND COMMISSIONING
For reliable operation of an interconnected system, testing and commissioning protection elements for the MV recloser switch must be performed with satisfactory results.
Functional Tests
Functional tests include testing individual protective elements that are used in the logic of the MV recloser switch controller for interconnection requirements. The microprocessor-based controller under test can accommodate two-phase voltage: one phase current and one neutral current winding. It is also capable of functioning as either a singlepole or three-pole trip and close for reclosing applications.
• Undervoltage/Overvoltage Elements. Two undervoltage and overvoltage elements are set in phase-to-neutral (PhN) volts secondary. Time delays are set in units of cycles (Figure 4). Any modern relay test equipment that can provide three-phase voltages can be used.
• Pickup Test. Figure 5 shows that the pickup test can be designed using stepramp decrements with nominal secondary voltage as a pre-fault condition. The start of the ramp can be set to 110% of the expected level-1 pickup (100.2 V) value and the stop can be at 90%. Users can perform a three-phase and/or a singlephase ramp to validate all fault types: ABC, AB, BC, CA, AN, BN, CN. Setting
Figure 4: Voltage Element Settings
Figure 5: Undervoltage Level-1 Pickup Test Setup
Table 3: Undervoltage Level-1 Pickup Test Results
the dwell time is also crucial in this application since undervoltage elements are associated with time delay. Figure 5 shows that the time delay between each increment is kept higher than 100 cycles.
• Timing Test. This timing test can be done using two state sequences. The first state can be set to simulate nominal load conditions with a specified time duration; the second state can be set as a sudden drop in voltage to simulate the undervoltage fault condition. Figure 6A and Figure 6B show the setup. Refer to Table 4 for results. Similarly, overvoltage tests can be performed.
• Reclosing Elements
0 Unsuccessful reclose test. As the name indicates, this test can be
Figure 6A:
Setup: Fault Condition State
performed to check whether the reclosing logic works as intended and the recloser goes to lockout state if any permanent fault exists. For the reclosing cycle to be initiated, the controller provides the ability to set logic equations as a setting. This setting is a rising-edge detect setting and is supervised by recloser status. It is usually programmed to trigger when the trip condition goes true. Additionally, the controller under test has independent settings for singlepole and three-pole operation mode. Special attention is needed to set the test template to work as per the set operation mode.
The scheme uses a three-phase recloser capable of tripping and closing all three phases in unison. It is designed for just one reclose shot before going to the lock-out state in case of a permanent fault.
Popularly, state sequencer is used to design a test template to validate the auto-reclosing sequence in the MV recloser switch controller. Both controller and recloser on the pole can be simultaneously tested. Any modern test equipment with an interface to connect the control cable can be used. In a situation where only controller testing is desired, there is no need for special equipment with
Undervoltage Level-1 Timing
Test Setup: Load Condition State
Figure 6B: Undervoltage Level-1 Timing Test
Table 4: Undervoltage Level-1 Timing Test Result
the interface. One can use binary outputs on test equipment to simulate breaker conditions.
Depending on the number of shots, the state-sequencer file can be adjusted for the number of states. Since one shot is programmed in the controller under test, the total number of states needed will be five.
– A pre-fault state 1 is needed to simulate load conditions with the breaker closed for the amount of time the controller takes to reset from a past lockout. If the controller is already in the reset state, there is no need to delay.
– State 2 can be programmed to simulate trip conditions that initiate a reclosing sequence. In this state, test equipment expects to receive a trip signal; therefore, the timeout has to be long enough in case there are any timed elements in trip logic. According to the logic diagram of the trip output described in the previous section, a single-phase undervoltage condition can be simulated as a fault.
– State 3 can be simulated similar to state 2 where the fault condition still persists. As part of an agreement with utility operators for reconnection, the controller under test is set to wait four hours before going to lockout if it doesn’t read three-phase healthy voltage.
For testing purposes, the wait can be reduced since it is just a timer. The event report shown in Figure 7 indicates a three-phase lockout (79LO3P) trigger after the timer, which is set to 23 cycles in this particular scenario, expires.
0 Successful reclose test. As the name indicates, this test verifies that the reclosing logic works as intended and goes to reset state if any temporary fault exists. Similar to the unsuccessful reclose test, state sequencer can be used. Moreover, this test will ensure whether the set open interval timer for the reclose shot works as expected. State 1 and state 2 can be copied and pasted from the previous test. State 3 can be simulated as a recloser breaker opening condition with a timeout equal to the minimum trip duration timer set in the controller. The timer is usually set around 40 cycles for motor-operated reclosers; it is seen to be around 12 cycles for fast reclosers. This 40-cycle timer effectively adds on to any open interval time for auto-reclosing; therefore, it is better practice to have separate states for reporting purposes. Keeping that in mind, state 4 can be designed for the test equipment waiting to receive a reclose signal with a timeout little more than the set open interval time for shot 1.
0 Yellow operating-handle test. Some reclosers are equipped with a yellow operating handle that permits manual opening of the recloser. Pulling the handle down trips and locks open
Figure 7: Event Report of Unsuccessful Reclose Check
the main contacts and opens the low-voltage closing circuit of the recloser. The status of the handle is provided through the control cable to the controller. The contacts in the trip/close circuits open and stay open when the respective external handles on individual poles are pulled to lockopen positions. In many situations, just one of the opto-isolated wetting inputs of the controller monitors the combined status of the handle for individual recloser poles. The controller drives to three-phase lockout after sensing a time-qualified rising edge on that input.
Binary outputs on any modern test equipment can be used to mimic the handle status when the recloser breaker is not connected to the controller. Simulating a closed contact condition to that wetting voltage input indicates a normal system, whereas an open contact condition provides a handle operation state to the controller. State 1 and state 2 in the test software can be designed in the same fashion as an unsuccessful reclose test with an addition of providing closed binary output status for the yellow handle. State 3 should have open binary output.
• Frequency Elements
Both underfrequency and overfrequency elements must be tested for their pickup level and operation time. These elements are independent in the controller and follow a definite time operation concept where the timer starts the moment pickup is reached and stops after the set operation time irrespective of the frequency level. It is crucial to know the unit (cycles or seconds) of the set time before advancing to all the tests.
For pickup tests, frequency ramp is done with a long sequence to control the phase angle at each step of the sequence to create a smooth waveform and not one with jumps. The formula to calculate phase shift to obtain smooth is based on the rotating phasors with different pulsation (frequency).
Vectors A1 and A2 in Figure 8 represent present and future frequency vectors. The algorithm is recursive and is based on calculating the phase angle of the phasor with higher frequency to make sure that when the frequency needs to change, the previous frequency and new frequency vectors are overlapped indicating a continuous transition.
The time from one step to another must be deterministic to calculate the phase
8: Frequency Vectors on Time Axis
Figure
angle of the next phasor and know exactly when the frequency changes. For that reason, test software often uses the method that employs state change on zero-crossing.
Another important concept is to understand the relay’s measurement technique. Most relays adjust processing algorithms to track the frequency, and this can make the operate time seem shorter or longer than expected. The response time of the frequency elements to a valid frequency change is around three cycles in the controller under test. The testing crew must be cautious not to miss entering a time interval of more than three cycles between frequency changes in the test software.
The frequency elements of the controller operate on the frequency determined from the A-phase source-side voltage terminal. An undervoltage supervision check is also programmed to ensure frequency elements do not operate for a fault condition, since faults create transients that can result in incorrect system frequency measurement. Frequency elements are blocked until the system voltage recovers above the specified threshold, which is set to 12.5 Volts in the test example. Figure 9 shows the settings considered for this article.
Frequency elements are pretty tight on tolerances, and entering the right information is crucial. Tri-time tolerance for the controller under test is +/- 0.25 cycle plus +/- 0.1%, and pickup accuracy is +/- 0.01 Hz. Figure 10 shows a test setup screen with all the useful information. Prefault phase-to-neutral voltage of 69 V, higher than a UV block setting of 12.5 V, is entered. Note that the software is programmed to use two binary inputs on the test equipment. Input 1 will trigger when pickup is achieved, whereas input 2 will be triggered after the operation time lapses. A start time of three cycles is typically used to account for frequency tracking purposes explained earlier.
Figure 11, Figure 12, Figure 13, and Figure 14 show the results of frequency elements. Pickup and timing tests are both necessary.
Figure 10: Frequency Elements Test Setup
Figure 9: Frequency Element Settings
Commissioning and Interoperability Tests
This group of tests includes field tests that are useful to check system operation and interoperability — that is, the dynamic response of grid-tie inverters and recloser switch at the point of common coupling (PCC).
Step 1 . Verify system components. A field commissioning group must verify the engineering parameters and confirm proper programming for the inverters and recloser control settings. Test results should be documented to comply with ANSI/NETA
ATS and coordination study requirements. The local SCADA system should provide the status of each inverter.
Step 2. Verify the complete sequence:
1. The utility will intentionally drop a phase.
2. Immediately followed by the phase drop, the recloser switch must disconnect, and inverters should not produce any power.
3. The utility brings back the missing phase and restores voltage. Immediately, the recloser takes action to verify healthy voltages on the grid side.
4. Verification time is usually available as a setting in the recloser relay logic and can be tested easily.
5. After this delay, reclose occurs and voltages are restored to the grid and the line side of the inverters.
6. Voltage is restored, and the inverters should be timed to verify the start of power production after approximately five minutes.
7. The same procedure is repeated dropping each phase.
Step 3. A final recommended step is phase sequence verification. A drop in A-phase voltage on the recloser switch side should result in the same phase drop on the recloser.
Figure 11: Underfrequency Pickup Test Results
Figure 12: Underfrequency Timing Test Results
Figure 13: Overfrequency Pickup Test Results
Figure 14: Overfrequency Timing Test Results
Similarly, other phases should be tested for a complete phase sequence.
CONCLUSION
The requirements for grid connection of distributed generation need detailed scrutiny to comply with EPS requirements. This article presents relay protection testing procedures to aid in validating the MV recloser control and operation as part of a PV solar farm system.
Strategic steps in the relay testing routines included validation of the real operation for the MV recloser at the PCC, including detailed practical scenarios where the relay protection system must respond properly for continuity of service (i.e. reconnection and coordinated verifications) as well as protection of equipment assets (i.e. coordinated disconnection and lockout.)
Even though it is not possible to subject the MV recloser protection system to all possible scenarios in a constantly changing grid, it is important to have a testing methodology to validate protection system settings and coordinated response with other parts of the solar farms, i.e. inverters.
Mohit Sharma is currently part of the engineering team at Megger where he designs, develops, and validates testing solutions in the areas of system protection and automation. In 2015, he joined Megger as an Applications Engineer for protective relay products after receiving his MS in electrical power systems engineering from North Carolina State University, Raleigh. Mohit obtained his BTech in electrical engineering from the National Institute of Technology, Bhopal, India, and worked with India-bulls Power as an Electrical Maintenance Engineer responsible for the testing and maintenance of LV and MV switchgear. He is currently a member of IEEE-PSRC.
Luis Montoya, PE, has worked in the industry in several positions in the electrical industry as an Engineering Manager in low- and medium-voltage electrical testing and design. He is currently a Senior Systems Engineer for FlexGen Power Systems and a PhD candidate in electrical engineering at North Carolina State University with a concentration in power system and power electronics, including active power harmonic filters. Luis was a senior engineer in designing and testing solutions for utility-scale project substations and solar farms. He most recently led efforts in arc flash analysis, protection coordination, MV and LV field testing, and power quality field testing and solutions. Luis graduated from the National University of Colombia with a BS in electrical engineering with a concentration in power systems and received his MSEE from the University of Wisconsin, Milwaukee with an emphasis in power electronics and renewable energy.
IMPACT OF SFRA SETUP ISSUES ON TRANSFORMER FREQUENCY RESPONSE
BY MICHAEL D. WOLF, PE, Doble Engineering Co.
Sweep frequency response analysis (SFRA) is a popular test to confirm the mechanical and electrical integrity of a transformer. However, the resulting traces can be difficult for field personnel to interpret due to the visual nature of the data. It is more straightforward to compare numbers against prior data or against a stated limit than to interpret subtle differences in SFRA traces. If setup-related issues are not addressed during the testing process, return trips are often required to take additional shots to represent the transformer more accurately. These trips cost time and resources, so being able to identify a setup problem early can keep extra work to a minimum. A trained eye can focus in on a problem area quickly and identify a test setup issue promptly. Such confidence only comes at the expense of hours spent analyzing data. This article discusses common setup problems and their impacts.
BASIC CONCEPTS
SFRA testing hinges on sending a signal into a transformer winding at a known frequency and measuring back the signal received at the other end of the test circuit. This process is repeated across the desired frequency range. The difference between the signal that goes into the transformer and the signal that comes out is the attenuation of the signal, which is plotted on a vertical axis for each tested frequency on the horizontal axis. The individual data points become a trace as the test progresses and sweeps through the desired frequency. The attenuation is plotted as decibels (dB). The trace is plotted on a graph with high attenuation (very little signal returning to the test set) at the lowest ranges of the graph’s
vertical axis, while very-low attenuation (most of the signal returning to the test set) is shown at the highest vertical ranges.
To summarize: The more negative the dB, the higher the attenuation; the closer it is to zero, the lower the attenuation.
THE TEST
The transformer under test is a network of resistive, inductive, and capacitive (RLC) elements made up of the transformer’s magnetic circuit, windings, insulation, and countless other components that create power transformers as we know them. The impedance of inductive and capacitive elements, by their
nature, are dependent on physical properties — areas, lengths, distances. Therefore, changes to those physical properties will create a change in the impedance of the corresponding segment of the RLC network. Impedance is also dependent on frequency.
As the range of sweeping frequencies remains the same between different test sessions, damage, physical changes, and/or electrical changes that occur inside the transformer will change the impedance of various inductive and capacitive elements and will also change the level of attenuation of the input signal.
In addition, and perhaps even more important, these changes may yield different frequencies at which the inductive and capacitive elements resonate with each other when compared to previous tests. Observing left-right movement or the disappearance (or creation) of the various extrema points between different test sessions are key aspects to look for, as they indicate some physical or electrical changes to those capacitive and inductive elements. Extrema points are the local maximum and minimum points on the traces that resemble peaks and V-shaped valleys, to put a common visual to the term.
CONCERN OVER SETUP
In any electrical test, it is well understood that correct and consistent test setup is essential for repeatable, representative test results. SFRA tests are also dependent on consistent test setup between different test sessions. Changing setup may cause changes in the RLC network of the transformer by introducing varying capacitances, resistances, and inductances. This variation may mask other concerning changes in the transformer itself, or it may create false positives. If variations between past and present traces are noted, all efforts should be made to troubleshoot possible setup errors before accepting the traces as representative of the transformer.
Poor Grounding
Among the more common SFRA setup problems, poor grounding practices can massively impact the expected traces. This is not just the grounding of the transformer itself, but the entire grounding path of the measurement setup. If the grounding path introduces additional impedances due to poor connections, the signal will be measured with respect to a different reference, resulting in changes to the traces. Typically, poor tank grounding influences
Figure 1: Drastic Example of Poor Lead Grounding
the entirety of the trace and may be seen across the high-voltage open circuit (HVOC), lowvoltage open circuit (LVOC), and high-voltage short circuit (HVSC) traces. The traces may appear jagged, noisy, shifted to a higher (-)dB, and may not follow an expected shape.
Poor connections on the test lead ground clamps can also produce wide-ranging changes in the response and will most likely be apparent when comparing phases in a given test session. If the test lead ground clamp is not adequately grounded, the impedance of the test lead changes, impacting the higher frequencies of the swept range. The impact can move further down the frequency range with worsening ground lead connections. These seemingly minor changes to the grounding circuit can make dramatic changes similar to that shown in Figure 1. In less significant cases, the changes may begin much higher in the frequency range.
In Figure 1, the blue trace was captured during routine testing. The tester identified something was wrong and began to troubleshoot. The connections at the test lead grounds were cleaned up with a wire brush to ensure solid metal-to-metal contact. This resolved the initial issue and resulted in the red trace.
Poor Test Lead Connections
When test leads are poorly connected to the bushing terminals, extra impedances are introduced into the measurement lead circuit. These additional impedances cause the characteristic impedance of measurement cables to change, which will impact the response of the transformer. These impedance changes impact a wide range of frequencies and will yield poor comparison to prior traces with good lead connections.
In the traces shown in Figure 2, the red trace was captured initially. Noting the jagged nature of the trace, the tester determined that troubleshooting was required. Bushing terminal connections were cleaned thoroughly with a wire brush and solvent. After ensuring a robust metal-to-metal connection between the test lead clamps and the bushing terminals, the blue trace was captured. The resulting response follows an expected shape with less jagged features.
Varying Tap Changer Positions
When load tap changers or deenergized tap changers (DETC) change position, the way
Figure 2: Example of Very Poor Test Lead Connection
the tapped winding interacts with the various RLC networks of the transformer will change. This interaction will impact the response of the swept frequencies through the transformer, and different tap positions will cause different responses. The extent of the differences will depend on the specific design of the transformer and the tap positions being compared. Tap changers should always be checked to ensure
they are in the same positions as previously recorded traces prior to testing to ensure no additional uncertainties are introduced into the analysis. It should be noted that changing taps on one specific winding will not only impact that winding’s response, but may also impact the responses of other windings; for example, lowvoltage open circuit traces may also change upon DETC position change on the high-voltage
Figure 3: Drastic Example of Different Tap Changer Positions
Figure 4: More Subtle Example of Different Tap Changer Positions
winding. This is due to the changing interaction between the RLC components of the highvoltage and low- voltage windings.
In the example in Figure 3, the prior (red) trace and the present (blue) trace were tested before and after a planned DETC position change. The transformer was fully tested before the DETC was moved to ensure it was in good condition and aligned with prior results. The unit was then tested after the DETC was moved to attain new baseline results. After changing DETC positions, new SFRA baseline traces should always be captured to enable future analysis.
In Figure 4, the red trace was captured just before a DETC change; the blue trace was captured immediately after a change. Notice how the changes are far less drastic than in Figure 3, which emphasizes how important the specific design of the transformer is to the degree responses may change when changing tap positions.
Stabilizing Tertiary Winding Configuration
Much like the impact varying tap positions may have on a transformer’s response, manipulating the configuration of a stabilizing tertiary winding
can cause the transformer’s response to change. Some stabilizing tertiary windings may come out to a single bushing at one corner of the delta, which could be either grounded or ungrounded while the SFRA tests are performed on the primary and secondary windings. Some stabilizing tertiary windings have one corner of the delta brought out to two bushings, which can either be shorted and left floating, shorted and grounded, open and floating, or open and grounded. These changes will impact the interaction of the circuit elements that make up the RLC network inside the transformer and will result in variations to the response while performing SFRA tests. The changing response will most likely be seen in traces captured on all windings within the transformer, to varying degrees on each winding.
In the example shown in Figure 5, the prior (red) HVOC trace and the present (blue) HVOC traces were found to have different characteristics upon review in the field. After troubleshooting, it was determined that the stabilizing tertiary winding was in a different configuration when tested in the factory compared to the configuration when first assembled in the field. The tertiary was manipulated to be open, open and grounded, closed, and finally closed and grounded to ensure that a matching configuration was found. After
Figure 5: Varying of Stabilizing Tertiary Winding Configuration
INDUSTRY TOPICS
testing in the exact tertiary configuration as in the initial trace, the responses lined up extremely well. After matching with the factory results, notes describing the test setup were documented to give testers more guidance for future SFRA testing.
CONCLUSION
It is essential to remember what an SFRA trace shows: the attenuation of the output signal compared to the input signal of the test set. As frequencies are varied, the inductive and capacitive elements that make up the transformer respond differently. Those inductive and capacitive elements are also dependent on physical parameters — lengths, areas, distances, materials — so physical or electrical changes inside the transformer will influence the way the countless inductive and capacitive elements respond to varying frequency. If the test setup does not remain consistent between test sessions, the interactions between the RLC parameters of
the tested transformer will change and will show deviations between traces of different test sessions. These changes can be misleading to the tester and potentially mask other more meaningful issues. By identifying and ruling out possible setup discrepancies as the traces are being recorded, corrections can be made, and the setup can be adjusted immediately, ensuring the traces correctly and accurately represent the transformer’s condition.
Michael D. Wolf, PE, is a Principal Engineer in the Client Services Engineering department at Doble Engineering in Folsom, California. He has been in the power industry since 2008 in substation commissioning and maintenance support roles. Michael has a BSEE from Clarkson University, a MEPE from Worcester Polytechnic Institute, and is a licensed electrical power engineer.
UNDERSTANDING AND AVOIDING BATTERY FAILURE
BY RODRICK J. VAN WART, AVO Training Institute
Earthquakes, hurricanes, tsunamis, wildfires, and the like do not occur with any predicted great frequency. Nonetheless, we have established precautionary programs that protect people and property from the physical threats posed by such events. In recent times, however, we have witnessed all too well the impact these events can have on the quality of our lives and businesses.
Our world has become highly — in many cases, wholly — dependent upon electricity. This energy source supports our global economy, e-commerce, and communications. When primary AC systems fail, DC storage systems in the form of uninterruptable power supplies are required. The prime source of this backup power is batteries.
An Eaton Corporation root-cause study revealed that two-thirds of downtime events stem from preventable causes. The good news is that routine established condition and performance monitoring coupled with the IEEE-recommended preventative maintenance (PM) can appreciably reduce downtime. In fact, the same load-loss report indicated that clientele without any PM were more likely to experience a UPS failure than those who complete the IEEE recommended maintenance visits. These findings alone
validate the significance of routine UPS service as a highly effective means to reduce the effects of downtime.
BATTERY MAINTENANCE AND TESTING
There are several philosophies and ambition levels for maintaining and testing batteries.
1. Replace batteries when they fail or die. This option includes minimal or no maintenance and testing. Obviously, not testing batteries at all is the least costly when considering only maintenance costs, but the risks are high, and the consequences must be considered. Batteries have a limited lifetime, and they can fail earlier than expected. Time between outages is usually long, and if outages are the only occasions battery capability is confirmed, risk is high
that reduced — or no — back-up will be available when needed. Using batteries to back up important installations without any idea of their current health invalidates the whole concept of a reliable system.
2. Replace after a certain time with minimum or no maintenance and testing. This can also be a risky approach. It is also a waste of capital if the batteries are replaced earlier than needed. Properly maintained batteries can and do live longer than the predetermined replacement time.
3. Implement a serious maintenance and testing program to ensure the batteries are in good condition, prolong their life, and determine the optimal time for replacement. A maintenance program including inspection and impedance and capacity testing is the way to track a battery’s state of health. Degradation and faults will be found before they become serious, and surprises can be avoided.
Maintenance costs are higher, but this is the cost for a reliable back-up system. The best testing scheme is a balance between maintenance costs and the risks of losing the battery and supported equipment. Each company is different, and each must individually weigh the cost versus risk of battery maintenance
The batteries in any UPS require routine inspection and maintenance regardless of their age or warranty status — even maintenancefree batteries are only deemed maintenance-free because they do not require adding water on an as-needed basis. Industry studies have shown that up to 20 percent of UPS failures can be attributed to bad batteries; temperature and cumulative discharges including micro-cycling are the primary culprits. When performing preventive maintenance, data is obtained from ohmic testing procedures during which impedance or conductance measurements trace battery performance and identify any batteries with potential internal failures.
BATTERY FAILURE
Each battery type has multiple failure modes, some of which are more prevalent than others. Some failures manifest themselves with use and aging such as sediment build-up due to excessive cycling. Others such as positive grid growth (oxidation) occur naturally. It is just a matter of time before the battery fails. Maintenance and environmental conditions can increase or decrease the risks of premature battery failure.
• Positive grid corrosion is the expected failure mode for flooded lead-acid batteries. The grids are lead alloys (lead calcium, lead-antimony, lead-antimonyselenium) that convert to lead oxide over time. Since lead oxide is a larger crystal than lead metal alloy, the plate grows. The growth rate has been well characterized and is considered when designing batteries. Many battery data sheets specify clearance at the bottom of the jar to allow for plate growth in accordance with its rated lifetime, e.g. 10 or 20 years.
At the designed end of life, the plates may have grown sufficiently to pop the tops off the batteries. But excessive cycling, temperature, and overcharging can also increase the speed of positive grid corrosion. Impedance will increase
over time corresponding to the increase in electrical resistance of the grids to carry the current. Impedance will also increase as capacity decreases. Sediment build-up (shedding) is a function of the amount of cycling a battery endures. Shedding is the sloughing off of active material from the plates, converting to white lead sulphates.
• Sediment build-up is the second reason battery manufacturers leave space at the bottom of the jars to allow for a certain amount of sediment before it builds up to the point of shorting across the bottom of the plates, thus rendering the battery useless. The float voltage will drop, and the amount of the voltage drop depends upon how relatively “hard” the short is. Shedding, in reasonable amounts, is normal.
• Corrosion of the top lead, which is the connection between the plates and the posts, is difficult to detect even with a visual inspection since it occurs near the top of the battery and is hidden by the cover. The battery can fail due to the high current draw during discharge. The heat build-up when discharging results in melting, causing the battery to crack open, and then the entire string drops offline, resulting in a potentially catastrophic failure.
Top Lead Corrosion
Everything looks good (left) until closer inspection reveals that sulfation has caused the plate to expand and breach the container (right).
• Plate sulphation is an electrical path problem. A thorough visual inspection in vented lead acid (VLA) batteries can sometimes find traces of plate sulphation. Sulphation is due to low charger voltage settings or incomplete recharge after an outage. Sulphates form when the volts per cell (VPC) are not set high enough during recharge. Sulphation will lead to higher impedance and a lower capacity.
• Dry-out is a phenomenon that occurs primarily in valve regulated lead acid (VRLA) batteries due to excessive heat (lack of proper ventilation), high ambient temperatures, and overcharging, which can cause elevated internal temperatures. At elevated internal temperatures, the sealed cells will vent through the pressure relief valve (PRV). When sufficient electrolyte is vented, the glass matte is no longer in contact with the plates, thus increasing internal impedance and reducing battery capacity. This failure mode is one of the more common failure modes of VRLA batteries and is easily detected by impedance testing.
• Soft (aka dendritic) shorts and hard shorts occur for a number of reasons. Hard shorts are typically caused by paste lumps pushing through the matte and shorting out to the adjacent (opposite polarity) plate. Soft shorts, on the other hand, are caused by deep discharges. When the
specific gravity of the acid gets too low, the lead dissolves into it. Since the liquid (and the dissolved lead) are immobilized by the glass matte, when the battery is recharged, the lead comes out of solution and forms threads of thin lead metal, known as dendrites, inside the matte. In some cases, the lead dendrites short through the matte to the other plate. The float voltage may drop slightly but impedance can detect this failure mode easily.
• Thermal run-away occurs when a battery’s internal components melt down in a selfsustaining reaction. The impedance and float current increase in advance of thermal run-away. Thermal run-away is relatively easy to avoid simply by using temperaturecompensated chargers and properly ventilating the battery room or cabinet. Temperature-compensated chargers reduce the charge current as the temperature increases. Remember that heating is a function of the square of the current. Even though thermal run-away may be avoided by temperature-compensated chargers, the underlying cause is still present.
CONCLUSION
Systematic inspections and an effective preventive maintenance plan can ensure standby battery systems are capable of supporting the critical role UPS systems play in maintaining power to critical loads.
INDUSTRY TOPICS
REFERENCES
Eaton Corp. “The Benefits of a Preventive Maintenance Service Plan for Your UPS SVS-WP04,” https://www.eaton.com/content/ dam/eaton/markets/healthcare/knowledgecenter/white-paper/the-benefits-of-a-preventivemaintenance-service-plan-for-your-UPS.pdf, March 22, 2009.
IEEE 450, IEEE Recommended Practice for Maintenance, Testing and Replacement of Vented Lead-acid Batteries for Stationary Applications.
IEEE 1188, IEEE Recommended Practice for Maintenance, Testing and Replacement of Valve-Regulated Lead-Acid Batteries for Stationary Applications.
National Security Council. “The Comprehensive National Cyber-Security Initiative,” http://www. globalsecurity.org/security/library/policy/national/ cnci_2010.htm, October 29, 2010.
William L. Tafoya, PhD. “FBI Report on Cyber Terror,” FBI Law Enforcement Bulletin, November 2011.
Rodrick J. Van Wart is a Senior Consultant and Instructor at AVO Training in Dallas, and an Instructor at the Omega Institute for Continuing Education. His 47 years of experience in the electrical industry includes chairing test development for the International Code Council’s inspector exams, overseeing development of Iowa’s electrical licensing and permitting programs, and providing training for the state’s Electrical Examining Board members and support staff. Rod served several municipalities as an electrical and mechanical inspector, earned Public Management certification from Drake University, and is a Certified Building Official. A subject matter expert in adult learning precepts and instruction in a classroom setting, he designed and implemented new curriculum subject matter and was awarded Top Gun status at Mike Holt’s Instructor Training Conference. During the last four years of his 18-year US Navy career, Rod certified apprentices and third-class nuclear electricians logging 336,800 hours of total student contact time. He currently serves as a member of the IEEE PES/ESSB Committee on Working Groups 450, 484 (Vice Chair), 485, 1188, 1578, and 1679.
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PF MEASUREMENTS ON COMPLETE
BY MATHIEU LACHANCE, OMICRON electronics Canada Corp.
Power factor (PF) measurement has been performed on stator windings for many decades and is a widely accepted and recommended tool to assess the insulation system of individual bars/coils and for complete stator windings. The test is known to be sensitive to several global defects such as the degree of curing of the bonding materials, moisture ingress, contamination, and thermal aging.
In addition, the power factor tip-up variation of this test is commonly used to detect the void content of insulation. The power factor tip-up test compares the results of two PF measurements performed at two different voltages. Outside of North America, the PF measurement is often referred to as dielectric dissipation factor (DDF) or the tangent delta test, where the tangent of the loss angle is instead recorded. The difference between PF and DDF is negligible for values below 10%.
Two main standards specifically cover power/ dissipation factor testing for rotating machines:
1. IEEE Std. 286, Recommended Practice for Measurement of Power Factor TipUp of Electric Machinery Stator Coil Insulation
2. IEC/TS 60034-27-3, Rotating Electrical Machines – Part 27: Dielectric Dissipation Factor Measurements on Stator Winding Insulation of Rotating Electrical Machines
Both offer useful information and guidance regarding the test procedure, test voltage, and data interpretation. One thing they have in common is that neither document provides absolute limits as pass/fail criteria for complete stator windings. This creates additional challenges for data assessment. Without pass/fail criteria, the test is classified as a diagnostic test, and the data must be analyzed and assessed with care. Typically, a combination of four parameters is used for the assessment:
1. Variation of the PF values in time (trend evaluation)
2. Change in power factor between two prescribed voltages (tip-up values)
3. PF value at low voltage
4. PF value at high voltage
This article reviews challenges that can be faced when performing an assessment of PF data on complete stator windings and will discuss the reason global absolute values should not be used. A modern approach to evaluate PD activity in stator winding from the PF data will also be discussed.
END-POTENTIAL GRADING (EPG)
Rotating machines with a rated voltage of 6 kV and above usually have end-potential grading (EPG) tape or paint installed in the
end-winding area. This material can be found under various names in the literature: Semi conductive grading, end winding stress grading, or EPG are only a few names; all indicate the same area. EPG is illustrated in Figure 1.
The purpose of EPG is to distribute electric field lines over a longer portion of the bars at the exit of the stator slots. Even if insulation is applied at the end-winding area, this area is at high-voltage potential due to the capacitive coupling between the conductor and the ground. Without EPG, a high local electric
This behavior creates additional losses at higher voltage levels. As voltage is increased, the resistance of EPG decreases. The loss current (I2) increases, which results in an increase of resistive losses. It is important to know that this surface current is not an indication of the health of the bulk insulation (Figure 4) and will be added to the total measured test current.
Various compounds are used for EPG, and each of them has its own conductive behavior. The chosen material will remarkably affect power factor values when voltage is increased above voltage breakdown (V BD), which is usually significantly lower than the rated lineto-ground (L-G) voltage of the machine.
POWER FACTOR TIP-UP
field would appear at the laminated core as shown in Figure 2. This would result in high partial discharge (PD) activity.
Currently, silicon carbide (SiC) is the primary component of EPG and is responsible for its grading properties. The conductive behavior of EPG is voltage-dependent and non-linear. When voltage is increased, the SiC layer becomes more and more conductive, resulting in a behavior shown in Figure 3.
Power factor tip-up is the difference between two PF values obtained from two measurements at two different voltages. Historically, when testing complete windings in North America, measurements are performed at 0.25 x UN/√ 3 and at UN/√ 3, where UN is the rated line-toline voltage. The test is mainly used to detect voltage dependent anomalies in the winding such as those that create PD activity.
The theory of partial discharges is comprehensive and is beyond the scope of this article. However, a short description is helpful from this point forward. Even though normal PD activity is present in most medium- and high-voltage stator windings, PD can result from different anomalies. When these anomalies occur, the discharges will result in a small amount of dissipated energy. If there are several PD events, the amount of dissipated energy might be measurable during a PF measurement. PD activity only occurs above a specific inception voltage level that is dependent on the insulation system and the type of defect.
When performing a power factor tip-up test, the value obtained at 0.25 x U N/√ 3 is assumed to be exempt from PD activity, while the value at U N /√ 3 is assumed to
Figure 2: Electric Field Distribution: (left) without EPG, (right) with EPG
Figure 3: Typical Current-Voltage Curve of a Given EPG
Figure 4: Schematic of Surface Current Circulating around Insulation
Wire (High Voltage)
contain the dissipated energy from the PD activity if present in the winding. In theory, a difference between these two measured values would indicate the presence of significant PD activity. However, with only two measuring points, it can be difficult to distinguish losses caused by a voltage-dependent defect from the expected increased losses caused by the conduction behavior of EPG. It is even more difficult to establish a tip-up limit because of the wide variety of EPG used by different manufacturers.
GUARDING FOR INDIVIDUAL BARS/COILS
The power factor tip-up test is commonly used for quality control on newly manufactured coils and bars. Depending on the manufacturer and on customer requirements, it can be performed on each coil/bar or on samples of a production lot.
To remove the influence of EPG, various guarding techniques are used in the factory that cause the test to become more sensitive to the void content within the bulk insulation and less sensitive to the conduction behavior of EPG. Figure 5 shows a schematic of one guarding technique; Figure 6 illustrates the difference between measurements on a single coil with and without guard electrodes. Guard electrodes are not perfect, and a small contribution of surface currents is usually still measurable even with some guarding techniques.
ADVANCEMENTS IN INDUSTRY
It is not feasible to install guard electrodes on every bar of completely assembled stator windings. Therefore, tip-up values obtained in the field — even for healthy machines — are usually higher than values recorded in the factory on individual coils/bars. Some EPG can be conductive even at lower voltage. For this reason, it is not recommended to compare values from individual coils/bars with the values obtained in the field on a complete assembled winding.
PD HYSTERESIS
Modern power factor test instruments are now able to record as many points as necessary and take measurements during the decreasing voltage stage of the test. Instead of simply measuring the tip-up value between two points, instruments can now record many data points, enabling visualization of the power factor voltage sweep curves. These curves can be used to extract additional information and enhance diagnostic capability.
Figure 6: PF Voltage Sweep Curves: (left) without Guard Rings, (right) with Guard Rings
Figure 5: Stator Bar with Guard Electrodes
ADVANCEMENTS IN INDUSTRY
PD usually occurs above a certain voltage level and results in small current impulses that create additional losses. Two parameters are commonly measured during offline PD measurements:
a) PD inception voltage (PDIV): the voltage at which PD appears when voltage is increased
b) PD extinction voltage (PDEV): the voltage at which PD disappears when voltage is decreased.
In many cases, PDIV is higher than PDEV. This means that, for a winding with high PD activity, losses can be higher when the voltage is decreased versus when voltage is increased. It is believed this behavior creates so-called PD hysteresis in PF curves when performing an upward and a downward voltage ramp. In various measurements, this correlation was confirmed between PD activity and a hysteresis of PF curves. It is important to mention that
not all PD activity will exhibit this behavior. For example, corona-type PD is known to have similar PDIV and PDEV values and therefore will not exhibit the hysteresis curve. Figure 7 shows the results of a PF measurement of a winding with high inner PD activity; Figure 8 shows the PF results of a winding with low inner PD activity; Figure 9 shows an example of a winding with no significant inner PD activity.
Using power factor voltage sweep curves can help the test operator visualize whether the increase in power factor, with respect to the voltage, is due to partial discharges or simply the normal conduction behavior of EPG.
With guard rings
MACHINE CONSTRUCTION
Machine construction can significantly influence the expected PF results for traditional tip-up values and for PF voltage sweep curves.
Figure 7: PF Voltage Sweep Curve with High Inner PD Activity
When performing PF measurements on a clean and healthy stator winding that does not have an EPG area, no significant increase of losses with respect to increased voltage is expected. A stator winding with rated voltage of 6 kV and below is an example of a machine that does not have an EPG area. However, some manufacturers have started to install EPG on machines operating at lower voltage, especially if they are inverter fed. Figure 10 shows the results of a healthy and clean 4.16 kV machine without EPG; Figure 11 shows a retired 4 kV machine with high PD activity and no EPG.
Figure 8: PF Voltage Sweep Curve with Some Inner PD Activity
Figure 9: PF Voltage Sweep Curve with Low Inner PD Activity
The number and length of slots can also significantly impact expected values. Machines that have many short slots will be subjected to higher influence from the surface current caused by EPG. This is because the surface current becomes dominant in comparison with the current that goes through bulk insulation (refer back to Figure 4). An example can be seen in Figure 12, where PF measurements of a healthy and clean winding show a large increase of PF values with respect to voltage. The PF values start at 1.50% at 1,000 V and increase to approximately 3.85% at 9,500 V. This is another factor to consider if tip-up limits are applied to a complete stator winding.
ASSESSMENT
Neither IEEE 286 nor IEC 60034-27-3 currently publish limits for complete stator windings. IEC 60034-27-3 does include limits for individual coils and bars using guard electrodes. However, it is important to mention that many have questioned those values; they are viewed as too restrictive by some and overly lenient by others. In addition, these limits should not be applied for complete stator windings. The difficulty of establishing global limits results from numerous variables such as various insulating materials, different conductive behavior of installed EPG, and the geometry of the machine itself.
Power factor values, tip-up values, and voltage sweep curves should be recorded and trended over time. When measurements are recorded during similar environmental conditions at
different points in time, increased power factor is generally a sign of insulation deterioration or aging. A comparison between phases and between similar machines can be useful, and empirical limits based on measurements performed on similar machines can also be established. In any case, it is recommended to consult with the machine manufacturer or the test equipment manufacturer when PF values display an upward trend over time.
If no historical data is available, the ability to perform an assessment from one single measurement is limited. PD hysteresis can therefore be used to verify the presence of PD within the insulation. In addition, a comparison between phases of the machine could also be used if the neutral point can be isolated.
CONCLUSION
Power factor measurement provides a general assessment of insulation with limited capability to detect localized weak points. Therefore, the
Figure 10: PF Voltage Sweep Curve of a Healthy 4 kV Machine
Figure 11: PF Voltage Sweep Curve of a Retired 4 kV Machine with High PD Activity
Figure 12: High Loss Contribution from EPG
ADVANCEMENTS IN INDUSTRY
values do not represent the most deteriorated part of the winding, as a large power factor value can be due to voids distributed all over the winding or a few single, heavily aged bars or coils. The impact of the latter case is potentially much more severe for the longevity of the winding. It is, however, good practice to perform measurements whenever possible and to trend the values throughout the asset’s lifetime. If an increase in power factor values or tip-up values is observed, further investigation including visual inspection and additional electrical tests can be triggered to complete the assessment.
CASE STUDY
In January 2012, power factor measurements were performed on a 6.4 kV, 5.6 MVA hydro generator as part of a planned outage. The machine was manufactured in 1981. The neutral point was disconnected to test each individual phase separately, and the line terminals were isolated from the system as recommended by relevant standards.
The only available historical data from 1991 is illustrated in Table 1 and Figure 13.
In this specific case, it was necessary to increase the test voltage up to UN. To display the PD hysteresis curves with enough resolution, a minimum of 10 data points is usually recommended. Therefore, the voltage was increased using increments of 0.1 x UN. The results are shown in Table 2 and Figure 14.
Comparing the data from 2012 (Table 2 and Figure 14) to the data of 1991 (Table 1 and Figure 13) shows significant increase of all values for all three phases. Increased PF values could be expected due to aging since the measurements were taken 20 years apart. After all, at the time of the 2012 measurements, the machine had been operating for a little more than 30 years. However, the losses in phase A were more than twice the losses measured in the other two phases. In addition, hysteresis behavior was noticeable in all three phases, but predominantly on phase A. For these reasons, additional electrical tests were recommended to investigate the results.
The results of a dielectric frequency response (DFR) analysis confirmed the presence of an anomaly on phase A. To locate the defect in
Table 1: PF Data from 1991
Table 2: PF Measurements before Repairs
Figure 13: PF Voltage Sweep Curves from 1991
Figure 14: PF Voltage Sweep Curves before Repairs
ADVANCEMENTS IN
Table 3: PF Measurements after Repairs
REFERENCES
IEEE Std. 286-2000, Recommended Practice for Measurement of Power Factor Tip-Up of Electric Machinery Stator Coil Insulation, pp 1-29, 2001, doi: 10.1109/ IEEESTD.2001.92415.
IEC/TS 60034-27-3, Rotating Electrical Machines – Part 27: Dielectric Dissipation Factor Measurements on Stator Winding Insulation of Rotating Electrical Machines, 2015.
M. G. Krieg-Wezelenburg. “Dielectric Dissipation Factor Measurements on Stator Insulation — Results from a Global Survey,” 2020 IEEE Electrical Insulation Conference (EIC), Knoxville, TN, USA, 2020, pp. 269-273, doi: 10.1109/ EIC47619.2020.9158740.
the winding, an AC dielectric withstand test at 1.5 x UN was initiated. A breakdown occurred in one coil located in the middle of the winding of phase A before reaching the final voltage level.
The failed coil was isolated from the winding, and the electrical tests were repeated. The results of the power factor measurements, after repairs, are shown in Table 3 and Figure 15.
Following the repairs, the losses of phase A were similar to losses from phase B and phase C. Figure 15 also shows that hysteresis behavior has significantly diminished. Nevertheless, the values are still significantly higher (100%) than the data from 1991 and indicate insulation deterioration on all three phases.
R. Omranipour and S. U. Haq. “How Critical are IEC 60034-27-3 Maximum Values for Dielectric Dissipation Factor and TipUp to Determine the Reliability of Motor Stator Insulation?” 2015 IEEE Electrical Insulation Conference (EIC), Seattle, WA, USA, 2015, pp. 364-368, doi: 10.1109/ ICACACT.2014.7223474.
Mathieu Lachance joined OMICRON electronics Canada Corp. in 2019 and presently holds the position of Regional Application Specialist for rotating machines and partial discharges. He previously worked as a test engineer in the fields of partial discharges and high voltage. Mathieu received a BS in electrical engineering from Université Laval in 2014.
Figure 15: PF Voltage Sweep after Repairs
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• Programmable test currents from 10mA to 200A
• Accurately measures resistance down to 1µ
• Accuracies to .05%
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• Large easy to read backlit digital displays
• Automatic multipoint measurements (model 6255)
• Internal data storage of results
• Comprehensive analysis and reporting DataView® software
AEMC® INSTRUMENTS:
OVER 125 YEARS OF TECHNICAL HERITAGE AND INNOVATION IN TEST INSTRUMENTATION
NETA 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.
In our continuing CAP Spotlight series, we highlight some of their individual successes. In this issue, NETA World interviews John Olobri, Director of Sales and Marketing for AEMC® Instruments in Foxborough, Massachusetts.
NW: What is something NETA World readers don’t know about AEMC?
Olobri: AEMC Instruments originally started in business in the United States in Boston, Massachusetts, in 1976 as Instrumentation Corporation. It was a distribution arm of Chauvin Arnoux based in Paris, France. As the business grew, a production facility opened in Dover, New Hampshire, in the early 1980s, and two additional business units were added. A name-change to Advanced Electrical Measurement and Control took place as it was a better fit for the company’s business model, and in the early 1990s, the name was shortened to AEMC® Instruments as it is known today. The company is incorporated as Chauvin Arnoux® Inc., d.b.a. AEMC® Instruments. It is still privately held and owned by the
Arnoux family. AEMC was originally known as a premier supplier of current measurement probes, and we still hold that position. Today, we offer a wide range of test instruments for ground resistance testing, insulation resistance testing, power and energy monitoring, and much more. Chauvin Arnoux in France was one of the first developers of the multimeter.
NW: What recent company achievement or milestone are you particularly proud of?
Olobri: As a world-leading manufacturer of ground resistance test instrumentation, we continually look for ways to advance the technology to address the needs of the customer. Our latest offering to test the ground resistance of towers such as electrical transmission and cellular communication has greatly improved
JOHN OLOBRI
the safety of the technician doing the test, the quality of the test results, and the cost to get the job done. Our tower tester is capable of testing towers while they are energized or de-energized. In the case of electrical transmission towers, we can accomplish the testing without the need for a crew to climb the tower to disconnect the overhead ground conductor that runs from tower to tower in the transmission line. This alone saves considerable time and money for the utility company and is much safer for the personnel doing the work. The test results provided by this instrument include footing resistance of individual and total tower legs, quality of the overhead ground conductor bonding to the tower, leakage current, stray voltage, and a resistance vs frequency plot that provides valuable information of the reactive component — important to determine the effects of a lightning strike on the tower. All of this testing can be completed in 30 to 40 minutes where it would take several hours with other test methods. Today, several major electrical utility companies have standardized on our tower tester as the required instrument for their technicians and electrical contractors to use to verify that their transmission towers are within acceptable ground-resistance values.
NW: What evolution do you see on the horizon that will have a positive impact on your work?
Olobri: The cost and reliability of digital communication technology and the wide use of smart devices such as cell phones and tablets has given us the opportunity to effectively provide remote operation and access to test instrumentation. It allows the technician to remain outside hazardous areas while performing electrical measurements. It simplifies and reduces the time to properly configure the test instrument. It gives us the opportunity to provide real-time information, particularly in power and energy monitoring, to the appropriate decision makers and engineers anywhere in the world. Continued developments in this area will improve reliability of this communication and increase the transmission speed of large
amounts of data. It will also help us simplify connectivity for the user who is interested in getting the job done right without spending an excessive amount of time learning computer technology to make that data communication happen. Springboarding off the developments of battery technology for the automotive industry and others will provide us an opportunity to offer longer operation of test and measuring instrumentation particularly in the area of data logging, which inherently is mostly used in unattended operation.
NW: What challenges do you see going forward for the industry?
Olobri: A most important challenge that faces the test instrumentation industry is in configuration simplification and presentation of application-oriented measurement results. Technicians and engineers today are pulled in many directions and are under considerable time pressures. The last thing they want to do is spend hours learning software or the layers of buttonpushing to set up instrumentation. Although great strides have been made in this area, more needs to be done to literally make instruments as close to plug-and-play as possible and provide the operator the confidence that the instrument is configured right the first time and the results will be accurate.
AEMC’s Groundflex® Field Kit
• Cables
• LV/MV Circuit Breakers
• Rotating Machinery
• Meters
• Automatic Transfer Switches
• Switchgear and Switchboard Assemblies
• Load Studies
• LV/MV Switches
• Relays - All Types
• Motor Control Centers
• Grounding Systems
• Transformers
• Insulating Fluids
• Thermographic Surveys
• Transient Voltage Recording and Analysis
• Electromagnetic Field (EMF) Testing
• Reclosers
• Surge Arresters
• Capacitors
• Batteries
• Ground Fault Systems
• Equipotential Ground Testing
• Harmonic Investigation
• Replacement of Insulating Fluids
• Power Factor Studies
ANSI/NETA STANDARDS UPDATE
ANSI/NETA ATS–2017 REVISION UNDERWAY
ANSI/NETA ATS–2017, Standard for Acceptance Testing Specifications for Electrical Power Equipment & Systems continues an American National Standard revision process that is scheduled to be completed by the end of 2020. The new edition will be released in March 2021.
A project intent notification published in ANSI’s Standards on January 3, 2020, announced the opening of a 45day public comment period. The initial ballot was issued on January 17, 2020, and closed on February 18, 2020. A second ballot was issued July 10, 2020, and closed August 10, 2020. The administrative approval process from ANSI continues. The revised edition of ANSI/NETA ATS is scheduled to debut at PowerTest 2021 in Orlando.
ANSI/NETA ATS covers suggested field tests and inspections for assessing the suitability for initial energization of electrical power equipment and systems.
ANSI/NETA
SPECIFICATIONS AND STANDARDS
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 ETT–2018 REVISION SCHEDULED FOR 2021
A project intent notification has been published in ANSI’s Standards Action in fall 2020, announcing the opening of a 45-day public comment period. The initial ballot is expected in summer 2021. A second ballot is scheduled for issue in fall 2021. The revised edition of ANSI/NETA ATS is scheduled to debut at PowerTest 2022.
ANSI/NETA ETT establishes minimum requirements for qualifications, certification, training, and experience for the electrical testing technician. It provides criteria for documenting qualifications for certification and details the minimum qualifications for an independent and impartial certifying body to certify electrical testing technicians.
ANSI/NETA ECS–2020 LATEST EDITION
ANSI/NETA ECS, Standard for Electrical Commissioning of Electrical Power Equipment & Systems, 2020 Edition, completed the American National Standard revision process. ANSI administrative approval was received on September 9, 2019. ANSI/NETA ECS–2020 supersedes the 2015 Edition.
ANSI/NETA ECS describes the systematic process of documenting and placing into service newly installed or retrofitted electrical power equipment and systems. This document shall be used in conjunction with the most recent edition of ANSI/NETA ATS, Standard for Acceptance Testing Specifications for Electrical Power Equipment & Systems The individual electrical components shall be subjected to factory and field tests, as required, to validate the individual components. It is not the intent of these specifications to provide comprehensive details on the commissioning of mechanical equipment, mechanical instrumentation systems, and related components.
The ANSI/NETA ECS–2020 Edition includes updates to the commissioning process, as well as inspection and commissioning procedures as it relates to low- and mediumvoltage systems.
Voltage classes addressed include:
• Low-voltage systems (less than 1,000 volts)
• Medium-voltage systems (greater than 1,000 volts and less than 100,000 volts)
• High-voltage and extra-high-voltage systems (greater than 100 kV and less than 1,000 kV)
ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Equipment & Systems, 2019 Edition, completed an American National Standard revision process and received ANSI approval on February 4, 2019. The revised edition of ANSI/NETA MTS was released in March 2019 and supersedes the 2015 Edition.
ANSI/NETA MTS contains specifications for suggested field tests and inspections to assess the suitability for continued service and reliability of electrical power equipment and systems. The purpose of these specifications is to assure that tested electrical equipment and systems are operational and within applicable standards and manufacturers’ tolerances, and that the equipment and systems are suitable for continued service. ANSI/NETA MTS–2019 revisions include online partial discharge survey for switchgear, frequency of power systems studies, frequency of maintenance matrix, and more. ANSI/NETA MTS–2019 is available for purchase at the NETA Bookstore at www.netaworld.org.
PARTICIPATION
Comments and suggestions on any of the standards are always welcome and should be directed to NETA. To learn more about the NETA standards review and revision process, to purchase these standards, or to get involved, please visit www.netaworld.org or contact the NETA office at 888-300-6382.
The Power of Positive Results
TECH QUIZ ANSWERS
Thomas D. Sandri is Training Development Manager at Shermco Industries. He has been active in the field of electrical power and telecommunications for over 30 years. During his career, he has developed numerous training aids and training guides and has conducted domestic and international seminars. Tom supports a wide range of electrical and telecommunication maintenance application disciplines. He has been directly involved in supporting test and measurement equipment for over 20 years and is considered an industry expert in application disciplines, including battery and dc systems testing and maintenance, medium- and high-voltage cables, ground testing, and partial discharge analysis. Tom holds a BSEE from Thomas Edison University in Trenton, New Jersey.
ANSWERS
1. a. 25. Also known as a synch-check relay, it verifies that two voltages are within the specified quantity and phase angle. These are used mostly for synchronizing a generator with an existing source to be connected to it, not for synchronizing two generators. Auto-synchronizing relays are usually used to synchronize two generators.
2. d. Loss-of-excitation. Probably an easy question since it has the longest answer. A generator uses an exciter to apply a DC voltage across the field winding. The resulting current produces a magnetic flux that cuts the windings on the rotor, producing an output voltage. Figure 3 shows a simple diagram of a generator. This was the simplest one I could find on the internet. The automatic voltage regulator (AVR), which is not shown, controls the exciter output voltage and could be one of many types. Increasing the AVR output voltage increases the generator output.
3. a. Figure 1 showed a common Mho (opposite characteristic of an Ohm) relay characteristic where:
X = reactance, r = resistance, z = impedance
It could also show the maximum torque angle (Figure 4) and the values for the three. Any impedance value that falls inside the circle means a contact-closed condition.
4. a. Seal-In coil. This is an electro-mechanical relay. The schematic also shows the seal-in contacts.
b. Tapped current operating coil. This is a reverse power relay.
c. Shorting bars, for the CTs
d. Potential operating coils
Figure 2 in the question is a reverse power relay. To operate, it must see both a voltage (potential) and a current. It looks for power flow going in the wrong direction.
Figure 3: Simple Generator System
Figure 4: Mho Relay
Protective relays use their own symbol system. It’s easy to get confused if you’re not used to them. This one is a bit quirky. The current coil (b) is normally shown as the potential coils are in Figure 2, but the potential coil (d) is shown split. Since the shorting bars (c) are on terminals 5 and 6, the current coil must be connected there. Terminals 7 and 8 are the potential coil terminals and 1 and 2 are the trip circuit with (a) being the seal-in coil. This is an IJS Sync-Check relay.
NFPA Disclaimer: Although Jim White is a member of the NFPA Technical Committee for both NFPA 70E, Standard for Electrical Safety in the Workplace, and NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, the views and opinions expressed in this column are purely the author’s and shall not be considered an official position of the NFPA or any of its technical committees and shall not be considered, nor be relied upon, as a formal interpretation or promotion of the NFPA. Readers are encouraged to refer to the entire text of all referenced documents.
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