NETA Handbook Series II - Protective Vol 3-PDF

SERIES II

Equipment Rental

Published by NETA - The InterNational Electrical Testing Association

T 972.317.0479

|

www.intellirentco.com

|

contact us at [email protected]

ANDBOOK

VOLUME 3

Test

VOLUME 3

ROTECTIVE RELAY

PROTECTIVE RELAY HANDBOOK

the test equipment answer

SERIES II

Published By

Sponsored by Intellirent

PROTECTIVE RELAY HANDBOOK VOLUME 3

Published by

InterNational Electrical Testing Association

the test equipment answer

the test equipment answer

We support testing of

We support testing of

■■

■■

Relay and Protection Systems Switchgear and Breakers (Low, Medium and High Voltage)

■■

■■

Relay and Protection Systems Switchgear and Breakers (Low, Medium and High Voltage)

■■

Cable and Bus

■■

Cable and Bus

■■

Transformers

■■

Transformers

■■

Batteries

■■

Batteries

■■

Motors and Rotating Apparatus

■■

Motors and Rotating Apparatus

■■

Watthour Metering

■■

Watthour Metering

■■

Power Quality and Consumption Analysis

■■

Power Quality and Consumption Analysis

Test Equipment Rental

Test Equipment Rental

888.902.6111 972.317.0479 [email protected] www.intellirentco.com

888.902.6111 972.317.0479 [email protected] www.intellirentco.com

Published by InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 102, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published 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 any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “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 in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser, or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct, or indirect damages. NETA further disclaims any and all warranties, express or implied including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date. Copyright © 2013 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

PROTECTIVE RELAY HANDBOOK VOLUME 3 TABLE OF CONTENTS Better, Faster, and More Efficient Relay Testing... We Have the Technology!........................................................................................5 Chris Werstiuk, Manta Test Systems

Using Hall-Effect Sensors to Add Digital Recording Capability to Electromechanical Relays.......................................................................................24 Amir Makki, Softstuf, Inc., Sanjay Bose, The Consolidation Edison Company of New York, Tony Giuliante, ATG Consulting and John Walsh, Sean Breatnech Technical Services (SBTS) LLC

An Improved Constant Source Impedance Testing Method for MHO Distance Relays............................................................................................29 Jason Buneo and Rene Aguilar, Megger

Instantaneous Ground Fault Relays (50GS) and Zero-Sequence CTS Powel Technical Brief #68......................................................................................35 Baldwin Bridger, Powell Electrical Manufacturer Co.

Modern Protective Relay Techniques: Using a 94-Year-Old Concept to Protect Electrical Equipment......................................36 Suparat Pavavicharn, Basler Electric Company

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 102, Portage, Michigan 49024

269.488.6382

www.netaworld.org

TABLE OF CONTENTS CONTINUED Multi-Function Numerical Protection Relays Using Symmetrical Components for More Reliable and Secure Protection............................................................................41 Steve Turner, Beckwith Electric Co., Inc.

Newer Solid-State Relays Offer Enhanced Flexibility for SCADA Solutions in the Municipal Environment.............................................................46 Lynn Hamrick and Owen Wyatt, Shermco Industries

Relay Maintenance Has Changed, Hasn’t It?..............................................................49 Kerry Heid, Magna Electric Corp.

Modern Protective Relay Techniques: Using a 94-year Old Concept to Protect..................51 Suparat Pavavicharn, Basler Electric Company

Industry Advisory – NERC Relay Safe Work Practices....................................................55 Scott A. Blizard, American Electrical Testing Co., Inc.

Solving Relay Misoperations with Line Parameter Measurements.....................................58 Will Knapek, OMICRON

An Introduction to End-to-End Testing...........................................................................60 Chris Werstiuk, Manta Test Systems

GPS Testing, The Future of Testing................................................................................61 William Knapek, OMICRON electronics

NETA Accredited Companies..................................................................................... 65

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 102, Portage, Michigan 49024

269.488.6382

www.netaworld.org

5

Protective Relay Handbook

BETTER, FASTER, AND MORE EFFICIENT RELAY TESTING...WE HAVE THE TECHNOLOGY! PowerTest 2012 by Chris Werstiuk, Manta Test Systems

1. INTRODUCTION Modern Microprocessor relays are much more powerful than their predecessors and testing one of these relays can be a daunting task for the average relay tester. All of this new power increases the relay’s complexity exponentially which can make installation mistakes easier to create and harder to find. The modern relay tester needs to adapt to new technologies to find the most effective test plan possible to make sure the relay has been installed correctly, and will operate when required after the testing is completed. The purpose of this paper is to discuss the possible test techniques available to help the reader determine which techniques will be most effective for his/her skill level and available technology.

2. A BRIEF HISTORY OF PROTECTIVE RELAYS We will start with a brief history of protective relays to compare the different generations and understand their basic operation.

A) Electro-Mechanical Relays Electro-mechanical relays are considered the simplest form of protective relays. Although these relays have very limited operating parameters, functions, and output schemes, they are the foundation for all relays to follow and can have very complicated mechanical operating systems. The creators of these relays were true geniuses as they were able to apply their knowledge of electrical systems and protection to create protective relays using magnetism, polarizing elements, and other mechanical devices that mimicked the characteristics they desired. The simplest electro-mechanical relay is constructed with an input coil and a clapper contact. When the input signal (current or voltage) creates a magnetic field greater than the mechanical force holding the clapper open, the clapper closes to activate the appropriate control function. The relay’s pick-up is adjusted by changing the coil taps and/or varying the core material via an adjusting screw. The relay has no intentional time delay but has an inherent delay due to mechanical operating times. (see figure 1)

Figure 2: Typical Electro-Mechanical Relay with Timing Disk The next level of Electro-mechanical relay incorporates an internal time delay using a rotating disk suspended between two poles of a magnet. When the input coil’s magnetic strength is greater than the mechanical force holding the disk in the reset position, the disk will begin to turn toward the trip position. As the input signal (voltage or current) increases, the magnetic force increases, and the disk turns faster. The relay’s pick-up is adjusted by changing input coil taps and/or adjusting the holding spring tension. The time delay is altered by moving the starting position and varying the magnet strength around the disk. Time characteristics are preset by model. (see figure 2) The next level of complexity included polarizing elements to determine the direction of current flow. This element is necessary for the following protective functions to operate correctly: • Distance (21) • Reverse Power (32) • Loss of Field (40) • Directional Overcurrent (67)

Figure 1: Example of Clapper Style Relay

These relays used the components previously described but will not operate until the polarizing element detects that the current

6

Protective Relay Handbook

is flowing in the correct direction. Polarizing elements use resistors, capacitors, and comparator circuits to monitor current flow and operate a clapper style contact to shunt or block the protective functions accordingly. (see figures 3 and 4)

also deteriorate over time and cause the pick-up and timing characteristics of the relays to change or drift without regular testing and maintenance.

These relays usually only have one or two output contacts and devices.devices Dirt, dust,are corrosion, moisture, nearby magnetic fields can auxiliary oftentemperature, required for moreandcomplex protection affect relay operation. The magnetic relationship between devices can also deteriorate schemes. Figure 5 depicts a simple overcurrent over time and cause the pick-up and timing characteristicsprotection of the relays scheme to change or ese relays used the components previously described but will not using operate until thetesting driftelectromechanical without regular and maintenance. relays for one feeder. Notice that four rerizing element detects that the current is flowing in the correct direction. Polarizing lays are provide and any single-phase Theseused relaystousually only optimum have one or protection two output contacts and auxiliary devices are often required for protection schemes. Figure 5 depicts a simple ents use resistors, capacitors, and comparator circuits to monitor relay current flow andmoreforcomplex can be removed testing or maintenance without comproovercurrent protection scheme using electromechanical relays for one feeder. Notice ate a clapper style contact to shunt or block the protective functionsmising accordingly. the relays protection that four are used scheme. to provide optimum protection and any single-phase relay can be removed for testing or maintenance without compromising the protection scheme.

+ POS

A PH CO RLY 50/51

C PH CO RLY 50/51

GND CO RLY 50/51

10

10

10

ICS

ICS

ICS

ICS

A PH 51 CO

125Vdc TRIP CIRCUIT

B PH CO RLY 50/51

10

A PH ICS

1

A PH 50 IIT

A PH 51 CO

2

1

A PH ICS

A PH 50 IIT

2

A PH 51 CO

1

A PH ICS

A PH 50 IIT

2

A PH 51 CO

1

A PH ICS

A PH 50 IIT

2

TRIPX-1

Figure 3: Example of an Electro-Mechanical Relay Polarizing Element

- NEG gure 3: Example of an Electro-Mechanical Relay Polarizing Element Figure 5: Typical Electromechanical Overcurrent Trip Schematic TOC WOUND SHADING COILS

D OPER

C1 C2

D

Figure 5: Typical Electromechanical Overcurrent Trip B) Solid State Relays Schematic As technology progressed and electronic components shrunk in size, solid-state relays

D POT POL

P1 P2

began to appear. smaller, lighter, and cost-effective solid-state relays were designed B) Solid StateThe Relays to be direct replacements for the electro-mechanical relays. However, this generation of

TOC

R2

LINE

TOC

SI

R1

TOC

SI

*

*

*

relays introduced new, unforeseen problems including; power supply failures and As technology progressed and electronic components electronic component failures that prevented relays from operating, and sensitivity to harmonics that caused nuisancerelays trips. Protective relays are the The last line of defense shrunk in size, solid-state began to appear. smaller, during an electrical fault, and they must operate reliably. Unfortunately, early solid-state lighter, and cost-effective solid-state relays were designed to be direct replacements for the electro-mechanical relays. However, this generation of relays introduced new, unforePage 7/ Werstiuk seen problems including; power supply failures and electronic component failures that prevented relays from operating, and sensitivity to harmonics that caused nuisance trips. Protective relays are the last line of defense during an electrical fault, and they must operate reliably. Unfortunately, early solidstate relays were often unreliable, and you will probably find many more electro-mechanical relays than solid state relays in older installations.

Solid-state relays used electronic components to convert the analog inputs into very small voltages that were monitored by SI =SEAL IN * = SHORT FINGERS electronic components. Pick-up and timing settings were adTOC = TIME OVERCURRENT UNIT justed via dip switches and/or dials. If a pick-up was detected, D = DIRECTIONAL UNIT a timer was initiated which caused an output relay to operate. Figure 4: Typical Polarizing Element Electrical Schematic Although the new electronics made the relays smaller, many Figure 4: Typical Polarizing Element Electrical Schematic electro-mechanical relays are largely dependent on the interaction between models were made so they could be inserted directly into existAs electro-mechanical relays are largely dependent the in-with nets and mechanical parts, their primary problems areonshared mechanical ingall relay cases allowing upgrades without expensive retrofitting teraction between magnets and mechanical parts, their primary expenses. Early models were direct replacements with no addiproblems are shared with all mechanical devices. Dirt, dust, corro- tional benefits other than new technology, but later models were sion, temperature, moisture, andWerstiuk nearby magnetic fields can affect multi-phase or multi-function. Page 6/ relay operation. The magnetic relationship between devices can 1

3

2

7

5

4

6

8

Protective Relay Handbook

comparatively As ee comparativelyslow, slow,but butthey theywere werealso alsosimple simplewith with small small programs. programs. As feature featureororlevel levelofofcomplexity complexityisis added, added, the the processor processor speed speed must must bb compensate compensateforforthe theadditional additionallines linesofofcomputer computercode code that that must must be be process process 7 response time response timewill willincrease. increase. DIGITAL DIGITAL INPUTS COMMS OTHER OTHER INPUTS COMMS

C) Microprocessor Based Relays Microprocessor based relays are computers with preset programming using inputs from the analog-to-digital cards (converts CT and PT inputs into digital signals), digital inputs, communications, and some form of output contacts. The digital signals are analyzed by the microprocessor using algorithms (computer programs) to determine operational parameters, pick-up, and timing based on settings provided by the end user.

CT CT PT PT

MICROPROCESSOR MICROPROCESSOR

ANALOG ANALOG TOTO DIGITAL DIGITAL

Perform self check Perform self check Record inputs Record CTCT inputs Record PT inputs Record PT inputs Record digital inputStatus' Status' Record digital input Overcurrentpick pick up? Overcurrent up? If Yes, start timer If Yes, start timer InstantaneousPick Pickup? up? Instantaneous If yes, start timer If yes, start timer Turn OUT101 On (1)? Turn OUT101 On (1)? Turn OUT102 On (1)? Turn OUT102 On (1)? Back to start Back to start

OUTPUT OUTPUT RELAYS RELAYS

The microprocessor relay, like all other computing devices, can COMMS COMMS only perform one task at a time. The microprocessor and will anaFigure Microprocessor Operation Flowchart Figure 6:Simple SimpleMicroprocessor Microprocessor Operation Flowchart 6:6:Simple Operation Flowchart lyze each line of computer code in predefined order until it reachesFigure ANALOGTO the end of the programming where it will begin analyzing from the ANALOGTO OUTPUT RELAYS MICROPROCESSOR DIGITAL CONVERSION OUTPUT RELAYS MICROPROCESSOR DIGITAL CONVERSION beginning again. The relay scan time refers to the amount of time the relay takes to analyze the complete program once. A simplified program might operate as follows: 1. Start 2. Perform self-check 3. Record CT inputs 4. Record PT inputs 5. Record digital input Status’ 6. Overcurrent pick-up? If yes, start timer 7. Instantaneous Pick-up? If yes, start timer 8. Any element for OUT101 On (1)? If yes turn OUT101 on. 9. Any element for OUT102 On (1)? If yes, turn OUT102 on.

Figure 7: Simple Microprocessor Internal Schematic

Figure 7: Simple Microprocessor Internal Schematic Figure 7: Simple Microprocessor Internal Schematic

10. Back to Start

D) Simple Digital Relays

Microprocessor relays also evaluate the input signals to determine if the analog input signal is valid using complex analyses of the input signal waveforms. These evaluations can require significant portions of a waveform or multiple waveform cycles to properly evaluate the input signal which can increase the microprocessor relay’s operating time.

Early microprocessor based relays were nothing more than direct replacements for electro-mechanical and solid state relays. Most were simple multiphase, single function relays with limited outputs. These relays were typically cheaper than comparable relays from previous generations and added additional benefits including:

Electrical faults must be detected and cleared by the relay and circuit breaker as quickly as possible because an electrical fault can create an incredible amount of damage in a few cycles. The microprocessor relay’s response time is directly related to the amount of programming and its processor speed. Early microprocessor speeds were comparatively slow, but they were also simple with small programs. As each additional feature or level of complexity is added, the processor speed must be increased to compensate for the additional lines of computer code that must be processed or the relay response time will increase. (see figures 6 and 7)

1. More sensitive settings,

Page 9/ Werstiuk

2. Multiple time curvePage selections 9/ Werstiuk 3. Metering functions, 4. Remote communications, 5. Self-test functions that monitored key components to operate an LED on the front display or operate an output contact. 6. Simple fault recording These relays were relatively simple to install, set, and test as they had limited functions and limited contact configurations. The General Electric MIF/MIV Series or Multilin 735/737 are good examples of simple digital relays.

8 E) Multi-Function Digital Relays As technology improved and microprocessors became faster and more powerful, manufacturers began to create relays with the allin-one-box philosophy we see today. These relays were designed to provide all the protective functions for an application instead of a protective element as seen in previous relay generations. Instead of installing four overcurrent (50/51), three Undervoltage (27), three overvoltage (59), two frequency (81), and 1 synchronizing (25) relays; just install one feeder management relay such as the SEL-351 or GE Multilin 750 relay to provide all these functions in one box for significantly less cost than any one of the previous relays. As a bonus, you also receive metering functions, a fault recorder, oscillography records, remote communication options, and additional protection functions you probably haven’t even heard of. Because all the protective functions are processed by one microprocessor, individual elements become interlinked. For example, the distance relay functions are automatically blocked if a PT fuse failure is detected. The all-in-one-box philosophy caused some problems as all protection was now supplied by one device and if that device failed for any reason; your equipment was left without protection. Periodic testing could easily be performed in the past with minimal risk or system disruption because only one element was tested at a time. Periodic testing with digital relays is a much more intrusive process as the protected device must either be shut down or left without protection during testing. Relay manufacturers downplay this problem by stating that periodic testing is not required because the relay element tests will not change over time because of the digital nature of microprocessor relays and the relays have many self-check features that will detect most problems. However, output cards, power supplies, input cards, and analog-to-digital converters can fail without warning or detection and leave equipment or the system without protection. Also, as everyone who uses a personal computer can attest, software can be prone to unexpected system crashes and digital relays are controlled by software. As relays became more complex, relay settings became increasingly confusing. In previous generations a fault/coordination study was performed and the relay pick-up and time dial settings were determined then applied to the relay in secondary amps. Today we can have multiple elements providing the same protection but now have to determine whether the pick-up is in primary values, secondary values, or per unit. There can also be additional settings for even the simplest overcurrent (51) element including selecting the correct curve, voltage controlled or restraint functions, reset intervals, etc. Adding to the confusion is the concept of programmable outputs where each relay output contact could be initiated by any combination of protective elements and/or external inputs, and/or remote inputs via communications. These outputs are programmed with different setting interfaces based on the relay model or manufacturer with no standard for schematic drawings.

Protective Relay Handbook Multifunction digital relays have also added a new problem through software revisions. The computer software industry appears to be driven by the desire to add new features, improve operation, and correct bugs from previous versions. Relay programmers from some manufacturers are not immune from these tendencies. It is important to realize that each new revision changes the relay’s programming and, therefore creates a brand new relay that must be tested after every revision change to ensure it will operate when required. In the past, the relay manufacturers and consumers, specifically the utility industry, extensively tested new relay models for months — simulating various conditions to ensure the relay was suitable for their systems. The testing today is either faster or less stringent as the relays are infinitely more complex, and new revisions or models disappear before some end users approve their replacements for use in their systems. Examples of multifunction digital relays include the Schweitzer Laboratories product line (SEL), the GE Multilin SR series and the Beckwith M Series.

F) The Future of Protective Relays A paradigm shift occurred when relay designers realized that all digital relays use the same components (analog-to-digital cards, input cards, output cards, microprocessor, and communication cards) and the only real differences between relays is programming. With this principle in mind, new relays are being produced that use interchangeable analog/digital input/output, communication, and microprocessor cards. Using this model, features can be added to existing relays by simply adding cards and uploading the correct software. These protective relays will have the same look and feel as their counterparts across the product line. These relays will be infinitely configurable but will also be infinitely complex, requiring specialized knowledge to be able to operate and test. Also, software revisions will likely become more frequent. Another potential physical problem is also created if the modules are incorrectly ordered or installed. Examples of this kind of relay include the Alstom M series, General Electric UR series, and the ABB REL series.

G) Digital Relay Considerations While digital relays are more powerful, flexible, effective, and loaded with extras, they are also exponentially more complex than their predecessors and can easily be misapplied. As the relay accomplishes more functions within its programming, many of the protective functions within an electrical system become invisible and are poorly documented. The electrical protection system in the past was summarized on a schematic drawing that was simple to understand and almost all of the necessary information was located in one place. If information was missing, you could look at the control cabinet wiring and trace the wires.

9

Protective Relay Handbook Today’s protection system is locked within a box and poorly documented at best; this makes it nearly impossible for an operator or plant electrician to troubleshoot. It can even be difficult for a skilled relay technician due to communication issues, complex logic, cyber security, and difficult software. A one-character mistake can be catastrophic and can turn thousands of dollars’ worth of protective relay into a very expensive Christmas decoration. Some problems may never be discovered because the relay may only need to operate one percent of the time and testing periods are rare due to manufacturer’s claims that metering and self-diagnosis tests are all that’s required for maintenance. There is also a lack of standardization between engineering companies and relay manufacturers regarding how control, annunciation, and protection should be documented. While electro-mechanical or solid-state relay schemes would be well documented in the schematic diagrams for the site, few engineering companies provide an equivalent drawing of internal relay output logic and often reduce a complex logic scheme into “OUT 1/TRIP” or simply “OUT1.” This kind of documentation is almost useless when trying to troubleshoot the also a lack of standardization betweenhas engineering and relay causeThere of anis outage, especially if the relay cryptic companies annunciation on manufacturers regarding how control, annunciation, and protection should be its display panel. Anelectro-mechanical operator usually does not need the extra documented. While or solid-state relay schemes would hassle be well documented in the schematic diagrams for the site, few engineering companies provide of finding a laptop, RS-232 cable and/or RS-232 to RS-485 adapter, an equivalent drawing of internal relay output logic and often reduce a complex logic scheme into “OUT simply “OUT1.” This kindcommunication of documentation is probalmost cable adapter, only1/TRIP” to sortorthrough the various when trying to troubleshoot the cause of an outage, especially if the relay has lemsuseless and menu layers only to determine that an overcurrent (51) elecryptic annunciation on its display panel. An operator usually does not need the extra hassle of finding a laptop, and/or RS-232 RS-485 walk adapter,tocable ment caused the trip. In theRS-232 past, cable the operator couldto simply the adapter, only to sort through the various communication problems and menu layers only electrical panel and look for the relay target and read the label above to determine that an overcurrent (51) element caused the trip. In the past, the operator could simply walk to the what electrical panel and for(see the relay target 8 andthrough read the label the relay to determine caused thelook trip. figures 11)

Figure 10: Electro-Mechanical Generator Protection Panel

above the relay to determine what caused the trip. A PH CO RLY 50/51

+ POS

GND CO RLY 50/51

C PH CO RLY 50/51

10

10

10

ICS

ICS

ICS

ICS

A PH 51 CO

125Vdc TRIP CIRCUIT

B PH CO RLY 50/51

10

A PH ICS

1

A PH 50 IIT

A PH 51 CO

2

1

A PH 50 IIT

A PH ICS

A PH 51 CO

A PH ICS

1

2

A PH 50 IIT

2

A PH 51 CO

A PH ICS

1

A PH 50 IIT

2

TRIPX-1

- NEG

Figure 8: Typical Electromechanical Overcurrent Trip Schematic

Figure 8: Typical Electromechanical Overcurrent Trip Schematic + POS 3 PHASE MICROPROCESSORRELAY

OUT 1

OUT 2

OUT 3

OUT 4

OUT 5

OUT 6

OUT 7

OUT 8

43CS LOCAL TRIP

Page 13/ Werstiuk 125Vdc Trip Circuit TC

52-211 TC#1

52a

52-211 TC#2

SCADA

EVENT RECORDER

52a

- NEG

Figure 9: Typical Digital Relay Trip Schematic

Figure 9: Typical Digital Relay Trip Schematic

94T1 REMOTE TRIP

Figure 11: Digital Generator Protection Panel A properly applied microprocessor relay, on the other hand, will usually provide protection that is more sensitive and can be a godsend when you are looking for those elusive, quirky problems. As with all aspects of life, there are trade-offs for every benefit. The difference between electro-mechanical relays and digital relays can be compared to the carburetor and fuel injection in a car. The modern fuel injector is more efficient with less moving parts than a carburetor, but you would probably prefer a carburetor when you are broken down in the middle of the desert with no help in sight, because you could at least try something with the carburetor to get you home.

10 3. REASONS FOR RELAY TESTING In the past, relay testing options were limited by the test equipment available and the simple (relatively speaking) electro-mechanical relays to be tested. Today’s relays are highly sophisticated with an incredible number of settings that are tested with equally powerful test equipment and test systems. Complicated electromechanical relays required only a day to calibrate and test all functions. A digital relay could require weeks to test all of its functions. Relay testing is expensive and intelligent choices regarding what we test and how the test must be made. The best answers to these questions come from an evaluation of our goals and options. Some of the reasons for relay testing include:

A) Type Testing Type testing is a very extensive process performed by a manufacturer or end user that runs a relay through all of its paces. The manufacturer uses type testing to either prove a prospective relay model (or software revision), or as quality control for a recently manufactured relay. The end user, usually a utility or large corporation, can also perform type tests to ensure the relay will operate as promised and is acceptable for use in their system. This kind of testing is very involved and, in the past, would take months to complete on complicated electro-mechanical relays. Every conceivable scenario that could be simulated was applied to the relay to evaluate its response under various conditions. Today, all of these scenarios are now stored as computer simulations that are replayed through advanced test equipment to prove the relay’s performance in hours instead of weeks. Type testing is very demanding and specific to manufacturer and/ or end-user standards. Type testing should be performed before the relay is ordered and is not covered in this book. However, independent type testing is a very important part of a relay’s life span and should be performed by end users before choosing a relay model.

B) Acceptance Testing There are many different definitions of acceptance testing. For our purposes, acceptance testing ensures that the relay is the correct model with the correct features; is operating correctly; and has not been damaged in any way during transport. This kind of testing is limited to functional tests of the inputs, outputs, metering, communications, displays, and could also include pick-up/timing tests at pre-defined values. Acceptance test procedures are often found in the manufacturer’s supplied literature.

C) Commissioning Commissioning and acceptance testing are often confused with each other but can be combined into one test process. Acceptance testing ensures that the relay is not damaged. Commissioning confirms that the relay’s protective element and logic settings are appropriate to the application and will operate correctly. Acceptance tests are generic and commissioning is site specific.

Protective Relay Handbook Commissioning is the most important test in a digital relay’s lifetime. The tests recommended in this book are a combination of acceptance testing and commissioning and includes the following items: • Functional tests of all digital inputs/outputs • Metering tests of all current and voltage inputs • Pick-up and timing tests of all enabled elements • Functional checks of all logic functions • Front Panel display, target and LEDs This battery of tests is a combination of acceptance testing and commissioning to prove: • The relay components are not damaged and are acceptable for service • The specific installation is set properly and operates as expected. • The design meets the application requirements. • The relay works in conjunction with the entire system.

D) Maintenance Testing Maintenance tests are performed at specified intervals to ensure that the relay continues to operate correctly after it has been placed into service. In the past, an electro-mechanical relay was removed from service, cleaned, and fully tested using as-found settings to ensure that its functions had not drifted or connections had not become contaminated. These tests were necessary due to the inherent nature of electromechanical relays. Today, removing a relay from service effectively disables all equipment protection in most applications. In addition, digital relay characteristics do not drift and internal self-check functions test for many errors. There is a heated debate in the industry regarding maintenance intervals and testing due to the inherent differences between relay generations. In my opinion, the following tests should be performed annually on all digital relays: • Perform relay self-test command, if available. • Check metering while online and verify with external metering device, or check metering via secondary injection. (This test proves the analog-to-digital converters) • Verify settings match design criteria. • Review event record data for anomalies or patterns. • Verify all inputs from end devices. • Verify all connected outputs via pulse/close command or via secondary injection. (Optionally, verify the complete logic output scheme via secondary injection.)

The following techniques were used when testing electrical-mechanical relays i)

Protective Relay Handbook E) Troubleshooting

Steady State

Steady state testing is usually used for pick-up tests. The injected current/voltage/freq 11 raised/lowered until the relay responds accordingly. Steady state testing can be replac jogging the injected value up/down until the relay responds.

Troubleshooting is usually performed after a fault to determine why the relay operated or why it did not operate when it was supposed to. The first step in troubleshooting is to review the event recorder logs to find out what happened during the fault. Subsequent steps can include the following, depending on what you discover in the post-fault investigation. • Change the relay settings accordingly. • Change the event record or oscillography initiate commands. • Re-test the relay. • Test the relay’s associated control schemes. • Replay the event record through the relay or similar relay to see if the event can be replicated.

4. EVOLUTION OF RELAY TESTING

5A

ELEMENT PICK-UP

4A 3A 2A

PICKUP SETTING

ELEMENT PICK-UP

60 A

PICKUP SETTING

40 A 20 A

1A

STEADY-STATE PICKUP TEST

JOGGING PICKUPTEST

Figure 12: Steady State Pickup Testing

Figure 12: Steady State Pickup Testing

ii) Dynamic On/Off Testing Dynamic on/off testing is the simplest form of fault simulation Pageto18/ Werstiuk and was the first test used determine timing. A fault condition is suddenly applied at the test value by closing a switch between the source and relay or activating a test-set’s output. (see figure 13)

This section will outline the evolution of relay testing to better understand the choices available to the relay-tester when testing modern digital relays.

A) Electromechanical Relay Testing Techniques Electromechanical relays operated based on mechanics and magnetism and it was important to test all of the relay’s characteristics to make sure that the relay was in tolerance. Various tests were applied to ensure all of the related parts were functioning correctly and, if the relay was not in tolerance; the relay resistors, capacitors, connections, and magnets were adjusted to bring the relay into tolerance. With enough patience, almost any relay could be adjusted to acceptable parameters. Relay testing in the electromechanical age was very primitive due to the limitations of the test equipment available. The most advanced test equipment available to the average relay-tester would include a variac for current output, another variac for voltage signals, a built in timer with contact sensing, and a phase shifter for more advanced applications. With this equipment, detailed test plans and connection diagrams, and a hefty dose of patience; the relay-tester was able to test the pick-up, timing, and characteristics of the electromechanical relays installed as well as most solid state relays. Test plans and connections for currents and voltages often had very little resemblance to the actual operating connections because the limited test equipment could not create simulations of actual system conditions during a fault. Electro-mechanical relays were also built with inter-related components that needed to be isolated for calibration.

Figure 13: Dynamic On/Off Waveform

iii) Simple Dynamic State Testing Some protective elements such as under-frequency (81) and under-voltage (27) require voltages and/or current before the fault condition is applied or the element will not operate correctly. Simple dynamic state testing uses pre-fault and/or post-fault values to allow the relay-tester to obtain accurate time tests. A normal current/ voltage/frequency applied to the relay suddenly changes to a fault value. The relay-response timer starts at the transition between prefault and fault, and the timer ends when the relay operates. Simple dynamic state testing can be performed manually with two sources separated by contacts or switches; applying nominal signals and suddenly ramping the signals to fault levels; or using different states such as pre-fault and fault modes.

The following techniques were used when testing electricalmechanical relays:

i) Steady State Steady state testing is usually used for pick-up tests. The injected current/voltage/frequency is raised/lowered until the relay responds accordingly. Steady state testing can be replaced by jogging the injected value up/down until the relay responds. (see figure 12)

Figure 14: Simple Dynamic Test Waveform

12 B) Solid State Relay Testing Techniques Solid state relays were primarily created to be direct replacements for electro-mechanical relays and the same test techniques were used for these relays. However, these solid state relays were constructed with silicon chips, digital logic, and mathematical formulas instead of steel and magnetism so the test plans were the same but the results were often very different. When an electromechanical relay was found out of tolerance, there were resistors or springs to adjust. Solid state relays did not have many adjustments besides the initial pick-up setting and these relays either operated correctly or did not operate at all. Relay-testers typically replaced entire cards instead of adjusting components when the relay failed. Test equipment did not evolve much during this period and the typical test-set changed all of its analog displays to digital and made the previously described tests easier to perform.

C) Microprocessor Relay Testing Techniques Simple microprocessor relays are almost identical in operation to the solid state relays they replaced and the test techniques for these relays are identical to the techniques previously described. Complex microprocessor relays included a large number of settings and interlinked elements which created confusion in the relay testing industry because a relay-tester could spend an entire week testing one relay and barely scratch the surface of the relay’s potential. The confusion increased when relay manufacturers claimed that relay testing was not required because the relay performed self-check functions and the end user would be informed if a problem occurred. Some manufacturers even argued that the relay could test itself by using its own fault recording feature to perform all timing tests. Eventually a consensus was reached where the relay-tester would test all of the enabled features in the relay. Relay-testers began modifying and combining their electromechanical test sheets to account for all of the different elements installed in one relay but the basic fundamentals of relay testing didn’t change very much. One of the first problems that a relay-tester experiences when testing microprocessor relay elements is that different elements inside the relay often overlap. For example, an instantaneous (50) element set at 20A will operate first when trying to test a timeovercurrent (51) element at 6x (24A) its pick-up setting (4A). The relay-tester instinctively wants to isolate the element under test and usually changes the relay settings to set one output, preferably an unused one, to operate only if the element under test operates. Now they can perform that 6x test without interference from the 50-element. While these techniques will give the test technician a result for their test sheet, the very act of changing relay settings to get that result does not guarantee that the relay will operate correctly when required because the in-service relay settings and reactions have not been tested.

Protective Relay Handbook Relay-testers often use the steady-state and simple-dynamic test procedures described previously to perform their element tests on microprocessor relays which create another problem. These complex relays are constantly monitoring their input signals to determine if those signals are valid. The steady-state and simpledynamic test procedures are often considered invalid system conditions by the relay and the protection elements will not operate to prevent nuisance trips for a perceived malfunction. For example, if a relay-tester tries to perform a standard electromechanical impedance test (21) on a digital relay, the relay will likely assume that there is a problem with a PT fuse and blocked the element; or the switch-on-to-fault (SOTF) setting could cause the relay to trip instantaneously. Relay-testers who encountered this problem often disable those blocking signals to perform their tests and, hopefully, turned the blocking settings back on when they were complete. Again, the act of changing settings is fine if you need a number for a test sheet but will not guarantee that the relay will operate correctly when it is required. Modern test equipment allows the relay-tester to apply several different techniques to overcome any of the situations described above. When an instantaneous element operates before a time element timing test can operate, that is usually a good thing if the relay is programmed correctly. Instead of modifying the settings to get a result, the technician can modify their test plan to ensure that all time-element tests fall below the instantaneous pick-up. If a ground element operates before the phase element you are trying to test, apply a realistic phase-phase or three-phase test instead and the ground element will not operate. If the loss of protection element prevents a distance relay from operating, apply a balanced 3-phase voltage for a couple of seconds between each test to simulate real life conditions. If switch-on-to-fault operates whenever you apply the fault condition; use an output to simulate the breaker status, apply prefault current, or lower the fault voltage so that you can lower the fault current when testing impedance relays. All of these possibilities are easily applied with modern test equipment to make our test procedures more intelligent, realistic, and effective. Modern test equipment also allows the following additional test methods.

i) Computer-Assisted Testing Because modern test equipment is controlled by electronics, computer-assisted testing became available. Standard test techniques could be repetitive on relays that were functioning correctly. Computer programs were created that would ramp currents and voltages at fixed rates in an effort to make relay testing faster with more repeatable results because every test would be performed identically. Computer-assisted testing has evolved to the point where the software will: • connect to the relay • read the relay settings • create a test plan based on the enabled settings • modify the settings needed to isolate an element and prevent interference

13

Protective Relay Handbook • test the enabled elements

iv) Dynamic System Model Based Testing

• restore the relay settings to as found values

Dynamic system model based testing uses a computer program to create a mathematical model of the system and create fault simulations based on the specific application. These modeled faults (or actual events recorded by a relay) are replayed through a sophisticated testset to the relay. Arguably, this is the ultimate test to prove an entire system as a whole. However, this test requires specialized knowledge of a system, complex computer programs, advanced test equipment, and a very complex test plan with many possibilities for error. My biggest concern regarding this kind of testing is the level of expertise necessary for a successful test. In the age of fast-track projects and corporate downsizing, many times the design engineer is barely able to provide settings in time for energization without relying on the designer to provide test cases as well.

By following the steps above, computer-assisted relay testing can replace the relay-tester on a perfectly functioning relay and can theoretically perform the tests faster than a human relay-tester can. This type of testing works extremely well when performing pick-up and timing tests of digital relays because these relays are computer programs themselves. However, it is very unlikely that the basic test procedures described by computer-assisted testing, whether initiated by computers or humans, will discover a problem with a digital relay. Most digital relay problems are caused by the settings engineer and not the relay. If a computer or human reads the settings from the relay and regurgitates them into the test plan, they will not realize that the engineer meant to enter a 0.50A pickup but actually applied 5.0A which will make the ground pickup larger than the phase pickup. Each element will operate as programed and, when tested in isolation, will create excellent test results but may not be applied in the trip equation which was probably not tested by the automated program. An excellent relay technician could create additional tests to perform the extra steps necessary for a complete test; but will that technician be more capable or less capable as they rely more heavily on automation to perform their testing?

ii) State Simulation State simulations allow the user to create dynamic tests where the test values change between each state to test the relay’s reaction to changes in the power system. Multiple state simulations are typically required for more complex tests such as frequency load shedding, end-to-end tests, reclosing, breaker fail, and the 5% under/over pick-up technique described later in this chapter.

iii) Complex Dynamic State Testing Complex dynamic state testing recognizes that all faults have a DC offset that is dependent on the fault incidence angle and the reactance/ resistance ratio of the system. Changing the fault incidence angle changes the DC offset and severity of the fault and can significantly distort the sine wave of a fault as shown in Figure 15. This kind of test requires high-end test equipment to simulate the DC offset and fault incidence angle and may be required for high speed and/or more complex state-of-the-art relays. (see figure 15)

Figure 15: Complex Dynamic Waveform

Figure 16: System Modeling Waveform

v) End-to-End Testing End to end testing is performed when two or more relays are connected together via communication channels to protect a transmission line. These relays can transfer status or metering information between each other to constantly monitor the transmission line in order to detect faults and isolate the faulted transmission line more quickly and reliably than single relay applications. The relays can communicate to each other through a wide range of possibilities including telecom equipment, fiber optic channels, or wave traps that isolate signals transferred over the transmission line. Testing these complicated schemes in the past was limited to functional tests of the individual components with a simplified system test to prove that the basic functions were operating correctly. For example, a relay-tester would configure and test the relay, configure and test the communication equipment, then inject a fault condition into the relay. A relay-tester at the other location would verify that they received the signal and they would repeat the process at the remote end. This procedure tested the base components of the system but they often failed to detect problems that occurred with faults in real time. For example, a fault on parallel feeders could change direction in fractions of cycles when one breaker in the system operated that often caused the protection schemes to mis-operate.

14 Relay-testers could only test one end at a time because there was no way to have two test-sets at remote locations start at exactly the same moment. If the test-sets do not provide coordinated currents and voltages with a fraction of a cycle, the protection scheme would detect a problem and mis-operate. Global Positioning System (GPS) technology uses satellites with precise clocks to communicate with equipment on earth which allowed test-set manufacturers to synchronize testsets at remote distances. After the test-sets are synchronized, test plans could be created with simulated faults for each end of the transmission line. To perform a test, the relay-testers synchronize their test-sets, load the same fault simulation with the values for their respective ends, set the test-sets to start at the exact same moment, and initiate the countdown. The test-sets will inject the fault into the relays simultaneously and they should respond as if the fault occurred on the line. The relays’ reactions are analyzed and determined to be correct before proceeding to the next test. Any mis-operations are investigated to see where the problem originates and corrected. End-to-end testing is typically considered to be the ultimate test of a system and should ideally perform using Dynamic System Model Testing to ensure that the system is tested with the most comprehensive test conditions. Simpler end-end schemes such as line differential schemes can be tested using Simple Dynamic State testing.

5. RELAY TEST PROCEDURES – PICKUP TESTING There are several methods used to determine pick-up, and we will review the most popular in order of preference. You must remember that we strive for minimum impact or changes when testing. If there is a method to determine pick-up without changing a setting…use it!

A) Choose a Method to Detect Pick-up i) Front Display LEDs

Many relays will have LEDs on the front display that are predefined for pick-up or can be programmed to light when an element picks up. Choose or program the correct LED and change the test-set output until the LED is fully lit. Compare the value to the manufacturer’s specifications and record it on the test sheet. SEL relays often allow you to customize LED output • configurations using the “TAR” or “TAR F” commands. Some SEL LEDs can only be controlled via the relay’s front panel. • Monitor Beckwith Electric relay pick-up values by pressing and holding the reset button. The appropriate LED will light on pick-up. Some elements share a single LED, and you must use alternate methods to determine pick-up. • GE UR relays allow you customize the front display LEDs using the “Product Set-up” “User Programmable LEDs” menu.

Protective Relay Handbook • Most of the GE/Multilin element pick-ups can be monitored via the pre-defined pick-up LED.

ii) Front Display Timer Indication Some relays, including the Beckwith Electric models, have a menu item on the front panel display that shows the actual timer value in real-time. After selecting the correct menu item, change the test-set output until the timer begins to count down. Compare the value to the manufacturer’s specifications and record it on the test sheet.

iii) Status Display via Communication Some relays provide a real-time status display on an external computer or other device via communication. While this is the most unobtrusive method of pick-up testing, the accuracy of this method is limited by the communication speed. Some relays will also slow down the communication speed during events that can further decrease accuracy. Slowly change the test-set output and watch the display to get a feel for the time between updates. Change the relay test-set output at a slower rate than the update rate until the relay display operates. Compare the value to the manufacturer’s specifications and record it on the test sheet.

iv) Output Contact This method requires you to assign an output contact to operate if the element picks up. Choose an unused output contact whenever possible and monitor the contact with your relay test-set or external meter. You can often hear the output contact operate, but you must be sure that you are listening to the correct relay. Another element in the control logic could be operating while you are performing your test. If you are unable to assign a pick-up element to an output contact, you can set the element time delay to zero. This method is obviously not a preferred method. Always test the time delay after the pick-up to ensure the time delay was returned to the correct value.

B) Pick-up Test Procedure After selecting a pick-up method, apply the current/voltage/frequency necessary for pick-up and make sure a pick-up is indicated by whichever method you have selected. Slowly decrease the relay test-set output until the pick-up indication disappears. Slowly increase the test-set output until pick-up is indicated. If the test current/voltage is higher than the input rating, only apply test value for the minimum possible duration. See individual element testing for tips and tricks for individual elements. (see figure 17)

make sure a pick-up is indicated by whichever method you have selected. 30 V ase the relay test-set output until the pick-up indication disappears. Slowly est-set output until pick-up is indicated. If the test current/voltage is higher 0 1 2 3 4 5 6 7 ut rating, only apply test Relay valueHandbook for the minimum possible duration. See TIME INCYCLES Protective ement testing for tips and tricks for individual elements. Figure 18: Simple Off/On Timing Test ELEMENT PICK-UP

5A

15

TEST IN PROGRESS

150 V 120 V

4A

90 V

PICKUP SETTING

3A 2A

PICKUP

60 V 30 V

1A 0

2

3

4

5

6

7

TIME IN SECONDS

STEADY-STATE PICKUP TEST

Figure of of Pick-up Test Figure17: 17:Graph Graph Pick-up

1

Figure 19: Dynamic On/Off Figure 19: Dynamic On/Off Testing Testing

Test

Whentothe digital relay timethedelay zero ordelay veryissmall than (less two than seconds), t When digitalisrelay time zero or(less very small cument setting return theand settings their values Alwayschanges documentand setting changes return the settingsoriginal to measured time delay can be longer than expected. There is an inherent delay two seconds), the actual measured time delay can be longer than ex- before eding! their original values before proceeding! 6. RELAY TEST PROCEDURES – TIMING TESTS

Timing tests apply a test input at a pre-defined value in the pickup region and measures the time difference from test initiation until the relay output-contact operates. This is the dynamic on/off testing described Some elements like undervoltage (27) or apply amethod test input at earlier. a pre-defined value in the pick-up under-frequency (81U) require pre-fault, non-zero values in order to Page 27/ Werstiuk ence from test initiation until the relay output-contact operate correctly.

st Procedures – Timing Tests

pected. There is an inherent delay before the relay can detect a fault plus an additional delay between fault detection and relay output operation. Some relays use error checking features that can also increase Page 28/ Werstiuk the expected time delay because most dynamic faults involve sudden gaps in the current/voltage waveforms that would not occur during a real fault. These delays are very small (less than five cycles) and are region and measures insignificant with operates. Thistime is delays the greater than two seconds.

The first delay(27) exists or because the relay is a computer, and comtesting method described earlier. Some elements like undervoltage puters can only perform one task at a time. The relay evaluates The output contact used to turn the timing set off is preferably y (81U) require pre-fault, non-zero values in order to operate correctly.

the actual output contact used while in-service. The timing test con- each line of programming, one line at a time, until it reaches the canactual detect fault an additional fault andtorelay output endaof theplus program, anddelay thenbetween returns todetection the start scan theoperation. entire tact can a sparethe output contactset if another interferes the with ontact used tobeturn timing off iselement preferably output contact Some relays use error checking features that can also increase the expected time delay program again. As more features areinadded, more program lines element timing, test but thecontact actual element be service.theThe timing can output be acontacts sparemust output contact iffaults another because most dynamic involve sudden gaps the current/voltage waveforms that wouldare not added. occur during a real fault. These delays very by small (less than five cycles) and Large program sizes areare offset faster processors that verified as well. Some outputs are designed to operate at different res with the element timing, but the actual element output contacts be than two seconds. with timemust delays greater spend less time evaluating each line. If a fault occurs just after the speeds. Always use the high-speed output if a choice is available. are insignificant The first delay exists because relay is a computer, and computers can only perform one . Some outputs are designed to operate at different speeds. usethe the relayAlways processes the line of code that detects that particular fault, task at a time. The relay evaluates each line of programming, one line at a time, until it If the time delay is a constant value such as zero seconds or one put if a choice is available. reaches the relay end of the then returns the startprogram to scan the entire programtime again. the hasprogram, to runand through thetoentire one more second, apply the input at 110% of the pick-up value and record As more features are added, more program lines are added. Large program sizes are offset before the fault is detected. This time delay is usually a fraction of by faster apply processorsthe that spend less time each line. If a fault occurs just after the time delay. Determine the zero manufacturers specified time deay is a the constant value suchif as seconds or one second, input at evaluating a cycle. The Accuracy” in Figure relay processes the line“Timer of code that detects thatspecifications particular fault, the relay has to20 rundetail through are in seconds, milliseconds, or cycles and record test results. program one more time before the fault is detected. This time delay is usually a ick-up lays value and record the time delay. Determinetheifentire the manufacturers this time delay. (see figures 18 and 19) fraction of a cycle. The “Timer Accuracy” specifications in Figure 20 detail this time delay.

delays are in seconds, milliseconds, or cycles and record test results.

Instantaneous/Definite-Time Overcurrent Elements

TEST IN PROGRESS 150 V

PICKUP

120 V 90 V 60 V

0

1

2

3

4

5

6

7

Figure Simple Off/On Timing Figure 18:18: Simple Off/On Timing Test

90 V

Steady State Pickup Accuracy:

+/- 0.05 A and +/-3% of Setting (5 A nominal) +/- 0.01 A and +/-3% of Setting (1 A nominal)

Transient Overreach:

< 5% of Pickup

Time Delay:

0.00 - 16,000.00 cycles, 0.25-cycle steps

Timer Accuracy:

+/- 0.25 cycle and +/-0.1% of setting

The Figure second time20: delaySEL-311C occurs after the relay has detected Specifications the fault and issues the command Relay Element to operate the output relays. There is another fraction of a cycle delay to evaluate what output contacts should operate and then the actual operation add up the to an The second time delay occurs aftercontact the relay has can detected additional cycle depending on relay manufacturer, model, etc. “Pick-up Time” in the Figure fault and to operate the output relays. There is 21 represents this issues delay forthe the command specified relay.

TIME INCYCLES

120 V

OFF, 0.25 - 100.00 A, 0.01 A steps (5 A nominal) OFF, 0.05 - 20.00 A, 0.01 A steps (1 A nominal)

Figure 20: SEL-311C Relay Element Specifications

30 V

150 V

Pickup Range:

TEST IN PROGRESS

Test

another fraction of a cycle delay to evaluate what output contacts 30 A Make Output Contacts: should operate and then6Athe actual continuous carrycontact at 70 C; 4 A operation continuous carrycan at 85 Cadd up 50A for one second MOV Protected: 270 360 Vdc, 40 ; Pickup Time: awhat 0correction andcorrections Y > 0tothen the angle isZang tan, may Y/Xbe show necessary: Eq. 26 Zt solving for X and Y. The following relations  Radius  Y-1adjustment  ZZs Im . Y to TestAngle *line sin( necessary angle correct Mag IfEq. X 21 < 0 and Ykeep > 0 the then you needinto)the add 180 to Ang Ifshow X > what 0 andcorrections Y > 0 thenare thenecessary: angle is tan Y/X IfEq. X < 0 and Y 0 and Y < 0 then you need to add 360 to ZAng. If X > 0 and Y > 0 then the angle is tan Y/X for YX Y/X to ZAng. X the Ifnecessary X >< 00 and andtoY Y keep < 0 then you need to add the line angle angle is intan the 180 correct 0 If Eq. 27 .. IfIfUsing X < 0 and Y > 0 then you need to add 180 to the relay settings and the previous X > 0 and Y these < 0correction then you need to addnote 360 to Z ZaAng Ang quadrant. This is one determined after When using equations, must that correction to Ifequations, X < 0 andone Y 00the and YXZang 0, then then the angle is to tan Y/X solving for relay and Y. be The following relations the angle, may necessary keep the in the . If X > and Y 0 you need to add 360 toline ZAngangle X Mag M 0A 0M 0A  Z 0New Z Zshow line angle, Zcorrection , are 1.095Ώ andreach, 77.2° Tot, 0 then you need to add 180 to Z Eq. 15 12 CZ New Re al ImZ New2 *s Imcos( Z LAngNew ) equations, one can determine the apparent Ang what corrections are necessary: correct quadrant. This is determined after solving forBy X solving fo Eq. Y  Zangle Z New Using the relay settings and and the previous Re Re al) circle has been The zero sequence magnitude and kpoint *al sin( ksthe After the center of respectively. the new reach line angle If X Y. 0the and Y can applied 0 and Y >the 0determine then angle canThe be The compensation are to be to relay can be computed. First, NewIm al Re equations, one can the apparent reach, the radius of the circle and compensation known, the secondary currents and voltages Eq. 15 determined. C Eq. 14 C Y X After the center point the circle new reach line angle Thezero zero is sequence magnitude and then respectively. If XK< factor 0 andAfter Y > 0the then you needand to add 180 to ZAng. Eq. 12  angle Z Z cos( ) arebeen magnitude chosen as aZapparent percentage of*compensation thethat 2 New 2of The sequence magnitude and angle angle is the line angle thehas relay sees the needs to be New Re al LAngNew ZUsing and lineto angle, ZAng ,determined: arebe 1.095Ώ and 77.2° angle can be determined. The compensation to be applied the relay can computed. First, Tot, f the relay settings and the previous found, the radius of the circle and compensation are known, the secondary currents and voltages If X < 0 and Y < 0 then you need to add 180 to ZAng. Eq. 28 Ia applied to the original line impedance and angle. The source imline impedanceangle and the line and  of Z to Z*angles compensation are then applied the original during the fault. Next, an adjustment Eq. 13 source Zground ZIm Z circle )relay New ssin( Im After the center point the has been respectively. After the new reach and line angle is the apparent line angle that the sees the K factor needs to be determined: New Im New LAngNew equations, oneto the apparent Eq. is 15can as Cbe If be X >applied 0 and Ycan < 0determine then can yoube need to add reach, 360 angle determined. The compensation the relay computed. First,to ZAng. Y f pedance magnitude chosen aasthe percentage the line imped- to are set equal to another shown inofan line impedance and angle. The source impedance for one the position of circle is determined. Eq.known, 24 K the  ( 3secondary  k 0 )  1 currents and voltages Eq. 29 Ib 2mho found, the radius of the circle and compensation are during the ground fault. Next, adjustment Z and line angle, Z , are 1.095Ώ and 77.2°  Z Z Tot, Ang angle is the apparent line the relay sees the K factor needs to be determined: New al angle s Rethat alto one Re set ance and the line and source angles are equal another as equations 6 – 9. Eq. of total magnitude is for chosen as aCnew ofcircle thecircle Finally, thecenter apparent reach, Ztotbeen and Eq. f Xpercentage angle can be determined. The compensation to be24applied to the First, Using the andbe thecomputed. previous equations, one can dethe14 position thefault. mho is K relay (3  ksettings )relay  1 can After point the has respectively. After Eq. 30 Ic 0the new reach and line angle 2ofNext, during the ground andetermined. adjustment shown in equations 6angle, –the 9.line line impedance and the and source angles line Z , can be determined. This is Using the relay settings and the previous ang angle is the the radius apparent line angle that the relay sees the K factor needs to reach, be determined: termine the apparent ZTot, andand linevoltages angle, ZAng, are 1.095Ώ Finally, new oftotal apparent reach, Ztot and found, the circle are known, the currents  ZofNew Z Im and for the position the iscompensation determined. Eq. 24following K  ( 3 secondary expression k0 )  1 The is the then derived by Immho scircle are set equal to one another as shown in shown in equations 16 – 23. equations, one can determine apparent reach, Eq. 15  C during the ground fault. Next, an adjustment and 77.2° respectively. After the new reach and line angle are line angle, Z , can be determined. This is Y Z Line *can ZeroComp Eq. 6 Z New Finally, angdetermined. angle be The compensation to be applied to the relay can be computed. First, Mag the new total 2apparent reach, Ztot and The adding allline of angle, the impedances of the sequence following is then derived equations 6 – 9.shown ZTot, 1.095Ώ and 77.2° Ang, are for theisin position of the mho circle is the determined. known, the currents and voltages tobybe applied to the Eq. 24 K secondary needs ( 3 expression  k 0to ) Z 1 equations 16line –be23. angle the apparent angle that relay the K and factor be determined: 2 2sees line angle, Z , can determined. This is Z LAngNew Z ZeroComp   Eq. 7 Eq. network in Figure 8: ang 16 After center C  ( Zcircle has RadiusLAng C Y ) been ( Z New point ) the Ang adding all of the impedances of the sequence the of respectively. After the new reach and line angle Mag al X New Re Im relay can be computed. First,isthethen K factor needsbyto be determined: Finally, the new total apparent Ztot and The following expression derived during in the ground fault. Next, reach, an adjustment shown equations 16 – circle 23. 2 2 network in Figure 8:impedances found, the radius of the and compensation are known, the secondary currents and voltages Z  Eq. 8 Eq.Z16 0 . 016 *  XC)determined. Zcan     Radius Z C Z C ( ( ) line angle, Z , be This is  1New       New Im Y sMag Line ang adding all of the of the sequence Mag al New Y Re Im of the mho circle is determined. Eq. KZ ( 3Z k0 )Z 1  Z  Z Z the ZeroComp for Eq. 6 Eq.Z 17 *position Comp Eq. 24 25  K  Z S by SOURCE K  Z LinIMPEDANCE New Line Ang  tan Mag t S Lin e IMPROVED S then Lin eCONSTANT e AN TESTING The following expression is derived angle can be determined. The compensation to be applied to the relay can be computed. First,  Z C 76 • SPRING 2012 2 2 shown in equations 16 – 23. New Re al C network in Figure 8: must Ztotal the new ZYtot) using and these Z sAng Zand Finally, Eq. 9 Eq. (1Zimpedances       New Im apparent 16line   ( Zreach, C Radius C XY )X are The voltages ar Because the source When equations, one note LAngNew Mag New Re al New Im  Comp tan Z17 Z ZeroComp   Eq. 7 Eq. Eq. 25 Z  Z  Z  Z  Z  K  Z  K  Z adding all tof needs the impedances ofLinthe sequence Ang angle isLAngthe apparent line angle that the relay sees the K following factor toLinbe determined: S expression e Sis then e derived Sby adding Lin eall of the Ang The Eq. LAngNew 18 line  Radius * cos( ) X adjustment Comp  Z C Mag Ang angle, Z , can be determined. This is ang ZNew Re down al  C X into fault voltages c vector quantities, they cansource be broken thatquantities, a correction to the line angle, Zang, may be  2 2  8:    New Im network inZ Figure Because the line are during the fault. an adjustment Eq. 16 Ztanground  C X Y) Next,  ( Zvector  CY ) Radius (Z1 impedances The following is byK  Z Lin impedances of sequence Figure 8: Eq. 17 Comp Z18  Eq. 8 Eq. 0 .and 016 Eq. 25  the Z expression  Z Linto:  Znetwork then Z Lin e in derived K  ZS  Mag* al New Re 16 Ang Eq. 19imaginary equations Yadjustment Radius Comp * cos( sin( )) Imnecessary This can be simplified tangle S in the e correct S e sMag Line New shown – 23. X Comp equations: their real and components. Then, the to keep the line adjustmentin Mag Ang Mag Ang  Cand New Re real al mho X they can be broken down into Ztheir imaginary compo- adding for the position Eq. 24 allKof the ( 3  kimpedances ) 1 of the sequence 0  C Y circle is determined. ZofNewthe  1 * cos(      Im be found Z Z  Eq. 20 Eq. 9point center along the mho circle can quadrant. This correction is determined after    X Radius TestAngle X Z ) Eq. Radius Comp * *sin( ) can This can beZ tsimplified Eq. 17 tan Mag s Re as al Eq. 25  ZS  Z to: Z S  Z Lin e  K  Z S  K  Z Lin e sAng LAngNew adjustment Mag the Eq. 19 18 cos( )adjustment X Radius Comp Angpoint nents. Then, theYComp center along mho circle be found 2 Ang 2 and adjustment Mag  Finally, the total reach,  8: Lin e  network in Figure Eq. 16  new apparent  CZY tot Radius CCX X)  (Ang Z New ( Z NewNew ) for Eq. 31 V f  V Eq. Y. 26 TheZ t following  ( Z Line  Zrelations )  (2  K ) Mag– 15. Z al al ReRe Im asshown shownEq. in equations 10 solving X and S Eq. 21    Y Radius TestAngle Y Z * sin( ) 20  This Xline10angle, TestAngle Zs Ims Re al is cos( )  Xadjustment in – 15. MagZang Mag adjustment Eq.equations 19 Y  Radius Comp * sin( ) This can be simplified to: , can be determined. Mag Ang    Eq. 18  Radius * cos( ) show what corrections Xadjustment This canZnecessary: be simplified  CComp adjustment Mag Ang are Eq. 32 V f  ( 1 Z expression   New Im Y Eq. 26  Z Sto: ) Z(2is Z K) derived The then TESTING METHOD FOR MHO RELAYS 2 tan 2 Eq. 17 Mag Eq. 25following Zt t  (ZZSLine Z  K  Z S by K  Z Lin e NETAWORLD • 75 Eq. 21 DISTANCE  Zs ImZ YComp Radius TestAngle * *sin( ) ) Y shown equations 16 – 23. Angin Lin e S Lin e Eq. 22   Z X Y adjustment Eq. 20  X Radius TestAngle X cos( MagZ Z ) s Re al Eq. 10 Eq.Z19  Ztot sMag * cos(  C X Ang ) adjustment 0 Radius This can be simplified to: s Re al Y adjustment sAng New*Resin( al Comp  impedances adding all of the of) the sequence Mag Eq. 33 V f  ( Eq. 26here, Z t the  (Z  Z S )  ( 2can  Kbe From fault expressed: 2 2 Line currents Y Eq. 21    Y Radius TestAngle Y Z * sin( )  1 Eq. 22   Z X Y s Im 2 2  adjustment Eq. 18 * cos( Comp ) XZtotadjustment Radius network in Figure 8: -1 Eq. 23 * sin( tan Mag  Radius X Eq. 11 Eq. Z s20 Z *( Zcos( )New MagTestAngle Ang Eq. 16 Z   CX ))  Radius C YZ)sand (XZadjustment Ang Re al Im sMag Mag MagsAng NewIfImX > 0 Re al Y >From 0 then thethe angle tan Y/X  iscurrents X here, bebe 2 Y 2 Eq. 26 Z t simplified (fault Z fault  currents )Vn (can 2 can K ) expressed:  1 From here, 0the  Z 19 * sin( ) If X < can be to: Eq. 22MHO  RELAYS X* Radius Y* Z S TESTING Eq. METHOD FOR These quantiti Eq. 21  YZYZadjustment Radius Z s0Im and Y • sin( Mag Ang tot tan . > This 0Eq. then to 180 to ZAngexpressed: 12 Eq. DISTANCE Z23 ZNew cos( ) Comp I fneed  I Line  Iadd  27 you ZTestAngle C Y)  Y Mag adjustment NETAWORLD 75  1 LAngNew New Re al Ang   New Im f f Eq. 17 Comp Ang  X tan Eq. 25 Zthe  fault Z S to  currents Z Z tZ can  Zbe  K  Z S  K  Z Lin e From here, t Lin eV180 S to Z Linexpressed: e. If X < 0 and Y < 0 then you need add Y phase quantitie Eq. 20   X  Radius TestAngle X Z * cos( ) 0   Ang 2 1 Mag 2 Z New Re al  C X adjustment s Re al I I I  n Eq. 27

. To osen zone urce able nce, osen the urce urce lable lent ance, so the ous. urce ifies alent e 10 so rcle eous. lifies e 10 ircle

as vectorreach quantities. When theusing source thetwo dynamic of the mho circle the impedance angle, ZSang, and theThe linezone impedance settings of the protective relay. 1 reach, another, aZstraight line is angle, Lang, equal sourceone impedance, ZLMag,Zand S, are plotted formed the center the mho circle. as two through vector quantities. When the source Protective Relay of Handbook Because theangle, expansion is due toand a source line-to- impedances are impedance ZSang, and the impedance Because the lineline ground the ground impedance also needs one quantities, another, a they straight line isimpedances angle, Zfault, vector can be broken down into Lang, equal Because the line anddetermine source are Using geometric principles, onea can the dynamic reach to be considered. There will be change in the formed through the center of the mho circle. their real and imaginary components. Then, the vector quantities, they can be broken down of the mho circle using thethe settings of the protective relay. Theinto zone Because line and source impedances are apparent and apparent line angle as seen Because reach the expansion is due to a line-tocenter point along the mho circle can be found real and imaginary Then, 1 reach, ZLMagThe , their and source impedance, Zcomponents. , are plotted as two the vecvector quantities, they can S be broken down into by the relay. assists in calculating 0 factor ground fault, the impedance also askground shown in equations 10 –needs 15. Because the line and source impedances are center point along the mho circle can be found tor quantities. When the source impedance angle, Z , and the line their real will andwill imaginary components. Sang Then, the how groundas impedance affect the reach to bethe considered. There be athey change in the vector quantities, can be brokenline down into shown in equations 10 – 15. impedance angle, Z , equal one another, a straight is formed center along the mho circle be found Lang and angle reach of the apparent seen by Eq. 10point Z Z impedance Z sAng can *as cos( ) Then, apparent and apparent line angle seen s Re al sMag components. their real and imaginary the Because the line and source impedances areto through the center of the mho circle. Because the expansion is due as shown in equations 10 – 15. the relay. TheThe zero sequence magnitude and by the relay. k factor assists in calculating 010 Eq.  Z Z Z * cos( ) center point along the mho circle can be found Eq. 11  Z Z Z * sin( ) s sRe sMag can also sAng vectorthe quantities, they be sAng broken into Imal impedance sMag a line-toground fault, needs todown be considangle compensation are ground expressed in 10 equations how the groundas impedance will affect the reach shown –cos( 15. their real and imaginary components. Then, the Eq. 11  Z Z Z * sin( ) Eq. 12 in  Z Z * cos( ) Eq. 10  ZZsequations Z Z * ) ered. There will be a change in the apparent reach and apparent line sAng sAng sNew Re alRe alsMagsMagNew 4and andangle 5. of the apparent Im impedance seencircle by LAngNew center point along the mho can be found angle as seen byEq. the12 relay. The k0Zfactor assists in) calculating how Z Zthe ZNew cos( Eq. 13 Z **cos( sin( Eq. 11 Zand * sin( New LAngNew the relay. The as zero sequence magnitude NewRe LAngNew Imal Because line and impedances are s Im sMag sAng Eq. 10 ZZNew ZZZsAng ) )) sequations Re al shown 10*source –and 15. the ground impedance willinaffect thesMag reach angle of the appar2 2 angle compensation arequantities, expressed in equations vector they down Eq. 13 MNew ZZ(New Zcos( Z broken *can sin( Eq.Mag 12  ZRe*New Z()LAngNew *Z cos( ) k 0 A into ZeroComp 1 ImRek 0alZZ k ))be k 0 M) sin( )) Eq.4 New alsin( al 0 A Zs Re LAngNew Eq. 11 ent impedance seen magnitude and Im  The sMagzero sequence sAng Eq.bythe 14 Zrelay. Cs New X 4 and 5. their real and components. 2** sin( Eq. are 10 Z s Re alimaginary Z Re cos( )5.) Then, the  ZNew Eq. 13 ZalZ)Z sMag sAng *al sin( ks Re angle compensation expressed in equations and New New LAngNew  1 Im k 0 A4 Eq. 12 0ZMthe ZZ New Z *Zcos( Eq. 14  C Newmho circle LAngNew Re al ZeroComp  tan Eq.5 center point along can) be found X Ang ZZNew Im *2sin( Z s ImZ Eq. 11  Z ) 1  ( k * cos( k )) Z s15. Eq. 13 15 in  Z New Cs YIm sMag 0Re M al *sin( 0alA 2 Re Eq. Z2sAng as – New 10 Eq.shown 14  ZC ZeroComp (New 1equations Imk  Zcos(  ( k ) sin( k )) Eq.4 2 k )) LAngNew

Eq.Z 22 23  tan  YZ LAngNew ) ZZtotAng X Eq. 13 Eq. Z New * sin( New Im

If X > 0 and X * sin( TestAngle  Z s Im Y X Radius MagRadius )  Y adjustment * cos( Comp ) Mag Ang Z 1 Y  ZZ Newadjustment s Re al Realtan Ang 2 2 * sin( Comp Ang )  2X  Radius XY ZYtotadjustment Mag

  f Y < Eq. 0 then to add ZAng 26 you Zft need  ( Zf Line Z S Z)360  ( 2to K ) .

Vt can be expressed: f From here, the fault currents 0   Eq. 34 V a  V I for  the I f sequence I f  n components in each Eq.solving 27 By f Z This canone be simplified to:V t the f By solving for the sequence components in each phase, one phase, calculate final secondary Eq.can 35 Vb  V 0 can  n components in each By sequence Using the relay settings and the Ifault the Icurrents previous Eq.solving 27here,Ifor From the can be expressed: f f f Eq. 20 Z X  Radius   TestAngle X Z * cos( ) calculate final secondary currents. Eqs. f currents. These are shownZ in Eqs. 28 – These 30: are shown inEq. adjustment s Re al  Z 1 YMag phase, onethe can calculate 36 Vc  V  tthe final secondary equations, one can determine the apparent Eq. 15 Eq.C Y23 ZNewAngIm tan s Im By solving for sequence in each Eq. 26 Z the (Z  Z S reach, ) components (2  K ) t Line 28 – 30: X Eq. 21 Y  Radius   TestAngle Y Z * sin( ) Mag adjustment s Im 2 Vinn Eqs. 28 – 30: currents. are shown 0 1.095Ώ  ZTot, and line angle, ,These are Ang phase, one the final secondary I ff can  I 0f calculate  I f and   77.2° Eq. Z27  2 2 3 I f Eq. 28 I  I  I  I components By solving for the sequence in each areachf andf lineZ f angle 22 point   Z point X Y After theEq. center of the circle has been respectively. After the new After the center the circle has been found, the radius of t The final calcu tot currents. These are shown in Eqs. 28 – 30: f f can0 0 calculate  2   the final  phase, one secondary From here, the fault currents can be expressed: 3 Eq. 28 I  I  I  I   I I  I    I    I Eq. 29 found, the radius of the circle compensation are The known, and voltages the circle and compensation can be determined. com-the secondary acurrents Yangle are shown in T f f f f f f f  1 and b Eq. 23 Z Ang  tan currents. These are shown incomponents Eqs. 28 – 30:in each By solving ffor 0computed. 2  f f bethe 00 sequence  pensation is the apparent angle that the relay during to Eq. angle can angle be determined. The compensation tosees be applied the relay can  First, 2 X line 3 I If f Eq. 28 Eq.29 30 IIIbac 0IIIf f f If IIfff V I fcan  I calculate  I f  nthe final Eq. 27one phase, secondary the ground fault. Next, adjustment thesees position mhoneeds angle is the apparent linean angle that the for relay theofKthe factor to be determined: f ff 00   2  2 Z f 0  30 IIIf f28 – 30: Eq. 29 IThese I fII f in f  Ishown 3Eqs. Eq. 28 IIcab  IIIfare  t  currents. circle is determined. Finally, the new total apparent reach, Ztot and Eq. during the ground fault. Next, an adjustment f f f f f 0  in a2 similar  The voltages are found manner. The fault voltages 2 I    line Zangof , can determined. This is shown Eq. in equations 30  for theangle, position the be mho circle is determined. 24 K  ( 3 Eq. Eq. k 0 )29  1 II cf  II 0f    If f    II ff b for the f By solving sequence components in each can be expressed following f 0 by the   equations: 16 – 23.the new total apparent reach, Ztot and Finally, Eq. 28 I af  I 0f  I f  I f  32  I f phase, secondary Eq. 30 one I c can I f  calculate   I f   the  I final f Table 2: C line angle, Zang, can be determined. This is f 0 2   Eq. 29 I  I    I    I currents. These are shown in Eqs. 28 – 30: b f f f TheSOURCE following expression is METHOD then derived by DISTANCE RELAYS Currents IMPEDANCE TESTING FOR MHO in equations 6 • shown SPRING 201216 – 23. AN IMPROVED CONSTANT f 0  2  adding all of the impedances of the sequence Eq. 30 I  I    I    I c f f MHO DISTANCE f AN IMPROVED CONSTANT SOURCE IMPEDANCE TESTING METHOD FOR RELAYS 6 • SPRING 2012 The values calc 2 2 network in FigureEq. 8: 28 I af  I 0f  I f  I f  3  I f Eq. 16 Radius Mag  ( Z New Re al  C X )  ( Z New Im  C Y ) AN IMPROVED CONSTANT SOURCE IMPEDANCE TESTING METHOD FORMHO DISTANCE RELAYS constant sourc f 0 2  6 • SPRING 2012 Eq. 29 I b  I f    I f    I f   1 Z New Im  C Y   of the mho c Eq. 17 Comp  tan Eq. 25 Z  Z Z Z Z  K Z K Z Eq. Eq. 21 18 Eq. Eq. 14 Eq. C23 X 19 Eq. 22

The voltages are found in a similar manner. The C on C l u sion s The voltages are found inbya the similar manner. TheWithCo n Cl us i o ncapabilities s fault voltages can be expressed following of today’s The voltages are found in a similar manner. The C onthe C l uincreasing sion s fault voltages can be expressed by the following With the increasing capabilitiessteady-state of today’s equations: relay test equipment and software, fault can be expressed by the following Withrelay thetestincreasing capabilities ofsteady-state today’s Protective Relay Handbook equations: 34 voltages equipment and software, methods are becoming replaced by more accurate equations:    relaymethods test equipment andreplaced software, steady-state are becoming by more accurate Eq. 31 V f  V n  ( I f  Z S ) forms of are testing. Computer simulations and Eq. 31 V  V  ( I  Z ) methods becoming replaced by more accurate forms of testing. Computer simulations and       Eq. Vf  (  If (I Z S )Z ) appropriate equipment can received quickly and easily Eq. 32 31 V V ReneComputer Aguilar his B.S. in Electrical Engineering from the f formsappropriate of testing. simulations and Eq. 32 n V f (  I S  Z ) equipment can quickly and easily 0   provide realistic scenarios that will thoroughly University of Texas at Austin. He Eq. V ff  ((II ff  ZZSS  ) K) Eq. 33 32 V appropriate equipment can quickly easily worked on APPDS (Automatic provide realistic scenarios that will and thoroughly Eq. 33 V  (  I  Z  K ) test protective relays before they are put into Protection Detection 0   test realistic protective relays before theySystem) are put used into for detecting coordinating isprovide scenarios that will thoroughly Eq. 33 V f  (  I f  Z S  K ) service. However, once in service, these same sues between devices in a distributed These quantities are converted to each theof thetest service. However, service, same generated system. In 2006, protective relays once beforein they are these put into These quantities are converted to of each relays must be periodically tested. The dynamic he joined Megger as an application relays must be periodically tested. The These phase quantities are converted to each of the phase quantities: phase service. However, once in service, thesedynamic same engineer in the technical supquantities: These quantities: quantities are converted to each of the methods are scaled back from a full simulation port group. Rene is in charge of developing automatic testing for scaled back tested. from a The full simulation relaysmethods must beareperiodically dynamic f 0   phase Eq. 34 quantities: V  V  V  V to values calculated from thethe systems sequence Eq. f V  V numerical relays well as the implementation of IEC 61850 on to values calculated from systems sequence a 34 f V f V methods are scaled back from aas full simulation ff 0 0  f 2 2   components. This article has illustrated components. This article has illustrated a extensive experience in the 0 various Megger products. Rene Eq. 35 V  V   V   V Eq. Vf  bV  f VffV f V f f Eq. 35 34 V Vba  V f to values calculated from the systems sequenceahas f method by which this can be performed. method by which this can be performed. f 0  2  testing and commissioning of electrical schemes and multivendor ff 00  2 Eq. 36 V 2 V    V    V components. This article has illustrated a  f

 S

 f

 S

0 f

 f

 S

f

a

Eq. Eq. 36 35

 f

n

 f

0 f

 f

 f

V Vcb  V Vff c VVf ffV Vfff

f

device applications of IEC 61850. He is a member of IEEE and method by r which thiss can be performed. r e Fe eCn Ce r e Feren es and an active member of the Power System Relay Committee. The final calculated test voltages and currents C.L. Fortescue, Methodof of Symmetrical Symmetrical The final calculated test voltages and currents are shown in Table 2. The final calculated test voltages and currents C.L. Fortescue, Method r e Feren C es are shown in Table 2. Jason Buneo received his B.S and Co-ordinates Applied are shown in Table 2. test Co-ordinates toto M.S in Electrical Engineering Table 2: calculated Calculated Secondary and Currents The final voltages Voltages and currents C.L. Fortescue, Method of Applied Symmetrical the Solution of Polyphase from the University at Buffalo in 2001 and 2005, respectively. In the Solution of Polyphase are shown in Table 2. Co-ordinates Applied to Networks, Annual Convention 2005, he joined GE Energy Services as a field service engineer. He Networks, Annual the of Solution of Convention Polyphase the inAmerican Institute of specialized arc-flash and coordination studies, protective relay of the American Institute of Electrical Engineers, Atlantic Networks, Annual Convention testing and calibration, and low- and medium-voltage switchgear Electrical Engineers, Atlantic NJ, 1918 of City, theIn 2008 American Institute repair. he joined Meggerofas an Applications Engineer speTable 2: Calculated Secondary Voltages and City, NJ, 1918 The values calculatedSecondary will simulate a system Electrical Engineers, protective relayAtlantic evaluation Table 2: Calculated Voltages and with constant cializing Currents A. T.inGuilante, Dynamic Relay and testing. He is also a parsource impedance precisely at the edge of the mho characteris- ticipating City, NJ, 1918 member of the IEEE Currents A. T. Guilante, Dynamic Relay Testing, ATG Consulting Power Systems Relaying Committee. Table 2: Calculated Secondary Voltages andandwith tic. To find values that arewill slightly outside slightly inside Thethe values calculated simulate a system Testing, ATG Consulting Currents A. T. Guilante, Dynamic Relay the operating characteristic, one must perform theedge previous series constant source impedance precisely at the The values calculated will simulate a system with Testing, ATG Consulting of the for mho characteristic. Toatfind the values of calculations each newprecisely test point. Fortunately, software proconstant source impedance the edge The values calculated willoutside simulate a slightly system with that slightly and inside for thethe user are grams that canare perform theseTo calculations quickly of the mho characteristic. find the values constantoperating source impedance precisely at theperform edge the characteristic, one must readily that areavailable. slightly outside andTo slightly inside the of the mho characteristic. find the values previous series of one calculations for eachthe new test operating characteristic, must perform CONCLUSIONS that are point. slightlyFortunately, outside and slightly inside the software programs that can previous series of calculations for each new test operating characteristic, one must perform the perform these capabilities calculations quickly forrelay the user With the increasing of today’s test equipment point. Fortunately, software programs that can are readily available. methods previous series of calculations for each test and software, steady-state arenew becoming replaced by perform these calculations quickly for the user point. Fortunately, software programs that can more accurate forms of testing. Computer simulations and approare readilythese available. perform calculations forprovide the userrealistic scenarios priate equipment can quicklyquickly and easily are available. test protective relays before they are put into thatreadily will thoroughly Eq. 36

f

0 f

 f

2

Vc  V   V   V

 f

Aguilar received his B.S. in Electrical Engineering from the University of Texas at Austin. He worked service. However, once in Rene service, these same relays must be perion APPDS (Automatic Protection Detection System) used for detecting coordinating issues between devices in odically tested. The dynamic methods are scaled from a full a distributed generated system. back In 2006, he joined Megger as an application engineer in the technical support Rene Aguilar received his B.S. in Electrical Engineering from the University of Texas at Austin. He worked group. Rene is inthe charge of developing automatic testing for numerical relays as well as the implementation of simulation to values calculated from systems sequence comon APPDS (Automatic Protection Detection System) usedextensive for detecting coordinating issuesand between devices inof IEC 61850 various Megger products. Rene has experience inoftheTexas testing commissioning ponents. This article hasAguilar illustrated aonmethod by which this can be from received his B.S.In in Electrical Engineering the Universityengineer attheAustin. He support worked aRene distributed generated system. 2006, he joined Megger as an application in technical electrical schemes and multivendor device applications of IEC 61850. He is a member of IEEE and and an on APPDS (Automatic Protection Detection System) used for detecting coordinating issues between devices in performed. group. Rene is in chargeofofthedeveloping automatic testing for numerical relays as well as the implementation of active member Power System Relay Committee.

a distributed 2006, he joined as an application engineer thecommissioning technical support IEC 61850 ongenerated various system. Megger In products. Rene hasMegger extensive experience in the testinginand of

group. Rene is in charge of developing automatic testingoffor numerical relays well as the implementation of Jason Buneo his B.Sdevice and M.S in Electrical Engineering Buffalo in 2001 REFERENCESelectrical schemes and received multivendor applications IEC 61850.from He the is aasUniversity member ofat IEEE and and and an

IEC 61850 onof various Megger products. Rene has extensive in the testingHe and commissioning of 2005, respectively. InSystem 2005, he joined GE Energy Services experience as a field service engineer. specialized in arc-flash active member the Power Relay Committee.

C.L. Fortescue. “Method Symmetrical Co-ordinates Applied toIEC electricalof schemes and multivendor device applications of 61850. and He islowa member of IEEE andswitchgear and an and coordination studies, protective relay testing and calibration, and medium-voltage repair. In 2008 he joined Megger as an Applications Engineer specializing in protective relay evaluation and active member of the Power System Relay Committee. the Solution of Polyphase Networks.” Annual Convention of the Jason Buneo received his B.S and M.S in Electrical Engineering from the University at Buffalo in 2001 and testing. He is also a participating member of the IEEE Power Systems Relaying Committee. 2005, respectively. In 2005, he joined GE Energy Services as a field service engineer. He specialized in arc-flash American Institute of Electrical Engineers, Atlantic City, NJ, 1918. Jasoncoordination Buneo received his B.S and M.S in testing Electrical at Buffalo inswitchgear 2001 and and studies, protective relay andEngineering calibration,from and the low-University and medium-voltage

A. T. Guilante. Dynamic Relay ATG Consulting. 2005, respectively. 2005, he joined GEApplications Energy Services as a field service engineer. He specialized in arc-flash repair. In 2008 Testing, he In joined Megger as an Engineer specializing in protective relay evaluation and

and coordination protective relay oftesting and Power calibration, and low- and medium-voltage switchgear testing. He is also astudies, participating member the IEEE Systems Relaying Committee. repair. In 2008 he joined Megger as an Applications Engineer specializing in protective relay evaluation and testing. He is also a participating member of the IEEE Power Systems Relaying Committee.

NETAWORLD

•

77

AN IMPROVED CONSTANT SOURCE IMPEDANCE TESTING METHOD FOR MHO DISTANCE RELAYS

NETAWORLD

•

77

AN IMPROVED CONSTANT SOURCE IMPEDANCE TESTING METHOD FOR MHO DISTANCE RELAYS

NETAWORLD

•

77

AN IMPROVED CONSTANT SOURCE IMPEDANCE TESTING METHOD FOR MHO DISTANCE RELAYS

the test equipment answer

the test equipment answer

We support testing of

We support testing of

■■

■■

Relay and Protection Systems Switchgear and Breakers (Low, Medium and High Voltage)

■■

■■

Relay and Protection Systems Switchgear and Breakers (Low, Medium and High Voltage)

■■

Cable and Bus

■■

Cable and Bus

■■

Transformers

■■

Transformers

■■

Batteries

■■

Batteries

■■

Motors and Rotating Apparatus

■■

Motors and Rotating Apparatus

■■

Watthour Metering

■■

Watthour Metering

■■

Power Quality and Consumption Analysis

■■

Power Quality and Consumption Analysis

Test Equipment Rental

Test Equipment Rental

888.902.6111 972.317.0479 [email protected] www.intellirentco.com

888.902.6111 972.317.0479 [email protected] www.intellirentco.com

35

Protective Relay Handbook

INSTANTANEOUS GROUND FAULT RELAYS (50GS)AND ZERO-SEQUENCE CTS POWELL TECHNICAL BRIEF #68 NETA World, Spring 2012 Issue by Baldwin Bridger, Powell Electrical Manufacturer Co. We previously discussed the problem of low-ratio CTs used on systems with high fault current and mentioned the IE working group report on this subject. Because of the emphasis in this report on making sure that CTs do not saturate, a number of people expressed concern about the operation of instantaneous ground fault relays connected to zero-sequence, or core balance, CTs. Because of this concern, Powell recently ran a series of tests to check the operation of typical CTrelay combinations. Two different relays were tested with each of two CTs. The relays were the GE HFC and the AB IT. Electromechanical relays were chosen for the test because their higher burden places a greater load on the CTs. The CTs used were both made by ITI. The first was Model 141-500, 50/5, C10 accuracy. The second was Model 143-500, 50/5, C20 accuracy. The test results are presented in the table below.

Both of these relays operated correctly and reliably with both CTs. However, we also tested a third relay, the AB ITH, a high dropout version of the IT. We found that this relay was not reliable in this service. It picked up at quite low values, and operated well with primary currents up to about 150 amperes. At currents of 600 amperes and higher, it chattered badly and did not close its contacts long enough to operate a circuit breaker. Upon asking around, we found that this relay had been recommended for 50 GS service in the past, but its manufacturer (Westinghouse at that time) changed the recommendation when the chattering problem was discovered. Based on this information and the tests, Powell strongly recommends that the ITH relay not be used as a 50GS relay. Summarizing, both the HFC and the IT work quite well at primary ground fault currents up to 1800 amperes, even though the CTs are badly saturated at that current level. This circuit, with these CTs and relays, should not be used on solidly-grounded systems with high ground fault current. For these systems, residuallyconnected relays should be used, or the zero-sequence CTs should have higher ratios.

Baldwin Bridger is retired Technical Director of Powell Electrical Manufacturer Co., Houston, Texas. He has worked as an engineer and engineering manager in the design of low- and medium-voltage voltage switchgear since 1950, first at GE and since 1973 at Powell. He is a Fellow of IEEE and a past president of the IEEE Industry Applications Society.

36

Protective Relay Handbook

MODERN PROTECTIVE RELAY TECHNIQUES: USING A 94-YEAR-OLD CONCEPT TO PROTECT FEATURE ELECTRICAL EQUIPMENT NETA World, Spring 2012 Issue The three sets

The of symmetrical components are Addi designated by a subscript 1 for the positiveFEATURE sequence components, a subscript 2 for the of th An extremely powerful tool for analyzing unbalanced threenegative-sequence components, and a subscript quan phase circuits is the method of symmetrical components intro- The three sets of symmetrical components are The duced by Charles Legeyt Fortescue. In 1918, Fortescue presented 0 for the zero-sequence components. The Add designated by a subscript 1 for the positiveV = a paper entitled Method of Symmetrical Coordinates Applied to positive-sequence set is the only one present sequence components, a subscript 2 for the of th the Solution of Polyphase Networks, which demonstrated that any V = during perfectly balanced system operation. set of n unbalanced phasors could be expressed asFEATURE the sum of n negative-sequence components, and a subscript quan V = symmetrical sets of balanced phasors. The n phasors of each set of The presence of negative-sequence and zero0 for the zero-sequence components. The components are equal in length, and the angles between adjacent sequence components unbalanced The quantity The three sets of symmetrical components are V = positive-sequence set is indicates the only one present phasors of the set are equal. The Adding V designated by a subscript 1 for the positiveA, V operation the power system and/or power FIGURE perfectly 1:of Positive-sequence, negative-sequence, and zeroV = balanced system operation. components, a subscript 2 for the of the symme In a normally balanced three-phase system, unbalanced fault during sequence there sequence components system faults. negative-sequence components, and a subscript quantitiesVyiel= conditions generally cause unbalanced currents and voltages to The presence of negative-sequence and zerocomp 0 for the zero-sequence components. The exist in each of the phases. Calculating unbalanced voltage and sequence components indicates unbalanced +V + three-phase in power canbyV a= ⅓ (VCurr three sets ofquantities symmetrical aresystem designated positive-sequence set is components thea only one present current levels through the elements of a power system is very com- AllThe The operation of the power system and/or power V = ⅓ (V + 1 for the positivesequence a subscript 2 for thea ∙rV during perfectly plex. Using Fortescue’s method, the unbalanced system conditions besubscript represented by thebalanced sum components, ofsystem the operation. symmetrical V = ⅓ (Vthere +a ∙ the negative-sequence and a subscript 0 for the zeroThe presence components, of negative-sequence and zerocan be mathematically changed into three easy to calculate bal- system faults. components. Let’s take voltages as an example. sequence components. The positive-sequence set is the only one com sequence components indicates unbalanced anced systems. After the three balanced systems are calculated, SEQ three-phase voltages can be expressed inThe A-phase present during perfectly balanced operation. The presence operation ofquantities the power in system and/or power the result is then, with simple addition, changed back into the ac- These All three-phase a power system can therefore, ICurr Nthe of negative-sequence and zerosequence components indicates system faults. tual unbalanced levels at each location of the power system. In terms of the sequence components as shown in be represented by the sum of the symmetrical the r components fact, most numerical relays operate from symmetrical component unbalanced operation of the power system and/or power system P R O equations (1), (2), and (3). All three-phase quantities in a power system can Currents can faults. components. Let’s take voltages as an example. Zerob quantities. be represented by the sum of the symmetrical the resulting s SEQ three-phase voltages cansystem beanexpressed in seque All three-phase quantities in a voltages power can be represented By organizing the separate equivalent components into net- These components. Let’s take as example. V V sum + Vof +the V symmetrical components. Let’s take voltages (1) SEas by =the QUIEN NC works according to the interconnections of the elements, we arrive terms of thethree-phase sequencevoltages components as shown These can be expressed in in indic an example. These three-phase voltages can be expressed in terms I N M OD + V +ofVthe sequence components as shown in(2) at the concept of three sequence networks. Solving the balanced V = V terms P REO equations (1), (2), and (3). of the sequence components as shown in equations (1), (2),PROT and zeroECT sequence networks for the fault conditions is relatively easy. The V = V equations + V + V (1), (2), and (3). (3) Zero Zero-sequenc solution gives symmetrical current and voltage components which (3). relay com can be summed together to reflect the effects of the original unV = V +V V= V + +VV + V (1) sequencesequ (1) The unknown quantities can be reduced by comp indications of balanced fault on the overall system. According to Fortescue’s indic (2) V = V +V V= V ++VV + V (2) of the fact that the positive andzero-sequence the method, there are three equivalent circuits for each element of a making Vuse =V +V +V (3) zero“ V =V +V +V (3) relays has no three-phase system. Figure 1 assumes ABC system rotation. The negative sequence components always have the p relay The unknown quantities can be reduced by component d balanced sets of components for a three phase system are the folexactly 120° between them. wereduced define making use of thecan fact thebe positive anduse an the operat unknown quantities bethat reduced by making of the“a” seque lowing: TheTheunknown quantities canSo by com negative sequence components always have the phase qua fact that the positive and negative sequence components always seque operator Using this “a” operator, a = 1  120º. 1. Positive-sequence components consisting of three phasors equal making use of the fact that the positive and the “ exactly 120° between them. Sodefine we define an Using sequence com have exactly 120° between them. So we an operator costl in magnitude, displaced from each other by 120° in phase, and we simplify equations (2) and (3) in equation negative sequence components have thisequations “a”always operator, sequence comp this “a” operator operator, a = 1120º. we Using simplify (2) and (3) in the 120º. having the same phase rotation sequence as the original phasors. (4) below. due we simplify equations (2) and (3) in equation costly to obtat equation (4) below. exactly 120° between them. So we define an sequ 2. Negative-sequence components consisting of three phasors (4) below. due to the hig filter = V2a Using this “a” operator, sequ 1a 120º. equal in magnitude, displaced from each other by 120° in operator a = 1V filter negativeV =V V1Bsimplify = a2 ∙ V1A equations V1C =(2) a ∙ Vand (4) phase, and having the phase sequence rotation opposite to that we (3) in equation costl 1A Mod V =a ∙V V =a∙V (4) Modern num 2 of the original phasors. = a ∙ VV2A= a ∙ V V2CV= a (4)V2Bbelow. due = a ∙ ∙V V2A advan advantages an 3. Zero-sequence components consisting of three phasors equal filter accurateaccur calcu V1adefinition = V2a that V =V =V in magnitude and with zero phase displacement from each other. We also by Weknow also know by definition that 0A = V 0A V0B 0C0B = V0C. from phase WeValso know by definition that V = V = V . 2 0A 0B 0C from V1C = a ∙ V1A (4) 1B = a ∙ V1A turns the an Mod Substituting equation (4)2 in equations (1), (2), V2B = a ∙ V2A V2C = a ∙ V2A turns into digital va and (3) equation (4) in equations (1), (2), Substituting adva angle. After intot by Suparat Pavavicharn, Basler Electric Company

0A 1A 2A

0A 1A 2A

A

0A

1A

2A

B

0B

1B

2B

C

0C

1C

2C

A

0A

B

0B

C

0C

A

1A 0A

2A 1A

2A

B

0B

1B

2B

1C

2C

1B

C

2B

0C

1C

2C

1a

1B 2B

2

1A

2A

2a

1C 2C

1A

2

2A

0A

A

1A

A

2A

A

B

2

fr components andThesenegativeSaccurate E Q three-phase Uthe SEENin Q Crelay U E ES N NEEC Q TEvoltage W UN EO N ERTC K W Ein Sdrop O Nfaulted R EK TW Sequation OR K S for a from location conditions. calculation of symmetrical components three-phase These three-phase These voltages three-phase voltages can be expressed can voltages be expressed can in beThe expressed in NE T W O R K S Th IN MO I NDinEMRN OID NN E RN M UM O ED NRI EUM RN C AELRI N UM C A LE RI C AL alsoboth knowterms by definition that V0B V0C .shownThis 0A = onentsWeare measurable ofterms the sequence of the terms sequence components ofVthe sequence components as = shown components asin as in shown high variation in phase angle is a reliable from phase quantities. The numerical relay in system can be voltages at two N N U ME R I C A L equations P R O TP Ethat C RT OI T VEEPCR R TO IEVrepresented LTEAY EC RS TEILVAY E S Rby E L AY S equations (1), (2),equations (1), and (2), (3). and (1),(3). (2), and (3). alanced conditions. Obtaining indication of the direction to a fault. turns the analog voltage and current levels Zero-sequence Zero-sequence components Zero-sequence components andvoltage components negativeand Vnegativelocations, system and negativefault37 S and E RESubstituting L AY S Protective Relay(4) Handbook equation in equations (1), (2), defined Th antities with electromechanical sequence sequence components sequence components are components both are measurable both are measurable both measurable into digital values with a magnitude and phase V = V + VV + = V + V V+ V =V +V +V (1) (1) (1) , is the following: voltage V sy F components negative(3) andbecause indications indications of unbalanced indications of unbalanced conditions. of unbalanced conditions. Obtaining conditions. ObtainingObtaining The three-phase voltage drop equation for a been and a problem V = V + VV =+the V + V V+ V =V +V +V (2) (2) (2) d angle. After the quantities A/D conversion, determining tion in zero-sequence faulted conditions. This high electromechanical variation in phase angle is a Substituting (4) in equations (1), (2), and (3) onents are both equation measurable zero-sequence quantities zero-sequence with electromechanical quantities with with electromechanical V = V + V V = + V V + V V + = V V + V + V (3) (3) (3) system that can be represented byisvoltages at two v not require phase shifting by reliable indication to a fault. V – symmetrical V =not Z has ∙been Irelays +of Zthe ∙problem Idirection + not Za problem ∙ been Ibecause (11) the the accomplished = V + V + V Obtaining (5) relays has relays not a components has been a problem because the the because balancedV conditions. locations, system voltage fault S and See equation (8). The The sum ofquantities The three-phase drop equation forof aVsystem that canby be unknown The unknown The unknown quantities can bequantities can reduced be can by bedefined by reduced by component does component notvoltage does require not does phase require not shifting phase require shifting by phase by shifting by thecomponent mathematical capabilities the modern = V electromechanical +a ∙V +a ∙V (6) reduced antitiesVwith V –V =Z ∙I +Z ∙I +Z ∙I (12) Figu represented by voltages at two defined locations, system voltage making making use of the use making fact of the that use fact the of that the positive fact the positive that and the and positive and the “a” operator. the “a” operator. See the equation “a” operator. See equation (8). See The equation (8). sum The of sum (8). The of sum of , is the following: voltage V F The quantity re ies is proportional to+ athe 1 + azero+ a2 = 10º + 1120º + 1240º = 0 Presult, O L A numerical R IZ I N Grelays DIREC TIO microprocessor. As a V = V + a ∙ V ∙ V (7) been a problem negative because the negative negative sequence sequence components sequence components always components always have have always have the the quantities phase the quantities isZphase quantities is Zproportional to isthe proportional zeroto the zeroto(13) the zero- used VSphase and fault voltage Vproportional , ∙isI the following: F V – V = Z ∙ I + + ∙ I Adding VAthe , VBnegative, and VC120° and solving for each e- Conversely, nent. O V E RConversely, CtheU R Rthe EN T can derive the positive-, negative-, andR E L AY 120° exactlybetween between them. 120°So them. between we define So them. we an define So we andefine an easily sequence sequence component. sequence component. Conversely, component. Conversely, the negativenegativenegativenot require phaseexactly shifting by exactly V – V = Z ∙ I + Z ∙ I + Z ∙ I (11) thequantity symmetrical he ent hasofbeen more difficult S been Ydifficult Mmore Mbeen E Tmore R Iand Cdifficult Arelays L and COM PO operator Using Using “a”A-phase operator, this “a” operator, thissequence “a” operator, sequence component component sequence has been component has more has difficult and The 1 + a + operator a2a components, =and += 11120º 240º = 0Using Adding 110º 120º. aoperator 120º. a+ =with 11this  120º. zero-sequence quantities. Numerical A gro See equation (8). The sum of we simplify we simplify equations we equations simplify (2) and equations (2) (3) and in equation (3) (2) in and equation (3) in equation costly to costly obtain to with costly obtain electromechanical to with obtain electromechanical with electromechanical relays relays relays V , V , and V and solving for each of the symmetrical compoW quantities yields pt with electromechanical relays V –V = Z impedances ∙ I the + Z tools ∙I +Z ∙ I the (12) Directional overcurrent relays A B C When the are closely balanced, Figu also provide for relay engineers ies is proportional tobelow. the (4) (4)zerobelow. (4) below. due to the duehigh to the cost due high of to techniques cost the high of techniques cost required of techniques required to to required to seque nents, with A-phase quantities yields e The cost of techniques required to the phase relationship of voltag equations (13) can berecorded expressed used to sequence V analyze – Vfilter = (11), Z ∙ filter I +(12), Znegative-sequence ∙ I and +components Zcomponents. ∙I (13) in filter negative-sequence negative-sequence components. components. to re in nent. Conversely, the negativeV =V V =V V =V V = ⅓ (V + V + V ) (8) nt uence components. to determine the direction to in symmetrical component quantities as shown in oscillography files. V =a ∙V V and = a ∙ V V = a ∙ ∙VV V = a ∙ V V = a (4) ∙V (4) When(4) the impedances closely equations (11), (12), nent hasVbeen more difficult ModernModern numerical numerical Modern relaysare include numerical relays include a balanced, number relaysa include number of a ofnumber of Figur = ⅓ (V + a ∙ V + a ∙ V ) (9) A gr n. determine the direction to asupp faul V = a ∙ VV = a ∙ V V = a ∙ ∙VV V =a ∙VV =a ∙V in equations (14), (15), and (16). and (13) can expressed inand symmetrical component quantities as advantages advantages andbefunctions advantages and functions associated functions associated with simple, associated with simple, with simple, with electromechanical relays When the impedances are closely balanced, al relays include a number of V = ⅓ (V + a ∙ V + a ∙ V ) (10) sequ shown in equations (14), (15), and (16). ois the only concern. accurateaccurate calculation calculation accurate of symmetrical calculation of relationship symmetrical components of symmetrical components components to th cost of techniques required toknow equations (11), (12), and (13) can be expressed We alsosimple, know We also by definition We also by definition know that V by0Adefinition that V= = V0B =that V.0B V =0A V = . V = V . 0A V 0C 0C 0B 0C nctions associated with from phase phase The angle numerical quantities. The setting numerical relay The of numerical relay relay to re V –phase V = Zquantities. ∙ Ifromquantities. (14) d the directional The A-phase components are the reference; therefore, the suffix from quence components. component quantities as shown turns the turns analog theturns voltage analog thevoltage and analog current and voltage current levels and levels current levels zeroThe components are the reference; on components Figu equation Substituting equation (4) equations (4) equation in (4) in equations (1), in (2),symmetrical (1), (2), “A” isA-phase droppedSubstituting and theSubstituting components are in denoted byequations V(1), , V(2), , and er of symmetrical to as the maximum torque angle 0 1 V digital –V Z ∙ Iinto (15) and phase into into=values digital with values digital a magnitude with values a magnitude with and aphase magnitude and phase imba in equations (14), (15), and (16). and (3) and (3) and (3) . Currents can be determined in a similar manner; the resulting V therefore, the suffix “A” is dropped and the ntities. 2The numerical relay supp concept of detectingpowe faulM angle. After angle.theAfter A/D angle. theconversion, After A/D simple the conversion, A/D determining conversion, determining determining al relays include a number ofI . sequence currents are I , I , and 0 1 2 V – V = Z ∙ I (16) components are denoted by V , V and V . g voltage and current levels 0 1, 2 the symmetrical the components the symmetrical components is accomplished components is accomplished accomplished th V = V + VV = + V + V V+ V =V +V +V (5) (5) (5) symmetrical a these relays is isthat there is anittoapp unctionsSEQUENCE associated with simple, cou Vthe –mathematical V the = Zmathematical ∙ by I the (14) IN =MODERN NUMERIby by capabilities mathematical capabilities of the capabilities modern of the modern of the modern can NETWORKS be determined similar manner; snwithCurrents a magnitude Vand =V +phase aV ∙ = VV + + aa ∙ V∙VV in + V aa∙+V a ∙V +a∙V (6) (6) (6) zeroc Modern Protective relay techniques: using a 94-year-old concePt difference of numerical calculated sequenc G Modern numerical protective relays use the angular relationCAL PROTECTIVE RELAYS on2012 of symmetrical components microprocessor. microprocessor. As microprocessor. a result, As a numerical result, As a numerical result, relays relays relays curre n V = V + aV∙ V= V+ a+ a ∙ V∙ V V =+Va ∙+Va ∙ V + a ∙ V (7) (7) Protect electrical equiPMent al the resultingdetermining sequence currents are I0, I1, and I(7)2. Modern A/D conversion, V –of V symmetrical =numerical Z ∙ I tocomponent (15) protective relays use the imba ships currents and voltages and the , Z , and Z for faults in the Z 0 1 2 can derive can easily derive can the easily derive positive-, the easily positive-, negative-, the positive-, negative-, and negative-, and and antities. Zero-sequence The numerical relayand negativesequence components components involdt e.components , Z , and Z to resultant angular nature of sequence impedance Z is accomplished angular relationships of symmetrical component 0 location 2 in faulte zero-sequence quantities. Numerical quantities. Numerical relays Numerical relays relays powim both indications from the relay V – zero-sequence V = Z quantities. ∙ zero-sequence I (16)1 g voltage andmeasurable current levels Sare E QU Eof N C Emodern N E T WofOunbalanced R K S conditions. Ob- also determine the direction totools a the fault. These three impedances are used we aw provide alsoand provide the also tools the provide for the for relay tools the engineers relay for the engineers relay engineers ncal capabilities taining zero-sequence quantities with electromechanical relays currents the voltages assessments; and resultant angular itang co Thisthe high variation in phase s withI has a magnitude and phase create directional 67recorded N Mbeen O Da problem ER Nrelays NUM R I CA Ldoes not require totoanalyze to three analyze sequence tosequence analyze components sequence components recorded components in , 67POSrecorded in, and 67NEG in relayre ZERO not because theEcomponent n a result, As numerical Zrelays. , and Zcommon nature of sequence impedance Z0 , of 1the 2 to to curre respectively, in modern The indication direction oscillography oscillography files. oscillography files.numerical files.protective A/D P conversion, determining phase shifting by the “a” R operator. SeeSequation (8). The sum of Modern re numerical protective relays use theand a fau R O TE C TI V E E L AY process in these relays is to measure the impedance angle the positive-, negative-, and determine the direction to a fault. These three invo the phase quantities is proportional to the zerosequence compoto With components is accomplished of symmetrical component Zero-sequence components and negative- angular compare relationships it to a window of the MTA ±90° as forward or reverse. drop eit uantities. Numerical relays nent. Conversely, the negativesequence component has been more impedances The three-phase voltage are used to create three directional we w again ical capabilities ofcomponents the tomodern and voltages and the resultant angular areelectromechanical both measurable ov difficult costly obtain with relays due currents ZERO-SEQUENCE CURRENT FORcan GROUND tools sequence for theandrelay engineers system that be represented bygr 67 and 67 assessments; 67 relay ZERO, POS, NEG A As a indications result, numerical relays to the high cost ofunbalanced techniques required to filter negative-sequence nature FAULTofPROTECTION sequence impedance Z0 , Z1, and Z2 to ofrecorded nce components in conditions. Obtaining respectively, defined locations, system voltage modern numerical protective components. all p the positive-, negative-, andwith electromechanical determine theindirection to a fault. These three zero-sequence quantities With . voltage V , is the following: F relays. The common process in these relays is Modern numerical relays include a number Modern of advantages and zone Modern Protective Protective Modern relay techniques: Protective relay techniques: relay using techniques: a using 94-year-old a 94-year-old using concePt a 94-year-old concePt concePt M quantities. Numerical relays used to create three directional 8 •58 SPRING • 58 SPRING •not SPRING 2012 relays has2012 been a2012 problem because the impedances are again Protect to Protect electrical toelectrical Protect equiPMent electrical equiPMent equiPMent to functions associated with simple, accurate calculation of sym- to measure to the impedance angle and compare of de for the relay engineers assessments; 67 , 67 , and 67 bytools component does not require phase shifting by Z E R O POS NEG metrical components from phase quantities. The numerical relay V – V ±90° = Z ∙ as I + forward Z ∙ I + Z ∙ I A gr it to a window of the MTA relay in levels(8). turns“a” the operator. analogrecorded voltage andequation current into The digitalsum valuesof with respectively, in modern numerical protective dnce components the See all p or reverse. V – V = Z ∙ I + Z ∙ I + Z ∙ I curre a magnitude and phase angle. After the A/D conversion, determins. ve the phase quantities is proportional to the zero- relays. The common process in these relays is zone ing the symmetrical components is accomplished by the mathV –angle V = Z and ∙ I +compare Z ∙I +Z ∙I to measure the impedance n sequence component. Conversely, the negativeematical capabilities of the modern microprocessor. As a result, of de numerical relays can derive easily themore positive-, negative-, r, sequence component has been difficult andand it to a window of the MTA ±90° as forward relay zero-sequence quantities. Numerical relays also provide the tools or reverse. nusingcostly to obtainconcePt with electromechanical relays Modern Protective relay a 94-year-old techniques: using a 94-year-o When the impedances are curre clos for the relay engineers to analyze sequence components recorded Protect electrical equiPMent to Protect electrical equiPMent due to the high equations (11), (12), and (13) can in oscillography files.cost of techniques required to filter negative-sequence components. in symmetrical component quant POLARIZING DIRECTIONAL OVERCURRENT RELAYS WITH SYMMETRICAL COMPONENTS in equations (14), (15), and (16). : using a 94-year-old concePt Modern Protective relay techniques: using a 94-year-o Modern numerical relays include a number of overcurrent relays (67) can use the phase relation- to Protect electrical equiPMent o ProtectDirectional electrical equiPMent advantages associated withtosimple, ship of voltageand and functions current to determine the direction a fault. To V –V =Z ∙I determine the direction to a fault, the angular relationship is the accurate calculation of symmetrical components only concern. Usually, the angle setting of the directional relay is V –V =Z ∙I C. from relay referredphase to as the quantities. maximum torqueThe angle numerical (MTA). The simple con- FIGURE 2: Zero-sequence current components used for V –V =Z ∙I turns analog voltage andrelays current levels cept of the detecting fault direction in these is that there is an ground fault protection ), approximate difference sequence into digital180° values withofa calculated magnitude andimpedances phase Z0, Z1, and Z2 for faults in the two directions from the relay locaangle. After the A/D conversion, determining Modern numerical protective r the symmetrical components is accomplished angular relationships of symmetric A

0A

B

0A

C

A

0A

1A A

2A 0A

1A A

2A 0A

1A

2A

B

0B

1B B

0B 2B

1B B

2B 0B

1B

2B

C

0C

1C C

0C 2C

1C C

2C0C

1C

2C

1A

2A

2

0A

1A

2A

2

1A

0A

A

1A

A

2A

A

B

1B

1a

2

B

C

0A

B

0A

C

0A

1A A

2

1a

2

2A 2C 2B

0A 2A

B

1A 0A

C

1A 0A

1A A

2

2

2a

2

1A 1C 1B

C

2A2B

A

2a

2

1A 1B

2

2B

2

A,F

AA

A

AB

B

AC

C

B,S

B,F

BA

A

BB

B

BC

C

C,S

C,F

CA

A

CB

B

CC

C

A,S

A,F

AA

A

AB

B

AC

C

B,S

B,F

BA

A

BB

B

BC

C

C,S

C,F

CA

A

CB

B

CC

C

2A

C

B

A,S

2A 0A

1a

2a

1A 1A 1C

1A 1C

2

2A 2A 2C

1A

2AB 1A

0A

2 2A

2AC1A

2 0A

2A

2A 2C

2A

1A

1A

2A

2

2A

1A

2

2A

0,S

0,F

0

0

1,S

1,F

1

1

2,S

2,F

2

2

0,S

0,F

0

0

1,S

1,F

1

1

2,S

2,F

2

2

A,S

A,F

AA

A

AB

B

AC

C

B,S

B,F

BA

A

BB

B

BC

C

C,S

C,F

CA

A

CB

B

CC

C

0,S

0,F

0

0

1,S

1,F

1

1

2,S

2,F

2

2

38

Protective Relay Handbook

A ground fault current can be considered a zerosequence current as it passes through the system to reach the location of the ground fault. (See Figure 2.) This zero-sequence current may be supplied from different sources and delivered to the particular zone involving ground fault. A zero-sequence current also can be caused by an imbalance in impedances and sources within the power system that has multiple groundings or it could be a triplin (3, 6, 9, 12, etc.) harmonic current. These currents would not necessarily involve a ground fault. In these circumstances, we would not want ground fault protective relays to cause false tripping. With numerical protective relays, protection against a phase-toground fault is less difficult. A ground fault protective relay must detect all phase-to-ground faults within its defined zone of protection. relay The well-known of detecting groundof faults The simply method measures the sum theis to useThe connection in Figure 4 is also known as flux a numerical relay that responds only to the zero-sequence current three-phase currents. See equation (17). Under summation. The conductor cables pass through of the system. FIGURE 4: Core-balance CT connection

balanced conditions, the sum equates to zero. the center hole of the core-balance current The relay simply measures the sum of the three-phase currents. Note that zero-sequence current is also Unbalanced theas A, The connection in Figure 4 flux is alsoin known flux B, summation. See equation (17). Under balanced conditions, theknown sum equates totransformer. The conductor cables pass through the center hole of aszero. residual current. Note that zero-sequence current is also known as residualand C conductors will induce current flow in the corecurrent transformer. Unbalanced flux in the A, B, and C current. the balance secondary of the CT. This produces conductors will induce current flow in the secondary of the CT. secondary current in thecurrent system known zero-as zerose3I0 = IA + IB + IC (17) This produces secondary in the systemasknown sequence quence current. current.

Ground fault protection elements should not be set more sensitive than the normal system unbalance. There are two types of ZERO-SEQUENCE VOLTAGE FOR GROUND Ground fault protection elements should not ZER O - S EQ UENCE current transformer connections to measure zerosequence current FAULT PROTECTION IN UNGROUNDED SYSTEM bein set moreassensitive than 3the normal VO LTA GE FO GR for O UND the system shown in Figure and Figure 4. system The available faultRcurrent a single-phaseto- ground fault unbalance. There are two types of current FAisULT P R OforTECTI O Nsystems. I N That makes it difficult very limited ungrounded to detectOzerosequence a ground fault protective relay transformer connections to measure zeroUNGR UND EDcurrent S Y in S TEM that responds to only zero-sequence current. In this case, sensitive sequence current in the system as shown in The available fault current for a single-phasevoltage relays can be used to detect ground fault where the fault Figure 3 and Figure 4. to-ground fault very limited for ungrounded currents are veryissmall.

systems. That makes it difficult to detect zeroA set of voltage transformers is wired with a grounded wye on sequence current a ground fault protective a primary side andin a broken delta on a secondary side. The 59N element of the relay is connected across the broken delta. relay that responds to only zero-sequence It is necessary In to connect a resistor acrossvoltage the broken deltacan to avoid fercurrent. this case, sensitive relays roresonance. See Figure 5. be used to detect ground fault where the fault currents are very small.

A set of voltage transformers is wired with a grounded wye on a primary side and a broken delta on a secondary side. The 59N element of the relay is connected across the broken FIGURE 3: Residual CT connection delta. It is necessary to connect a resistor across connection The setting of the ground fault protective relay in Figure 3 the broken delta to avoid ferroresonance. should be above the line maximum unbalance current to avoid nui- FIGURE 5. Zero-sequence voltage components used for Figurefault 5. protection in ungrounded 3-phase, 3-wire system sance tripping and to accommodate for initial asymmetrical motorSee ground starting currents.

The setting of the ground fault protective relay in Figure 3 should be above the line maximum unbalance current to avoid nuisance tripping

over a long period of time, this excessive heat conditions induces double-frequency currents in 40 seconds. It is common to use current wye/broken delta voltage condition will result in motor burn out and into the rotor, causing overheating. The reduce the life spanfilters. of the motor. continuous to unbalance currentancapability provide alarm offirst so that act as also zero-sequence TheUsually,unbalance overheating is caused by overcurrent conditions, a cylindrical-rotor synchronous generator corrective action can be taken before removing relay measures theRelay sumcan of the three-phase whichHandbook be overloads, locked-rotor conditions, is defined in IEEE/ANSI C50.13 and of a 39 Protective undervoltage, failure,balanced repetitive starts, orthe salient wired with a polefrom generator is defined in IEEE/ANSI motor service. voltages. See equation (18). phase Under unbalance. and a broken C50.12, as shown in Table 1. conditions, sum phase equates to transformers zero. When Grounded the wye/broken delta voltage act aas zero- TABLE 1: Continuous Unbalance Current Capability of 59N element an1.inverse-time overcurrent element Unbalance in the feeder phase voltages or motorThere isTable Continuous Unbalance Current Capability of Generators the broken ground relay will detect thecurrents Generators sequencefault filters.occurs, The relaythe measures the sum of the three-phase winding impedance causes unbalanced resistor across (51) that uses negative-sequence current Permissible as the I voltages. of Seethe equation (18). Under conditions, the sum presence secondary zero-sequence voltage to flow to thebalanced motor. Current unbalance is a Type of Generator rroresonance. (% of stator rating) equates to zero. When amajor ground fault occurs, theincrease relay will detect operating quantity. The curve characteristic factor in temperature in motors. (3V 0). Salient Pole Currentzero-sequence unbalance in a motor can be represented the presence of the secondary voltage (3V ). 0 shouldWith beconnected a straight line on log-log scales, amortisseur windings 10 by the presence of an excessive negative-sequence With non-connected 5 2 •amortisseur windings to I2 t = K and should be set to component in the motor current. The negative-corresponding Cylindrical Rotor 3V0 = VA + VB + VC sequence current (I2) from(18) unbalance causes cooled match Indirectly the motor running mode characteristic.108 Directly cooled (to 960 MVA) rotor heating and additional copper losses in the

ero-sequence Grounded age relays can here thetransformers fault

2

NEGATIVE-SEQUENCE CURRENT FORto MOTOR stator windings. It is necessary protect motors

Directly cooled (961 to 1200 MVA)

6

Directly cooled (1201 to 1500 MVA) 5 NAND E G ATIVE-S EQ UENC against excessive E negative-sequence overcurrent.For generators, protection is based on the same GENERATOR PROTECTION C UInRthe REN FO RCurrent TOR Amotor ND as where excessive heatingcurrents in unbalance (46) measurement inprinciple There are motors several of unbalanced threephase case T of motors, theMO primary cause of failure is exThere are several causes causes of unbalanced threenumerical protective relays is easy to implement. a generator. most common causeswill are system cessive heat. If sustainedPROT over a long period of time, this excessive phase currents inThe a generator. Thecurrents most common GE NERATOR EC TION from unbalanced stator result asymmetries, in Measuring algorithms includes the true negativee components causes are systemloads, asymmetries, unbalanced loads, faults, and open circuits. unbalanced unbalanced system heat condition will result in motor burn out and also reduce the In the case of motors, themeasurement primary and cause damage. In open addition, the negativesequence the of differencegenerator n ungrounded unbalanced system faults,ofand circuits. The current is the generator The highest source negative-sequence life span of the motor. Usually, overheating is caused by overcurbetween theheat. maximum minimum phasesequence highest source of negative-sequence motor failure is excessive If and sustained current producedcurrent byis unbalanced FEATURE phase-to-phase fault. rent conditions, which can be overloads, locked-rotor currents. The current unbalance conditions, measuring the generator phase-to-phase fault. 2 over a long period ofelements time, this heat have anstarts, I2excessive t or = Kphase characteristic thatconditions induces double-frequency currents undervoltage, phase failure, repetitive unbalance. The short time (unbalanced fault) negativesequence capability The short time (unbalanced The fault) negativemakes the time delay settings easier to apply condition will result inphase motor burn out winding and imintoof athe rotor, causing generator is defined in ANSIoverheating. C50.13 of as ashown in isTable 2 beUnbalance in the feeder voltages or motor sequence capability generator defined in than with the voltage element. The worst-case low. also reduce theunbalanced life span of the Usually, unbalance ANSI current pedance causes currents tomotor. flow to the motor. C50.13 ascapability shown in Table 2of below. unbalance occurs for an open phase Current at fullcontinuous load. In this case, theincrease negative-sequence current unbalance is aismajor factor temperature in motors. Curoverheating caused byinovercurrent conditions, a cylindrical-rotor synchronousCapability generator TABLE 2: 2.Short Negative-Sequence Capability of Table Short Time Time Negative-Sequence of Generators equates positive-sequence If K =of rent unbalance in a motor can to bethe represented by thecurrent. presence which can be overloads, locked-rotor in IEEE/ANSI C50.13 Kand of a 40, the time dial shouldconditions, be set to cause trippingis defined Type of Generator (permissible I ∙t) an excessive negative-sequence component in the motor current. Salient Polegenerator is defined in IEEE/ANSI 40 undervoltage, phase current failure,(I2repetitive starts,causes or rotor salient pole ) from unbalance The negativesequence Cylindrical rotor phase unbalance. as shown heating and additional copper losses in the stator windings. It C50.12, is Indirectly cooled in Table 1. 30 •

2 2

Directly cooled (0 – 800 MVA) Modern Protective relay techniques: to protect motors against excessive negative-sequence Directly cooled (801 – 1600 MVA) using a 94-year-old concePt to Protect electrical equiPMent overcurrent.in the feeder phase voltages or motor Unbalance

techniques: necessary al equiPMent

Currentimpedance unbalance (46) measurement in numerical protective winding causes unbalanced currents relays is easy to implement. Measuring algorithms includes to flow to the motor. Current unbalance is a the true negativesequence measurement and the difference between major factor in temperature increase in motors. the maximum and minimum phase currents. The current unbalCurrent unbalance in a motor ance measuring elements have an can I2 2 • be t =represented K characteristic that the time delay easiernegative-sequence to apply than with the voltage bymakes the presence of ansettings excessive element. Thein worst-case unbalance occurs an open phase at component the motor current. Thefornegativefull load. In this case, the negative-sequence current equates to the sequence current (I2) Iffrom unbalance causes positive-sequence current. K = 40, the time dial should be set to rotor the unbalcauseheating tripping and in 40additional seconds. It iscopper commonlosses to use in current ance to provide an It alarm first so that to corrective action can be taken stator windings. is necessary protect motors before removing motor from service. overcurrent. against excessivethenegative-sequence There is an inverse-time overcurrent element (51) that uses neg-

10

Electrica Master Managem Table 1. Continuous Unbalance Current Capability of G Modern numerical protective relays provide German Generators negative-sequence inverse-time protection using towards an I22 • relays t characteristic to match the Perm Modern numerical protective provide shaped negative-sequence at Webs Type of Generator short-time capability of theshaped generator.to(%years of of st inverse-time protection using an withstand I2 2 • t characteristic The relay time units can be set to protect utility, a match the short-time withstand ofofthe generator. The Salient Pole generatorscapability with K values 10 or less. An alarm over the relay units can be set to associated protectwindings generators withcanKprovide values Withtime connected amortisseur setting with these relays of prote for negative-sequence currents as ofWith 10 ornon-connected less. An alarm detection setting associated with these relays can amortisseur windings setting a small as 0.3 percent currents of a generator’s rating.asThe provide detection as small 0.3 Cylindrical Rotorfor negative-sequence trip pickup can be set at the continuous negativepercent of a generator’s rating. The trip pickup can be set at the Indirectly cooled sequence capability of the generator operating at continuous negativesequence capability output. Directly cooled (to full 960 MVA) of the generator operating

NETAWORLD • 61 10 – (0.00625)(MVA-800)

atDirectly full output. Normally, thetoprotection against negativesequence cooled (961 1200 Normally, the MVA) protection against negativecurrent is connected to trip the main generator breaker(s) and the Directly cooled (1201 to 1500 sequence current isMVA) connected to trip the main field breaker. An alarm should be provided the generator breaker(s)for andindicating the field when breaker. generator’s continuous capability exceeded. An alarm isshould be provided for indicating

when the generator’s continuous capability is ative-sequence current as the operating quantity. The curve Current unbalance (46) measurement in charThereSUMMARY are several causesexceeded. of unbalanced threeacteristic should be a straight line on log-log scales, corresponding numerical protective relays is easy to implement. numerical relays include amost number of advantages and phase Modern currents in a generator. The common SUM M ARY to I2 2 • t = K and should be set to match the motor running mode Measuring algorithms includes the true negativefunctions associated with the simple and accurate calculation Modern numerical relays include a number ofof causes are system asymmetries, unbalanced loads, characteristic. advantages and functions associated with the symmetrical components from phase quantities. Hardware sesequence measurement and the difference unbalanced system faults, and circuits. The For generators, protection is based on the same principle as mosimple andopen accurate calculation symmetrical quence filters in predecessor technologies have been of replaced with between maximum andunbalanced minimum components from phase quantities. Hardware tors wherethe excessive heating from statorphase currents will highest of negative-sequence current simplesource mathematical techniques that implement theis equations sequence filters in predecessor technologies currents. The current measuring curresult in generator damage. Inunbalance addition, the negativesequence for symmetrical components with the mathematical capabilities the generator phase-to-phase fault. have been replaced with simple mathematical 2 • rent produced by unbalanced conditions induces double-frequency elements have an I2 t = K characteristic that techniques that implement the In equations for of the microprocessor and the digitized quantities. particular, currents into the rotor, causing overheating. The continuous unbal- zero-sequence and negative-sequence symmetrical components withelements the mathematical based relay extend makes the time delay settings easier to apply capabilities of the microprocessor and the ance current capability of a cylindrical-rotor synchronous genera- protection options for finding fault direction and providing both digitized quantities. In particular, zero-sequence than with the voltage element. The worst-case tor is defined in IEEE/ANSI C50.13 and of a salient pole generator ground fault and motor/generator protection. based relay elements and negative-sequence unbalance forC50.12, an open phase at 1.full is defined inoccurs IEEE/ANSI as shown in Table extend protection options for finding fault direction and providing both ground fault and load. In this case, the negative-sequence current motor/generator protection. equates to the positive-sequence current. If K = 40, the time dial should be set to cause tripping

40

Suparat Pavavicharn is a Senior Application Engineer with Basler Electric Company. Pavavicharn is a 1997 graduate of Khon Kaen University, Thailand, with a Bachelor of Science Degree in Electrical Engineering. She also received a Master of Science in Sustainable Energy and Management from Flensburg University, Germany, in 2003 and is presently working towards a Masters in Business Administration at Webster University. Pavavicharn brings 14 years of experience in power station, electric utility, and industrial sectors. Her experience over the last eight years has focused on all facets of protection including design, fault studies, setting and testing, and on-site commissioning.

Protective Relay Handbook

41

Protective Relay Handbook

MULTI-FUNCTION NUMERICAL PROTECTION RELAYS USING SYMMETRICAL FEATURE COMPONENTS FOR MORE RELIABLE AND SECURE PROTECTION A grounding resistor is sometimes used since the transformer A grounding resistor is sometimes used since the transformer alone equates to alone2012 equates to reactance reactance grounding. grounding. Typically, Typically, the the zigzag zigzag NETA World, Spring Issue transformer is is sized sized such such that that its its impedance impedance is is 100 100 percent percent on on transformer by Steve Turner, Beckwith Electric Co., Inc. its own base. For the 10-second rating, 400 amps primary its own base. For the 10-second rating, 400 amps primary is is commonly applied applied in in the the United United States. States. commonly

Multi-function protection relays calculate and use symmetrical components to enhance their performance during system faults. Three examples are presented in this article: • Zero-sequence current elimination for transformer differential protection

A grounding resistor is sometimes used since the transformer alone equates to reactance grounding. Typically, the zigzag transformer is sized such that its impedance is 100 percent on its own base. For the 10-second rating, 400 amps primary is commonly applied in the United States.

• Positive-sequence voltage polarization for mho phase distance elements • Negative-sequence current detection to inhibit out-of-step blocking

fig fig

Figu Figu char char exter exter

ZIGZAG TRANSFORMER INSIDE TRANSFORMER DIFFERENTIAL ZONE A shunt-connected zigzag transformer provides a zero-sequence current sink forungrounded systems such as that shown in Figure 1 by establishing a connection fromground to neutral. Zerosequence current (I0) flows up through the neutral of the zigzag transformer during ground faults. Therefore, it is simple to apply non-directional overcurrent protection for the detection of single line-to-ground faults. If the system is left ungrounded, high voltage appears on the unfaulted phases during single line-to-ground faults and conventional ground overcurrent protection is useless. A zigzag transformer consists of three 1:1 ratio transformers. Each leg of the zigzag transformer consists of two windings that are 120 degrees out of phase. Windings are wound around the core such that zero-sequence current flows through the bank when there is system unbalance (i.e., ground fault). Only exciting current flows through a zigzag transformer during balanced system conditions. The grounding transformer appears as the leakage reactance of the core when a ground fault occurs and zero-sequence current flows splitting evenly into the three phases.

figUre figUre 2: 2: Ungrounded Ungrounded System System with with Zigzag Zigzag Transformer Transformer for Ground Current for Ground Current FIGURE 2: Ungrounded System with Zigzag Transformer

for Ground Current If If the the zigzag zigzag transformer transformer is is located located inside inside the the zone zone of of

transformer for deltatransformer differential protection,such aszone forofthe the deltaIf the zigzagdifferential transformer isprotection,such located inside theas transformconnected windings shown in Figure 2, then the zeroconnected shownas in 2, then the zeroer differentialwindings protection,such for Figure the deltaconnected windings sequence current contribution during external ground faults sequence current2,contribution during external ground faults shown in Figure then the zero-sequence current contribution must be be eliminated orfaults else must misoperation can occur. Here during external groundor be eliminatedcan or else a misopmust eliminated else aa misoperation occur. Here is one method in which numerical transformer protection eration occur.inHere is one method in which numerical transis one can method which numerical transformer protection relays can can reliablyrelays remove the ground current. former protection canthe reliably remove the ground current. relays reliably remove ground current. = IIBB = = IIC C IIAA = I   I 00 IIAA = = TAP TAP

  II 00 IIBB = = TAP TAP

I IIC =  I 00 C = TAP TAP

The Thecurrents currentsshown shownare aretaken takendirectly directlyfrom fromthe theCT CTsecondary secondary The currents shown are taken directly from the CT secondary and have been divided by the tap setting for the delta winding and to andhave have been beendivided dividedby bythe thetap tapsetting settingfor forthe thedelta deltawinding winding to convert them into per unit. If zero-sequence current convert them into per unit. If zero-sequence current elimination to convert them into per unit. If zero-sequence currentis elimination is (see Figure as then selected (see Figure 3 as an theexample), relay calculates the elimination is selected selected (seeexample), Figure 33then as an an example), then the the ground current asthe follows: relay calculates calculates the ground current current as as follows: follows: relay ground IIG = IA + + IIBB + + IIC G = IA C I  3 I  3 0 0 IIG = G = TAP TAP ’ are the internally-compensated currents: IIAA’, ’, IIBB’’ and and IIC C’ are the internally-compensated currents:

FIGURE 1: Zigzag Transformer Three-Line Diagram

II G IIAA’’ = = IIAA + + G 3 3

II G

II G

II G IIBB’’ = = IIBB + + G 3 3

II G IIC ’ = IC + + G C’ = I C 3 3

fig fig Char Char

d d is is P Po o v vo o Dist Dist trans trans pola pola class class

V Voo Vpp V

Whe Whe xx = = ZZ11 IIFF = = V VFF V V11

relay calculates the ground current as follows:

A-Phaseasaswell. well.The Themho mhophase phasedistance distanceelement elementmeasures measuresthe the transfor transfo A-Phase Where impedance up to the point of the fault (F) for that loop. I during AB impedance up to the orpoint of the fault up (F)tofor loop. IABfault (F) during IG = IA + IB + IC x = per unit reach per unit distance thethat point of the and arethe thefaultloop faultloopline current and faultvoltage voltage measured pre-fau =VAB positive-sequence replica impedance or line impedance pre-faul Z1LV AB and are current and fault measured  3I0 = relay fault current I42 G = Protective Relay Handbook that byIFthe the duringthe thefault. fault. that on o by relay during TAP VF = fault voltage balanc balance V1 = prefault positive-sequence memory voltage length :Zero-Sequence Zero-Sequence Current Elimination length and IC’ Elimination are the internally-compensated currents: IA’, IB’ Current short ee short I G differential IG IG hows theI ’transformer transformer differential operating ows the operating alsolea lea also I B’ = I B + I C’ = I C + A = IA + . Point A is the filtered operating point for an 3 3 3 Point A is the filtered operating point for an theang ang mer Figure 5 shows the A-Phase-to-B-Phase loop measuremen the ndfault faultand andPoint PointBBisisunfiltered. unfiltered. nd zag for a phase mho distance element. Note that there a is equa is equal I I IA’ = G - G = 0 I B’ = 0 I C’ = 0 corresponding loops for B-Phase-to-C-Phase and C-Phaseto on Figure Figure 3 3 y is A-Phase as well. The mho phase distance element measures th memor memor impedance up to the point of the fault (F) for that loop. IA • Gr • Gre and VAB are the faultloop current and fault voltage measure th the Multi-Function nuMerical Protection relays syMMetrical coMPonents by the relayusing during the fault. 32 • SPRING 2012 figUre 5: Phase Phase A-to-Phase Fault Loop Protection figUre BBBFault FIGURE 5: 5: A-to-Phase ForA-to-Phase More reliable andLoop secure • Re • Rel • Sec • Sec IAxZ xZ1L1L-I-IBBxZ xZ1L1L AB==IA figUre 3: Zero-Sequence Current Elimination VVAB • Sec • Sec IAIA== -I-IBB Figure 4 shows the transformer differential operating   Figure Figure characteristic. A is the filtered operating point for an 2IAAxZ xZ1L1L AB==2I VVAB FIGURE 3:Point Zero-Sequence Current Elimination distanc distanc external ground fault and Point B is unfiltered. 2IAA IAB== IAIA––IBIB==2I IAB obtain obtaine Figure 4 shows the transformer differential operating characterTheloop loopimpedance impedanceisiscalculated calculatedas asfollows: follows: curren The current istic. Point A is the filtered operating point for an external ground of the the a : Transformer Transformer Differential isOperating of VVABAB 22 IIAA  xx ZZ11LL faultDifferential and Point B Operating unfiltered. xZ1L1L AB== ZZAB == ==xZ weaker weaker IIABAB

cee PPrroT oTeecT cTiion on Pr Pree -faUlT faUlT qUeenc n cee mem memory ory ee--s s eeqU Po lariZaTiion on ee PolariZaT ments applied for the protection ofhigh-voltage high-voltage ments of applied for the protection of linesoften oftenuse usepositive-sequence positive-sequencevoltage voltageasasthe the ines tagnal or reference. reference. These These two two equations equations show show aa nal or rotocreate create mho4: distance element: ddltsto aamho distance element: figUre Transformer Differential Operating ere Characteristic FIGURE 4: Transformer Differential Operating VF F OperatingVoltage Voltage F--V on ((Operating )) Characteristic PolarizingVoltage Voltage)) ((Polarizing

d i sTance ProT ecTion Pre- faUlT DISTANCE PROTECTION POSITIVEPoror o si unit Tunit ivdistance e-seqUence mPRE-FAULT emory nit reach per distance upto tothe thepoint point ofthe thefault fault(F) (F) it reach per up of SEQUENCE MEMORY VOLTAGE POLARIZATION v olTage PolariZaT ion ve-sequence linereplica replica impedanceor orline line impedance e-sequence line impedance impedance current urrent Distance Distance elements applied the protection of high-voltage elements applied for theforprotection of high-voltage voltage oltage transmission transmission lines often use positive-sequence voltage as the polines often use positive-sequence voltage as the ultpositive-sequence positive-sequencememory memoryvoltage voltage ult larizing signal polarizing signal or or reference. reference. These two equations equations show show aa classic ary classic method to create a mho distance element: method to create a mho distance element: ng

ent he

Vop = xZ1LIF - VF Vpol = V1

(Operating Voltage) (Polarizing Voltage)

Where

22 IIAA

figUre 5: Phase A-to-Phase B Fault Loop

corresponding phase distance element isgenerated generated as Vmho =phase IAxZ TheThe corresponding mho distance element generated AB phase 1L -IBxZ 1L The corresponding mho distance element isis follows using two internally-calculated potentials: = -I I A B followsusing usingtwo twointernally-calculated internally-calculatedpotentials: potentials: asasfollows

 = 2I xZ1L Voltage V–AB A V = xZ I Operating Voltage)) op= xZ1L 1LIAB AB– AB Vop VVAB ((Operating = I – I = 2I I AB A B A VAB1 PolarizingVoltage Voltage)) pol==V AB1 VVpol ((Polarizing The loop impedance is calculated as follows: Where Where

==

Vpol Vop op--V pol V V 2  I A  x  Z 1L AB ZAB = = = xZ1L I AB

2  IA

A-Phase-to-B-Phase faultisisisinternal internal with with the mho AnAn A-Phase-to-B-Phase fault internal withrespect respecttoto to the An A-Phase-to-B-Phase fault respect the element when the absolute value of θ is 90 electrical degrees mho element when the absolute value of Ѳ is 90 electrical mho element when the absolute value of Ѳ is 90 electrical or The corresponding mho phase distance element is generate less (see 6).Figure degrees orFigure less(see (see Figure 6). degrees or less 6). as follows using two internally-calculated potentials: Vop = xZ1LIAB – VAB (Operating Voltage) Vpol = VAB1 (Polarizing Voltage) Where  = Vop - Vpol

An A-Phase-to-B-Phase fault is internal with respect to th figU mho element when the absolute value of Ѳ is 90 figUr electric Charac Charac figUre 6: Mho MhoDistance Distance figUre 6: degrees or less (see Figure 6).

x = per unit reach or per unit distance up to the point of the fault (F) ElementDirectional DirectionalDiagram Diagram Element Z1L = positive-sequence line replica impedance or line impedance FIGURE 6: Mho Distance Element Directional Diagram IF = fault current VF = fault voltage VAB1 is the voltage recorded prior to the fault (i.e., pre-fault) and V1 = prefault positive-sequence memory voltage ection relaysusing usingsyMMetrical syMMetricalcoMPonents coMPonents Multi-FunctionnuMerical nuMericalProtection Protectionrelays relaysusing usingsyMMetrical syMMetrical coMP ction relays Multi-Function is stored in a buffer. If secure there isProtection no reference signal (e.g., bolted coMPo nts: For More reliable and secure Protection ForMore Morereliable reliableand andsecure For More reliable andthe secure Protection Protection Figure 5 shows A-Phase-to-B-Phase loop measurement for For

+

IG 3

a phase mho distance element. Note that there are corresponding loops for B-Phase-to-C-Phase and C-Phaseto-A-Phase as well. The mho phase distance element measures the impedance up to the point of the fault (F) for that loop. IAB and VAB are the faultloop current and fault voltage measured by the relay during the fault.

ion nuMerical Protection relays using syMMetrical coMPonents For More reliable and secure Protection

three-phase fault at the secondary terminals of the voltage transformer), then the mho distance element can misoperate during an external fault. This is one of the main reasons for using prefault memorized voltage as the polarizing quantity. Note that figUre 6: only Mho Distance positive-sequence quantities are present duringElement balanced system Diagram Directional

Multi-Function nuMerical Protection relays using syMMe For More reliable and secure Protection

Protective Relay Handbook conditions such as pre-fault load flow. The length of the buffer to store the memory voltage should be short enough that a skew is not introduced in θ which can also lead to misoperation. Typically 30 cycles is sufficient. θ is the angle between the two voltage signals and whenever this is equal to 90°, it describes a point along a circle as shown in Figure 7. Some other advantages to using positive-sequence memory voltage as the reference signal are as follows: • Greater expansion of the mho characteristic along the resistive axis • Reliable operation for close-in zero voltage faults • Security for close-in reverse phase-to-phase faults • Security during single pole tripping Figure 7 shows both the static and expanded dynamic mho distance operating characteristics in the voltage plane which is obtained by multiplying the impedance diagram by the fault current. Expansion along the resistive axis is a direct function of the apparent source impedance behind the relay; i.e., the weaker the source, the greater the expansion.

FIGURE 7: Static and Expanded Mho Distance Operating Characteristics

NEGATIVE-SEQUENCE CURRENT DETECTION TO INHIBIT PROTECTION Certain protection functions are typically only intended to operate during balanced three-phase conditions: • Rate-of-change-of-frequency (81R) • Loss-of-field (40) • Out-of-step tripping|blocking (78) • Under-voltage load shedding

43 If negative-sequence current (I2) is detected, this is an indication that an unbalanced disturbance is in progress. Figure 8 shows the oscillographic record captured by a relay for the simulation of a large generator that slipped three poles; the event then evolved into a resistive ground fault. Figure 9 shows two large generating units at one plant that are interconnected one substation away via the transmission system. If either machine was to go unstable, then the desired sequence of events is to trip only the runaway generator while blocking the distance relays protecting the local transmission line terminals. This criterion prevents cascading outages from occurring and preserves the integrity of offsite power sources to the plant. For this particular case, the desired end result would be to unblock the distance protection so as to clear the ground fault as shown in Figure 9. Figure 10 shows the trajectory of an unstable swing that passes through both the generator out-of-step (OST) tripping characteristic and a transmission line relay Zone 1 operating characteristic. Note that the point O in Figure 10 corresponds to the generator voltage transformer terminals. Such a swing could operate both the line protection and the generator outof- step tripping function–thereby illustrating one case why power swing blocking is required for the transmission line protection. Phase distance protection can also operate during a stable swing–also shown in Figure 10.

FIGURE 8: Pole Slip Evolves into Single Line-to-Ground Fault Figure 11 is a simple logic diagram that illustrates how to use negative-sequence current detection (46) to unblock the distance protection (21) after it has been inhibited by power swing blocking logic (78_PSB).

44

Protective Relay Handbook required to detect when a swing evolves into a three-phase fault as shown in Figure 12B. If a balanced line fault occurs, then the measured impedance drops in between the blinders and remains there. Thus, the blinders can detect this condition and quickly unblock the phase distance protection.

FIGURE 9: Two Large Generating Units Interconnected via the Transmission Grid

FIGURE 12A: Power Swing Blocking Characteristic

FEATURE Another post-swing disturbance that is even harder to detect is if a three-phase fault were to occur on one of the transmission FIGURE 10: Unstable Swing passes through Zone 1 and OST lines terminated at the plant following the first pole slip since there is no negative-sequence current present. Figure 12A shows a typical power swing blocking (PSB) characteristic. If the impedance trajectory passes relatively slowly (e.g., three cycles or more) through the outer characteristic to the inner characteristic, then a power swing is detected and the phase FIGURE 11: Negative-Sequence Current Unblocking distance protection is blocked. If there is a fault, then the measured quickly that (e.g.,istwo cycles or less) jumpis Anotherimpedance post-swing will disturbance even harder to detect from the pre-fault location a point on the faulted power if a three-phase fault were totooccur on one of the transmission lines terminated the plant following the first pole slip since system. A pair ofatinner blinders is required to detect when a there is no negative-sequence current present. Figure 12A shows swing evolves into a three-phase fault as shown in Figure 12B. power (PSB) If the imIfa atypical balanced lineswing fault blocking occurs, then thecharacteristic. measured impedance pedance passes relatively (e.g., threeThus, cycles drops in trajectory between the blinders andslowly remains there. theor more) through the outer characteristic to the inner characteristic, blinders can detect this condition and quickly unblock the then adistance power swing is detected and the phase distance protection phase protection. is blocked. If there is a fault, then the measured impedance will quickly (e.g., two cycles or less) jump from the pre-fault location to a point on the faulted power system. A pair of inner blinders is

FIGURE 12B: Power Swing Blocking using Inner Blinder

Out-of-step tripping and blocking characteristics operate Out-of-step tripping and blocking characteristics operate on the on the measured positivesequence impedance since a power measured positivesequence impedance since a power swing is a swing is a balanced three-phase phenomenon. The positivebalanced three-phase phenomenon. The positivesequence impedsequence be calculated as follows: ance can beimpedance calculated can as follows: V1 = I1 = Z1 =

1 3 1 3 V1

(Va + aVb + a2Vc) (Ia + aIb + a2Ic)

I1

Where a = 1 120 a2 = 1 240

con cl U s i on s This article presented several examples that illustrate how multi-function protection relays calculate and use symmetrical

Protective Relay Handbook CONCLUSIONS This article presented several examples that illustrate how multifunction protection relays calculate and use symmetrical components to enhance their performance during system faults. The use of symmetrical component quantities help to provide protection that is more reliable and secure. Steve Turner is a Senior Applications Engineer at Beckwith Electric Company. His previous experience includes working as an application engineer with GEC Alstom, an application engineer in the international market for SEL, focusing on transmission line protection applications. Steve worked for Progress Energy, where he developed a patent for double-ended fault location on transmission lines. Steve has both a BSEE and MSEE 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.

45

SERIES II

Equipment Rental

Published by NETA - The InterNational Electrical Testing Association

T 972.317.0479

|

www.intellirentco.com

|

contact us at [email protected]

ANDBOOK

VOLUME 3

Test

VOLUME 3

ROTECTIVE RELAY

PROTECTIVE RELAY HANDBOOK

the test equipment answer

SERIES II

Published By

Sponsored by Intellirent

46

Protective Relay Handbook

NEWER SOLID-STATE RELAYS OFFER ENHANCED FLEXIBILITY FOR SCADA SOLUTIONS IN THE MUNICIPAL ENVIRONMENT NETA World, Spring 2012 Issue by Lynn Hamrick and Owen Wyatt, Shermco Industries Shermco Industries recently completed a project that upgraded multiple generator control systems and main and feeder breaker control relays as well as provided an upgraded Supervisory Control and Data Acquisition (SCADA) system for an electric municipal utility. To meet customer requirements, the system had to be capable of communicating with and controlling several different protective devices while retaining the potential to expand in the future. In addition to communicating with various protective devices for data input, the SCADA system also had to be user friendly with control being accomplished through a simple touch-screen monitor.

SYSTEM DESCRIPTION The distribution system for this electric municipal utility consists of one main 15 kV distribution bus fed by a 69 kV to 15 kV transformer through a main breaker. The main bus is also fed individually by multiple generator sets, each with separate generator controls and a generator breaker. Feeder breakers are also tied to the bus for distributing electricity to the town. The two buses then distribute power to the community via 15 kV feeders. Adding complexity to the system is the recent addition of a single wind turbine to one of the distribution feeders. For this project, the utility required the capability of automating the 15 kV main and feeder breakers, as well as the various generators, through the SCADA system while using the SCADA system as a monitoring system for their generation capability.

COMMUNICATIONS DESCRIPTION The overall system architecture consists of a variety of SEL relays that control and monitor the 15 kV class breakers. Additionally, a combination of SEL relays and Woodward generator controls are provided for the generators including the wind turbine. To facilitate communication with all the devices, an Ethernet switch and an SEL Real-Time Automation Controller (RTAC) were installed in a star pattern (see Figure 1) for the system communication. By configuring the system in this star pattern, each relay has its own channel to the system communications controller as opposed to a multidrop network where each node must wait in turn to send data. Utilizing the RTAC with IEC 61850 protocol, each SEL relay can broadcast information to the entire SCADA system, thus enhancing data access throughput and speeding up response times.

Figure 1: Typical System Communication Diagram The SEL RTAC provides a real-time operating system with the functionality of sophisticated communication and data handling required for advanced power system integration projects. The RTAC features secure communications, advanced data concentration, high-speed logic processing, flexible engineering access, and protocol conversion capabilities between multiple built-in client/server protocols. The RTAC also gives integrators the necessary tools to easily integrate and concentrate information from the wide variety of microprocessor-based devices found in today’s substations. Breaker protection and control is provided using the SEL-451 relay for the main breaker and SEL-751A relays for the feeder breakers. The SEL-451 relay has capabilities to monitor power, including thermal or rolling interval demand, as well as peak demand on positive-, negative-, and zero-sequence current. It also provides sufficient programming capabilities to eliminate the need for a separate programmable logic controller (PLC) to control the various operating scenarios associated with the generation system. The SEL-751A relays provide complete feeder protection with overcurrent, overvoltage, undervoltage, and frequency elements. Both relays also accommodate Ethernet-based communication with IEC 61850 communication protocol for the SCADA system. The SEL-451 accommodates hard-wired digital and analog inputs to communicate with the Woodward LS-4 device.

47

Protective Relay Handbook Generator protection and control is provided using a combination of SEL-700G relays and Woodward’s GCP-30 series of generator controllers. The SEL-700G provides a complete protection and synchronization solution for synchronous generators. They also accommodate Ethernet-based communication with IEC 61850 communication protocol for the SCADA system. The SEL700G also accommodates hard-wired digital and analog inputs to communicate with the Woodward generator controllers. For coordinated generator operation and control, the Woodward LS-4 was utilized. The LS-4 is a breaker control and protection module that enables the user to control, synchronize, and protect the main bus in multiple generator applications. It accommodates an automatic adjustment in frequency, voltage, and load for multiple GCP-30 series generator controllers in a networked application using CANBus communication. Woodward’s GCP-30 Series generator controllers coordinate information with the engine controllers and provide load management features including automatic base loading/peak shaving, import/export control, and emergency power/backup power generation.

communication protocol and the associated relay initiates the operation when the protective features, such as synch-check, will allow. This utility chose to also provide automated synch-check for their generation breakers; therefore, a permissive-to-close bit was developed within the generator breaker relays to ensure that the relays will not initiate a close out-of-synchronization or into an existing fault. The SCADA system is a very effective way to operate devices without having personnel directly next to the device while it is operating. This eliminates the need for a remote operating panel.

HUMAN MACHINE INTERFACE (HMI) Operator interface and control is provided either through the front panel of each device or through a human machine interface (HMI) that consists of a PC-based workstation. The workstation also interfaces and communicates with the SCADA system via Ethernet connection. The HMI package that was implemented was the Wonderware InTouch software system. Utilizing a tool inside the Wonder-Ware InTouch software, an electrical historian is integrated into the SCADA system for each feeder and main interconnection point that records the amperes, volts, kVA, kW and kvar. A method of manipulating the historian chart has been developed that allows the user to zoom in and out of specific sections of time, allowing the characteristics of each feeder to be analyzed over minutes, days, and even weeks. As part of the control features of the SCADA system, the ability to operate the breakers and circuit generators is also included on the individual breaker screens. After selecting a distribution system device and requesting a device operation to trip or close the breaker, the SCADA system queries the user to go through a verification process prior to actually operating the device to mitigate accidental operations. Once verified that the operation is intended, the SCADA master then sends a permissive command using IEC 61850

Another feature added to the system utilized the alarming capability included within the SEL relays themselves. When an alarm condition occurs, the SCADA system flags the alarm and alerts the utility’s personnel of the situation. By looking at the main one-line screen of the SCADA system, the utility’s personnel can quickly identify the specific feeder and relay that indicated the alarm condition. As an example, the SCADA alarms are triggered in the event of a breaker tripping due to any one of the protective features. With this alarming feature, the utility is made aware of any breaker operations that have occurred while its personnel were not present at the main substations. Using available remote desktop applications, the system can be interrogated and operated remotely through a secure internet connection from a wireless laptop computer. Due to the enhanced capabilities of today’s smart phones, the SCADA system can also be interrogated and operated remotely via cell phone with full function capabilities.

CONCLUSIONS Technological advances in microprocessor-based protective relays and generator controllers have resulted in enhanced flexibility for implementing SCADA systems for utilities. A SCADA system allows the utility’s personnel to quickly react to transient situations. The system also assists personnel in performing their daily activities. With the protective relays that have the capability to communicate with other devices, data can easily be gathered and analyzed in order to mitigate or respond to problems within the distribution system. Utility personnel can oversee the entire electrical grid for a municipality remotely using a laptop or a smartphone.

48

Lynn Hamrick brings over 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. Lynn is a Professional Engineer, Certified Energy Manager and has a BS in Nuclear Engineering from the University of Tennessee. Owen Wyatt is a Level 2 NETACertified Test Technician and is a licensed professional engineer in the State of Iowa. Owen has experience in performing design activities associated with electrical substations, protective relay systems, SCADA systems, and electrical infrastructure systems in accordance with NEC requirements. Owen has also performed numerous power system studies to include fault current, protective device coordination and arc flash analysis. Additionally, he is experienced in commissioning electrical systems in accordance with NETA specifications. These commissioning activities include relay testing, medium-voltage switchgear testing, and associated control system testing to NETA specifications.

Protective Relay Handbook

49

Protective Relay Handbook

RELAY MAINTENANCE HAS CHANGED, HASN’T IT? NETA World, Spring 2012 Issue by Kerry Heid, Magna Electric Corp. In the area of protective relay maintenance, it is well understood that electromechanical relays require servicing to remain within expected pickup and operating specifications. Although electromechanical relays have protected electrical systems for many years, the physical integrity of relays can deteriorate over time. The required frequency of relay calibration and maintenance depends on the type of environment to which the protection is subjected. In harsher environments, the induction disc may need to be cleaned more often so as not to impede the electromechanical action of the magnet on the disc and affect the operation of the relay during a fault.

routine relay testing is required for the purposes of validating reliability, possible liability, and risk assessment evaluations for insurance purposes. The condition of the output contacts of a solidstate relay cannot necessarily be assessed by the relay’s self-checking feature. The self-check programming within a relay looks at internal PCB trace voltages, processor chip checks, etc. These error checks do not analyze the state of a damaged output contact that could either be welded closed from a previous dc arc or a permanently open contact due to damage to the relay. Obviously these types of hardware failures can severely compromise the integrity of a protection system, and verification of correct operation of the outputs and inputs of a solidstate relay is well warranted. Although bench testing of a relay can prove that the protection elements are operating according to manufacturer’s specifications, it is extremely important to perform functionality testing in the field before energizing. Additional testing of relay communications and custom designed control logic can reveal deficiencies in the desired protection scheme. A proactive approach would be to perform testing on the relay to definitively know that all systems are functioning correctly. This is in contrast to assuming that all relay protection systems are operating perfectly and possibly being subjected to a rare relay failure that could remain unnoticed until after a catastrophic fault that was not cleared by the same failed protection relay.

Photo 1: An example of a 50/51 electromechanical relay. In years past, it was common to calibrate relays and their various components. This meant adjusting springs, cleaning contacts, and adjusting magnets to ensure the relay operated as designed. This work is still required on existing systems where older, vintage equipment is in service. With the advent of solid state relays, one might question the value in performing maintenance testing of a protective relay that does not require any form of calibration. Although the manuals for relays from various manufacturers state that specific routine tests are not required, the operation standards for facilities may require regular testing. Most relay manufacturers have various self-testing functions that report any software issues within the relay. As such,

Photo 2: Remember the SR-51? A fabulous machine set up to test a variety of electrical protection components; a bit of a blast from the past for us older techs. One thing is for sure, relay protection system maintenance is performed considerably differently and more efficiently than in years past. Digital technology has brought about an entirely new

50 way of performing maintenance and in some cases a different philosophy as well. One of the major challenges is to remove multifunction relays from service. Single phase or individual functional relays of electromechanical style can be safely removed with the power system on line. This is not necessarily the case with multifunction relays as every function is being defeated with the relay out of service. Even with the advent of new technology, the importance of performing protection system maintenance has not changed. Asset management, system reliability, and personnel safety all hinge on the protection scheme operating according to the coordination study requirements. During power system faults, incident energy is in direct proportion to the amount of time the system takes to operate. Incident energy values are determined using an arc-flash hazard analysis and are based on the equipment working according to the time current characteristics. These TCCs are based on an operating value when the equipment is new from the factory. As time goes on, the maintenance of the protective devices becomes very critical to ensure the operating times found in the study match the times in the field. Service-aged equipment has been found to be unreliable and in some cases even inoperable which creates an obvious variance from the expected operation.

CONCLUSION Relay protection maintenance is critical to ensuring that major equipment damage and injury to personnel are not encountered. Maintenance also drives reliability. The frequency and type of relay maintenance depends on a number of factors including criticality, environment, and type of relay system. Kerry Heid is the President of Magna Electric Corporation, a Canadian based electrical projects group providing NETA certified testing and related products and solutions for electrical power distribution systems. Kerry is a past President of NETA and has been serving on its board of directors since 2002. Kerry is chair of NETA’s training committee and its marketing committee. Kerry was awarded NETA’s 2010 Outstanding Achievement Award for his contributions to the association and is a NETA senior certified test technician level IV. Kerry is the chair of CSA Z463 Technical committee on Maintenance of Electrical Systems. He is also a member of the executive on the CSA Z462 technical committee for Workplace Electrical Safety in Canada and is chair of working group 6 on safety related maintenance requirements as well as a member of the NFPA 70E – CSA Z462harmonization working group.

Protective Relay Handbook

51

Protective Relay Handbook

INDUSTRY ADVISORY – NERC North American Electric Reliability Corporation Reducing Human Performance Errors By The Use Of Configuration Control Practices

RELAY SAFE WORK PRACTICES NETA World, Spring 2012 Issue by Scott A. Blizard, American Electrical Testing Co. Inc. While preparing an outline and gathering research for an article for the spring addition of World I received an email from one of our senior relay technician at AETCO. In the email was an attached Industry Advisory from NERC (North American Electric Reliability Corporation) titled “Reducing Human Performance Errors by use of Configuration Control Practices” at first I thought this advisory would be just another research document for the article. Upon further deliberation I felt the real life examples used in this advisory and the control practices recommended for mitigation of human error not only apply to Bulk Power Systems but are good tools to be applied to all facilities within our industry when Acceptance and Maintenance Testing of Relays and protection systems employed on Transmission, Generation and Distribution system industry wide. Instead of paraphrasing the advisory I felt this advisory should be shared in its entirety with the NETA community.

ADVISORY Initial Distribution: November 08, 2011 NERC and the Regional Entities have observed inadequate configuration control procedures being employed during Protection System construction or maintenance activities. Entities can further reduce the bulk power system’s (BPS) exposure to these reliability risks by considering these examples and suggested barriers and if warranted, augmenting their existing configuration control practices during construction and maintenance activities. This alert applies only to non-cyber assets. • Primary Interest Groups: • System Operators • System Operators – System Protection • System Operations—Transmission Engineering • Generation Engineering • Transmission Planning While the vast majority of Protection System construction and maintenance activities take place without negatively impacting the BPS, NERC and the Regional Entities are aware of situations where entities inadequately employed configuration control practices, resulting in unnecessary BPS equipment outages. The impact of these situations highlights the need for improvement in con-

figuration control procedures during Protection System construction and maintenance. Effective configuration control procedures include the evaluation, approval, and management of changes to an established equipment configuration. By developing and implementing proper configuration control, entities can reduce exposure to the inherent risk of human performance errors that occur during the maintenance and testing of Protection Systems. This document does not intend to prescribe or define all aspects of a configuration control program. Instead, it is intended to highlight a few key elements of a configuration control program that, if properly implemented, could have prevented these incidents. The goal is to improve awareness of common industry practices that, if employed, can help reduce the risks associated with the construction and maintenance of Protection Systems. Below are a few real-world examples of incidents that emphasize the need for better configuration control procedures during Protection System construction and maintenance. Each of these examples demonstrates the risk to BPS reliability when adequate configuration control procedures are not observed.

EXAMPLE 1 A relay technician performing scheduled maintenance on a protective relay system established the proper clearance and isolation procedures to perform the work. These procedures included opening several test switches that would provide an electrical barrier between the isolated equipment and any in-service equipment. After completion of the work, the technician began restoring the test switches to the closed position; however, he overlooked one of the switches in the process, leaving that test switch open. The open switch happened to block the only trip signal to one of the circuit breakers. The technician released his clearance on the equipment and exited the substation. Sometime later, a fault occurred on the BPS and the open test switch prevented a trip signal from tripping the circuit breaker and from initiating the breaker failure scheme. Because the circuit breaker did not trip, the fault continued to be fed through the closed breaker until it was cleared by remote, timedelayed backup relaying. The result was an undesirable increase in the scope of the BPS equipment outage.

EXAMPLE 2 During a substation project, the construction team failed to use the latest version of a construction document to complete the in-

52 stallation of a protective relay system. The most recent version of the document had incorporated a configuration change to the CT ratio for the protective relays. Because the team used outdated documentation, the incorrect CT ratio was configured for the relaying. During commissioning, the team failed to detect the error, since their testing reference was to the outdated documents. The Protection System equipment was placed into service with the wrong CT ratio and then sometime later tripped improperly during a system disturbance.

EXAMPLE 3 A relay technician is performing a preventive maintenance activity on a transmission line protective relay and makes a temporary setting change in order to perform a calibration check. Upon completion of the work, the technician fails to restore the temporary setting to its original value. The equipment was inadvertently placed back in service with the temporary setting installed. The incorrect setting did not immediately produce an improper response; however, weeks later, the relay operated incorrectly for a fault on an adjacent transmission line. The improper line trip resulted in the outage of more BPS equipment than was necessary to clear the fault.

EXAMPLE 4 A relay technician is working inside a transmission line relay panel, with the necessary work clearance and equipment isolation already established. The technician discovers a need for some additional documentation and steps out of the relay panel and walks over to a nearby file cabinet. Upon his return to the relay panel, the technician is distracted and inadvertently enters a different but identical panel with relaying protecting a BPS element that is in service. Unaware that he has entered the wrong panel, the technician resumes working and eventually crosses two wires that sends a transfer trip signal to a remote substation, tripping an in-service 345Kv transmission line.

EXAMPLE 5 A technician accidentally opens the wrong current shorting switch for one contribution to a differential relay protecting an inservice transformer, causing the transformer to trip. The above cases are examples of human performance errors that may have been prevented had adequate barriers and configuration control been applied. Below are examples of some configuration control practices that are being applied in the maintenance and testing of protection systems. Employing these or similar practices can help entities reduce the risks of human performance errors. • Maintenance Alteration Log (MAL) – A record of all manipulations of equipment during a construction or maintenance activity. This document requires the owner to initial each manipulation once when it is performed, and again when the item is restored to its normal state. Proper use of a MAL could have

Protective Relay Handbook prevented the human error incidents in Examples 1 and 3 above. • Isolation Card – A laminated plastic card placed by technicians on the physical equipment at points of isolation during maintenance or testing activities. Each technician has a personalized set of numbered isolation cards. Individual cards are placed on the physical equipment at points of isolation (e.g. test switch, control switch, or control panel) and often in a oneto-one association with entries on the MAL. After the technician has completed the work, and all items on the MAL have been restored to normal, the full set of isolation cards should have been collected. If cards are missing, the technician works to resolve the discrepancy before releasing his clearance on the equipment. By employing practices that include proper use of a MAL and Isolation Cards, entities can reduce the risk of the human performance incidents such as in Examples 1 and 3. • Barriers – Colored electrical tape or rubber blankets are examples of soft barriers used to cover or protect exposed, energized components to prevent undesired electrical connections during maintenance. A device used to deter the operation of a control switch during a maintenance activity is an example of a rigid barrier. Soft barriers, such as safety tape, can be used as a visual barrier and placed across the openings of in-service equipment panels during maintenance to help prevent personnel from inadvertently entering these panels during a maintenance activity. Use of visual barriers could have been used to help prevent the technician from inadvertently entering an in-service relay panel as in Example 4. • Flagging – Signage, safety tape, or any device used to attract the attention of personnel. Flagging can be used to identify equipment that is within the technician’s zone of protection or to identify equipment that is outside the zone of protection. Flagging could have been used to help attract the attention of the technician prior to his entering the wrong relay panel, as in Example 4. • Controls for distributing project documentation – Revised documentation should be distributed to personnel responsible for the construction, installation and testing, as well as those affected by the change. Old documents should be removed and filed or discarded, as appropriate. After documents have been approved, they should be available at all locations for which they are designated, used, or otherwise necessary, and all obsolete documents should be promptly removed from all points of use to prevent unintended use. Some entities apply such controls by establishing a single source of record for protection information. Proper document distribution controls, including timely distribution of updated documentation and destruction of outdated documentation, could have prevented the incident in Example 2. Equipment Isolation List – A detailed list of equipment •  isolation points used to electrically isolate the equipment under test during a maintenance or construction activity. Examples of items that would appear on an equipment isolation list are individual test switch poles, control switch positions, circuit breakers, etc. A technician should develop an equipment

53

Protective Relay Handbook isolation list and have a peer check it prior to starting the job. • Peer Review/Peer Check – The peer check is an independent review, by qualified personnel, to validate the technicians’ equipment isolation list. The peer check should be provided by someone other than the technician performing the work or by members of a team that peer check each other’s work. Peer review may be effectively used in conjunction with other practices, such as when relay settings have been modified in the field for testing or installation purposes by downloading or documenting the setting left on the relay and having an independent reviewer compare the setting with the office record. • Self Check – Self checking is the process of pausing to review one’s own actions prior to executing error-likely tasks. It is a four-step mental process to prevent errors, particularly on critical tasks or an irreversible procedure or step. Using the acronym STAR: Stop and take the time to eliminate external distractions, focus on the task at hand with 100% undivided and focused attention. Think, verify that no critical conditions have changed, consider the impact of your immediate action and question anything that you are have uneasy feelings about or are uncertain. Act, without losing physical or visual contact with the device, remain poised and attentive to your actions. Lastly, Review, verify that you got only the specific results that you expected and wanted. By implementing self-checking skills, the technician could have avoided opening the incorrect test switch in Example 5. • Place-keeping – A physical marker, either temporary or permanent, that helps one keep his/her place when reviewing sequential lines or columns. Using a straight edge or consistent marking methods, one can mark sequential progress when executing long and detailed procedures. These methods are essential when interruptions or delays prevent fluid movement through a process. Consistent procedures in placekeeping allow smooth transitions and handoffs for events that involve multiple persons to interact on the same or related procedures. Detailed place-keeping also provides a historical record for procedures that occur over extended time periods. • Pre-job briefing – A pre-job briefing, also referred to as a tailgate or tailboard meeting, is helpful for providing clarity prior to a job start. These are usually carried out by the supervisor or more experienced personnel who understand details of the work and can point out the potential perils personnel may encounter during construction or maintenance. Some entities document the prejob briefing in writing and have the document signed by each employee or contractor present on the job site. Pre-job briefings may be appropriate on a daily basis or multiple times during the day depending on the complexity of the work being performed. The ES-ISAC estimates that the risk to BPS reliability from this vulnerability is HIGH, due to the daily exposure of the BPS to the adverse consequences of human performance errors during protection system maintenance and testing.

BACKGROUND: The analysis of BPS events frequently identifies human performance errors during protection system maintenance as a root cause or contributing cause of the event.

CONTACT: Earl Shockley Director of Reliability Risk Management Office: (404) 446-2570 [email protected] To report any incidents related to this alert, contact: ES-ISAC 24-hour hotline (609) 452-1422 [email protected]

CONCLUSION Prior to testing relays and protection systems, a pre job brief should be performed outlining not only the work to be performed, identify all hazards associated with the work, identify circuits that will be affected and identify the proper level of PPE required to be worn in accordance with NFPA 70E to perform the work. Test for the presence of current, ac voltage and dc voltages prior to servicing equipment. Exercise extreme caution when performing modifications, maintenance, and testing in current transformer secondary circuits. Current transformers act as constantcurrent sources to whatever load is applied on the secondary. This means that the voltage changes to provide the same current, no matter what the impedance is in the secondary circuit. When the secondary is open circuited the voltage becomes extremely large. This high voltage may destroy the insulation, causing a fault that can destroy the CT, damage other equipment, and be hazardous to personnel. Extreme care must be taken to ensure that a reasonable secondary burden is always present or that the CT secondary’s have been shorted to prevent high voltages when the primary is energized. Be safe; when in doubt, always err on the side of caution. Scott Blizard is the current Vice President-Chief Operations Officer and the former head of Safety for American Electrical Testing Co. Inc. Scott is a master electrician and a NETA level 4 test technician with over 30 years of experience in the electrical industry.

54

Protective Relay Handbook

SOLVING RELAY MISOPERATIONS WITH LINE PARAMETER MEASUREMENTS NETA World, Fall 2012 Issue Will Knapek, OMICRON

LINE IMPEDANCE TESTING Between 80-90 percent of all power system faults involve ground. Many protective relaying schemes depend on ground distance protection to accurately sense and locate ground faults on multiterminal subtransmission and transmission lines. In addition to the need for dependable ground fault detection, protective relaying must provide adequate selectivity to avoid ovetripping for faults outside of its zone of protection and other undesired consequences, such as undertripping or unintended automatic reclosing initiation. The problem has become more apparent due to recent major power system disturbances in North America such as the Northeast blackout of 2003. Correct application and setting of protective devices, particularly distance relays, have become subject to heavy scrutiny lately. Validation of accurate distance relay settings is now a major topic of discussion by electric power utilities as well as professional technical committees such as the IEEE Power Systems Relaying Committee. It becomes apparent very quickly that the accuracy of line parameter values may affect many people. Although ground distance relay design, charac-teristics, and implementations vary, some of the typical parameters required to set a ground dis-tance relay include the following: • Zone impedance reach and characteristic angle • Blinder positions, resistive reaches, and angles • Directional supervision limiting angle • Polarizing current (3I0, I2) • Supervising element (3I0) • Z0/Z1 (zero-sequence compensation) • Z0M/Z1 (zero-sequence mutual coupling compensation Relay manufacturers have di°erent methods of calculating zerosequence compensation, also known as the k factor, but generally it is deÿned as the ratio between the zero-sequence imped-ance Z0 and the positive-sequence impedance Z1 of a given transmission line. The k factor is used to correct the ground impedance calcula-tion so that the ground fault loop calculation can be simpliÿed and treated similarly to the phase-to-phase fault loop calculations performed in the protective device. Therefore, if the k factor is not accurate, fault reach (distance) will be calculated incorrectly. Transmission line impedances used for k factor are o˝en calculated

Figure 1: OMICRON CPC 100 +CP CU1 by line con-stants programs. Due to the large number of vari-ables required, line parameter calculations are prone to error, particularly in the zero-sequence impedance value of the line. For example, utili-ties often assume fixed soil resistivity values (10 Ωm, 100 Ωm, etc.) applied across their system models, even in cases where the transmission line may span types of soils different from those assumed in the line constants program. Due to the uncertainties related to soil resistivity and actual transmission tower grounding, the calculation of Z0 of a given line is more susceptible to error than its Z1. This is because the calculation of Z1 is independent of the ground path impedance. For parallel transmission lines, the accurate calculation of zero-sequence mutual impedance Z0M is also prone to the errors described above. Such errors in the estimation and calculation of line parameters will affect accuracy of settings used in transmission line protective devices, particularly in distance and overcurrent relays, causing them to either underreach or overreach, resulting in a misoperation. In order words, relay sensitivity to detect ground faults will be affected. Additionally, ZO and Zl are used as inputs by many digital relays to calculate the location from the line terminal to the fault. Accurate fault location data is needed by utility crews to promptly locate and remove foreign objects from the primary system, and repair damaged lines as quickly as possible. Moreover, short-circuit and coordination studies also depend on accurate modeling

Protective Relay Handbook data to enable the protection engineer to set relays correctly. The alternative to line parameter calculation is taking actual measurements on a given transmission line to accurately determine its impedances and k factor. Measuring the line impedance using the correct techniques, equipment, and safety precautions provides the opportunity to eliminate the uncertainties described above. In the past, line parameter measurement was considered prohibitive and costly as it required large, high-power equipment to overcome nominal frequency interferences, since off-nominal frequency injection was not possible. With modern digital technology and ingenious design, OMICRON has overcome these challenges with the CP CUI coupling unit, an extension to the CPC 100 (Figure 1). Will Knapek is an Application Engineer far OMICRON electronics Corp, USA. He holds a BS ftom East Carolina University and an AS ftom Western Kentucky University, both in Industrial Technology. He retired ftom the US Army as a Chief Tfdrrant Officer after 20 years of service, 15 of which were in the power field. Will Knapek has been active in the testing field since 1995 and is certified as a Senior NICET Technician and a farmer NETA Certified Test Technician,Level IV. Will is also a member of IEEE.

55

56

Protective Relay Handbook

AN INTRODUCTION TO END-TO-END TESTING NETA World, Winter 2012 Issue by Chris Werstiuk, Manta Test Systems Your first end-to-end test can seem to be a daunt-ing task, but the actual test procedure is not very complicated and can be performed more quickly and effectively than traditional relay test tech-niques; if everything works correctly. That last statement is the hard part because you are typically working with a team at a remote location which makes it difficult to determine whether the problem lies with the test plan, relay settings, test-set configuration, or operator error. This article will introduce you to end-to-end testing and answer many of the questions you might have. Providing protection for a transmission line is difficult because the typical transmission line is fed from multiple sources and can carry loads that vary significantly. Traditional protection schemes use an impedance relay on either side of the transmis-sion line that constantly monitors voltage and cur-rent to calculate impedance in real time. If a fault occurred on the transmission line, the measured

Figure 1: Typical Impedance Relay’s Zone of Protection

Figure 2: Typical Relay’s Primary and Backup Zones of Protection

impedance would be less than the calculated line impedance and the relays would operate to isolate the fault from the system. gnfortunately, the relays cannot be set at the exact line impedance because the typical protection-class current transformer has a 10 percent error factor and the calculations will make assumptions (conductor spacing, splices, conductor impedance, etc.) that could cause the re-lay protection to overreach and isolate the wrong transmission line, so most impedance relays are set at 75 to 90 percent of the transmission line impedance as shown in Figure 1. A time-delayed backup impedance element is often set to reach beyond the transmission line to protect for faults in that last 75 to100 percent of the protected line so that all faults will be isolated from the system eventually. This element will also provide backup protection for the adjacent transmission line as shown in Figure 2. Remember that the other relay is looking in the op-posite direction as shown in Figure 3.

57

Protective Relay Handbook

Figure 3: Typical Transmission Line Impedance Protection Including All Zones of Protection Every misoperation will cost the utility labor and lost revenue, so 75-90 percent protection is often not good enough, even though both sides overlap to provide a reasonably good protection scheme. Modern protection schemes apply a communication channel between the relays on either side of a transmission line that allows the relays to communicate with each other. The simplest scheme (not really, but easiest to understand) applies differential protection principles. Each relay measures the current entering or leaving the transmission line and shares its local current with the remote relay bidirectionally. If the current in does not match the current out, both relays will trip. These relays often have a backup scheme using traditional impedance protection that is only active if the relays are unable to communicate. The other communication schemes have many names (DUTT, PUTT, POTT, DCUB, etc.) and operating parameters, but they all perform the same basic function. Both relays monitor the real-time impedance and current direction. If both relays agree the fault is between them, both relays will trip as soon as possible depending on the communication medium and scheme. While it is possible to test each of the individual components of a communication scheme separately, many problems can only be detected when the entire scheme is tested as a whole. It is possible to test one side at a time which can give the tester a reasonable sense that the scheme will operate successfully on proven relay settings, but many problems with communication-assisted protection occur when the fault changes direction or by incorrectly defined communication delays which are inherent in the system. These problems can only be detected by properly applied end-toend testing or a review of an incorrect relay operation after a fault.

End-to-end testing was considered daunting a decade ago, but advances in relay testing technology and personal computers have reduced the complexity to a couple of extra steps for a reasonably experienced relay tester.

2. WHAT IS END-TO-END TESTING? End-to-end testing uses two or more test-sets at multiple locations to simulate a fault at each terminal of a transmission line simultaneously to evaluate the entire protective relay scheme as a whole. This test technique previously required specialized knowledge and equipment to perform, but modern test-sets make it a relatively simple task. Figure 4 represents an overview of the equipment and personnel required for a typical end-to-end test using a simple transmission line with two ends or, as they are sometimes called, nodes. It is possible to have a system with three or more nodes which simply adds another location to the test plan. The following components are necessary to perform a successful end-to-end test: 1. A relay test-set for each location with a minimum of: • three voltage channels • three current channels • at least one programmable output to simulate breaker status or other external signals • at least one programmable input to detect trip or breaker status signals • an internal GPS clock (Some test-sets allow for other time signal synchronizations such as IRIG) or an external GPS clock with output signal and an additional test-set start input

58

Protective Relay Handbook

Figure 4: Typical End-To-End Test Overview • waveform playback or fault state/state simulator with at least three states available. 2. Some test-sets require a computer to control the test-set playback or state functions. 3. A  computer and software to download and display event records obtained from the relay after each test. 4. At least one relay tester at each location with some form of communication between the two locations such as telephone or overnetwork communication. It is possible, but not recommended, for one person to perform all tests if the relay, relay test-sets, and communication systems have all been configured properly. 5. A setting file, waveform, or detailed description of the specific test scenarios. 6. An understanding of the relay protection scheme and what the expected result for each test should be.

7.The design engineer who created the settings and test plans standing by if any problems are detected that need correction.

3. HOW DOES IT WORK? Most system disturbances develop within one millisecond of their initiation and modern protective relays must be able to detect faults within this time frame to be effective. Practical experience has shown that two test-sets must start within 10 microseconds of each other to provide reliable results. This causes a problem for multiple relay testers at multiple locations because it is nearly impossible for them to press start within 10 microseconds of each other. The remote relay testers could use the power system to synchronize their test-sets, but this method could add up to one millisecond or 22° error to the test which is not within the ten microsecond tolerance required for consistent results. The GPS system time allows synchroni-zation within 1 microsecond which is within the maximum allowable time delay. A substation IRIG signal can also be used but synchronization errors can be as high as 10 microseconds.

Figure 5-1: Typical 3-Phase Comtrade Fault File for 1st breaker

Figure 5-2: Typical 3-Phase Comtrade Fault File for 2nd breaker

59

Protective Relay Handbook

Figure 6: Typical State Simulation Instructions for 1st Breaker (SOURCE BUS) and 2nd Breaker (LOAD BUS)

Figure 7: Typical End-to-End Test Scheme Once two test-sets have synchronized time sources, both testsets simultaneously apply fault simula-tions that are calculated to be similar to the signals that would occur if a real fault occurred. If the test-sets are properly synchronized, and the test plans are created and implemented correctly, and the re-lays are set correctly, and the correct auxiliary con-nections are made, and the communication scheme is working, then the test should be successful. Fault simulations can be supplied as waveform files (Figure 5) such as IEEE C37-111 COMTRADE files. This is typically the simplest method for everyone involved, as long as everything works correctly. Bowever, waveform files can be difficult to troubleshoot if problems occur. Fault simulations can also be supplied in a test-set proprietary format that can be loaded directly into the test-set or in a standard spreadsheet format (Figure 6) to be entered using the state simulation feature in the test-set. State simulations are easier to understand and troubleshoot but can be prone to conversion errors. It is also important to note that different test-set manufacturers and test-set models may be synchro-nized to the same time source and set to the same start time, but may not start outputting the test at the same moment. Different firmware revisions can also be problematic with some manufacturers. Always consult with the relay test-set manufacturers if two different models of test-sets will be used for end-to-end testing on one line to determine if a cor-

rection factor must be applied. Different models from the same manufacturer can produce different starting times without notice, and the correction factors should be verified at the same location, if possible, before performing any remote testing.

4. ON WHAT SCHEMES SHOULD I PERFORM END-TO-END TESTING End-to-end testing should be performed whenever it would be beneficial to test an entire protection scheme in real time to make sure that all equipment will operate correctly when required. This test technique need not be limited to transmission lines and can be applied any time you wish to test coordination between different devices. For example, a number of test-sets can be connected to the protective relays for all feeders in a system. A fault simulation can be played into all relays simultaneously to ensure that complex blocking schemes work as intended.

5. WHEN SHOULD I PERFORM END-TO-END TESTING? All new installations with remote communication between relays should be tested via end-to-end testing. This test technique can also be a useful and effective maintenance test, particularly if end-to-end testing is performed during commissioning that will provide expected results. There is no more effective way of proving the entire protection scheme than replaying the same number

60 of tests into the protection system and observing the same results. Performed correctly, using this test technique for maintenance tests can be more efficient as well.

6. HOW DO I PERFORM AN END-TO-END TEST? The relay testers at each end of the line should perform the following steps when performing an end-to-end test: 1. Obtain all of the test cases for all sides of the test procedure from the design engineer be-fore the scheduled test date. This step can be skipped for line differential relays if the test is to be performed by personnel who have a good understanding of the relay’s intended operation and test-set functions. It is possible to create test plans for impedance schemes, but they will be a poor substitute for real simula-tion files and may be too simple to truly test the entire scheme. A typical end-to-end test procedure will have 8 to 15 tests that are on either side of each impedance zone as shown in Figure 7. The test cases should have a combina-tion of fault types and phases. (For example: Test Case #1 = 3 Phase Fault, #2 = A-N fault, #3 = A-B fault, etc.) 2. Review all sides of each test case on a split screen and make sure the test plans make sense and that you understand what is supposed to happen. Most test plan files have a description such as “Test1=50%fromBRK1=Zone1Trip.” Some common problems to look for between all ends of a single test case include: • Are prefault times consistent? • Are prefault voltages nearly identical? • Are prefault current magnitudes nearly identical? • Are prefault current angles 180° apart? • Same fault times? • Same fault type? • Same faulted phases on current and voltage? • A  re fault current magnitudes in phase for line faults and 180° apart for external faults? • Any postfault enabled? 3. After arriving on site, determine the test location, setup your test-set, install yourGPS antenna outside the building with good access to the sky, and a pply gPS time as your test-set reference. (Or use other reference such as IRIG, if required) 4. Always remember that the relays under test communicate with each other, and your actions could cause an unintended trip on the other sides. Communicate with all ends under test. If all locations agree, isolate the circuit breaker and relay under test at all locations. 5. Connect the appropriate digital inputs and outputs between your test-set and protection scheme. I always recommend using the circuit breaker under test as part of the test, if possible, instead of simulating the breaker contacts. 6. Connect your test-set to replace current/potential transformer connections using the site’s three-line drawings.

Protective Relay Handbook 7. Prepare a metering test and communicate with remote testers. If they agree, apply a meter test on all sides and verify correct results. Make sure that A-phase from your test-set is A-phase in the relay and repeat for B- and C-phase. A three-phase balanced meter test will NOT prove this. 8. Communicate with all remote sites and determine which test plan will be used for the test. (Test Case #1 for example) 9. L  oad the selected test case into all test-sets. Every site should have a unique test to load. 10. P  lace all circuit breakers in the correct posi-tions or ensure circuit breaker contacts are properly simulated by the test-set. 11. C  ommunicate with all remote sites and select a start time. Apply the start time to the test-set. 12. The test should start automatically. 13. Review targets for correct operation and download all event records. Review the event records for correct operation or no operation, as required by the test procedure. Clear event records in the relay between tests to make sure you get the correct event files. 14. Repeat Steps 8-13 for all test cases. As you can see, the key to any end-to-end test procedure is correct preparation. Steps 1 and 2 of the test procedure are the hardest parts of any end-to-end test. If the design engineer has correctly specified the tests and their outcomes, and you have carefully reviewed the test cases, the actual test procedure usually runs very smoothly with enough practice. ghen you review the test results in the field, these two principles will apply to most communication schemes: 1. Faults inside the zone of protection (current at the same angle on both ends) will be isolated more quickly by both relays than they would without the communication scheme. 2. Connect A-phase voltage and current from both test sets into any phase of the relay. 3. Perform the end-to-end test procedure using the same test plan. 4. Review the event record waveform from the relay. The voltages and currents should be identical. 5. Repeat until you feel comfortable. Chris Werstiuk is an Electrical Tech-nologist, Journeyman Electrician, Professional Engineer and author of the upcoming book, “digital Relay test-ing: A Practical Guide from the Field.” He is also the founder of “RelayTesting. net”, an online resource for testing tech-nicians who need custom test leads, test sheets templates, step-by-step testing guides, or an online forum to exchange ideas and information.

61

Protective Relay Handbook

GPS TESTING, THE FUTURE OF TESTING NETA World, Winter 2012 Issue by William Knapek, OMICRON electronics With the introduction of multifunction relays, testing methods for these devices must be approached in a different fashion. Gone are the days when the need to verify the operating characteristics of a relay were the only tests performed.

tromechanical relays this was fairly straight forward, as the tests were applied to one relay and one element. Now the challenge is to be able to simulate conditions that operate an element without another element operating at the same time.

The characteristic of an element is no longer dependent on the mechanical operation of a rotating disk, bearings, drag magnets, and capacitors. The characteristic is derived from the execution of a mathematical formula determined by various settings, applied to variables that are the output of analog-to-digital converters modified by sequence filters and carried out by a microprocessor. This change in how the protection element works means a change in what is important to test. With the intelligent electronic devices (IEDs) monitoring the health of the power system instead of multiple, single-function, electro-mechanical relays, internal logic verification is as important as verifying the individual protection elements.

One of the tools available to the modern testing technician is the ability to simulate faults in two relays at two different locations that are synchronized by Global Positioning Satellites (GPS). With modern test sets, the capability is available to test the protection scheme as a system. Two or more locations can be set up to inject a simulated fault into the local relay with the values that would be seen by that relay during an actual fault. These signals are synchronized by the GPS signals and are coordinated to allow for a true system test.

Testing of the logic in an IED presents a plethora of challenges. It is now the test technician’s job to inject the proper voltages and currents to simulate various operating and fault scenarios and observe the elements’ action to the overall logic scheme. With elec-

THE GLOBAL POSITIONING SYSTEM The current GPS system consists of 31 satellites. Each satellite has a highly accurate atomic clock on board which is used to send a synchronized time signal to earth. Using the mathematical principle of four equations with four unknowns, a receiver must receive the time signal of at least four satellites to determine its position (longitude, latitude, and height) as well as accurate time.

Figure 1: Fault At 95% of Line Length

62

Protective Relay Handbook

The position can be determined to an accuracy of 66 feet and the time to an accuracy of 14 nanoseconds. Two types of GPS receivers are available. One is the navigation unit which is even available in your cell phone and the other is the satellite clock. The satellite clock has the ability to output a selection of timing signals which can be used to synchronize third party units with each other. To be able to use the time signal for synchroniza-tion purposes, a GPS clock is needed, which provides a number of timing signals. These signals are the IRIG-B, PPM, and a programmable pulse signal. The Inter-Range Instrumentation Group time code is commonly known as IRIG-B. The IRIG-B signal is one pulse per second. The PPM is a pulse per minute and of course the program-mable signal is programmable to your needs. The PPM and programmable signals can be used to synchronize test equipment at two or more loca-tions to the closest accuracy around the world. The GPS system is thus well suited for this type of test due to its availability all over the world and due to the accuracy of the timing signal. To synchronize a test set with a satellite clock, the PPM signal is used. This signal triggers each test set to start the testing sequence. Each test sequence will be injecting the currents and voltages at the same magnitudes and phase angles that the protective relay would see during the actual fault.

Figure 2: Fault At 5% of Line Length

TESTING TRIP SYSTEMS As modern relays often have complex logic schemes applied, the actual operation of the protection system must be verified. Testing the logic as a system will preclude misoperations of the protection system. This is most important in schemes that involve multiple relays, such as breaker-failure schemes, differential schemes, and communication-based schemes. A state sequencer routine can be set up on one test set to start on a GPS pulse, inject the ap-propriate analog signals, and then measure the response of an IED to the applied signals. A sec-ond test set is set up at a remote location to start on the exact same GPS pulse. It applies the ap-propriate analog signals to the remote relay with the values expected at that location based on the fault characteristics. Using a time signal view to measure the response time of the outputs from the relay, the system performance can be evaluated. These signals can confirm that the protection system performs as designed. Figure 1 is an example of a time signal view that can be used to verify a communication scheme. This test was for a permissive overreaching transfer trip cheme (POTT). This relay was injected with variables that equated to a fault at a location of 95 percent of the line length.

Protective Relay Handbook Figure 2 is a screen shot of the remote location set for a fault of five percent of the line length. As you can see, the time signal view shows that the system performs as intended. In the case of a bus differential system, several test sets can be set up to initiate a fault at the same time and measure the response of the 87B device. This is a much more effective test than just verify-ing the pickup and timing of a differential relay. It is possible to use different models of test sets to perform these tests. With the use of the GPS signal to start the test, which manufacturer’s test set you use is not important as long as it produces a quality signal. However it must be noted that not all test sets will process the GPS signal at the same speed. This could cause a variance in the timing of the injected signals. This variance can skew the test results. When using multivendor test sets, you must perform a few trials, preferably in the lab, to see the difference in the signal start times. When this is determined then an adjustment to the faster test set can be programmed to get all test sets to inject at the same time.

PMU TESTING Another application of GPS testing is to verify the correct operation of phasor measurement units (PMU) or syncrophasors. These are appearing in more and more protection systems throughout the world. In typical applications PMU’s are located at various points in the power system network and synchronized by a GPS signal. Synchrophasors measure voltages and currents at diverse locations on a power grid and can output accurately time-stamped voltage and current phasors. Because these phasors are truly synchronized, synchro-nized comparison of two quantities is possible, in real time. These comparisons can be used to assess system conditions. When testing PMU’s you must inject signals from various locations and retrieve the results for analysis. The timing of the injected signals must be exact or the results will not be a true representation of the power system condition.

CONCLUSION The advent of GPS has led to a new way to look at the traditional testing methods. New possibilities are available in the commissioning and maintenance of protection systems. Use of these tools allows us to go well beyond the verification of pickup/ dropout and curve verification of relays. GPS or end-to-end testing is the future of testing.

REFERENCES 1. Alexander Dier, Heinrich Metzler; GPS synconized tests at the Vorarlberger Illwerke AG; OMICRON User Conference, Berlin, November 1995 2. Global Positioning System; Wikipedia.com 3. Phasor Measurment Units; Wikipedia.com

63 William Knapek received a BS Degree in Industrial Technology from East Carolina University in 1994. In 1995 he retired from the US Army as a Chief Warrant Officer after 20 years of service. During his time with the Army Corps of Engineers, he held positions as a power plant instrumentation specialist, a writer/instructor for the Army Engineer School, and a facility engineer for a Special Operations compound. He has been active in the electrical testing industry since retiring in 1995. He worked for NETA companies in the Nashville, Tenessee, area until joining OMICRON electronics as an application engineer in April of 2008. He is currently the Secondary Engineering Service and Customer Support Manager for OMICRON electronics Corp, USA. He is certified as a Senior NICET Technician and a former NETA Level IV Test Technician. Will is a member of IEEE.

NETA Accredited Companies Valid as of January 1, 2014

For NETA Accredited Company List Updates Visit www.netaworld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

United StateS

Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com

8

Southwest Energy Systems, LLC 14 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Robert Sheppard

9

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

AlAbAmA 1

2

AMP Quality Energy Services, LLC 4220 West Schrimsher SW, Site W1 PO Box 526 Huntsville, AL 35804 (256) 513-8255 [email protected] Brian Rodgers Utility Service Corporation 4614 Commercial Dr. NW Huntsville, AL 35816-2201 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

ArizonA 3

4

5

6

ABM Electrical Power Solutions 3602 East Southern Ave., Suite 1 & 2 Phoenix, AZ 85040 (602) 796-6583 www.abm.com Jeff Militello

13

7

ABM Electrical Power Solutions 720 S. Rochester Ave., Suite A Ontario, CA 91761 (951) 522-8855 Fax: (909) 937-6798 www.abm.com Ben Thomas

American Electrical Testing Co., Inc. 12566 W. Indianola Ave. Avondale, AZ 85392 (480) 383-9242 11 Apparatus Testing and Engineering [email protected] 7083 Commerce Cir., Suite H www.aetco.us Pleasanton,CA 94588 Donald Madaglia (925) 454-1363 Fax: (925) 454-1499 [email protected] Electric Power Systems, Inc. www.apparatustesting.com 557 E. Juanita Ave., #4 Harold (Jerry) Carr Mesa, AZ 85204 (480) 633-1490 Fax: (480) 633-7092 12 Apparatus Testing and Engineering www.eps-international.com PO Box 984 Folsom, CA 95763-0984 Electrical Reliability Services (916) 853-6280 Fax: (916) 853-6258 1775 W. University Dr., Suite 128 [email protected] Tempe, AZ 85281 www.apparatustesting.com (480) 966-4568 Fax: (480) 966-4569 James Lawler www.electricalreliability.com

Electrical Reliability Services 5810 Van Allen Way Carlsbad, CA 92008 (760) 804-2972 www.electricalreliability.com

15

Electrical Reliability Services 6900 Koll Center Pkwy., Suite 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436 www.electricalreliability.com

16

Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 www.electricalreliability.com

17

Hampton Tedder Technical Services 4571 State St. Montclair, CA 91763 (909) 628-1256 x214 Fax: (909) 628-6375 [email protected] www.hamptontedder.com Matt Tedder

18

Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

CAliforniA 10

Applied Engineering Concepts 1105 N. Allen Ave. Pasadena, CA 91104 (626) 398-3052 Fax: (626) 398-3053 [email protected] www.aec-us.com Michel Castonguay

For additional information on NETA visit netaworld.org

67

19

20

21

22

23

24

Pacific Power Testing, Inc. 27 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert 28

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

Magna IV Engineering 96 Inverness Dr. East, Unit R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573 [email protected] Glenn Stuckey

ConneCtiCut

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com POWER Testing and Energization, Inc. 731 E. Ball Rd., Suite 100 Anaheim, CA 92805 (714) 507-2702 www.powerte.com

29

30

31

Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 x111 Fax: (310) 549-9747 [email protected] www.tdeinc.com Anthony Demaria

ColorAdo 25

Electric Power Systems, Inc. 6753 E. 47th Avenue Dr., Unit D Denver, CO 80216 (720) 857-7273 Fax: (303) 928-8020 www.eps-international.com

26

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy

floridA 34

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] Mark Chapman

35

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.eps-international.com

36

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772 www.electricalreliability.com

37

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

American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 38 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.99aetco.com Gerald Poulin EPS Technology 29 N. Plains Hwy., Suite 12 Wallingford, CT 06492 (203) 679-0145 www.eps-technology.com

32

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com

33

Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

39

Industrial Electric Testing, Inc. 11321 West Distribution Ave. Jacksonville, FL 32256 (904) 260-8378 Fax: (904) 260-0737 [email protected] www.industrialelectrictesting.com Gary Benzenberg Industrial Electronics Group 850369 Highway 17 South PO Box 1870 Yulee, FL 32041 (904) 225-9529 Fax: (904) 225-0834 [email protected] www.industrialgroups.com Butch E. Teal

GeorGiA 40

Electrical Equipment Upgrading, Inc. 21 Telfair Pl. Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller

41

Electrical Reliability Services 2275 Northwest Pkwy. SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501 www.electricalreliability.com

For additional information on NETA visit netaworld.org

68 42

Electrical Testing, Inc. 2671 Cedartown Hwy. Rome, GA 3016-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com

49

Electrical Maintenance & Testing Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

43

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

50

High Voltage Maintenance Corp. 8320 Brookville Rd., #E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

illinois

51

44

Dude Electrical Testing, LLC 145 Tower Dr., Suite 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

45

Electric Power Systems, Inc. 23823 Andrew Rd. Plainfield, IL 60585 (815) 577-9515 Fax: (815) 577-9516 www.eps-international.com

46

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

47

PRIT Service, Inc. 112 Industrial Dr. PO Box 606 Minooka, IL 60447 (815) 467-5577 Fax: (815) 467-5883 [email protected] www.pritserviceinc.com Rod Hageman

52

58

Tidal Power Services, LLC 1056 Mosswood Dr. Sulphur, LA 70663 (337) 558-5457 Fax: (337) 558-5305 [email protected] www.tidalpowerservices.com Steve Drake

Shermco Industries 2100 Dixon St., Suite C Des Moines, IA 50316 (515) 263-8482 [email protected] www.shermco.com Lynn Hamrick Shermco Industries 796 11th St. Marion, IA 52302 (319) 377-3377 Fax: (319) 377-3399 [email protected] www.shermco.com Lynn Hamrick

mAine 59

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

60

Three-C Electrical Co., Inc. 72 Sanford Drive Gorham, ME 04038 (800) 649-6314 Fax: (207) 782-0162 [email protected] www.three-c.com Jim Cialdea

louisiAnA 53

Electric Power Systems, Inc. 1129 East Hwy. 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.eps-international.com

54

Electrical Reliability Services 14141 Airline Hwy., Building 1, Suite X Baton Rouge, LA 70817 (225) 755-0530 Fax: (225) 751-5055 www.electricalreliability.com

indiAnA American Electrical Testing Co., Inc. 4032 Park 65 Dr. Indianapolis, IN 46254 (317) 487-2111 Fax: (781) 821-0771 [email protected] www.99aetco.com Stephen Canale

Tidal Power Services, LLC 8184 Hwy. 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 [email protected] www.tidalpowerservices.com Darryn Kimbrough

iowA

55

48

57

56

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 www.electricalreliabilty.com Electrical Reliability Services 121 E. Hwy108 Sulphur, LA 70665 (337) 583-2411 Fax: (337) 583-2410 www.electricalreliability.com

mArylAnd 61

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com Bill Hartman

62

ABM Electrical Power Solutions 4390 Parliament Pl., Suite Q Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 www.abm.com Frank Ceci

63

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 Fax: (410) 679-0800 [email protected] www.harfordtesting.com Vincent Biondino

For additional information on NETA visit netaworld.org

69

64

65

66

71

Potomac Testing, Inc. 1610 Professional Blvd., Suite A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 [email protected] www.potomactesting.com Ken Bassett

DYMAX Service Inc. 46918 Liberty Dr. Wixom, MI 48393 (248) 313-6868 Fax: (248) 313-6869 www.dymaxservice.com Bruce Robinson

72

Electric Power Systems, Inc. 11861 Longsdorf St. Riverview, MI 48193 (734) 282-3311 www.eps-international.com

Reuter & Hanney, Inc. 11620 Crossroads Cir., Suites D - E Middle River, MD 21220 (410) 344-0300 Fax: (410) 335-4389 www.reuterhanney.com Michael Jester

mAssAChusetts 67

68

69

70

miChiGAn

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

73

74

High Voltage Maintenance Corp. 24371 Catherine Industrial Dr., Suite 207 Novi, MI 48375 (248) 305-5596 Fax: (248) 305-5579 www.hvmcorp.com Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

American Electrical Testing Co., Inc. 480 Neponset St., Bldg. 6 Canton, MA 02021-1970 (781) 821- 0121 Fax: (781) 821-0771 [email protected] www.99aetco.com 75 POWER PLUS Engineering, Inc. Scott A. Blizard 46575 Magallan Dr. Novi, MI 48377 High Voltage Maintenance Corp. (248) 344-0200 Fax: (248) 305-9105 24 Walpole Park South Dr. [email protected] Walpole, MA 02081 www.epowerplus.com (508) 668-9205 Salvatore Mancuso www.hvmcorp.com Infra-Red Building and Power Service 152 Centre St. Holbrook, MA 02343-1011 (781) 767-0888 Fax: (781) 767-3462 [email protected] www.infraredbps.com Thomas McDonald Sr. Three-C Electrical Co., Inc. 40 Washington Street Westborough, MA 01581 (508) 881-3911 Fax: (508) 881-4814 [email protected] www.three-c.com Jim Cialdea

76

77

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

minnesotA 78

DYMAX Holdings, Inc. 4751 Mustang Cir. St. Paul, MN 55112 (763) 717-3150 Fax: (763) 784-5397 [email protected] www.dymaxservice.com Gene Philipp

79

High Voltage Service, Inc. 4751 Mustang Cir. St. Paul, MN 55112 (763) 717-3103 Fax: (763) 784-5397 www.hvserviceinc.com Mike Mavetz

missouri 80

81

82

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.eps-international.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.eps-international.com Electrical Reliability Services 348 N.W. Capital Dr. Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 www.electricalreliability.com

nevAdA 83

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East 84 Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls 85

ABM Electrical Power Solutions 6280 South Valley View Blvd., Suite 618 Las Vegas, NV 89118 (702) 216-0982 Fax: (702) 216-0983 www.abm.com Jeff Militello Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 [email protected] www.controlpowerconcepts.com Zeb Fettig Electrical Reliability Services 6351 Hinson St., Suite B Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

70 86

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com

87

Hampton Tedder Technical Services 4920 Alto Ave. Las Vegas, NV 89115 (702) 452-9200 Fax: (702) 453-5412 www.hamptontedder.com Roger Cates

93

Longo Electrical-Mechanical, Inc. One Harry Shupe Blvd., Box 511 Wharton, NJ 07855 (973) 537-0400 Fax: (973) 537-0404 [email protected] www.elongo.com Joe Longo

94

101 M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.99aetco.com Michael Schacker

95

102 Scott Testing Inc. 1698 5th St. Ewing, NJ 08638 (609) 882-2400 Fax: (609) 882-5660 [email protected] www.scotttesting.com Russ Sorbello

Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 Fax: (631) 589-6670 [email protected] www.elemco.com Courtney O’Brien

103 Trace Electrical Services & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 [email protected] 104 www.tracetesting.com Joseph Vasta

High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

new hAmpshire 88

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 Fax: (603) 657-7370 www.eps-international.com

new Jersey 89

90

91

92

American Electrical Testing Co., Inc. 96 50 Intervale Rd., Suite 1 Boonton, NJ 07005 (973) 316-1180 Fax: (781) 316-1181 [email protected] www.99aetco.com Jeff Somol Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Joseph Wilson High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard Longo Electrical-Mechanical, Inc. 1625 Pennsylvania Ave. Linden, NJ 07036 (908) 925-2900 Fax: (908) 925-9427 [email protected] www.elongo.com Joe Longo

100

new mexiCo 97

98

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com

99

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

north CArolinA 105

Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com

new york

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton

106

ABM Electrical Power Solutions 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ABM Electrical Power Solutions 5805 G Departure Dr. Raleigh, NC 27616 (919) 877-1008 Fax: (919) 501-7492 www.abm.com Rob Parton

For additional information on NETA visit netaworld.org

71

107

108

109

110

111

112

113

114

115 ELECT, P.C. 7400-G Siemens Rd. PO Box 2080 Wendell, NC 27591 (919) 365-9775 Fax: (919) 365-9789 [email protected] www.elect-pc.com 116 Barry W. Tyndall

Electric Power Systems, Inc. 319 US Hwy. 70 E, Unit E Garner, NC 27529 (919) 322-2670 www.eps-international.com

117

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 www.electricalreliability.com Power Products & Solutions, Inc. 12465 Grey Commercial Rd. Midland, NC 28107 (704) 573-0420 x12 Fax: (704) 573-3693 [email protected] www.powerproducts.biz Ralph Patterson

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com

118

Power Services, LLC 998 Dimco Way, PO Box 750066 Centerville, OH 45475 (937) 439-9660 Fax: (937) 439-9611 [email protected] Mark Beucler

119

Power Solutions Group, Ltd. 670 Lakeview Plaza Blvd. Columbus, OH 43085 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

Power Test, Inc. 2200 Hwy. 49 Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 120 Power Solutions Group, Ltd. [email protected] 425 W. Kerr Rd. www.powertestinc.com Tipp City, OH 45371 Richard Walker (937) 506-8444 Fax: (937) 506-8434 [email protected] ohio www.powersolutionsgroup.com Barry Willoughby CE Power Solutions, LLC 4500 W. Mitchell Ave. oklAhomA Cincinnati, OH 45232 (513) 563-6150 Fax: (513) 563-6120 121 Shermco Industries [email protected] 1357 N. 108th E. Ave. Rhonda Harris Tulsa, OK 74116 (918) 234-2300 DYMAX Service, Inc. [email protected] 4213 Kropf Ave. www.shermco.com Canton, OH 44706 Jim Harrison (330) 484-6801 Fax: (740) 333-1271 www.dymaxservice.com oreGon Gary Swank 122 Electrical Reliability Services Electric Power Systems, Inc. 4099 SE International Way, Suite 201 2601 Center Rd., #101 Milwaukie, OR 97222-8853 Hinckley, OH 44233 (503) 653-6781 Fax: (503) 659-9733 (330) 460-3706 Fax: (330) 460-3708 www.electricalreliability.com www.eps-international.com

123

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvAniA 124

ABM Electrical Power Solutions 710 Thomson Park Dr. Cranberry Township, PA 16066-6427 (724) 772-4638 Fax: (724) 772-6003 [email protected] www.abm.com William (Pete) McKenzie

125

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.99aetco.com Jonathan Munley

126

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 x221 Fax: (215) 826-0964 [email protected] www.betest.com Walter P. Cleary

127

Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.eps-international.com

128

Electric Power Systems, Inc. 2495 Boulevard of the Generals Norristown, PA 19403 (610) 630-0286 www.eps-international.com

129

130

EnerG Test 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Katie Bleiler High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com

For additional information on NETA visit netaworld.org

72

131

132

133

Longo Electrical-Mechanical, Inc. 1400 F Adams Road Bensalem, PA 19020 (215) 638-1333 Fax: (215) 638-1366 [email protected] www.elongo.com Joe Longo North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] Robert Messina Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Reuter

135

139

140

141

south CArolinA 134

138

Power Products & Solutions, Inc. 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

142

Power Solutions Group, Ltd. 135 Old School House Rd. 143 Piedmont, SC 29673 (864) 845-1084 Fax: (864) 845-1085 [email protected] www.powersolutionsgroup.com Frank Crawford

tennesee 136

137

144 Electric Power Systems, Inc. 146 Space Park Dr. Nashville, TN 37211 (615) 834-0999 Fax: (615) 834-0129 www.eps-international.com

Electrical & Electronic Controls 6149 Hunter Rd. Ooltewah, TN 37363 (423) 344-7666 x23 Fax: (423) 344-4494 [email protected] Michael Hughes

145

Power & Generation Testing, Inc. 146 480 Cave Rd. Nashville, TN 37210 (615) 882-9455 Fax: (615) 882-9591 [email protected] www.pgti.net Mose Ramieh

Saber Power Systems 9841 Saber Power Lane Rosharon, TX 77583 (713) 222-9102 [email protected] www.saberpower.com Ron Taylor

texAs

Shermco Industries 33002 FM 2004 Angleton, TX 77515 (979) 848-1406 Fax: (979) 848-0012 [email protected] www.shermco.com Malcom Frederick

147

Absolute Testing Services, Inc. 6829 Guhn Rd. Houston, TX 77040 (832) 467-4446 Fax: (713) 849-3885 [email protected] www.texasats.com Richard Gamble 148 Shermco Industries 1705 Hur Industrial Blvd. Electric Power Systems, Inc. Cedar Park, TX 78613 4100 Greenbriar Dr., Suite 160 (512) 267-4800 Fax: (512) 258-5571 Stafford, TX 77477 [email protected] (713) 644-5400 www.shermco.com www.eps-international.com Kevin Ewing Electrical Reliability Services 149 1057 Doniphan Park Cir., Suite A El Paso, TX 79922 (915) 587-9440 Fax: (915) 587-9010 www.electricalreliability.com Electrical Reliability Services 1426 Sens Rd., Suite 5 Houston, TX 77571 (281) 241-2800 Fax: (281) 241-2801 www.electricalreliability.com Grubb Engineering, Inc. 3128 Sidney Brooks San Antonio, TX 78235 (210) 658-7250 Fax: (210) 658-9805 [email protected] www.grubbengineering.com Robert D. Grubb Jr. National Field Services 649 Franklin St. Lewisville,TX 75057 (972) 420-0157 www.natlfield.com Eric Beckman Power Engineering Services, Inc. 9179 Shadow Creek Ln. Converse,TX 78109 (210) 590-4936 Fax: (210) 590-6214 [email protected] www.pe-svcs.com Miles R. Engelke

150

151

Shermco Industries 2425 E. Pioneer Dr. Irving, TX 75061 (972) 793-5523 Fax: (972) 793-5542 [email protected] www.shermco.com Ron Widup Shermco Industries 12000 Network Blvd., Bldg. D, Suite 410 San Antonio, TX 78249 (512) 267-4800 Fax: (512) 267-4808 [email protected] www.shermco.com Kevin Ewing Tidal Power Services, LLC 4202 Chance Ln. Rosharon, TX 77583 (281) 710-9150 Fax: (713) 583-1216 [email protected] www.tidalpowerservices.com Monty C. Janak

utAh 152

153

Electrical Reliability Services 3412 South 1400 West, Unit A West Valley City, UT 84119 (801) 975-6461 www.electricalreliability.com Western Electrical Services, Inc. 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 [email protected] www.westernelectricalservices.com Rob Coomes

For additional information on NETA visit netaworld.org

73

virGiniA

162

Taurus Power & Controls, Inc. 6617 S. 193rd Pl., Suite P104 Kent, WA 98032 (425) 656-4170 Fax: (425) 656-4172 [email protected] www.tauruspower.com Jim Lightner

163

Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

154

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 548-5690 Fax: (757) 548-5417 www.abm.com Mark Anthony Gaughan, III

155

Electric Power Systems, Inc. 827 Union St. Salem, VA 24153 (540) 375-0084 Fax: (540) 375-0094 www.eps-international.com

156

Potomac Testing, Inc. 11179 Hopson Rd., Suite 5 164 Western Electrical Services, Inc. Ashland, VA 23005 4510 NE 68th Dr., Suite 122 (804) 798-7334 Fax: (804) 798-7456 Vancouver, WA 98661 www.potomactesting.com (888) 395-2021 Fax: (253) 891-1511 [email protected] Reuter & Hanney, Inc. www.westernelectricalservices.com 4270-I Henninger Ct. Tony Asciutto Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com wisConsin

157

wAshinGton 158

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 www.electricalreliability.com

159

POWER Testing and Energization, Inc. 22035 70th Ave. South Kent, WA 98032 (253) 872-7747 www.powerte.com

160

POWER Testing and Energization, Inc. 14006 NW 3rd Ct., Suite 101 Vancouver, WA 98685 (360) 597-2800 Fax: (360) 576-7182 [email protected] www.powerte.com Chris Zavadlov

161

165

CE Power Solutions of Wisconsin, LLC 3100 East Enterprise Ave. Appleton, WI 54913 (920) 968-0281 Fax: (920) 968-0282 [email protected] Rob Fulton

166

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com William Styer

167

Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado

168

169

Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

For additional information on NETA visit netaworld.org

74

canada 170

178

Magna IV Engineering 200, 688 Heritage Dr. SE Calgary, AB T2H1M6 Canada (403) 723-0575 Fax: (403) 723-0580 [email protected] Virginia Balitski 179

171

172

173

174

175

176

177

Magna IV Engineering 1005 Spinney Dr. Dawson Creek, BC V1G 1K1 Canada (780) 462-3111 Fax: (780) 462-9799 [email protected] Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski Magna IV Engineering 106, 4268 Lozells Ave Burnaby, BC VSA 0C6 Canada (604) 421-8020 Magna IV Engineering 8219D Fraser Ave. Fort McMurray, AB T9H 0A2 Canada (780) 791-3122 Fax: (780) 791-3159 [email protected] Virginia Balitski Magna IV Engineering 1040 Winnipeg St. Regina, SK S4R 8P8 Canada (306) 585-2100 Fax: (306) 585-2191 [email protected] Peter Frostad Magna Electric Corporation 3430 25th St. NE Calgary, AB T1Y 6C1 Canada (403) 769-9300 Fax: (403) 769-9369 [email protected] www.magnaelectric.com Cal Grant

180

Magna Electric Corporation 1033 Kearns Crescent, Box 995 Regina, SK S4P 3B2 Canada (306) 949-8131 Fax: (306) 522-9181 [email protected] www.magnaelectric.com Kerry Heid Magna Electric Corporation 851-58th St. East Saskatoon, SK S7K 6X5 Canada (306) 955-8131 x5 Fax: (306) 955-9181 [email protected] www.magnaelectric.com Luis Wilson Magna Electric Corporation 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 [email protected] www.magnaelectric.com Curtis Brandt

BrUSSelS 184

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com Paul Idziak

chile

185

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) 9-9-517-4642 [email protected] Cristian Fuentes

PUerto rico 186

181

Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

182

Pacific Powertech Inc. #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 1T2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Conkin

183

REV Engineering, LTD 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, Puerto Rico 00715 (787) 844-9366 Fax: (787) 841-6385 [email protected] Rafael Castro

Magna Electric Corporation 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.magnaelectric.com Franz Granacher

REV 01.14

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifica-tions. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2000 Standard for Certification of Electri-cal Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing associa-tion dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2000 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using cali-brated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard