Protective Relaying Handbook Vol 1 PDF

• Evaluation of future relay operations Th e testing pro vides signifi cant advantages of ob tain ing more re li able test results which confi rm the con fi g ra tion, settings and corr

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Published by InterNational Electrical Testing Association

Volume 1

Protective

Relaying

Handbook

Published by InterNational Electrical Testing Association

Volume 1

Published by

InterNational Electrical Testing Association

3050 Old Centre Avenue, Suite 102, Portage, Michigan 49024

269.488.6382www.netaworld.org

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

Protective Relaying

Handbook

Volume 1

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 1

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

Dynamic-State Relay Testing

NETA World, Winter1999-2000 Issue

by A T Giuliante ATG Exodus

Th e traditional method of test ing individual relay

func-tions us ing steady-state calibrafunc-tions is no longer a viable

test method for testing modern mul ti func tion re lays

To-day, relay designs in clude in no va tive nu mer i cal techniques

that enhance relay per for mance by com bin ing a number of

mea sur ing criteria and by optimizing the relay’s operation

for power sys tem conditions If these relays are tested under

the pseu do power system conditions created by steady-state

test ing, problems in testing and understanding the re lay’s

operation can occur In ad di tion, the time for testing

di vid u al elements would be ex ces sive because of the time

required to reconfi gure each in di vid u al el e ment tested

Relay Test Methods

A report from IEEE, Relay Per for mance Testing, dis cuss es

the meth ods of steady-state, dy nam ic-state, and transient

testing of mod ern relays A steady-state test is defi ned as

ap-plying phasors to de ter mine relay settings by slowly varying

relay input Obviously, this test method does not rep re sent

pow er system faults Dy nam icstate test is defi ned as si mul

-ta neous ly applying fun da men -tal frequency com po nents of

volt age and current that represent power system states of

prefault, fault, and postfault Uti liz ing this technique results

in fast er relay testing be cause, in most cases, relay elements

do not need to be disabled in order to test a relay function

Tran sient test ing is defi ned as si mul ta neous ly applying

fundamental and nonfundamental frequency com po nents of

voltage and cur rent that represent power system con di tions

obtained from digital fault re cord ers (DFR) or elec tro

-mag net ic transient programs (EMTP)

Dynamic Relay Testing

Dynamic relay testing means test ing under true simulated

pow er system conditions De pend ing on the level of testing

re quired, test values can be easily calculated with PC-based

short cir cuit or EMTP pro grams For dynamic-state

ing, a short-cir cuit pro gram would be used to calculate the

fun da men tal com po nent of voltage and cur rent val ues for prefault and fault con di tions For transient sim u la tions, an EMTP program would be used to create waveforms that rep re sent the fault condition Dy nam ic-state test ing and transient simulations provide a faster and more mean ing ful way to test re lays and relay sys tems Th ese tech niques pro vide the user with a far better un der stand ing of how the relay system per forms and can aid both relay application and test

en gi neers in evaluating relay op er a tions

Dynamic-state testing is based on a power system model that is used to simulate diff erent events se lect ed according

to the ap pli ca tion Events are played back through power system simulators that also mon i tor scheme per for mance Each event is mod eled to sim u late conditions for the tested relay cir cuit 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 pro tec tion for a power system component Some of the newer designs have over 2,000 setting possibilities and require extensive confi gu-ration and setting pro ce dures Th e traditional method of testing in di vid u al steady-state calibrations, one at a time,

is no longer a viable method because of the excessive time

it would require to reconfi gure for each individual el e ment tested In addition, traditional test methods were de signed

on the assumption that users did not have test equipment for testing relays under power sys tem conditions So traditional test procedures were developed using basic test equipment com po nents such as variacs, phase shifters, and load box es With today’s modern test equipment, power system con-

di tions can easily be simulated By making a pro fi le of the operation of the scheme, malfunctions can be found faster because it is easier to identify the chang es in areas that do not operate the way they are ex pect ed

Advantages of Dynamic-State Testing

Some of the advantages off ered with dynamic-state

test-ing as compared to traditional test methods are:

• Complete relay scheme tests

For each sim u lat ed power system event, the per for mance

of the complete relay scheme is tested Th e high power

capability of power system sim u la tors allows the user to

test the complete relay scheme Th is provides a faster way

to test relays since relay settings or con fi g u ra tion need

not be changed as they would if individual circuits were

tested one at a time Th e performance of all scheme

re-sponses, including unfaulted phase units, can be evaluated

since the model and simulators gen er ate three-phase wye

volt ag es and currents Th is allows the accurate mod el ing

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 in tend ed Contact

races and operating and resetting of measuring units

may be common prob lems Th ere fore, the complete relay

scheme needs to be tested as a whole to insure proper

op er a tion and prop er nonoperation under simulated

pow er system con di tions

• Realistic relay operating time tests

Th e operating time of many line relay systems de pends

upon the sys tem impedance ratio (SIR) With dy nam

ic-state test ing, diff erent SIRs can be modeled to de ter mine

the range of relay operating times Th e tra di tion al test

method never considers the affect of SIR on relay

performance

• Evaluation of future relay operations

Th e testing pro vides signifi cant advantages of ob tain ing

more re li able test results which confi rm the con fi g

ra tion, settings and correct operation of the pro tec tion

scheme while signifi cantly reducing test time Since the

test results describe how the relay scheme op er ates under

power system conditions, the test data becomes a

use-ful relay performance da ta base When the relay system

is in service and op er ates for a pow er system event, its

performance can be com pared to the relay performance

database to de ter mine if the relay scheme has operated

cor rect ly Many com pa nies have ex pe ri enced that after

a ques tion able op er a tion has oc curred and a request for

in ves ti ga tion was made, no fi ndings could be gained from

the steady-state test meth od in most cases since only the

set points of in di vid u al com po nents were checked To

meaningfully in ves ti gate a questionable op er a tion, the

actual power system con di tions at the time of the incident

need to be simulated to be able to observe the reaction

of the sys tem as a whole

What Is Needed for Dynamic-State Testing?

Th e test method involves testing the complete scheme with dynamic-state simulations that model the power sys-tem the relay scheme will protect Com pu ta tion al programs such as One Bus, One Liner, CAPE and oth er mathematical calculation tools such as spreadsheets and Mathcad can be used to model the power system in order to derive the fault volt ag es and currents for the power system event

Dynamic-State Test Procedure

1 Create a dynamic-state test plan

Th e test plan for dynamic-state testing depends on the type of protection to be tested and how it is con fi g ured

Th e intent of the test plan is to test the relay scheme’s operation under simulated dynamic-state con di tions

2 Calculate values for simulated fault conditions

A power system model of a two-machine equiv a lent tem can be used to aid in the calculation of voltage and current values for line relay testing For the ap pli ca tion

sys-to be tested, line and source values are entered Faults are simulated on the model with varied fault locations, resis-tances, and load fl ows ac cord ing to the tests defi ned in the test plan Each case is a test that will characterize the scheme op er a tion for reach and direction (faults behind and in front) and for the var i ous zones and com bi na tions

of zones For reach tests, the fault locations are defi ned according to the ac cu ra cy of the unit being tested For a zone one relay with plus-or-minus fi ve percent accuracy,

an op er a tion test would be defi ned at 95 percent of ting (op case) A test for no operation would be defi ned

set-at 106 percent of setting (non-op case) Th ese two cases confi rm the accuracy of the zone one re lay Th e reach tests are conducted for phase and ground distance relays For phase dis tance tests, use a phase-to-phase fault type; for ground distance tests, use a phase-to-ground fault type

3 Make dynamic-state test cases

Each test case requires three-phase voltage and cur rent values For reach and direction tests for line relay schemes, three states are usually de fi ned for each test case Th e prefault state pro vides balanced three-phase voltages to the relay long enough to sta bi lize the relay before a fault

is simulated Th e prefault time assures that the relay will have the correct memory circuit re sponse Th e 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 dis abling the adja-cent over reach ing zones Th e postfault time is required

to re ap ply restraint voltage after the test to prevent any spurious operations

4 Playback with power system simulators.

Depending on how many relay functions are con fi g ured

there may be a number of cases to run How ev er, it only

takes seconds to run a dynamic-state test so that 150 tests

will take approximately fi ve minutes To run a steady-state

test with this amount of detail will take signifi cantly

lon-ger be cause of all the communications that are required

with the relay to reconfi gure its set tings Also,

dynamic-state test ing gives true relay op er at ing performance for

each power system event test ed

Conclusion

Dynamic relay testing has allowed users to sig nifi cant ly

decrease the amount of time needed for test ing while

in-creasing the quality of the test and the doc u men ta tion of

results Dynamic relay testing has also provided the user

with the capability of de vel op ing an understanding of the

power system and the protection scheme’s function within

that power system Utilities have used dynamic relay

test-ing to fi nd problems that were unexplained with previous

test methods In ci dent reports can now be mean ing ful ly

investigated

A.T Giuliante is President and Founder of ATG Ex o dus Pri or to

forming his Company in 1995 Tony was Executive Vice Pres i dent of

GEC ALSTHOM T&D Inc.-Protection and Control Di vi sion, which

he started in 1983 From 1967 to 1983, he was em ployed by General

Electric and ASEA In 1994, Tony was elect ed a Fellow of IEEE for

“con tri bu tions to pro tec tive relaying ed u ca tion and their anal y sis in

op er a tion al en vi ron ments.” He has authored over 35 technical papers

and is a frequent lecturer on all aspects of protective relaying Tony is a

past Chair man of the IEEE Power System Relaying Committee

1993-1994 and has de grees of BSEE and MSEE from Drexel University

1967 and 1969.

Introduction to Dynamic Testing

NETA World, Winter1999-2000 Issue

by D L Tierney Doble Engineering

Figure 2 — Dynamic State Wave forms

Steady state testing is used to verify the set tings for a relay

element Th e test quantities are applied to the relay and held

steady for a pre de ter mined time equal to or greater than the

op er at ing time of the relay If the relay does not respond, the

test quantities are raised or lowered by a small increment

less than the res o lu tion of the relay Th e test quan ti ty is then

re ap plied to the relay for the same pre de ter mined time Th is

procedure is re peat ed un til the re lay operates

Figure 1 — Steady State Wave forms

Th e dynamic state test, on the other hand, is used to

de-termine the relay’s response to power sys tem conditions All

applied test quan ti ties are si mul ta neous ly switched between

states Each state rep re sents a diff er ent steady-state power

system con di tion One state may rep re sent prefault

condi-tions, while the next rep re sents the fault followed by the

postfault con di tion More states may be add ed to represent

evolv ing faults or reclosing

However, the dynamic state test does not include the

high fre quen cy and dc components found in many faults

To simulate a more realistic power sys tem dis tur bance

re quires a tran sient sim u la tion test Th is test contains the

nonsteady state fre quen cy com po nents, mag ni tude, phase

re la tion ships, and du ra tion the re lay will see, unlike the nam ic test which uses stepped sine wave states to sim u late the diff er ent pow er sys tem con di tions Th e tran sient sim u -

dy-la tion test uses con tin u ous wave form for each test quan ti ty

Th e wave form it self con tains the prefault and fault pow er sys tem con di tions Th ese wave forms can come from actual dis tur banc es as recorded by dig i tal fault re cord ers or the re- lays them selves An oth er source of tran sient wave forms can

be soft ware pro grams such as Electro-Magnetic Tran sient Pro gram (EMTP) or MathCAD

In the real world, relays respond to chang ing or transient con di tions Th ese dynamic conditions are not simulated

us ing stepped sine wave testing Dy nam ic state test ing and transient sim u la tion test ing are eff ective 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 Th is ar ti cle deals with the

dy nam ic state test ing of pro tec tion sys tems

Why use dynamic state testing?

Dynamic state testing can be used in every stage of relay

test ing:

• During evaluation testing, dynamic testing can be used

to sim u late current reversal or pow er swings to compare

the per for mance of diff erent relays

• During acceptance testing, dynamic testing can be used

to test internal relay elements such as block ing for loss

of potential with high loads, or testing the reset time of

the keying output when a fault changes from a forward

zone 2 to a reverse zone 3

• During commissioning testing, dynamic test ing can be

used to test the relay in the pro tec tion system For

ex-ample, fault can be applied to two relays at the same

time to test a back block ing scheme or breaker failure

scheme

• During troubleshooting, dynamic testing can be used

to sim u late faults for which relays did not operate as

expected

• During routine testing, dy nam ic tests can be used for

rapid go/no-go testing of protection sys tems

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 diff erent sources:

• Phasor fault calculations

• Two terminal line fault simulation software such as GE

• “What If ” simulation In the absence of DFRs or croprocessor relay event logs, the “What If ” sim u la tion

mi-is used Dynamic state simulations are written to test what if the ground fault current was 200 amperes higher then the fault simulation soft ware 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 in struc tion manual may contain part or all of the data needed

-to construct the dynamic state ac cep tance test

Getting started

Having the right software and equipment to run a dynamic state test is only the start How many sourc es are needed? Are there enough test instruments to run the tests? How can the pro tec tion system be test ed in parts with a lim it ed num ber of sources? Can the en tire scheme be tested at once? How many states are need ed to test a function of the scheme? Which test leads are re quired and where do they get con nect ed? Th e following can help answer some of these ques tions and more:

re-• Also from the relay type information, de ter mine source burden If the burden exceeds the ca pac i ty 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 du ra tions

• Identify relay settings and then calculate ap pro pri ate test quantities to determine ex pect ed time de lays

• Th ree-line diagram

• Determine isolation points for sources to avoid ing active relaying

feed-• Avoid backfeed potential transformers

• Determine injection points for current and po ten tial sources

• Relaying schematic

• Writing the test plans and expected results:

• What equipment is expected to operate?

Figure 3 — Transient Wave forms

• What equipment is not expected to operate?

• What targets should the test produce?

• How many cycles should a given state be?

• What points should be isolated to avoid tripping

in-service equipment?

• Identifi cation of the type and number of dy nam ic state

tests based on number of trip paths shown in the

sche-matic

• Identifi cation of the type and number of log ic out puts

• Are the test instruments required to supply sig nal ing

normally supplied by other equipment or de vic es that

can not be operated during the dy nam ic state test?

• Connection Diagrams

• Connection points for current and potentials

• Connection points for logic outputs

• In some cases, the physical location of devices

Choosing the correct number of sources

In any dynamic state test each state should con tain the

cor-rect number of quantities for the pro tec tion system being

tested Relay burdens and test in stru ment power ratings

must be taken into account when choosing the number of

sources required to run the test Electromechanical relays

require more energy to operate than most solid-state and

mi cro pro ces sor relays In any case, energy requirements

climb with each relay added to a test

In some cases, with a high-impedance ground, the neutral

must be broken and ground relays must be operated with

diff erent sources

Th e following is a typical list for voltage and cur rent

sources when testing electromechanical im ped ance relays

with an electromechanical directional ground overcurrent

relay:

• A-phase relaying voltage

• B-phase relaying voltage

• C-phase relaying voltage

• A-phase relaying current

• B-phase relaying current

• C-phase relaying current

• Polarizing voltage

• Polarizing current

Choosing the correct number of states

Th e data should contain voltage and current val ues for

pre-fault conditions, pre-fault conditions and postpre-fault conditions

• In most cases prefault is set to normal load con di tions

to allow the relay to stabilize In the case of an

electro-mechanical distance relay the prefault state applies the

voltage polarization In many mi cro pro ces sor relays the prefault period allows the relay to build voltage memory

In some cases, the prefault is set to zero volts and rent to test switch-on-to-fault logic Typical time dura-tion for prefault is about 60 cycles

cur-• Fault states vary in number from simulation to tion If you are testing single line-to-ground fault with

simula-no reclosing relay, a single fault state will do If you are testing with an evolving fault you will need one state for each stage of the fault Th e fi rst state will have a single line-to-ground fault for one or two cycles Th e next state will have a double line-to-ground for two, three, or four cycles A three line fault follows Th is data should be as close to real fault levels as practical In some cases where the fault occurs on a line close to a strong source, the sec ond ary current will ap proach levels that test equip-ment can not provide

• Postfault usually occurs at the end of the dy nam ic state test However, postfault states can occur be tween fault states also In this case you are sim u lat ing the reclose interval In postfault state the breaker is open so the line currents are zero Th e voltages, on the other hand, are either zero or full potential depending on where the relay potential trans form ers (PT) are located, i.e., on the line or on the bus

Test lead considerations

When pushing high currents, the impedance of test leads becomes a factor Th ere are several ways to minimize the

impedance of the test lead, but it can not be eliminated.

• Keep the test leads as short as possible Short er test leads have less impedance

• Do not use the instrument ground as the re turn path for grounded-wye systems

• Do not coil excess test leads Coiling the test leads turns them into an inductor Th is inductance in creas es the impedance of the test leads

• Twisted pairs could be used to cancel mutual in duc tance Th is inductance would otherwise in crease the impedance of the test leads

-• Larger gauge test leads Using a larger gauge test lead will decrease the resistance of the test lead

Test lead connection point considerations

Where the test leads are connected is one of the most portant factors in dynamic testing

im-• When connecting test potentials always make sure you will not backfeed potential transformers Make sure the PTs are isolated by pulling fuses, open ing test switches,

or by whatever practices are used by your company

• Potential and current test leads should be con nect ed to test as much of the wiring in the scheme as possible Re-lays make up only part of the pro tec tion system scheme

Test switches, cutout switch es, meters, transducers,

dig-ital fault re cord ers (DFR), re lays from other schemes,

and wire make up the rest of the total scheme either as

part of the scheme or by sharing currents and po ten tials

In any case they all can aff ect how a pro tec tion scheme

responds

• When testing breaker-and-a-half scheme one set of

current transformers (CT) will have to be dis con nect ed

before the test can be conducted Fail ure to do so will

give the test current multiple paths As a result, the

de-vices under test will not receive the correct currents

• When testing protection schemes with a pri ma ry and

backup system or two primary systems one scheme at

a time, care should be taken to not dis able or cause an

operation of the in-service scheme Unless each system

has its own CTs, it is better, in this case, to jack the

cur-rents and po ten tials into the individual relays

Logic output considerations

If your test requires using the relay’s digital in puts for

emu-lating contact closures, your test in stru ment will require

logic outputs

• Pay attention to the ratings of the device be ing driven

by the logic output relays Th ese can be low-power

sig-naling relays Using them to trip or open high-power

devices such as trip/close coils can and will damage the

relays

• Study the scheme and connection diagrams well before

connecting the logic output contacts Fol low ing are

things to avoid:

• Connecting battery positive to battery neg a tive

• Tying diff erent battery banks together

• Backfeeding diff erent devices Make sure that only the

device(s) that are intended to operate are en er gized

• Is the device being driven by the logic output con tacts

looking for dry contacts or wet contacts? In other words,

is the device supplying the voltage or is the test

instru-ment supplying the voltage?

• Is the device being driven by the logic output con tacts

look ing for open-to-close, close-to-open, volt age-to-no

voltage, or no voltage-to-voltage tran si tions?

What am I forgetting?

• Are you connected to the correct relay? Th is is the

num-ber one cause of misoperations dur ing scheme testing,

misidentifi cation of relays Do not let this hap pen to

you Take the time to mark off the adjacent relays so you

do not accidentally op er ate the wrong relay

• When testing protection systems with break er fail ure

schemes or other similar schemes, isolation points for

these relays should be opened Th ese open iso la tion

points (cutoff switches or test switch es) will prevent

trip ping of in-service equip ment in the event that the breaker failure relays or similar relays operate

• Do not wait until you start testing to fi nd out whether your test leads are connected correctly or whether the phases are rolled in the wir ing Turn on the po ten tials and currents one at a time or to geth er at diff erent phase angles and/or mag ni tudes Th en trace the quan ti ties through the PT and CT strings to ver i fy each phase

• To trip the breaker or not to trip the breaker, that is the ques tion Th e actual breaker should be tripped at least once to ensure that the relay con tacts can handle the trip current Reason number two to trip the breaker is

to en sure that the volt age drop across the wir ing during trip ping is not a factor in the op er a tion of the breaker dur ing a fault Another reason is to test the breaker’s

“a” and “b” con tacts connected to the pro tec tion scheme However, for all oth er break er trips, the use of a breaker simulator is rec om mend ed to save wear and tear on the breaker, es pe cial ly high-volt age breakers

• Many breaker simulators in use today are built around

a lockout relay One problem with the lock out breaker simulator is its speed Th e lockout relay op er ates in less then eight mil li sec onds Th is is faster than most break-ers and can give diff erent test results when used instead

of operating the breaker Th erefore, time delay circuits may be need ed to slow down the tripping and the clos- ing of lockout breaker simulator boxes

• When connecting the break er simulator care should be taken not to backfeed signals

• Do you want the station oscillograph or dig i tal fault cord er to operate for each and ev ery test? If not, you may want to temporarily disconnect the trig gers to de-vices

re-• When testing schemes with transfer trip, op er a tion of

lo cal relays may cause the remote breaker to operate or change state Care should be taken to isolate these sig-nals if you do not want to op er ate the remote breaker

In a future issue of NETA World, a specifi c ex am ple with

con nec tion details, source selection, and state cal cu la tions will be presented

Dennis Tierney has been a Senior Applications En gi neer for Relay Protection at Doble Engineering Com pa ny for ap prox i mate ly one year Prior to this position, for eleven years, Dennis worked at the Salt River Project in Phoenix, Arizona, in relay pro tec tion, power quality and, SCADA Before working at the Salt River Project, he worked in HVDC and Com mu ni ca tions at the Los Angeles Department of Wa ter and Power Dennis grad u at ed from Arizona State University in 1982 with a Bachelors of Science De gree in Electrical Engineering.

Through-Fault Testing — the Ultimate Test for Protection Schemes Prior to Energizing

PowerTest 2000 (NETA Annual Technical Conference)

Roderic L Hageman PRIT Service, Inc.

Concept

Th e concept of through-fault testing is not new to our

industry Take, for example, primary injection testing of

low-voltage circuit breakers Technicians routinely inject

fault level current through these breakers to verify pickup

and timing of the associated trip units Most technicians

have learned that single-phase injection can create problems

with the ground fault elements, masking the pickup and

timing of the phase functions If there is no way to defeat

the ground fault element at the trip unit, an injection in one

pole and out another will cause cancellation of the ground

fault current Other through-fault tests are frequently made

on substation bus ground fault schemes and bus diff erential

schemes

Th e fault current for all of these tests is typically provided

by a single-phase, high current test set that can deliver

thousands of amperes at a very low voltage Th e procedures

are relatively safe due to the low voltage Typically, one of

the primary hazards is the temperature rise of the test set

leads or connections

For the same reasons that the procedures described above

are performed, similar tests are desirable for more

sophis-ticated protective relay and metering schemes In these

schemes, phase angles are as important as current magnitude

for the correct operation of the scheme A prime example

is that of a transformer diff erential scheme Th e primary

current and the secondary current will diff er, not only due

to the ratio of the protected transformer, but also due to any

other phase angle shifts caused by delta-wye confi gurations

Electromechanical relays typically require that the current

transformer connections correct for the delta-wye shifts

Modern microprocessor-based relays can be programmed

to account for the shifts internal in the relay

However these corrections are made, it is desirable to

perform an overall system test to confi rm that the design and

installation provide protection without nuisance tripping

Source

In some cases utilities will actually stage faults on the power system Th is amounts to deliberately short circuiting

a transmission line or distribution feeder and energizing it

at normal voltage Obviously, this could be damaging to the system, and if the relaying systems do not work cor-rectly, severe damage to the power system can occur With the prominence of modern computer-operated dynamic test sets, GPS synchronizing, and end-to-end testing, the need for this type of staged fault testing is decreasing dramatically

Although I have not seen it, I have heard of using tem generators to provide the desired level of fault current Because the power system impedance is primarily reactive, fault currents require very little real power If the generator’s excitation system can be adjusted to produce a relatively low voltage compared to the normal system voltage, fault current can be controlled and kept to a reasonable magnitude

A relatively easy way to provide the fault current and yet control its magnitude is to use a low voltage source and the impedance of a transformer to limit the fault current Th is transformer might be, for example, the actual transformer

in the part of the distribution system that is being tested

If this is not convenient, a transformer of the appropriate ratio, impedance, and kVA size might be available from a rental agency

Metering

In setting up the through-fault test procedure, it is necessary to take into consideration the available meter-ing Older electromechanical phase-angle meters might require 0.5 ampere or more to reliably determine phase angle Modern power meters typically have a sensitivity as low as 50 milliamperes

It is convenient to use a polyphase power meter rather

than the “spaghetti jungle” associated with all of the

individ-ual meters necessary to monitor the full system Additionally,

modern power meters have functions such as event memory,

printing facility, and even on-screen phasor diagrams

In the planning, do not forget to determine where and

how to obtain the signal sources that are to be measured In

some cases, relay test switches or test plugs can provide the

secondary variables In other cases, microprocessor-based

relays can actually provide the desired information either

directly on the relay display or via a computer

Example

Th e example comes from a 600 MW peaking station A

partial one-line is shown in Figure 1 Th e test was performed

initially to assess problems with the 345 kV line diff erential

scheme However in the process, several problems with the

transformer diff erential schemes were uncovered

There are several considerations when making the

calculations:

A Current magnitude at all system voltages must be high

enough to provide adequate current transformer

sec-ondary values to reliably register on available

meter-ing

B Current magnitude must be at a level that does not

overload system components

C A source of suffi cient kVA capacity and correct voltage

level must be available

Th e two most common three-phase low voltage systems

in the United States are 208Y/120V and 480Y/277 Th is

example was calculated knowing that a 1000 kVA, 480Y/277

source was available on site for construction power

Calculation of Fault Current

Calculations are made in per unit and usually most

conve-niently on the transformer base of the transformer used as

the fault limiting impedance

Th ose with experience in per unit calculations will recognize

on the 345 kV system current will be:

18 kV

Fault = 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?

Source kVA = 3* Fault *kV L-L

= 1.732 * 936 * 0.48

= 778 kVA

So our 1000 kVA source was large enough, but it was

prudent to remove existing loads; therefore, the tests were

planned for the lunch hour

Th e electrical contractor installed a temporary run of

two 500 kcmil cables per phase with necessary barricades

and warning tape Before the contractor installed the cable,

calculations were made to insure adequate current would

be available in the CT secondaries Th e fi rst problem was

uncovered here Th e CT ratios on the 345 kV system were

not the same at each end of the protected line and could not

be made equal by tap selection Th e coordination engineer

was notifi ed and new settings were developed to

accom-modate the problem

Calculation of CT Secondary Current

At the peaking station the 345 kV CTs were 1200/5

Both currents were larger than the minimum 50 mA

re-quired for reliable phase angle measurement by the meters

we were using

Th e CTs on the 18 kV side at the peaking station were

8000/5 ratio and provided more than adequate current for

monitoring the 18 kV winding currents in the transformer

diff erential relays:

936 A

Relay = ——— = 0.585 A

1600

After checking that the through-fault current magnitude

was less than any of the components, we were fi nally ready

to proceed with the test Th e source was turned on, and the

transformer diff erential lockout relay immediately tripped

the MOD Fortunately, the transformer diff erential relay

had event recording, and it was soon apparent that there

were signifi cant problems with the 87T circuits Since the

utility engineers were waiting, we elected to disable the

87T and continue the tests on the 87L system Th ose tests

went very well Th e actual current was almost exactly what was calculated, and phase angle measurements confi rmed that the input currents to the line diff erential relays were as indicated on the drawings

Since the 87L currents appeared to be correct relative to the drawings, we joined with the utility engineers to review the entire scheme It was determined that the problem was with the design and not with the components A convenient place to reverse the polarity on one set of relays was located, and that system was fi nally functional

Once the main objective of the through-fault testing was accomplished, the unexpected transformer diff erential relay trip became the focus A number of problems were found with this system First, the design engineer had reversed the primary and secondary inputs causing an extreme ratio mismatch Further analysis of the event indicated one of the three CTs on the primary winding was reversed in polarity

Th is, despite the fact that the CTs had been tested for ratio and polarity, and the secondary circuits had been injected back to the relay

Although this example is somewhat extreme in terms

of the number of problems found, typically, through-fault testing will fi nd a problem or problems in the protection circuits

Roderic Hageman is President of PRIT Service, Inc His fi rm has provided consulting and testing for electric power distribution systems for more than 25 years He received his B.S in Electrical Engineering from Iowa State University and is a registered professional engineer

Mr Hageman has served two terms as President of the InterNational Electrical Testing Association (NETA) and nine years as a member of NETA’s Board of Directors He has three times been named NETA’s Man of the Year and continues to be very active in NETA

by providing leading edge independent electrical testing and

engineering services

CE Power provides:

Protective Relay Testing and Calibration

Protective Relay Upgrade Services

Arc Flash Hazard Analysis

Engineering Studies/Power System Evaluation

CE Power specializes in:

CE Power Solutions of Ohio

4500 West Mitchell Avenue

CE Power Solutions of Wisconsin

3255 West Highview Drive Appleton, WI 51914 800.434.0415 920.968.0281 phone 920.968.0282 fax info@cepower.net

Automated Test Point Cal cu la tions

for Electronic Re lay Testing

and Co or di na tion

NETA World, Summer 2000 Issue

Lonnie C Lindell and Steven R Potter SKM Sys tems Anal y sis, Inc.

Test Point Calculation for Relay ABC

Figure 1 — Sample spreadsheet for calculating test points

Modern software can be used to automate re lay

ting selection, documentation and test point spec i fi ca tion

Whereas electro- mechanical re lays are built to have a

cifi c time-current char ac ter is tic, mi cro pro ces sor-based relays

are available with pro gram ma ble selections of time-current

curve shapes and a wide range of pos si ble set tings To

to mate the gen er a tion of time-cur rent curves necessary for

relay co or di na tion and test ing, most mi cro pro ces sor-based

relays provide equa tions that can be used to generate the

curves Th ese equa tions can be used in simple spreadsheet

pro grams to generate time-current curves and to calculate

test points with very little eff ort Th e equations can also be

used in more so phis ti cat ed pro grams for relay co or di na tion

and test point specifi cation

In its simplest form, a spread sheet can automate cal cu

-la tion of test points Spread sheets can also be used to

generate complete setting sheets to doc u ment a more

ten sive series of tests It is important to note that a separate

spreadsheet may be required for each type of relay since the

equations, equation con stants and set ting ranges may vary

between diff erent relays Often an existing spreadsheet will

require only minor changes to be tai lored for a new relay

Using a spreadsheet to generate the test points di rect ly

from the re lay equation is substantially more effi cient than

reading points from the relay curves Th e spread sheet is also

more consistent and more reliable than read ing from the

curves A sim ple spreadsheet ex am ple is shown in Figure 1

In this sample spreadsheet, entering a time dial value

au-tomatically displays the cal cu lat ed test points based on the

equa tion shown New current mul ti ples can also be selected

by simply chang ing the cells with M=2, M=3 and M=5 for

2, 3 and 5x current mul ti ples

Spreadsheets combined with sci en tifi c plotting pro grams can be used to plot the relay time-current char ac ter is tics

by entering the re lay equations Mathematics and plot ting software combinations such as MathCAD™ can also use the relay equations to display the relay time-current char-

ac ter is tics While these methods can plot a sin gle curve, they stop short of pro vid ing com plete re lay co or di na tion and system protection func tions

System protection software that can incorporate

lished relay equa tions to generate time-current co or di na tion

curves and specify re lay test points is widely avail able Th ese

pro grams display damage and per for mance curves for power

sys tem com po nents such as motors, gen er a tors, trans form ers

and cables as well as time-cur rent response curves for relays,

fuses, cir cuit break ers and other protective devices

Figure 2 displays a sample co or di na tion drawing that

includes low-volt age motor protection with a motor cir cuit

protector and thermal-magnetic breaker; feeder pro tec tion

with a fuse; and transformer pro tec tion with a relay and

medium-volt age breaker

Figure 3 displays a sample co or di na tion drawing that

in-cludes me di um-voltage motor protection, feed er pro tec tion,

and trans form er pro tec tion with a combination of relays

Th e re lays include both elec tro me chan i cal and elec tron ic

equa tion-based relays

Many of the system protection and coordination

grams can also gen er ate relay test points A sample re port

that includes relay settings and test points is dis played in

Fig ure 3 Th e report was au to mat i cal ly gen er at ed by the

sys-tem protection and co or di na tion pro gram used to produce

the co or di na tion draw ing shown in Figure 3 Combining

the coordination, re port ing, and test point generation in a

single ap pli ca tion saves time and min i miz es errors

Th e important capabilities of sys tem protection and relay

test point specifi cation software include:

tab u lar data

the same drawing

points

ac ter is tics

Using software to automate relay setting selection,

docu-mentation, and test point specifi cation off ers sev er al benefi ts

to design and test engineers and tech ni cians:

chance for human error

en-hances understanding between mul ti ple en gi neers and

tech ni cians

saves time and money

Figure 2 — Sample protective co or di na tion drawing

Figure 3 — Sample protective co or di na tion drawing

With these substantial benefi ts and a relatively small

investment in time and resources needed to im ple ment

a software solution, there is no reason to use traditional

time-cur rent curves for selecting re lay test points for

tion-based elec tron ic relays From simple spread sheets to

so phis ti cat ed pro tec tive co or di na tion soft ware, using

pub-lished relay equa tion data will sub stan tial ly au to mate system

pro tec tion and relay test point spec i fi ca tion

Lonnie C Lindell is General Manager of SKM Systems Analysis, Inc.,

an electrical en gi neer ing company spe cial iz ing in pow er sys tem analysis

software de vel op ment He received a BS from the Iowa State Uni ver si ty

School of Engineering and an MBA from the Uni ver si ty of Phoe nix He

has over 15 years’ experience in the application of en gi neer ing com put er

software, is active in ed u ca tion and en gi neer ing pre sen ta tions, and is a

member of the IEEE.

Steven R Potter is a senior support en gi neer for SKM Systems

Analy-sis, Inc where he specializes in protective coordination and protection

equipment computer mod el ing He received his BSEE from San Diego

State Uni ver si ty He has over eight years’ ex pe ri ence in the ap pli ca tion of

engineering com put er software, is active in en gi neer ing ed u ca tion, and

is a member of the IEEE.

13800.0V

@5.0X, 0.970s

13800.0V

Figure 4 — Sample setting table including automatic relay test point specifi cation

Test & Maintenance Tips for Pro tec tive Relays

NETA World, Winter 2000-2001 Issue

by Scott Cooper Beckwith Electric

Figure 1 — Screen from IPSplot® Oscillograph Anal y sis Soft ware

showing a diff erential trip Th e vertical var ie gat ed line in center

indi-cates the break er tripping and subsequent Beckwith relay operation

Th e suspected cause is a wiring problem in their CT circuit.

Beckwith Electric pro tec tive relays in cor po rate several

self-checking routines that continuously monitor crit i cal

functions When an in ter nal fault is de tect ed the re lay safely

removes it self from ser vice and clos es the di ag nos tic contact

Th ese self-test func tions, how ev er, can not de ter mine the

in teg ri ty of a sta tus in put or trip cir cuit nor de tect small

prob lems in CT or VT cir cuits To verify the in teg ri ty of

these cir cuits, we rec om mend rou tine ly check ing the re lay’s

me ter ing dur ing nor mal op er a tion and per form ing the

di ag nos tic test pro ce dure dur ing out ag es Th e output trip

cir cuits can be ver i fi ed by ex er cis ing the out put re lays and

check ing the ex ter nal trip cir cuits for cor rect op er a tion Th is

com bi na tion of in ter nal self-di ag nos tics, in put ver i fi ca tion,

and out put test ing as sures that the re lay is ready to protect

the sys tem Th is main te nance should be per formed

cord ing to each com pa ny’s schedule To pre vent a lay er of

in su lat ing silver ox ide from foul ing the case con tacts, we rec om mend pe ri od i cal ly reseating M-0420 and M-0430

re lays in the drawout case

One of the most useful and of ten overlooked di ag nos tic features of our relays is the oscillographic re cord er With the recorder, up to 170 cycles (96 cycles in the M-0420 and M-0430 relays) of prefault in put wave forms can be recorded au to mat i cal ly Th e re cord er may be triggered manually or by the op er a tion of any output or input com-

bi na tion cho sen by the user Once triggered, this form data can be easily transferred from the re lay using the IPScom® Com mu ni ca tions Software Th e waveform may then be analyzed using the available IPSplot® Os- cil lo graph Anal y sis Software Th e re sult ant data can be

wave-a vwave-alu wave-able tool in de ter min ing the root cwave-ause of wave-a relwave-ay operation

If periodic functional testing is desired, consider that a single-phase or even a three-phase test set can not duplicate system con di tions for a relay which has seven current inputs and four voltage inputs Con se quent ly, the technician has

to disable or alter the setpoints of oth er functions to pre vent

in ter fer ence with the func tion under test Th is could result in the relay be ing placed back in service with a critical func tion

ac ci den tal ly dis abled To minimize this pos si bil i ty, use the IPScom software shipped with the relay to save the relay’s data fi le before testing Then write the same fi le back to the relay af ter testing Th is prac tice can dra mat i cal ly reduce the possibility of setting er rors while also pro vid ing a convenient record of “as found” settings

Successful functional testing of these relays in volves a few steps First, study the functional de scrip tion from the relay instruction book, carefully noting any special fea tures Sec ond, connect the relay exactly as it will be connected

to the system Th ird, isolate the function under test with the IPScom soft ware’s con fi g u ra tion screen Fourth, apply the nominal quan ti ties and check the metering using the IPScom soft ware’s secondary me ter ing screen Fi nal ly, ap-

ply the test quantities and check your results If the re sults

are not satisfactory, check the secondary me ter ing screen

again with the fault quantities applied If incorrect, check

con nec tions and inputs; if correct, check the function logic

de scrip tion and testing in struc tions

By performing this routine maintenance as re quired,

you are helping to ensure the integrity and reliability of

the protective relay

Scott Cooper, Field Service En gi neer, joined Beckwith Electric

Co in 1997 His responsibilities in clude training, commissioning, and

troubleshooting protective re lays for customers He is also in stru men tal

in testing new relay products and custom-en gi neered systems Scott was

previously an electronics technician at Beckwith testing pro tec tive re lays

and conducting failure anal y sis and in di vid u al component eval u a tions

He is a member of IEEE.

Using I op Characteristics

to Troubleshoot Transformer

Differential Relay Misoperation

PowerTest 2001 (NETA Annual Technical Conference)

Michael Thompson and James R Closson

Basler Electric

Abstract – When a transformer diff erential relay operates

with no obvious transformer fault, system operators have

a serious decision to make Is there a transformer fault, or

did the relay operate incorrectly? Testing the transformer

requires signifi cant time, with the associated direct and

indirect costs to do so On the other hand, reenergizing

a faulted transformer can lead to catastrophic equipment

failure Th is scenario of a questionable transformer operate

occurs more often than we would like to think, particularly

during the equipment commissioning process

Several conditions can cause diff erential relay false

trip-ping Th ese conditions can cause false trips from external

faults, or simply increased transformer loading Some

in-dication is needed that the relay is not operating as desired

before an incorrect operate happens A potential problem

can be identifi ed by monitoring the operating condition of

the diff erential relay Indications provided by this

monitor-ing can serve as a warnmonitor-ing if the settmonitor-ings or connections are

not correct

Th is paper will explore the issues contributing to

trans-former diff erential false trips, and suggest methods to

al-leviate this issue

Reviewing Differential Relaying Principles

When assessing relay system operation, a basic

under-standing of diff erential relay operation is necessary A

sum-mary of the concepts follows:

Figure 1 — General Diff erential Principle

Diff erential relaying off ers the highest selectivity and, therefore, the highest speed and most secure type of system protection In theory, a diff erential relay compares the cur-rents into and out of the protected zone If the sum of the currents is not zero, the relay will operate Th is is shown in the phasor diagram, Figure 2

Th e sum of the currents is identifi ed as the operate

conditions external to the protected zone Accordingly, coordination delay times are not necessary, and sensitivity can be optimized

Figure 2 — Phasors of Ideal Non-Fault Condition

Diff erential relaying relies on the quality of the incoming

currents from current transformer secondaries Th erefore,

CT performance is of particular concern in this application

Although the relay must be desensitized to ensure security

for all non-fault conditions, it must remain highly

sensi-tive to faults within the zone of protection To accomplish

this, a fi xed minimum pickup setting is commonly used, as

well as percentage restraint Percentage restraint increases

the amount of unbalance, or operate, current needed to

actuate the relay based on the current fl owing through the

protected equipment Th e restraint setting, or slope, defi nes

the relationship between restraint and operate currents (See

Figure 3) Relays vary in the way they defi ne the restraint

common methods are to take the average of the two

cur-rents (current entering the zone and current exiting the

zone) or to take the maximum of the two currents to use

in the percentage ratio

Figure 3 — Percent Restraint Characteristic

Transformer Differential Specifi cs

Transformer diff erential relaying does have some

com-plications, which can be the source of errors in connections

and set-up As noted, diff erential relaying is based on

vir-tually balanced current into and out of the protected zone

However, a transformer is not a balanced current device

Th e currents into and out of a transformer will diff er by

the inverse of the transformer’s voltage ratio Th us, the

as-sociated currents need to be adjusted to represent a balance

during non-fault conditions To a great extent, this

adjust-ment can be accomplished with the selection of the system

current transformers Th e fi nal balancing is accomplished in

the relay’s TAP settings Th e TAP settings scale the input

currents, eff ectively defi ning per unit values Th e success of

this balancing is measured by the mismatch, which is the

percentage diff erence between the ratio of the currents seen

by the relay and ratio of the relay taps

Figure 4 — Transformer Diff erential Relaying

Th ere are also conditions on the power system that create unbalance currents in a transformer but do not represent transformer faults When system voltage is applied to a transformer at a time when normal steady-state fl ux should

be at a diff erent value from that existing in the transformer,

a current transient occurs, known as magnetizing inrush rent Th e diff erential relay must detect energization inrush current and inhibit operation Otherwise, the relay must

cur-be temporarily taken out of service to permit placing the transformer in service In most instances this is not an op-tion Th e harmonics in faults are generally small In contrast, the second harmonic is a major component of the inrush current Th us, the second harmonic provides an eff ective means to distinguish between faults and inrush

Almost every transformer diff erential relay available

the energization current A parallel ‘high set’ operate level

is included to ensure that larger faults will still be detected during energization Th e high set, unrestrained element is also provided to ensure operation for a heavy internal fault such as a high side bushing fl ashover Th is high grade fault may result in CT saturation, which can generate signifi -cant harmonics that may restrain the sensitive harmonic restrained element Th is is shown in Figure 5

External faults can also cause unbalanced currents in a power transformer, depending on the transformer’s connec-tions A Wye connected transformer winding can act as a power system ground source, providing ground current to external faults Th is unbalanced current must be blocked from the diff erential circuit to ensure relay security Th is blocking is usually achieved by a Delta connection in the as-sociated relay input transformer circuit, which traps the zero sequence (ground) current component Th is delta connection can be achieved either with the current transformers, or, if

an option, within the transformer diff erential relay itself

An important issue with transformer diff erential relaying

is the phase shifts inherent in most transformer connections

A delta connection in a power transformer aff ects a 30°

phase shift in the associated currents Since the diff

eren-tial relay compares the currents on an instantaneous basis,

this phase shift will create an unbalance, which must be

compensated Th is compensation is usually achieved with a

corresponding delta connection in the CT secondary circuits

and must be coordinated with any zero sequence blocking

connections required

Many transformers are connected with delta windings

on the high side and wye windings on the low side Th is provides isolation between the power system voltages and

a ground source for detecting faults on the low voltage side

Th e three-line drawing, Figure 6, shows a delta/wye former with the associated phase shifts In this example, the phase shift is accomplished by connecting the CT’s on the wye side in a delta confi guration Th e required phase shift compensation can also be accomplished within the diff erential relay Th is is desirable for several reasons Prob-ably the most important of these is that it allows the CT’s

trans-to be connected in wye, making them easier trans-to connect and verify during installation

Figure 5 — Simplifi ed Block Diagram

Th e presence of a Load Tap Changer (LTC) in

trans-formers will also aff ect diff erential relay operation Usually,

these taps provide the possibility of modifying the voltage

ratio 10% for voltage or Var control Th is ratio variance,

in turn, varies the current ratios Th is variation is usually

within the security margin provided by the relay’s restraint

characteristic For a given LTC position, the ratio of operate

current to restraint current will remain constant, as shown

For each case discussed, the TAP settings are presumed

to be set to the transformer’s full load current Th is defi nes the 1 per unit value to be equal to full load Th is is the easiest setting to calculate, and simplifi es analysis Th e minimum pickup of the transformer diff erential relay is taken as 0.35

trans-former full load, given the defi ned setting A restraint slope

of 40% of maximum restraint current is assumed Th e % of Maximum characteristic is preferred because it uses infor-

mation from the best performing CT to restrain the relay

A relay using % of Average restraint current would provide diff erent results but the concepts are the same In modern numerical diff erential relays, the restraint characteristic may

be user-selectable

Figure 6 — Phase Shifts in Transformers

Figure 11 — Operate Characteristic with Reversed Input Current

Th ere are two problems that can occur with phase shift compensation Th e engineer performing the work can forget

to apply compensation or compensation can be incorrectly applied

When a transformer includes a phase shift, a

correspond-ing adjustment must be made in the relay scheme Th is is

generally accomplished by connecting the relay input rents in delta, and can be done either at the CT inputs or within the relay’s circuitry Th e proper correction is shown

cur-in phasor diagram cur-in Figure 12

Figure 12 — Transformer Diff erential Phasors with Proper Phase

Shift Adjustment

If phase shift compensation is not performed when the

relay As load increases, the relay will begin to see an ance Th e diff erential relay will interpret this unbalance as

unbal-a funbal-ault unbal-and operunbal-ate Phunbal-asor unbal-anunbal-alysis, Figure 13, shows thunbal-at

an uncompensated 30° phase shift will cause an unbalance current that is approximately half the normalized load cur-

Figure 13 — Phasor Diagram with Missing Phase Shift

Single Restraint Input

If one set of current transformers is not connected to the

diff erential relay or the current transformers are shorted out,

the diff erential relay acts as an overcurrent relay Given this

Figure 8 — Transformer Diff erential Phasors with Missing Input

Current

When the single input current exceeds the minimum

pick-up the relay will operate So for this scenario, the

trans-former will trip at 35% of full load under this condition

Figure 9 — Operate Characteristic with Missing Input Current

Current Transformer Lead Reversal

Reversing a current transformer lead, or group of leads,

is the simplest mistake made when wiring a new panel or

upgrading a protection system Since the diff erential relay

compares the transformer currents, CT polarity is extremely

important When a CT lead is reversed, the resulting

unbal-ance current is double the normalized load current Th at is

diagram, Figure 10

Figure 10 — Transformer Diff erential Phasors with Reversed Input

Current

Under this condition, increased loading will cause the

35% of transformer full load (based on the setting tions) Th is will be when the load (restraint) current reaches 17.5% of full load (or 17.5% of TAP setting) Th is condition

presump-is plotted on the characterpresump-istic graph in Figure 11

If this condition exists, the relay will operate with

in-creases in load, unless the restraint slope setting is larger

transformer full load (based on the previous setting

pre-sumptions) Th is will occur when the load (restraint) current

reaches 68% of full load (or 68% of TAP setting) Figure 14

shows this situation

Figure 14 — Relay Operate Characteristic with Missing Phase Shift

Another error can occur by incorrectly applying a phase

shift For example, shifting the relay input on the delta side

of a delta/wye transformer While the required phase angle

adjustment is achieved, the necessary zero sequence blocking

is not provided In this case, the diff erential relay will operate

for external ground faults on the wye side of the transformer

Th is condition is not detectable by taking readings under

balanced loading conditions Th e other incorrect shift is a

phase shift in the wrong direction

As shown in Figure 15, there are two ways to apply a delta

connection Each aff ects a 30° phase shift, but in diff erent

directions If the wrong connection is applied, it will result

in a 60° diff erence rather than proper phase compensation

will operate with increasing load Phasor analysis, Figure 16,

shows that a 60° diff erence in the relay currents will cause

an unbalance current equal to the normalized load current

Figure 16 — Phasor Diagram with Wrong Phase Shift

Th e relay will operate when the load (restraint) current reaches 35% of full load (or 35% of TAP setting) as shown

in Figure 17 Th is is a similar level of load to the scenario where one side of the diff erential zone is completely missing

as shown in Figure 9

Figure 15 Two Delta Applications

Figure 17 — Operate Characteristic with Wrong Phase Shift

Transposed Tap Settings

Incorrect TAP settings can occur when the TAP settings for the relay are transposed Th at is, the high side TAP setting

is applied to the low side input, and vice versa Th e resulting relay performance will depend on how closely matched the

current signals into the relay are If the currents into the relay are very close, the TAP settings will also be similar, and relay security may not be aff ect-

ed However, if the inputs are substan-tially diff erent, the resulting unbalance will likely cause the relay to operate and cause a nuisance trip

For example, presume a condition where the currents

to the relay are 3.8 amps on the high side and 4.2 amps

on the low side Th e proper relay TAP settings would be

3.8 for the high side input and 4.2 for the low side input

If the settings are transposed, the current magnitudes will

be incorrectly scaled Th is results in a mismatch of 22%, as

shown below

Mismatch = (current ratio) - (TAP ratio)

smaller of abovewith proper settings:

Mismatch = (3.8/4.2) - (3.8/4.2) = 0%

(3.8/4.2)with transposed settings:

Mismatch = (3.8/4.2) - (4.2/3.8) = 22%

(3.8/4.2)

In this example, the security of the relay will depend

on the setting of the restraint slope At a slope setting of

15%, the relay will operate on increasing load, when the I

restraint exceeds about 1.6 multiples of TAP or at 160 % of

transformer full loading At a slope setting of 40%, it would

not operate on load However, the security margin would be

reduced by this mismatch Figure 18 shows this example

3 Factor Neglected In Tap Settings

Another TAP setting problem that can occur is to

overlook the magnitude increase associated with a delta

connection in the current circuit Th is is a by-product of

the phase shift adjustment, and must be taken into

ac-count Th e magnitude shift is the square root of 3, or 1.73

Th is magnitude compensation must be included if the

delta compensation is achieved with CT connections It

may or may not be required if the delta compensation is

achieved internal to the relay Care must be taken to review

the operating characteristics of the relay in question when

calculating tap factors Th is problem is mitigated in some

numerical relays that are capable of automatically calculating

their own tap adjust factors

Using the previous example of 3.8 and 4.2 as the currents

into the relay, assume that the 4.2 amps current requires a

phase shift Th e delta compensated 4.2 amps is now eff

ec-tively 4.2*1.73=7.3 amps for the diff erential element Th us,

for the delta side of the transformer, 3.8 amps = 1PU and,

for the wye side of the transformer 7.3 amps = 1PU Th e

proper current ratio is now (3.8/7.3) rather than (3.8/4.2)

If the protection engineer overlooks this, the resulting

mismatch will be:

Mismatch = (3.8/7.3) - (3.8/4.2) = 73%

(3.8/7.3)

Th is will clearly cause a problem Th e relay will operate at

48% of transformer full load current in this case Th e eff ect

of this setting error is shown in Figure 19

Figure 18 — Characteristic with Bad Tap Settings

Figure 19 — Relay Operate Characteristic with Missing √3 Factor in Taps

Checking and Troubleshooting Differential Circuits

Field personnel can apply the lessons noted in this per in order to troubleshoot CT connections and rectify problems For example, a quick simple check of measuring the current in the operate coil of the diff erential relay may

pa-be suffi cient to detect the gross problems descripa-bed such as reversed polarity or one CT completely missing However, many of the problems identifi ed result in relatively small mismatches

Th is check also does not acknowledge the fact that the relay can adjust for magnitude mismatch by its tap settings For example, a properly designed diff erential relay circuit with one tap set at 5 amps and the other set at 10 amps would result in 5 amps of operate current under full load balanced conditions On one side of the zone 5 amps = 1PU, while on the other side of the zone 10 amps = 1 PU

which would be 10 – 5 = 5 amps for this example

A better approach is to measure and record both the nitude and angle of the restraint currents at each terminal

mag-of the relay For example, the criteria should be:

• Th e ratio of the magnitudes of the restraint current on each phase should be equal to the ratio of the magni-tudes of the tap settings

• Th e currents on each phase relay should be nearly

ex-actly 180° out of phase

Differential Current Monitoring as a

Diagnostic Tool

Modern relays with internal phase compensation do

not allow the fi eld engineer to do it the old way with phase

angle and magnitude readings It is necessary to see the

values seen by the diff erential element after they have been

manipulated inside of the relay, and this cannot be done by

direct measurement Other methods must be employed

As this paper has noted, there are many connection or

setting problems that can cause incorrect operations in

transformer diff erential relays Th e task is to detect these

problems before an incorrect relay operation Diff erential

current monitoring is a diagnostic function designed to aid

in the installation and commissioning of diff erential relays,

especially on transformer banks Th is function attempts to

identify and prevent false trips due to incorrect polarity,

incorrect angle compensation, or mismatch

During transformer commissioning, it would be

particu-larly useful to analyze the system installation and create a

record of the settings and measured currents Th e diff erential

current monitoring function can create a diff erential check

record like the sample shown in Figure 20 Th ese records

are also useful when comparing the present system

char-acteristics to the charchar-acteristics at commissioning during

troubleshooting to determine if something has changed

Th e diff erential check record shown in Figure 20 is an

example of a diff erential current check record developed by

a numerical diff erential relay Th is particular example is from

an actual installation Th e names and dates on the record

have been changed Upon putting load on the transformer

bank after installing the upgraded protection, the diff erential

relay alarmed, triggering the diagnostic routine to generate

this report, and tripped Th e relay’s trip outputs were not

connected at the time

Th e fi rst grouping of information in the record is the

date and time the record was captured and the basic relay

identifi cation Th e second grouping is a record of the CT

and transformer connection settings and the 87 (diff erential)

settings that were entered by the user Th e third grouping is

a report of the tap and angle compensation factors that the

relay is using for each of the three phase CT input circuits

It is important to note that the angle compensation cannot

be entered manually Th e angle compensation is calculated

by the relay based on the CT and transformer connections

Additionally, the tap compensation setting may be entered

manually or automatically calculated

As mentioned earlier in the paper, a transformer delta winding can be confi gured in two ways: Delta IA-IB or Delta IA-IC Th e type of delta and the normal phase se-quence of the system determines whether the phase shift will be +30 degrees or –30 degrees From the information

in the report, it can be noted that the user has described the transformer winding connected to CT circuit 1 of the relay as a delta with DAB (Delta IA-IB) connections; and the transformer winding connected to CT circuit 2 of the relay is described as a wye confi guration Th is would be

a pretty safe assumption based on the fact that an ANSI standard delta high-side/wye low-side transformer uses this confi guration so that the low side lags the high side by 30 degrees when system phase sequence is ABC

Th e fourth grouping of information in the record tempts to identify polarity and angle compensation errors by looking at the phase angle diff erences of compared phases

at-Th e diff erential alarm is set whenever the minimum pickup

or the slope ratio exceeds the diff erential alarm, percent of trip setting If the diff erential alarm is set and neither the polarity alarm nor the angle compensation alarm is set, a mismatch error is identifi ed indicating that the most likely cause of the alarm is incorrect tap settings In this example, the record clearly identifi es that the problem appears to be with the angle compensation

The fifth grouping of information MENTS) displays the measured and calculated currents

(MEASURE-at the time of the diff erential record trigger Th e relay measures secondary current and develops the tap and phase compensated currents for use by the diff erential element Primary current (MEASURED I PRI) is calculated simply

as the secondary current multiplied by the CT turns ratio Secondary current (MEASURED I SEC) is the current actually measured by the relay Angle compensated current (ANGLE COMPENSATED I) is the measured secondary current with phase compensation applied Tap compensated current (TAP COMP I) is the tap and phase compensated current actually used by the diff erential function From this information, it is easy to see how the relay goes about compensating for magnitude and angle diff erences between the two sides of the zone of protection

Th e fi nal two lines of the report give the most critical information IOP is the operating current SLOPE RATIO

is the ratio of IOP to the restraint current (in this case it is the maximum of the two TAP COMP I currents) Th ese values should be compared to the settings shown earlier

in the report to determine if the relay is in a trip or alarm condition

Figure 21 shows the A phase currents before and after compensation plotted on a polar graph From the informa-tion in Figures 20 and 21, it is easy to see that the internal phase compensation is the opposite of what it should be and that the currents were shifted 30 degrees the wrong way In this installation the transformer being protected was actually a delta IA-IC/wye confi guration and that the low side leads the high side by 30 degrees Changing the transformer connection parameters in the relay’s settings, corrected the problem

Tap Side Low

Tap Side

High Current

Side

Low

Current Side

High

_ _

_

_ _

_

_ _

Th is facility of modern relays can also be used to simplify

commissioning and documentation To verify correct CT

circuit connections, internal phase, zero sequence and tap

compensation settings for the diff erential functions, load

should be placed on the protected zone and a diff erential

check record triggered, recorded, and examined Th e check

record can then become a permanent relay commissioning

record

Summary

Diff erential protection is simple in concept Measure the

current that goes in versus what goes out If there is a

dif-ference, there must be a short circuit within the protected

zone and a trip should occur When the protected zone

includes a transformer, the situation is not so simple and

special considerations must be made One of the greatest challenges is compensation for phase angle and magnitude diff erences Th e paper describes the eff ects of many of the possible errors that can be made in installing and checking out a transformer diff erential circuit

Proper installation checks and fi nal in-service readings can detect these problems and ensure reliable and secure op-eration Th e paper describes these traditional fi nal in-service checks However, with modern solid state and numerical diff erential relays, traditional checkout procedures may not

be capable of detecting all possible errors For this type of relay, diagnostic routines and reporting functions can make

up for this It is important for the relay technicians and engineers to make use of these advanced features to ensure proper operation of the protection system

Figure 20 — Annotated Diff erential Check Record

Annoted Differential Check Record

Figure 21 — In-Service Current Circuit Verifi cation Form

1 Blackburn, J Lewis, Protective Relaying Principles

and Applications, Second Edition, Marcel Dekker,

Inc., New York, 1998

2 ANSI/IEEE C37.91-1985, IEEE Guide for Protective

Relay Applications to Power Transformers

3 Criss, John, and Larry Lawhead, “Using Transformer

Conditions”, Protective Relay Conference at Georgia

Institute of Technology, April 1997

Jim Closson received his BS from Southern Illinois University at

Carbondale, and an MBA from the University of Laverne Prior to

rejoining Basler Electric as a Protection and Control Product Manager,

he served as a Regional Application Engineer for Basler Electric He has

also held managerial and sales positions with Electro-Test, Inc and ABB

He has taught courses on Electrical Power Systems Safety, Ground Fault

Applications and Testing, and Power System Maintenance Mr Closson

is a Senior Member of the IEEE and serves on the Power Distribution

Subcommittee for the Pulp and Paper Industry Committee of the IAS

and on the Transportation Subcommittee for the Petrochemical Industry

Committee of the IAS

Michael Th ompson served nearly 15 years at Central Illinois Public

Service Co where he worked in distribution and substation fi eld

opera-tions before taking over responsibility for system protection engineering

He received a BS, Magna Cum Laude from Bradley University in 1981

and an MBA from Eastern Illinois University in 1991 During his years

at Bradley University, Mike was involved in the cooperative education

program and worked in electrical engineering and maintenance at a

large steel and wire products mill Mike is Senior Product and Market

Manager for the Protection and Control Product Line at Basler Electric

Mr Th ompson is a member of the IEEE

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Published by InterNational Electrical Testing Association

Volume 1

Motor Protection Fundamentals

PowerTest 2001 (NETA Annual Technical Conference)

Bernie Moisey Northern Alberta Institute of Technology

Summary

To enter set points into modern management type motor

protection relays for a specifi ed motor the end user must be

familiar with all of the motor characteristics and is able to

interpret the technical data supplied by the manufacturer

Without this knowledge the protection scheme could result

in one that over or under protects the motor

Motor Specifi cations

Th e following motor data could be considered minimum

requirements for a protection scheme on a large motor:

Horse power; voltage rating; full load speed; type of motor;

frequency; full load torque; breakdown torque; locked rotor

torque; service factor; NEMA design; insulation class;

sym-metrical locked rotor amps at rated voltage; type of

enclo-sure; maximum temperature rise at specifi ed load; ambient

temperature; kVA code; current at 100%, 75%, 50% and

no-load; power factor at full load; no-load and locked rotor

current; effi ciency; cold and hot safe stall time; power factor

correction data; load inertia; rotor inertia; load torque

dur-ing the acceleration period; time-current and hot and cold

thermal limit curves; motor starting and accelerating curves;

speed curves at diff erent voltages; performance curves;

per-missible starting sequence; minimum time between starts;

number of starts per hour and residual voltage data

Symmetrical Components

Most microprocessor based motor protection relays use

symmetrical components in thermal and unbalance

algo-rithms Some relays estimate positive, negative and zero

sequence quantities while others use the actual sequence

equations A good understanding of these fundamentals is

required to select appropriate set points and to design test

circuits to verify relay operation

Voltage

Th e voltage on the nameplate of a motor may diff er from the system nominal voltage, i.e 4000 volts on the nameplate connected to a 4160-volt system In most cases when the motor is started, the voltage at the motor terminals will “sag”

To ensure that suffi cient 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 “sags” on start the locked rotor/starting current will decrease Because the motor is driven into saturation at rated starting voltage, the starting current is not directly proportional to voltage Th is must be considered when entering set points for locked rotor protection Setting alarm set points for current unbalance requires that one must be able to determine an acceptable current unbalance by converting the normal system voltage unbalance to current unbalance Set points are also required for over voltage and reclosing when the residual voltage is present

Grounding

Electrical systems may be ungrounded, direct or solidly grounded, low impedance grounded and high impedance grounded In all cases the magnitude of the charging cur-rent or the line to ground fault current must be known Th e ground element of the relay must be connected to detect this abnormal condition and disconnect the motor as quickly

as possible

Th e two most common methods of connecting ground relays to the system are using a zero sequence current transformer and the residual connection In each connec-tion it is possible for the ground element to receive a false signal, which could result in the motor being taken off line Compensation must be considered when determining set points to minimize nuisance trips Th e residual connection uses three current transformers False ground fault signals can occur due to unbalanced phase burdens, asymmetrical starting current and the normal mismatch of the three cur-

rent transformers Compensation for these false signals can

be achieved by increasing the pick up or by increasing the

time delay False signals can enter the ground relay through

the zero sequence connection If any triplen harmonic is

present in the primary circuit this will pass through the

zero sequence current transformer and appear as a ground

fault When two motors are connected to the same bus, the

running motor can trip out when the other motor is started

A “sagging” bus voltage combined with the residual voltage

and noise that is generated during the starting sequence

can result in a trip Compensation for the zero sequence

connection is achieved by a short time delay set point, not

instantaneous

In high impedance grounded systems, the neutral

limit-ing resistor limits the fault current to a magnitude of 1 to

10 amps High impedance faults may be diffi cult to detect

and low set points may result in false trips When this is

the case, the use of a low pick up directional relay with an

angle of maximum torque, current leading voltage should

be considered

Thermal Limit Curves

Large motor manufacturers include thermal limit curves

as part of the specifi cations One is called the cold thermal

limit curve and the other is referred to as the hot thermal

limit Th e cold thermal limit curve is the limit of the

mo-tor when the momo-tor temperature is equal to or less than

curve is the thermal limit of the motor when it is operated

in the maximum ambient temperature, at specifi ed rise and

specifi ed load

All thermal limit curves consist of the following three

curves: locked rotor; failure to accelerate and running

over-load Th e locked rotor and failure to accelerate are voltage

dependent Th ese limit curves usually are plotted on

semi-log paper and the slope of the hot curve can be diff erent from

the slope of the cold curve When the limit curve is given for

a motor that can be started at two diff erent voltages, 100%

voltage and 80% or 90% voltage, the locked rotor thermal

curve appears as a straight line and the failure to accelerate

thermal limit curve is for the lower starting voltage When

the starting voltage is determined for a specifi c motor, the

limit curves must be altered to refl ect this condition Th e

time between the cold safe stall time and the hot safe stall

time can be of short duration, long duration or, in the case

of a motor that is “ring” limited, the hot safe stall time can

be equal to the cold safe stall time Also the acceleration

time can be greater than the safe stall time

Thermal Protection

Th ermal protection includes protecting the motor

dur-ing startdur-ing, acceleration and runndur-ing Manufactures of

microprocessor based motor protection relays will supply

the end user selects one that “fi ts” the motor characteristics

Other manufacturers allow the end user to generate a

time – current values in a look-up table Th e custom curve

provides fl exibility and results in a more reliable protection scheme

When designing the thermal protection scheme the engineer or technologist must determine the degree of protection Is the motor to be over protected or allowed

to operate at the maximum thermal limit? To accomplish this, an understanding of the relay’s thermal algorithm is

curve to “move downwards” when the motor temperature increases Th is is accomplished by multiplying all values in

the time – current look-up table by a constant Th e complete

protection curve moves “up or down” by the same proportion

Th e thermal algorithm can be biased by stator RTD inputs

or if RTDs are not used the biasing is accomplished with a

full load thermal capacity reduction set point.

Hot and cold thermal limit curves can be parallel or have diff erent slopes and may have acceleration time that

is greater than the safe stall time In each case care must

be taken to insure that the motor is protected in all three

intersect the thermal limit curve Where motors have a variable starting voltage and a long acceleration period, one may consider selecting a motor protection relay that has a

type of relay it is necessary to manipulate the thermal limit curve supplied by the motor manufacturer or at the time of ordering the motor, request limit curves for minimum and maximum starting and accelerating voltages Motors with acceleration times greater than the safe stall time may fail

to restart after a normal shutdown If this situation arises then it is necessary to adjust the thermal algorithm so that

protection curve

Protection – Phase Current

Set points are required for over current conditions that result from three phase and phase-to-phase faults that may occur on the load side of the current transformers Mechani-cal jam or rapid trip set points may be required to prevent the motor from stalling when maximum or breakdown torque is exceeded Under current protection may be used

as secondary protection to protect the mechanical load from damage, i.e a pump that uses the product as lubrication A phase sequence set point may also be required By entering the proper sequence the relay now has the ability to select the proper symmetrical component equations and prevent operation in the reverse direction When using an instan-taneous element to clear faults insure that the disconnect has the required interrupting capacity For some contactor applications it may be necessary to disable the instantaneous device Also the asymmetrical starting current must be al-lowed for If the sensitivity is too great, a small diff erence between the starting current and the maximum three-phase fault current, consider using diff erential protection Diff er-ential protection requires that all six leads from the motor

be accessible

Unbalanced Protection

Most microprocessor type motor protection relays have

two types of unbalanced protection One type uses alarm

and trip set points Th e other type of unbalanced

protec-tion involves biasing the thermal algorithm When the

motor draws an unbalanced current, the relay will calculate

an equivalent balanced current that will produce the same

motor heating Th is equivalent current, not the actual motor

current is used to determine the trip time Th e equivalent

current must be greater than the pick up for the algorithm to

be enabled Depending upon the manufacturer of the relay

the K factor, a ratio of negative sequence rotor resistance to

positive sequence rotor resistance may be pre-determined

or entered by the users

Th e ambient temperature plus the rise under ideal

con-ditions plus the rise due to the unbalanced current drawn

determines the temperature of a motor Th e temperature rise

due to unbalance depends upon the amount of unbalance

and the amount of load on the motor Care should be taken

to prevent the motor from being disconnected when it is not

stressed Most algorithms have fl exibility that allows the end

user to determine at what percent unbalance and percent

overload the algorithm is enabled Motors with a service

times the full load current, while a 1.15 service factor motor

allows the protection curve to be enabled at 1.25 times the

full load current By entering the appropriate service factor

as a set point the relay then determines at what unbalance

the algorithm is enabled Other relays allow a set point to

be entered as to when the protection curve can be enabled

Typical values for enabling the protection curve are 1.01

to 1.25 times the full load current of the motor Knowing

the unbalanced algorithm equation allows the protection

engineer to calculate the percent unbalance that is required

to enable the algorithm A typical equation is,

I e is the equivalent current calculated by the relay when the

motor draws unbalanced current

component

K is the ratio of negative sequence rotor resistance to

posi-tive sequence rotor resistance

IEEE states that for every 3% voltage unbalance the

temperature rise of the motor will increase 25% Motor

protection relays do not use voltage unbalance in algorithms,

they use current unbalance An approximation of converting

voltage unbalance to current unbalance is, for every 1%

volt-age unbalance at the terminals of the motor, the percent current

unbalance will be approximately equal to the per unit starting current expressed as a percent.

Control

Th e emergency start feature allows the operator to restart a

hot motor by resetting the thermal algorithm to zero percent thermal capacity used In some cases the relay will not allow

an emergency restart if the motor temperature exceeds the stator RTD trip set point

Start inhibit, when enabled, prevents a restart until suffi cient

thermal capacity is available Th ermal capacity required to start the motor is a “learned “ feature

Acceleration timer, when enabled, will lock out the motor if

it does not come up to speed in the specifi ed time

Backspin timer prevents a restart when the direction of motor

rotation is opposite to the norm, i.e a down hole pump

Time between starts, is a set point that controls the minimum

time between when the motor is fi rst started and when another start is allowed

Anti jogging, when enabled, prevents a series of rapid

start-stop operations It can be used for a lock out condition that prevents a restart when residual voltage is present

`Phase reversal prevents the motor from starting in the

“wrong” direction

Some relays have auxiliary contacts and logic that allow

the motor to start on a reduced voltage, i.e wye-delta,

auto-transformer, etc

Starter failure is a signal from the starter to the relay that

implies that the contacts have changed state Th is is the same as the 52b contact signal of an electrically operated breaker

Conclusion

To properly protect a motor the end user must be familiar with the motor characteristics and load requirements An understanding of the microprocessor based motor protec-tion relay algorithms allows for fl exibility Do not disable algorithms because you do not understand them

Reference

“Concepts of Motor Protection” written by B.H Moisey

Bernie Moisey has been an instructor at the Northern Alberta tute of Technology for 33 years and is currently teaching in the power systems and protective relaying section Bernie has presented motor protection seminars in Canada, United States, South America, and Australia He acts as a consultant for major manufacturers of protective relays designing and upgrading protection algorithms He is actively involved in application engineering.

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