The Anatomy of a Shermco Field Service Engineer Reliable and Responsive Part of a large international team available 24/7 Back by the Best From the field, to our full-service rotating apparatus services NETA-Certified Qualified to perform to the highest standards Protective Relaying Handbook Trusted Advisor Offering independent service across all brands Safety First On record as an industry leader in safe work practices Volume Cutting-Edge Trained from utility transmission to low-voltage distribution Our experience in commercial, industrial, generation and specialized sectors, such as oil refineries, pulp and paper, steel and wind power, uniquely qualifies us to handle the largest, most complex assignments Our people are trained on the latest technologies and safety practices And, we support them with full-service rotating apparatus services and a large fleet of service vehicles, ready to respond 24/7 Corporate Headquarters | 2425 East Pioneer Drive, Irving, Texas 75061 p 972.793.5523, 888.SHERMCO | f 972.793.5542 | www.shermco.com Why trust your vital power services to anyone less? Count on an industry leader Visit www.shermco.com and learn more today Published by InterNational Electrical Testing Association Odds are, you won’t find a job anywhere that a Shermco field service engineer can’t handle As one of the world’s most respected electrical maintenance and testing companies, Shermco delivers A+ service from utility transmission to low-voltage distribution Published by InterNational Electrical Testing Association Protective Relaying Handbook Volume Published by InterNational Electrical Testing Association Protective Relaying Handbook Volume Table of Contents Dynamic-State Relay Testing .1 A T Giuliante Introduction to Dynamic Testing .4 D L Tierney Through-Fault Testing — the Ultimate Test for Protection Schemes Prior to Energizing Roderic L Hageman Automated Test Point Calculations for Electronic Relay Testing and Coordination .11 Lonnie C Lindell and Steven R Potter Test & Maintenance Tips for Protective Relays 14 Scott Cooper Using 1op Characteristics to Troubleshoot Transformer Differential Relay Misoperation 16 Michael Thompson and James R Closson Motor Protection Fundamentals 27 Bernie Moisey Meaningful Testing of Numerical Multifunction Protection Schemes 30 Jay Gosalia Using Dynamic Testing Techniques for Commissioning and Routine Testing of Motor Protection Relays 35 Benton Vandiver III, P.E Commissioning Numerical Relays — Part One 37 James R Closson and Mike Young Steady State vs Dynamic Testing 44 Steven Stade Published by InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 102, Portage, Michigan 49024 269.488.6382 www.netaworld.org Protective Relaying Handbook Volume Table of Contents (continued) Dynamic State and Other Advanced Testing Methods for Protection Relays Address Changing Industry Needs 46 Kenneth Tang Acceptance Testing a Synch Circuit 51 Steven C Reed, P.E Partial Differential Relaying 53 Baldwin Bridger, P.E Modern Relays and Software Provide Valuable Tools for Analysis 54 Scott Cooper Understanding and Analyzing Event Report Information 57 David Costello 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 © 2009 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 Relaying Handbook — Volume Dynamic-State Relay Testing NETA World, Winter1999-2000 Issue by A T Giuliante ATG Exodus The traditional method of testing individual relay functions using steady-state calibrations is no longer a viable test method for testing modern multifunction relays Today, relay designs include innovative numerical techniques that enhance relay performance by combining a number of measuring criteria and by optimizing the relay’s operation for power system conditions If these relays are tested under the pseudo power system conditions created by steady-state testing, problems in testing and understanding the relay’s operation can occur In addition, the time for testing individual elements would be excessive because of the time required to reconfigure each individual element tested Relay Test Methods A report from IEEE, Relay Per formance Testing, discusses the methods of steady-state, dynamic-state, and transient testing of modern relays A steady-state test is defined as applying phasors to determine relay settings by slowly varying relay input Obviously, this test method does not represent power system faults Dynamic-state test is defined as simultaneously applying fundamental frequency components of voltage and current that represent power system states of prefault, fault, and postfault Utilizing this technique results in faster relay testing because, in most cases, relay elements not need to be disabled in order to test a relay function Transient testing is defined as simultaneously applying fundamental and nonfundamental frequency components of voltage and current that represent power system conditions obtained from digital fault recorders (DFR) or electromagnetic transient programs (EMTP) Dynamic Relay Testing Dynamic relay testing means testing under true simulated power system conditions Depending on the level of testing required, test values can be easily calculated with PC-based short circuit or EMTP programs For dynamic-state testing, a short-circuit program would be used to calculate the fundamental component of voltage and current values for prefault and fault conditions For transient simulations, an EMTP program would be used to create waveforms that represent the fault condition Dynamic-state testing and transient simulations provide a faster and more meaningful way to test relays and relay systems These techniques provide the user with a far better understanding of how the relay system performs and can aid both relay application and test engineers in evaluating relay operations Dynamic-state testing is based on a power system model that is used to simulate different events selected according to the application Events are played back through power system simulators that also monitor scheme performance Each event is modeled to simulate conditions for the tested relay circuit but only for the time period needed to test Why Use Dynamic-State Testing? Modern relay systems are multifunction digital devices that are designed to provide complete protection for a power system component Some of the newer designs have over 2,000 setting possibilities and require extensive configuration and setting procedures The traditional method of testing individual steady-state calibrations, one at a time, is no longer a viable method because of the excessive time it would require to reconfigure for each individual element tested In addition, traditional test methods were designed on the assumption that users did not have test equipment for testing relays under power system conditions So traditional test procedures were developed using basic test equipment components such as variacs, phase shifters, and load boxes With today’s modern test equipment, power system conditions can easily be simulated By making a profile of the operation of the scheme, malfunctions can be found faster because it is easier to identify the changes in areas that not operate the way they are expected Protective Relaying Handbook — Volume Advantages of Dynamic-State Testing What Is Needed for Dynamic-State Testing? Some of the advantages offered with dynamic-state testing as compared to traditional test methods are: The test method involves testing the complete scheme with dynamic-state simulations that model the power system the relay scheme will protect Computational programs such as One Bus, One Liner, CAPE and other mathematical calculation tools such as spreadsheets and Mathcad can be used to model the power system in order to derive the fault voltages and currents for the power system event • Complete relay scheme tests For each simulated power system event, the performance of the complete relay scheme is tested The high power capability of power system simulators allows the user to test the complete relay scheme This provides a faster way to test relays since relay settings or configuration need not be changed as they would if individual circuits were tested one at a time The performance of all scheme responses, including unfaulted phase units, can be evaluated since the model and simulators generate three-phase wye voltages and currents This allows the accurate modeling of power system events In addition, if the relay scheme includes programmable logic, simulated events which test how the complete system logic operates must be used to assure the relay logic is performing as intended Contact races and operating and resetting of measuring units may be common problems Therefore, the complete relay scheme needs to be tested as a whole to insure proper operation and proper nonoperation under simulated power system conditions • Realistic relay operating time tests The operating time of many line relay systems depends upon the system impedance ratio (SIR) With dynamicstate testing, different SIRs can be modeled to determine the range of relay operating times The traditional test method never considers the affect of SIR on relay performance • Evaluation of future relay operations The testing provides significant advantages of obtaining more reliable test results which confirm the configuration, settings and correct operation of the protection scheme while significantly reducing test time Since the test results describe how the relay scheme operates under power system conditions, the test data becomes a useful relay performance database When the relay system is in service and operates for a power system event, its performance can be compared to the relay performance database to determine if the relay scheme has operated correctly Many companies have experienced that after a questionable operation has occurred and a request for investigation was made, no findings could be gained from the steady-state test method in most cases since only the set points of individual components were checked To meaningfully investigate a questionable operation, the actual power system conditions at the time of the incident need to be simulated to be able to observe the reaction of the system as a whole Dynamic-State Test Procedure Create a dynamic-state test plan The test plan for dynamic-state testing depends on the type of protection to be tested and how it is configured The intent of the test plan is to test the relay scheme’s operation under simulated dynamic-state conditions Calculate values for simulated fault conditions A power system model of a two-machine equivalent system can be used to aid in the calculation of voltage and current values for line relay testing For the application to be tested, line and source values are entered Faults are simulated on the model with varied fault locations, resistances, and load flows according to the tests defined in the test plan Each case is a test that will characterize the scheme operation for reach and direction (faults behind and in front) and for the various zones and combinations of zones For reach tests, the fault locations are defined according to the accuracy of the unit being tested For a zone one relay with plus-or-minus five percent accuracy, an operation test would be defined at 95 percent of setting (op case) A test for no operation would be defined at 106 percent of setting (non-op case) These two cases confirm the accuracy of the zone one relay The reach tests are conducted for phase and ground distance relays For phase distance tests, use a phase-to-phase fault type; for ground distance tests, use a phase-to-ground fault type Make dynamic-state test cases Each test case requires three-phase voltage and current values For reach and direction tests for line relay schemes, three states are usually defined for each test case The prefault state provides balanced three-phase voltages to the relay long enough to stabilize the relay before a fault is simulated The prefault time assures that the relay will have the correct memory circuit response The test time for the fault state must be long enough to operate the tested zone of protection but short enough not to operate the next overreach zone of protection In this way, the faulted zone can be tested without disabling the adjacent overreaching zones The postfault time is required to reapply restraint voltage after the test to prevent any spurious operations Protective Relaying Handbook — Volume Playback with power system simulators Depending on how many relay functions are configured there may be a number of cases to run However, it only takes seconds to run a dynamic-state test so that 150 tests will take approximately five minutes To run a steady-state test with this amount of detail will take significantly longer because of all the communications that are required with the relay to reconfigure its settings Also, dynamicstate testing gives true relay operating performance for each power system event tested Conclusion Dynamic relay testing has allowed users to significantly decrease the amount of time needed for testing while increasing the quality of the test and the documentation of results Dynamic relay testing has also provided the user with the capability of developing an understanding of the power system and the protection scheme’s function within that power system Utilities have used dynamic relay testing to find problems that were unexplained with previous test methods Incident reports can now be meaningfully investigated A.T Giuliante is President and Founder of ATG Exodus Prior to forming his Company in 1995 Tony was Executive Vice President of GEC ALSTHOM T&D Inc.-Protection and Control Division, which he started in 1983 From 1967 to 1983, he was employed by General Electric and ASEA In 1994, Tony was elected a Fellow of IEEE for “contributions to protective relaying education and their analysis in operational environments.” He has authored over 35 technical papers and is a frequent lecturer on all aspects of protective relaying Tony is a past Chairman of the IEEE Power System Relaying Committee 19931994 and has degrees of BSEE and MSEE from Drexel University 1967 and 1969 Protective Relaying Handbook — Volume Introduction to Dynamic Testing NETA World, Winter1999-2000 Issue by D L Tierney Doble Engineering Steady state testing is used to verify the settings for a relay element The test quantities are applied to the relay and held steady for a predetermined time equal to or greater than the operating time of the relay If the relay does not respond, the test quantities are raised or lowered by a small increment less than the resolution of the relay The test quantity is then reapplied to the relay for the same predetermined time This procedure is repeated until the relay operates Figure — Dynamic State Waveforms Figure — Steady State Waveforms The dynamic state test, on the other hand, is used to determine the relay’s response to power system conditions All applied test quantities are simultaneously switched between states Each state represents a different steady-state power system condition One state may represent prefault conditions, while the next represents the fault followed by the postfault condition More states may be added to represent evolving faults or reclosing However, the dynamic state test does not include the high frequency and dc components found in many faults To simulate a more realistic power system disturbance requires a transient simulation test This test contains the nonsteady state frequency components, magnitude, phase relationships, and duration the relay will see, unlike the dynamic test which uses stepped sine wave states to simulate the different power system conditions The transient simulation test uses continuous waveform for each test quantity The waveform itself contains the prefault and fault power system conditions These waveforms can come from actual disturbances as recorded by digital fault recorders or the relays themselves Another source of transient waveforms can be software programs such as Electro-Magnetic Transient Program (EMTP) or MathCAD In the real world, relays respond to changing or transient conditions These dynamic conditions are not simulated using stepped sine wave testing Dynamic state testing and transient simulation testing are effective test methods Because transient testing requires more complex data sets, dynamic tests are far easier to prepare and produce better results than steady-state testing This article deals with the dynamic state testing of protection systems Protective Relaying Handbook — Volume • The relay event log on microprocessor relays or digital fault recorders (DFR) can tell when to apply signals and when to remove them The DFR can also record the magnitudes of the fault Figure — Transient Waveforms Why use dynamic state testing? Dynamic state testing can be used in every stage of relay testing: • During evaluation testing, dynamic testing can be used to simulate current reversal or power swings to compare the performance of different relays • During acceptance testing, dynamic testing can be used to test internal relay elements such as blocking for loss of potential with high loads, or testing the reset time of the keying output when a fault changes from a forward zone to a reverse zone • During commissioning testing, dynamic testing can be used to test the relay in the protection system For example, fault can be applied to two relays at the same time to test a back blocking scheme or breaker failure scheme • During troubleshooting, dynamic testing can be used to simulate faults for which relays did not operate as expected • During routine testing, dynamic tests can be used for rapid go/no-go testing of protection systems What equipment will you need to start dynamic state testing? To start dynamic state testing you are going to need two basic pieces of equipment, dynamic state simulation software and high power active sources Sources of data for dynamic state testing: Data used in dynamic state testing can come from a number of different sources: • Phasor fault calculations • Two terminal line fault simulation software such as GE Fault • Multi-bus fault simulation software such as Aspen or CAPE • “What If ” simulation In the absence of DFRs or microprocessor relay event logs, the “What If ” simulation is used Dynamic state simulations are written to test what if the ground fault current was 200 amperes higher then the fault simulation software said it was What if the relay did not receive breaker fail initiate until the fault evolved from a single line-to-ground to a double line-to-ground fault? • When constructing acceptance tests the relay instruction manual may contain part or all of the data needed to construct the dynamic state acceptance test Getting started Having the right software and equipment to run a dynamic state test is only the start How many sources are needed? Are there enough test instruments to run the tests? How can the protection system be tested in parts with a limited number of sources? Can the entire scheme be tested at once? How many states are needed to test a function of the scheme? Which test leads are required and where they get connected? The following can help answer some of these questions and more: • One-line diagram • Identify the quantity and type of relays and the number of sources • From the relay type information, determine the required current, voltage, and control power of sources Relays located in different CT and PT strings will require more sources • Also from the relay type information, determine source burden If the burden exceeds the capacity of a single source, consider breaking current strings and using additional slaved sources • Identify the type and number of dynamic state tests For example, add two states for each reclose cycle and select appropriate state durations • Identify relay settings and then calculate appropriate test quantities to determine expected time delays • Three-line diagram • Determine isolation points for sources to avoid feeding active relaying • Avoid backfeed potential transformers • Determine injection points for current and potential sources • Relaying schematic • Writing the test plans and expected results: • What equipment is expected to operate? 51 Protective Relaying Handbook — Volume Acceptance Testing a Synch Circuit NETA World, Summer 2001 Issue by Steven C Reed, P.E Electric Power Systems On any new electrical installation startup, acceptance testing is an important step to ensure the correct operation of protective equipment and the safety of personnel Synchronization circuits are some of the most critical parts of any electrical distribution system, especially the first time they are put into use If for any reason there is an error in the engineering, application, or wiring there is a great concern for the safety of personnel and possible equipment damage There can be no short cuts in the startup of a synchronization circuit Basic Description A synchronization relay (25) is used to verify that the voltages on either side of a breaker are within appropriate voltage magnitude and phase relationship prior to initiating a breaker close The voltage comparison is made between the bus and the line See Figure for a basic example The relay close circuit will operate after an enable signal is received from each of the following circuits: voltage difference, phase difference, voltage monitor, and time delay The voltage difference (delta voltage) setting compares the magnitude of the bus voltage to the line voltage If the delta voltage is less than the set limit, it enables a close signal for the voltage difference If the magnitude of the voltage difference is exceeded between the line and the bus, the breaker close signal will be blocked The phase difference setting measures the phase angle between the line and bus voltage If the measured angle is less than the window setting, the phase difference setting will be enabled If the phase-angle reading between the bus and line voltage is greater than plus or minus the window setting, the close circuit will be blocked The voltage monitor setting allows programmable options that may best suit the system operating conditions, such as allowing breaker closure for live line, dead line, live bus, and dead bus Live line (LL) – enabled when the line voltage is greater than the setting Dead line (DL) – enabled when the line voltage is less than the setting Live bus (LB) – enabled when the bus voltage is greater than the setting Dead bus (DB) – enabled when the bus voltage is less than the setting The time window setting is an adjustable time delay that allows the relay close circuit to be enabled after all previous conditions have been met Pre-Energization Tests Before any work is performed the field technician must review the manufacturer’s literature to gain a full understanding of the design and capabilities of the relay The engineering drawings shall be compared to the manufacturer’s literature as a way of confirming the correct use of the relay The coordination study settings shall also be reviewed to verify the correct overall use and design (for example, LL, DL, LB and DB) After the relay operational review has been completed, each component of the synchronization circuit should be tested on the line side and bus side Insulation and ratio test of any PT or CCVT Insulation test and verification of secondary wiring Verify proper secondary grounding at the PT or CCVT Verify proper primary and secondary phasing of the line and bus PTs Calibrate synchronization relay in accordance with settings 52 Protective Relaying Handbook — Volume Energization Tests Although any problems should have been detected in the pre-energization tests, the synch system is not ready to be utilized Assuming a generator is on the line side of the synchronization system, it is not worth risking damage to the generator should a mistake be made during the verification of the synchronization scheme A back-up plan should be in place for verification that the synchronization scheme is correct As an example of the various methods for verification, we will assume the following: a generator is on the line side of the synch system, the synch system is set up across a generator breaker, and a step-up transformer feeds a high-voltage transmission breaker The synchronization relay PTs are connected on the line and bus side of the generator breaker There are three acceptable procedures allowing for correct verification in this case: isolation from utility grid while the generator runs, a backfeed from utility while the generator is isolated, or the use of two sets of phasing sticks (least desirable) The first method is the isolation from the utility grid The generator may be started, and the generator breaker closed onto dead bus only! The high-voltage transmission breaker will have already been opened, locked, and tagged out The open transmission breaker will isolate the generator from the utility system Most likely three PTs will be located on the line side and load side of the generator breaker Verify voltage through phase angle measurements at the synch relay No voltage should exist between similar phases (Line A-Bus A, Line B-Bus B, and Line C-Bus C) Obtain proper voltage readings from line-to-ground and phase-to-phase on the line and bus feeds Verify that the synch system is operating in accordance with all set parameters The second method is to backfeed the utility system by isolating the generator A portion of the generator bus will need to be removed to allow a backfeed from the utility system Proper clearances and safety standards need to be met prior to the initiation of this test The high-voltage breaker will be closed, backfeeding the step-up transformer The generator breaker needs to be closed (temporary adjustment to the breaker-closing scheme), to backfeed the generator bus This allows both the line and bus PTs to be energized Most likely three PTs will be located on the line side and load side of the generator breaker Verify voltage through phase angle measurements at the synch relay No voltage should exist between similar phases (Line A-Bus A, Line B-Bus B, and Line C-Bus C) Obtain proper voltage readings from line-toground and phase-to-phase on the line and bus feeds Verify that the synch system is operating in accordance with all set parameters The third method may need to be utilized if either of the other two energization procedures can not be met This method is the least desirable due to the number of personnel required and risks of electrical hazards Two sets of phasing sticks should be used to monitor the line and bus voltage The line side is fed from the generator The bus side is fed from the utility One phase set will monitor voltage on the line side and the bus side of A-phase The second phase set will monitor the line side and bus side of C-phase Figure — Connections for a Typical Application All necessary industry, site, and customer safety standards should be followed, such as the use of blast suits, since this is considered hot work Location of the monitoring will be critical for personnel safety but must be determined based on each job and rating of equipment This procedure will take at least four technicians to complete: two technicians (minimum) with phasing sticks, one (with radio) monitoring both phasing sticks, and one (with radio) monitoring synchronization process It should be determined that the synch relay will allow closure of the breaker just before the voltage at both phasing sticks is zero If both phases are in synch, the third phase must also be in synch The synch relay should never allow closure unless both phasing sticks show zero voltage During this entire process the generator breaker close scheme should be disabled as a protective measure After the pre-energization and energization tests have been completed, a new synchronization scheme can be operated with full confidence that it is within proper operating conditions Steven C Reed has a BS in electrical engineering from Villanova University, a MBA from the Olin School of Business at Washington University in St Louis, and has professional engineering licenses in multiple states Steve has worked at Electric Power Systems for 12 years and served as a field engineer, system protection engineer, and now serves as regional manager He is a NETA Certified Technician Level III 53 Protective Relaying Handbook — Volume Partial Differential Relaying NETA World, Summer 2001 Issue by Baldwin Bridger, P.E Powell Electrical Manufacturing Co “Partial differential” relaying is a form of overcurrent relaying frequently used to detect main bus overcurrent faults and to back up feeder overcurrent relaying The basic circuit is shown in the one-line diagram Note that this is a double-ended substation with two main breakers and a tie breaker The partial differential relaying concept can not be used on a straight radial distribution system True bus differential relaying compares all currents entering and leaving a switchgear bus Within the limits of the accuracy of the CTs and the relays, true bus differential relaying will detect all faults on the protected bus Since all currents are taken into account, the relays can be very fast Bus differential relaying, however, provides no backup to the feeder overcurrent relaying, so additional overcurrent relays are required on main and tie breakers to provide this backup function Also, high speed bus differential relaying can be quite expensive, and many switchgear users not feel that it is economically justified Partial differential relaying sums the currents entering or leaving a switchgear bus through main and tie breakers If a fault exists on the protected bus, the currents will add in the relays, but if fault current is flowing through the bus to a fault on another bus, the currents will subtract and the relays will not respond If the fault is on a feeder, the partial differential relays will act as backup to the feeder overcurrent relays Similar protection can be obtained by using separate overcurrent relays on each main and tie circuit breaker However, proper coordination of the overcurrent protection requires that the tie breaker relays coordinate with the feeder relays and that the main breaker relays coordinate with the tie breaker relays for a total of three steps of relaying at this bus Using the partial differential circuit, however, elimi- nates one step of coordination, since the same relays serve both the main and the tie breakers without compromising coordination This reduces the time delay required for the main breaker relays and improves the chances of getting good coordination with upstream relays which are often on the utility system serving the substation This improved coordination is the principal benefit of partial differential relaying Reprinted with permission of Powell Electrical Manufacturing Co Baldwin Bridger, PE, is recently retired Technical Director of Powell Electrical Manufacturing Co., Houston, Texas He has worked as an engineer and engineer manager in the design of low- and medium-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 54 Protective Relaying Handbook — Volume Modern Relays and Software Provide Valuable Tools for Analysis NETA World, Fall 2001 Issue by Scott Cooper Beckwith Electric Co In the past, the only indications of a trip were an alarm, a target flag, and a tripped breaker or lock-out relay There was no data to aid in determining what happened, how it happened, or the extent of the damage This often resulted in days of unnecessary testing and inspections or, worse, placing faulted equipment back on line, which can be a safety hazard or can cause further equipment damage This article discusses present-day fault recording and failure analysis using modern digital relay technology Unlike their electromechanical and static predecessors, digital relays provide a number of valuable tools to aid in determining exactly what happened and the extent of damage To provide appropriate indication for the operators, the relay front panel prominently displays some basic information: the relay’s operational status, current trip state, and the function tripped during the most recent event More detailed target event information may be retrieved via the keypad interface as well as remotely via PC or PLC systems Unlike traditional alarm panels which are wired directly to relays, these systems may use RS232, RS485, or modem communication connections and a variety of communication protocols to interrogate the relay Currently, detailed trip data may be accessed, processed, and appropriately displayed to operators, technicians, engineers, and management in different locations The troubleshooting process normally starts with the sequence of events record Each target is stored in order and is identified by a time stamp which corresponds to the relay clock time of the first trip In installations where multiple devices are present, all time stamps may be automatically synchronized using an IRIG-B network To prevent data loss, event data is stored in nonvolatile memory in case of input power interruption to the relay Typically, relays can automatically store 24 or more separate trip events, depending upon the application Each trip event may contain a number of individual targets that are identified as being either picked up or tripped At the inception of each event, digital relays also log I/O status and metering quantities Target History: Screen from Beckwith Electric’s IPScom® Communication Software showing a relay’s target history during testing The left panel shows the events available and the right panel displays the I/O status, line side currents, and targets in the selected event In addition to the target data, most digital relays also incorporate some form of waveform recorder or oscillograph record The oscillograph record can be used to identify the sequence of events, aids in verifying the validity of the relay’s operation, and speeds troubleshooting by helping to identify the faulted phase or component Oscillographs can also provide necessary data for engineers adjusting a relay set point to overcome a normal transient In the event of an actual fault, oscillographs provide insight on how far a parameter was out of specification and for how long This is often crucial data for determining what testing or inspections are needed after an incident Of course, if the worst should happen, the data may be used as evidence in court During normal relay operation, the relay continuously saves waveform and I/O data to RAM After an oscillograph event is triggered, that portion of memory is reserved The 55 Protective Relaying Handbook — Volume resultant waveform data may then be downloaded to a PC and saved as a file for analysis In the event that redundant or overlapping relays are used, both oscillograph recorders should be set to trigger if either relay trips Inevitably, in the event of an actual fault, one relay will trip first and open the breaker, while the other relay may not have the opportunity to time out even if the same settings are used on both For generator protection, this is especially true with slow developing faults or abnormal operating conditions such as loss of field (40) or volts per hertz (24) A second oscillograph can also help confirm a suspected incorrect trip or relay failure 59N: Screen from IPSplot® Oscillograph Analysis program showing an actual generator stator ground fault After the trip, meggering the stator could not verify the problem However, from the trace, the operators could see arcing and breakdown, so more testing was ordered The stator subsequently failed high potential test Having an accurate oscillograph record probably prevented this trip from being dismissed as a relay problem, and serious machine damage was averted Inadvertent Energization: Screen from Beckwith Electric’s IPSplot® Oscillograph Analysis program showing an actual generator inadvertent energization From the trace, we verified a secondary current equal to 24A for a period of cycles before the relay and breaker opened the circuit Input shows the indicated breaker position, output shows the Beckwith relay tripping The cause of this event was operator error To analyze the event waveforms, one must obtain the relay settings, target information, and review oscillographs from the event Next, study the target information to determine what function tripped first Finally, use the oscillograph record to calculate the associated values at the time of the trip The waveform can also be used to verify that the relay is operating correctly Relay or input circuit problems can be indicated by waveforms that are inconsistent with actual generator operation For example, was a corresponding neutral voltage or current recorded during a 51V inverse time overcurrent operation? Once the validity of an operation is established, the waveforms can be used for system troubleshooting For example, identification of a miswired CT circuit is easy with an oscillograph of the differential trip Since the oscillograph records both pre- and posttrigger data, the record can also be used to verify proper trip circuit operation This is easily accomplished by comparing the relay trip time mark, the breaker open indication, and the cessation of currents This process verifies that the breaker indicated open and did, in fact, open within the anticipated operating time Oscillograhs can also be used to check for breaker problems like unequal pole operation After analysis, resultant oscillograph files may be converted to the Comtrade format (see Transformer Inrush figure) for playback using modern test equipment Comtrade is a common waveform file format used by most test equipment manufacturers This capability provides a new and exciting means to evaluate equipment based on actual fault conditions In the past, the scope of normal relay testing did not include the harmonics, dc offsets, and CT saturation that may be present in actual operation This playback capability can be used to verify that a relay operates correctly for an actual system fault It can also be used to verify a relay does not improperly trip during plant transients (see Relay Comparison graph) 56 Protective Relaying Handbook — Volume Modern digital relay technology provides valuable tools for determining the cause and extent of trip events and faults By using fault recording and failure analysis functions available in digital protective relays, users can save time and money by eliminating unnecessary testing and inspections and avoiding equipment damage Scott Cooper, Field Service Engineer, joined Beckwith Electric Co in 1997 His responsibilities include training, commissioning, and troubleshooting protective relays for customers He is also instrumental in testing new relay products and custom-engineered systems Scott was previously an electronics technician at Beckwith for two years testing protective relays and conducting failure analysis and individual component evaluations He is a member of IEEE and served in the US Navy for six years in the nuclear reactor controls division He has served as a senior technician with Seapower Engineering Transformer Inrush: Screen from Omicron’s Transview Analysis program showing a “black start.” The left panel shows the distorted waveforms are the result of energizing a bank of load transformers The right panel shows the harmonics present The 100 percent dc offset and harmonics were causing the installed generator relay’s differential element to trip Relay Comparison: Excel Spreadsheet comparing the tripping performance of two digital relays from different relay manufacturers The above transient was captured and played through the two relays using an Omicron 256-6 test set From the graph, the differential element of relay B can be set to more sensitive and is much more tolerant to the black start transient than the currently installed relay A Accurately identifying the problem and proving the solution quickly solved this customer’s problem 57 Protective Relaying Handbook — Volume Understanding and Analyzing Event Report Information NETA World, Fall 2001 Issue David Costello Schweitzer Engineering Laboratories, Inc When faults or other system events occur, protective relays record sampled analog currents and voltages, the status of optoisolated inputs and output contacts, the state of all relay elements and programmable logic, and the relay settings The result is an event report, a stored record of what the relay found, and how and why it responded Readily available information, product instruction manuals, and assistance from analytic software equips the user with the necessary tools to determine if the response of the relay and the protection system was correct for the given system conditions Each time the power system faults and relays capture data, the results are ready-made test reports By analyzing the actual relay and system performance, utilities are saving money by extending or eliminating traditional routine tests Regulatory agencies require the installation of disturbance monitoring equipment and postfault event analysis Relays with event reporting help meet these requirements Information recorded in relay event reports are valuable for testing, measuring performance, analyzing problems, and identifying deficiencies prior to causing a misoperation The ability to quickly and accurately analyze event data is useful This article supports efforts through a real-world example which demonstrates the process of changing raw data into useful information How to Analyze an Event Report Understand the expected or desired operation Collect event reports and other information Look for possible exceptions and/or unexpected elements Compare actual operation to expectations Utilize manufacturers’ data and software Develop and test solutions This example is a step-by-step tutorial on analyzing an event report, valuable lessons, and problem resolution Before analyzing event report details, begin with a basic understanding of what took place, or what should have This process generally involves reviewing the relay settings and logic, obtaining the relay history report, and gathering any additional information that may be helpful (for example, known fault location, targets from other 1st Event Report: relays, breaker operations, SCADA and CARNALL CCT.# 2522 SN# 96143025 Date: 8/25/99 Time: 11:54:43.479 personnel records) The event report is Event : AB T Location: 0.12 Shot: Targets: INSTABQ used to verify that the actual operation Currents (A pri), ABCQN: 3766 3551 239 6124 20 matches the expected operation Historical information was down2nd Event Report: loaded from a distribution relay that had CARNALL CCT.# 2522 SN# 96143025 Date: 8/25/99 Time: 11:54:44.083 to be closed by SCADA after tripping Event : CG T Location: 0.21 Shot: Targets: INSTCQN to lockout The relay controls a recloser Currents (A pri), ABCQN: 3932 3930 3931 which is mounted on a steel stand within the substation and powered from the 3rd Event Report: substation dc battery Daily routine CARNALL CCT.# 2522 SN# 96143025 Date: 8/25/99 Time: 12:09:41.758 requires utility employees to investigate Event : ABC Location: 5.67 Shot: Targets : all out of the ordinary events, including Currents (A pri), ABCQN: 443 654 403 478 105 failures to automatically reclose and lockout events 58 Protective Relaying Handbook — Volume The pickup of the 50H element is (30 amperes secondary) • (CTR=120:1), or 3600 ampere primary We should, therefore, expect the initial INST A B trip target for a 3766 ampere fault The next expected sequence for this relay is to open the recloser, time on =N the first reclosing open interval, then automatically reclose The first reclose =Y attempt should be after an open delay =0 of 900 cycles, or 15 seconds (79OI1 set=0 ting) However, the second event is an instantaneous C-to-G trip only 0.604 second after the first event What would cause a fault to occur during a recloser open period during timing our first reclose attempt? The analytic software plots of the first (Figure 1) and second (Figure 3) event reports confirm our suspicion of a recloser failure and flashover inside the recloser tank In Figure 1, the initial A- to B-phase fault is evident The first digital element to assert is the 51P time-overcurrent pickup, the most sensitively set element This triggers the event report as expected by the ER = 51P setting To determine which element caused the trip, identify the point in time where the trip asserts (OUT T) and look for any other =RE element transitions at the same point The pickup of the instantaneous phase overcurrent element, 50HP, asserts at the same instant the trip output asserts, while the 51P element is shown picked up but still timing to trip The 79 reclosing element prepares to time to a reclose by changing from the reset state to the cycle state when the relay trips IN6, programmed to monitor a 52a auxiliary contact, comes open two cycles after the trip indicating the recloser has opened After adjusting the scaling on the C-phase current channel in the analytic assistant software (Figure 1), we can see that the C-phase interrupter did not open fully as current continues to flow The trip coil monitor, IN3 = TCM, is an optoisolated input wired as a voltage divider to monitor the health of the trip coil (refer to Figure 2) When the recloser is closed and the trip output contact is not asserted, the TCM input allows a few milliamperes of current to flow through the trip coil The voltage drop is across the relay TCM input because the input has a much higher impedance than the trip coil (roughly 1000 times greater) In the first five cycles of Figure 1, the TCM is asserted, indicating the trip circuit was intact At the time of trip, the TCM input deasserts, initially because of the closed trip contact and then because of the open 52a auxiliary in the trip circuit Partial Display of As Set Settings for CARNALL CCT.# 2522 SN# 96143025 CTR =120.00 79OI1 =900 79OI2 =2700 79RST =600 M79SH =11011 50C =99.99 50NL =99.00 51NP =12.00 51NTD =15.00 51NC =3 51NRS 50L =99.99 50H =30.00 51P =5.01 51TD =2.50 51C =4 51RS 52APU =0 52ADO =0 TSPU =0 TSDO TKPU =0 TKDO =0 TZPU =0 TZDO S(123) = A(12) = B(12) = E(34) = F(34) = K(1234) = L(1234) = A1(1234) = A2(1234) = V(56) = W(56) = X(56) = A3(1346) = A4(2346) =TCMA TR(1246) =50H+51T RC(1246) =TF ER(1246) =51P TDUR =5 TFT =30 IN1 =DC IN2 =DT IN3 =TCM IN4 IN5 = IN6 =52A Figure 1— C-Phase Interrupter Fails to Open In order to understand normal relay operation, examine the output contact logic and determine what elements in the relay are actually used in this application In this relay, we notice that only two elements are programmed to cause a trip (TR equation), the nondirectional phase instantaneous 50H element and phase time-overcurrent 51T element 59 Protective Relaying Handbook — Volume Figure — Trip Coil Monitor In the second event, the failed interrupter flashes over to the recloser tank 0.604 second after the first trip occurred In Figure 3, you can see the 79 reclosing element immediately goes to lockout The relay is designed to drive its reclosing element to lockout if a trip occurs before reclosing has been attempted This prevents reclosing after a flashover across an open pole or internal tank failures such as this Therefore, the operation of the relay was correct, and the cause of the failure to reclose was a recloser failure condition The information gathered in the first two events indicates that C-phase carried current for at least 0.721 second (the difference between the trigger times of each report, 0.604 second, plus additional cycles of fault data in event two) The fault current seen for the majority of this time was only around 50 amperes primary Could a recloser failure element have been used to clear this fault before it developed a more severe 4000 ampere fault? component magnitudes are calculated At the end of the first event, the C-phase current is only 0.42 ampere secondary (3IO = Ia + Ib + Ic = 0.412 A, as well) As set, the overcurrent elements used for tripping and those not used for tripping are set much too high to see the 0.412 ampere phase and residual current flowing through the failed interrupter, so the trip failure logic, as set, is ineffective In this relay, the elements which unlatch the trip output and trip failure timing are the same elements that prevent the reclosing relay from resetting after an automatic reclose Set a residual overcurrent element 50NL to 0.25 ampere secondary to provide sensitive breaker failure supervision for unbalanced faults The event reports in the history of the relay are reviewed to insure normal load unbalance is not greater than (0.25 ampere secondary) • (CTR=120:1), or 30 amperes primary With this setting, our trip failure logic would have detected the unbalanced condition as a result of the stuck C-phase interrupter Programming an output to close when a trip failure (TF) is detected could provide a trip to a back-up protective device (the transformer differential relay), assert an alarm to the SCADA system to initiate maintenance, and prevent a more intense fault Supervising the trip failure element with a phase overcurrent relay is more challenging in this relay but can still be done The maximum prefault load current in the relay’s history of events was 130 amperes primary, or 1.08 amperes secondary If we set any element other than 50C in this relay below load, our reclosing relay will be prevented from resetting (the trip and trip failure unlatch elements are the same elements used to allow the recloser to reset) The logic and wiring in Figure allow a sensitive 0.5 ampere secondary setting for 50C to be used for phase current supervision of the trip failure logic while not interfering with the reclosing reset logic Figure — Recloser Trip Failure Logic for Phase Faults Below Load Figure — Failed C-Phase Interrupter Flashes to Ground The recloser failure element as set in this relay is only intended to cancel reclosing The TF or trip failure bit asserts if none of the overcurrent elements in the relay (with the exception of the 50C element) have dropped out TFT cycles after a relay trip is initiated If the overcurrent elements drop out, the trip failure element stops timing Using the analytic assistant software, phase current and symmetrical We assume that the C-phase interrupter eventually opened because no backup protective device operated and the beginning of the third event (see Figure 5) indicates the C-phase current is zero The dispatcher instructed a local switchman to report to the substation because the SCADA system indicated the recloser was open and in lockout Approximately 15 minutes after the initial trip, the third event captures the SCADA close operation By noticing that IN4 (reclosing enable) is deasserted, we verify that the switchman manually turned automatic reclosing off By noticing that IN1 (direct close) is asserted, we verify that SCADA was used to remotely close the recloser once The recloser closed without incident 60 Protective Relaying Handbook — Volume Figure indicates the cold load inrush and the brief pickup of the 51P time-overcurrent element A cold load pickup scheme can be enabled through settings such that it is automatically put in service when the recloser is open and locked out for a long period of time After a successful close, the scheme automatically adjusts to the original settings When the scheme is active, the relay modifies the pickup of the phase time-overcurrent element to a higher value while keeping the same curve and time dial settings to maintain coordination with upstream devices Figure — SCADA Close of a Failed Distribution Recloser The third event emphasizes the importance of using a manual close delay In newer recloser controls and substation relays, front panel operator controls are built in so that traditional control switches can be eliminated For safety, the user may add a settable time delay to the operation of the front panel operator controls This delay allows an operator to initiate a manual close by pushing the close button and then walking away to a safe distance before the close signal is actually sent by the relay to the recloser or breaker The associated red close LED flashes as the timer counts down This safety improvement can be made in older relays such as the one in this example by wiring the manual close switch contact to a programmable relay input and time-delaying the close output with programmable logic as follows See Figure S(123) TSPU K(1234) TKPU L(1234) V(56) A4(2346) Figure — Cold Load Pick-Up Scheme Improves Security and Maintains Coordination To enable the cold load pickup scheme, an element called 52BT that follows the recloser status is used 52BT is the inverse of 52AT (see Figure 8) With the settings shown, the modified pickup will be in service for 52APU time, a settable value After the time expires, the pickup is forced back to the original value If 52ADO exceeds all reclosing relay open interval time settings (79OI1, 79OI2, etc.), the cold load pickup scheme will be disabled through the reclose cycle The 52AT element drops out, and the 52BT element asserts when 52ADO expires after the recloser goes to lockout The 52ADO is effectively the loss-of-diversity time delay The 52APU is effectively the time limit before minimum pick-up is restored following a close operation = IN5 IN5 is energized by a momentary manual close switch =0 TSDO = 300 = IN5 =0 TKDO = 315 = ST = KT*!L =V A4 is a time-delayed close output from the relay to the close coil Figure — Delayed Manual Close Setting Option Improves Safety 61 Protective Relaying Handbook — Volume 50L 51P 52APU B(12) C(12) F(34) G(34) X(56) Y(56) TR(1246) =7.50 =5.00 =30 =51T =50L =52BT =52AT =B*C*F =B*G =X+Y 51TD =2.50 52ADO =3600 51C =4 This was a B-to-G trip The reclose operation was successful for the fault Had a reclose failure 51RS =Y not occurred, an investigation of the first event, since it appeared at first glance to be a normal trip and reclose event, also may not have happened Further investigation proves that the C-phase interrupter experienced a problem during the initial trip as well During that event, however, the reclose occurred before the fault evolved into a larger problem Utilizing the analytic software to calculate phase current and symmetrical component magnitudes indicates there was sufficient current (1.3 A C-phase and 3I0) to assert the revised recloser failure logic Conclusion In summary, analysis of this series of event reports: • Reviewed the anticipated protection system behavior for a given fault • Used simple analysis techniques and analytic software to unravel complex event details Figure — Effect of 52APU and 52ADO Settings on Relay Word Bits 52AT and 52BT The relay generated ten event reports in just over 20 minutes according to its history In addition to the three events reviewed here, there were six event reports triggered by brief downstream B-to-G faults The oldest event in the history buffer was time stamped 11:47:33.395 (shown in Figure 9) • Verified correct operation of the relay • Revealed a recloser failure and the need for maintenance on the C-phase interrupter • Showed two occurrences of the breaker problem, indicating that event analysis can expose problems such as these before they become more extreme • Identified a weakness in the as-set trip failure settings and provided data to develop an improved set of settings and logic that would have identified this problem the first time, notified SCADA, and locked out the problem equipment • Highlighted the need for safety improvements through breaker failure logic, local and remote indication, manual close operation safety delays, and failed recloser lockout • Indicated multiple faults in the same vicinity, suggesting a problem at a specific line location requiring further investigation (trees invading line) • Demonstrated the need for cold load pickup logic to prevent misoperation on inrush Figure — Another Failure of the Interrupter Recorded by Event Reports • Illustrated the power of multifunction relays and programmable logic in developing solutions to each problem identified in the event reports (i.e., the power to solve all problems exists in the relay already installed) 62 The analytic assistant software used to create the oscillographic images generated COMTRADE files used to reproduce the fault sequence through test equipment into relays in the laboratory By doing this, the improved logic solutions shown proved to function correctly, solving problems for the actual system fault using the existing relay The event report files are stored as documentation for regulatory agencies and as proof of relay operations test For more information, please download the technical paper “Understanding and Analyzing Event Report Information” at http://www.selinc.com/techpprs.htm David Costello has a BS in electrical engineering from Texas A&M University From 1991 to 1996 he was employed with Central Power and Light and Central and Southwest Services, Inc., where he worked as a system protection engineer In 1996, he joined Schweitzer Engineering Laboratories, Inc (SEL) as a field application engineer He currently holds the position of Regional Service Manager and is responsible for SEL customer support in the Southcentral and Southwest United States Protective Relaying Handbook — Volume NETA Accredited Companies The following is a listing of all NETA Accredited Companies as of August 2011 Please visit the NETA website at www.netaworld.org for the most current list A&F Electrical Testing., Inc Kevin Chilton Advanced Testing Systems Patrick MacCarthy American Electrical Testing Co., Inc Scott Blizard Apparatus Testing and Engineering James Lawler Applied Engineering Concepts Michel Castonguay Burlington Electrical Testing Company, Inc Walter Cleary C.E Testing, Inc Mark Chapman CE Power Solutions of 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Davidson IV Scott Testing, Inc Russ Sorbello Shermco Industries Ron Widup Sigma Six Solutions, Inc John White Southern New England Electrical Testing, LLC David Asplund, Sr Southwest Energy Systems, LLC .Robert Sheppard Taurus Power & Controls, Inc Rob Bulfinch Three-C Electrical Co., Inc .James Cialdea Tidal Power Services, LLC Monty Janak Tony Demaria Electric, Inc Anthony Demaria Trace Electrical Services & Testing, LLC Joseph Vasta Utilities Instrumentation Service, Inc Gary Walls Utility Service Corporation Alan Peterson Western Electrical Services Dan Hook Setting the Standard About NETA NETA (InterNational Electrical Testing Association) is an association of leading electrical testing companies; visionaries, committed to advancing the industry’s standards for power system installation and maintenance to ensure the highest level of reliability and safety NETA is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by 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WESTINGHOUSE-CO-7-50/ 51 13800.0V AIC Rating: N/A Current Rating: 15 00A / 5A Setting: 1) Tap 5.0 2) Time Dials 3.0 Bus Name: Bus 1, 13 .8kV Bus Voltage: Fault Duty: Curve Multiplier: Test Points: @2.0X, 2 .15 0s @5.0X, 0.970s 12 000.0A 1. 00000 Bus Name: Bus 1, 13 .8kV Bus Voltage: Fault Duty: Curve Multiplier: Test Points: @2.0X, 9.200s @5.0X, 1. 250s 200000.0A 1. 00000 Device Name: Relay C Description: WESTINGHOUSE-CO -11 -50/ 51. .. Mitchell Avenue Cincinnati, OH 45232 800.434.0 415 513 .563. 615 0 phone 513 .563. 612 0 fax info@cepower.net 24/7 Emergency Service Available Nationwide 800-434-0 415 www.cepowersol.com CE Power Solutions of Wisconsin 3255 West Highview Drive Appleton, WI 519 14 800.434.0 415 920.968.02 81 phone 920.968.0282 fax info@cepower.net 11 Protective Relaying Handbook — Volume 1 Automated Test Point Calculations for Electronic... — Sample protective coordination drawing 13 Protective Relaying Handbook — Volume 1 Device Name: Relay A Description: MULTILIN-SR745 Xfmr Relay-5A CT Sec AIC Rating: N/A Current Rating: 300A / 5A Setting: 1) OC Pickup 1. 0 2) Mod Inverse 5.0 1. 0 3) Inst OC Pickup 7.0 Bus Name: Bus Voltage: Fault Duty: Curve Multiplier: Test Points: @2.0X, 3.787s @4.0X, 1. 909s Line 1, 69kV 69000.0V 200000.0A 1. 00000 Device... Base 3 *kV Base at 18 kV: Base 11 5 *10 00 = ————— = 3,688 1. 732 *18 on the 345 kV system current will be: Fault 18 kV = 936* ———— = 48.8 A kV Now let us check on some of the considerations we listed earlier First, does our available source have sufficient capacity? 10 Protective Relaying Handbook — Volume 1 Source kVA = 3* Fault *kV L-L = 1. 732 * 936 * 0.48 = 778 kVA So our 10 00 kVA source was large enough,... 0 .10 5 10 0 10 0 ZActual = 2. 817 * 0 .10 5 = 0.2958 If we connect a 480Y/277V source to the 18 kV winding and short circuit the 345 kV system, the following current will flow on the 18 kV system: V L-N = ———— Fault Actual 277 V = ———— = 936 A 0.2958 MVA Base: Base Rating of GSU Transformer = 11 5 MVA = 345 kV VBase: GSU Primary GSU Secondary = 18 kV MVA Base *10 00 = ——————— Base 3 *kV Base at 18 kV: Base 11 5 *10 00... Check Record Figure 20 — Annotated Differential Check Record Protective Relaying Handbook — Volume 1 Figure 21 — In-Service Current Circuit Verification Form 25 26 Bibliography 1 Blackburn, J Lewis, Protective Relaying Principles and Applications, Second Edition, Marcel Dekker, Inc., New York, 19 98 2 ANSI/IEEE C37. 91- 1985, IEEE Guide for Protective Relay Applications to Power Transformers 3 Criss,... following is a typical list for voltage and current sources when testing electromechanical impedance relays with an electromechanical directional ground overcurrent relay: • A-phase relaying voltage • B-phase relaying voltage • C-phase relaying voltage • A-phase relaying current voltage polarization In many microprocessor relays the prefault period allows the relay to build voltage memory In some cases,... impedance kVABase *10 00 Z Base = ——————— 3 * Base 18 *10 00 = ————— = 2. 818 1. 732*3,688 Those with experience in per unit calculations will recognize that ZBase is more easily calculated as: (kVBase )2 Z Base = —————— MVA Base 18 2 = ——— = 2. 817 11 5 Calculating the actual ohmic impedance of the transformer is as follows: Zactual = ZBase * Zpu From the transformer nameplate we find the %Z and %Z 10 .5% Zpm = ——... The voltage on the nameplate of a motor may differ from the system nominal voltage, i.e 4000 volts on the nameplate connected to a 416 0-volt system In most cases when the motor is started, the voltage at the motor terminals will “sag” To ensure that sufficient voltage is present to accelerate the load the starting voltage must be calculated and then limits set with an under voltage relay If the voltage... restraint Protective Relaying Handbook — Volume 1 Under this condition, increased loading will cause the relay to operate This operation will occur when Iop exceeds 35% of transformer full load (based on the setting presumptions) This will be when the load (restraint) current reaches 17 .5% of full load (or 17 .5% of TAP setting) This condition is plotted on the characteristic graph in Figure 11 Figure ... Field Service Engineer, joined Beckwith Electric Co in 19 97 His responsibilities include training, commissioning, and troubleshooting protective relays for customers He is also instrumental in... Current Figure 13 — Phasor Diagram with Missing Phase Shift 21 Protective Relaying Handbook — Volume If this condition exists, the relay will operate with increases in load, unless the restraint slope... University in 19 81 and an MBA from Eastern Illinois University in 19 91 During his years at Bradley University, Mike was involved in the cooperative education program and worked in electrical engineering