2001 Survey of Relaying Test Practices

7/27/2019 2001 Survey of Relaying Test Practices

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This is a special report of the IEEE Power System Relay Committee.

Page i January 2002

Contents

1. Introduction.. 12. Personnel Requirements 1

2.1 Personnel who Calibrate, Test and Maintain Relays.. 12.2 Education Level Required.. 2

2.3 Training Requirements .. 23. Relay Test Procedures.. 4

3.1 Resources Used to Develop Relay Test Procedures.. 43.2 How Normal Relay Testing is Accomplished 5

4. Allowable Relay Calibration Tolerances... 84.1 Determination of Allowable Relay Tolerances.. 84.2 Relay Applications that Require Tighter Tolerances. 9

4.3 Relay Applications for which Looser than Normal Tolerances are Permitted. 104.4 Documentation of Allowable Tolerances by the Relay Users. 10

5. Factors that Influence Relay Test Schedules 115.1 Basis for Test Intervals for Relays in T&D Substations 115.2 Rationale for Shorter Test Intervals 135.3 Rationale for Longer Test Intervals 13

5.4 Basis for Test Intervals for In-Plant Relays (Generator, Switchgear, etc.) 145.5 Test Intervals Actually Met in Practice.. 14

6. Relay Test Intervals.. 156.1 Actual Relay Test Intervals Presently Used.. 156.2 Comparison of Relay Test Invervals with the 1991 Survey.. 20

7. Relay Test Equipment.. 25

7.1 Acquisition of Test Equipment.. 257.2 Passive vs. Solid State Relay Test Sets.. 257.3 Dynamic Relay Test Equipment. 257.4 Power Swing Test Equipment.267.5 Computer Controlled Test Sets.. 277.6 COMTRADE Compatibility and Usage. 27

7.7 Portability of Test Equipment. 28

8. Testing Protective Relays in a Particular Station.. 289. Protective Relaying Scheme Operational Test Conditions and Intervals..299.1 Operational Trip Testing. 299.2 Operational Trip Test Intervals.. 299.3 Personnel Who Perform Operational Trip Tests.30

10. Maintenance Program Effectiveness. 3010.1 Criteria Used3110.2 Correlation between Measurements and Failure Rates.. 3110.3 Satisfaction of the Utilities Maintenance Programs.. 32

11. Bibliography.. 33


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Page 1 January 2002

1. Introduction

In 1971, the IEEE Power System Relaying Committee reported the results of A Survey of Relay Test Practices[1], which reflected the responses of 125 electric utilities with a total of 1,157 generating stations, 5,096

transmission substations, and 17,849 distribution substations.

In 1991, the IEEE Power System Relaying Committee reported the results of A Survey of Relay Test Practices[2], which reflected the responses of 146 electric utilities with a total of 1,229 generating stations, 9,814transmission substations and 26,680 distribution substations.

This present survey is based on 2001 data supplied by 79 electric utilities with an aggregate of 632 generatingstations, 8,461 transmission substations and 12,499 distribution substations. Results of these surveys are comparedto show significant changes in test practices and a trend toward longer test intervals.

The figures included in this report are named to identify with the Section of the survey from which the results arecompiled.

2. Personnel Requirements

2.1 Personnel who Calibrate, Test and Maintain Relays

As a rule, the number of relay personnel is proportional to the size of the service area of the utility. Exceptions to

this rule are those utilities having highly congested and heavily populated service areas which require significantlymore relay personnel than do those utilities with an equivalent size service area that is less congested and not asheavily populated.

82 % of the respondents use specialists to calibrate, test and maintain their protective relays and associatedequipment. 18 % of the respondents use non-dedicated personnel to perform relay testing in conjunction with other

work such as circuit breaker, transformer, or battery maintenance. None of the respondents used any type ofcontract personnel for relay testing or maintenance.

Figure 1: Personnel who Calibrate, Test and Maintain Relays

6%

82%

8%0% 4%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

PercentageofRespondents

Specialists whocalibrate and

test relays only

Specialists whoalso do

functional

testing of relay

circuits

Non-specialistswho also work

on breakers,

transformers,

etc.

Outsidecontracted relay

testers

Other


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Page 3 January 2002

Figure 4: Training Hours per Test Personnel Each Year

Figure 5 shows that the working group foreman or test team group leader concept is widely used for trainingpurposes by most utilities. The idea behind this type of training is that groups of personnel are assigned to workunder the supervision of various knowledgeable senior relay foremen. Periodically, the various groups oftechnicians are rotated to work for another foreman until all the technicians have worked for all foremen. This typeof training has many advantages for management.

Figure 5: Utilities that Use a Working Relay Foreman or Test Team Group Leader to Train Relay TestPersonnel

Significantly, 97 % of respondents utilize the same personnel to maintain both electromechanical relays andelectronic relays, as indicated in Figure 6. Figure 7 indicates that most of the respondents require their personnel tohave specialized electronics training, which is normally provided as on the job training.

63%

37%

0%

10%

20%

30%

40%

50%

60%

70%


Use Do Not Use

16%

27%

31%

4%

35%

46%

36%

23%

16%16%

21%

27%

15%

6%

3%

12%

8%

3%3%

8%9%

3%1%

9%

0%0%

4%

14%

0%0%1%3%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%


None 8 hours or

less

8-16 hours 16-24 hours 24-32 hours 32-40 hours More than 40

hours

Other

Relay Manufacturers

Test Equipment Manufacturers

Relay-Specific Independent

Relay-Specific In-House


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Page 4 January 2002

Figure 6: Personnel who Calibrate and Maintain Non-Electromechanical Relays

Figure 7: Utilities that Require Specialized Electronics Training for Personnel who Calibrate and/or Test Non-Electromechanical Relays

3. Relay Test Procedures

3.1 Resources Used to Develop Relay Test Procedures

Figures 8 and 9 reflect the number of utilities who use In-House Procedures, Relay Manufacturers Data and/orEquipment Manufacturers Data for testing relays and their assessment of the value of each of these sources of datafor test procedures.

9 7 % 9 6 %

0 % 0 % 3 %4 %

0%

1 0 %

2 0 %

3 0 %

4 0 %

5 0 %

6 0 %

7 0 %

8 0 %

9 0 %

1 0 0 %

PercentageofRespon

dent

T h e s a m e p e r s o n n e l w h o

ca l i b ra te

e l e c t r o m e c h a n i c a l r e l a y s

P e r s o n n e l w h o d o n o t

ca l i b ra te

e l e c t r o m e c h a n i c a l r e l a y s

P e r s o n n e l w i t h s p e c i a l

t r a i n i ng to ca l i b ra te th i s

type o f r e l ay

M a i n t a i n N o n - E l e c t r o m e c h a n i c a l R e l a y s

T e s t & C a l i b r a t e N o n - E l e c t r o m e c h a n i c a l R e l a y s

84%

16%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Percen

tageo

fRespon

den

ts

Required Not Required


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Page 5 January 2002

Figure 8: Resources Used to Develop Relay Test Procedures

Figure 9: Value of In-House and Manufacturers Materials in Developing Relay Test Procedures

All of the respondents use the Relay Manufacturers materials as the basis for their testing, and many respondents

also use test equipment manufacturers materials to develop their test procedures.

3.2 How Normal Relay Testing is Accomplished

Figure 10 shows that 86 % of the respondents noted that they test relays using test plugs and secondary values, while10 % cleared the circuit and tested the relay circuit with secondary values. Only 1 respondent stated that his utility

tested relays using primary quantities.

99% 99%94%

1% 1%6%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%


Used Not Used

In-House Procedures

Relay Manufacturers' Material

Test Equipment Manufacturers' Material

8%

1%

8%

48%

27%

48%44%

72%

44%

0%

10%

20%

30%

40%

50%

60%

70%

80%

Percentageo

fRespondents

Of little value Some value Very valuable

In-House

Relay Manufacturers

Test Equipment Manufacturers


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Page 6 January 2002

Figure 10: How Normal Field Relay Testing is Accomplished

Figure 11 details the percentage of respondents who test other items during routine relay testing. It should be notedthat 28 % of those responding indicated that they perform all of the items shown in Figure 11 during the relaycalibration procedure.

Figure 11: Associated Items Also Tested During Routine Relay Testing

Figure 12 reflects that when field testing of electromechanical relays indicate that repairs are needed, 95 % of the

respondents rely on field personnel to do the repairs and only 5 % rely on the relay manufacturer. For non-

electromechanical relays, 25 % of the utilities rely on their field personnel, 3 % on trained lab technicians and 72 %on the manufacturer. This is a major shift from the 1991 survey where 62 % relied on their field personnel, 12 % ontrained lab technicians and only 26 % on the manufacturer.

1%

10%

86%

3%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

PercentageofResp

ondents

Applying primary

signals with the

primary circuit

cleared

Applying secondary

signals with the

primary circuit

cleared

Applying secondary

signals with test

plugs or drawout

relays

Other

42% 40%

88%

42%

29%

45%37% 38% 40%

16%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%


Meters

Insulationof

wiring

Testtripping

CT/PT

Continuity

CT/PTRatio

VerifyCT

connections

Phasing

potentials

Fuseblocks

Control

circuits

Other


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Page 7 January 2002

Figure 12: Personnel who Typically Repair Relays when Field Testing Determines that Repairs are Necessary

For use in testing non-electromechanical relays, Figure 13 indicates that 82 % of the respondents use test proceduresdeveloped especially for non-electromechanical relays.

Figure 13: How Field Testing is Accomplished for Non-Electromechanical Relays

Figure 14 shows that performance of relays in service is evaluated for relay operations during faults by analysis oftarget, event recorder and oscillographic data by 46 % of the respondents, while 40 % rely on periodic relay test

data. The 1991 survey revealed that 77 % evaluated performance of relays in service with operations during faultsby analysis of target, event recorder, and oscillographic data and only 22 % relied on periodic relay test data. Notethat the 1991 report stated that periodic relay testing seldom found problems with the relays.

25%

87%

3%

8%

72%

5%0% 0%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%


Field testing

personnel

Trained lab

personnel

Manufacturer Other personnel

Non-Electromechanical

Electromechanical

14%

82%

0% 4%

0%

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

Percentag

eofRespondents

Using established

procedures for

electromechanical

relays

Using special

procedures

developed for non-

electromechanical

relays

Remote initiation of

self-diagnostic

features

Local initiation of

self-diagnostic

features


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Page 8 January 2002

Figure 14: How In-Service Relay Performance is Determined

4. Allowable Relay Calibration Tolerances

4.1 Determination of Allowable Relay Tolerances

Figure 15 indicates that the majority of electric utilities surveyed use the protective relay Manufacturersrecommendations (65 %), while Knowledge and experience of the relay test personnel represents a significantnumber of electric utilities that rely on personnel within their respective organizations (27 %) for relay tolerances.

Figure 15: Determination of Allowable Relay Tolerances

The survey data indicates that a majority of relay manufacturers provide sufficient relay documentation that isacceptable to most engineers and technicians for maintenance and training purposes.

46%40%

0%

6% 8%

0%

5%

10%

15%

20%

25%30%

35%

40%

45%

50%


Analysis of

performance

after faults

(targets,

oscill., etc.)

Periodic relay

testing

Staged

primary faults

Self-checking

(internal relay

diagnostics)

Other

65%

27%

1% 1%6%

0%

10%

20%

30%

40%

50%

60%

70%


Manufacturers'recommendation

Knowledge andexperience of relay

test personnel

Regulationrequirement

No establishedtolerances

Other


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Page 9 January 2002

The combined number of responses consisting of selections No established tolerance, Other means or practices,and No response to this question (12.8 %) indicates that the determination of acceptable tolerances is completed

by an internal or external organization and the survey may not have been transmitted to that group. This observation

is verified by the additional comments provided indicating that this function is either contracted out or accomplishedby engineering. Relaying engineers that responded to other means or practices provided information explainingthat relay tolerances were set by established company guidelines.

4.2 Relay Applications that Require Tighter Tolerances

The purpose of this question is to determine if utilities establish tighter tolerances based on the individual relaycharacteristic, user application, function in a particular protective scheme or some other defined criteria rather than

just the individual relay type or manufacturer involved.

Figure 16: Relay Applications Requiring Tolerances Tighter than Those Normally Required

Although in the majority of cases non-electromechanical relays may have a more precisely defined pickup and

dropout characteristic, only 19 % of the responses to the selection Non-electromechanical versuselectromechanical felt that there is sufficient justification to warrant closer setting tolerances when using non-electromechanical relays.

User responses shown under the selection Impedance versus overcurrent (10 %) illustrates the concern of possibleoverreaching and the additional complexities associated with this type of relay. In general, the simple overcurrent

relay has a larger allowable error setting tolerance due to its application.

The response under selection Type of equipment being protected by the relay (16 %) most likely denotes theconcerns regarding major damage to critical types of power system apparatus and facilities.

It should be noted, however, that no distinction was made within the survey for the variety of more complex relaysbelonging to the overcurrent family of relays, such as those based on directional, negative sequence, or other definedsupervising characteristics.

The survey responses shown under the selection Relay application or other instantaneous trips (17 %) regardingapplication such as Zone 1 or other instantaneous trip functions indicates that closer tolerances are used for theseapplication. Concerns regarding overreaching may be a major factor that directs testing philosophy for these

applications.

19%

10%

16%17%

0%

9%

30%

0%

5%

10%

15%

20%

25%

30%


Non-electro-

mechanical

vs electro-

mechanical

relays

Independent

and similar

vs over-

current and

equivalent

Type of

equipment

protected by

relay

Relay

application

such as

Zone 1 or

other inst.

trips

Over-

reaching vs

under-

reaching

Nuclear

power station

application

Other


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Page 10 January 2002

Selection Overreaching versus underreaching (0 %) shows that an underreaching element is not more critical thanan overreaching element.

Utilities with nuclear facilities obviously have eminent concerns regarding certain regulatory procedures andperceived outage effects. Tolerances are more closely reviewed than for companies without nuclear installations, orthose having more rural type of distribution networks. This is reflected under selection Nuclear power stationapplication (9 %) of the utilities responding to this question.

A large number of responses (30 %) indicated other. This may indicate that all relays are calibrated with equal

tolerances.

4.3 Relay Applications for which Looser than Normal Tolerances are Permitted

The response to the survey question regarding the acceptability of looser tolerances for certain relay applicationswith respect to defined application is shown in Figure 17. Other than those responses under selection Non-tripping

relays, it appears that from the selection Other (38 %) that, although no additional information was provided,many utilities may calibrate relays with equal tolerances.

Figure 17: Relay Applications Requiring Tolerances Looser than Those Normally Required

A moderate percentage (11 %) of utilities indicated that Relays that trip after a time delay are not required to have

a precise setting or other exacting factors that affect tolerances. The question does arise regarding the accuracy ofthe relay before tripping occurs if looser than normal tolerances acceptable with respect to its characteristic andthose effects on the overall time delay.

The response under selection Non-tripping relays appears that a relative number of surveyed relay users (50 %)did agree that non-tripping relays are not required to have as tight a tolerance as those assigned to actual tripping

purposes. Relays used for alarm applications, auto test, or circuit breaker reclosing are most likely part of thiscategory.

4.4 Documentation of Allowable Tolerances by the Relay Users

The response to the question of the survey regarding whether allowable relay tolerances are documented is provided

in Figure 18 below.

11%

50%

2%

38%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%


Relays that trip

after a time delay

Non-tripping relays Percentage

differential relays

Other


13/35



Figure 18: Documentation of Allowable Relay Tolerances

The combined selections Allowable relay tolerances are documented and Allowable relay tolerances are partiallydocumented (93.5 %) reflect that the majority of the polled users do indeed compile documentation on relaytolerances.

5. Factors that Influence Relay Test Schedules

There has been a lot of pressure to increase the time period between relay test intervals. Increasing the test intervals

obviously reduces direct testing costs. The probability that a failure will occur and exist undetected increases as theintervals go up. It is possible that relay crews will visit the less common relay systems so seldom that they willencounter delays while they have to relearn how to deal with them. This section of the survey was designed toinvestigate what are the most significant factors influencing selection of test intervals in the industry.

5.1 Basis for Test Intervals for Relays in T&D Substations

Figure 19 summarizes the respondents basis for selecting test intervals for relays protecting T&D substations.Nearly half of the respondents chose Analysis of past results and Voltage level of circuit. Manpowercapability or limitations and operations or misoperations were also selected by a large number of respondents. Itis interesting to note that all of the possible choices drew at least some selections, with More complex relay typesselected by only two of the respondents.

58.4%

35.1%

6.5%

0%

10%

20%

30%

40%

50%

60%

PercentageofRes

pondents

Allowable relay

tolerances are

documented

Allowable relay

tolerances are

partially documented

Allowable relay

tolerances are not

documented


14/35



Figure 19: Basis for Test Intervals for Relays in T&D Substations

Figure 20 summarizes the most important factors in selecting the test intervals for T&D substation relays. While theresults do not exactly correspond to those reflected in Figure 19, the two responses most frequently selected wereagain Analysis of past results and Voltage level of circuit.

Figure 20: Most Important Factors in Selecting Test Intervals for Relays in T&D Substations

45.6% 45.6%

32.9%

40.5%

30.4%

2.5%

19.0%

43.0%

13.9%

43.0%

36.7%

20.3%

31.6%29.1%

10.1%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

50.0%


Anaysispastresults

Voltagelevel

Typeofrelay

Constructionofrelay

Importanceofloads

Complexrelays

Manufacturersrec.

Manpowerlim

its

Outagetim

e

Operationsorm

isops.

Maintenancesch.

Age,type,style

Selftest

Regionalcriteria

Other

19%

6%

10%

18%

8%

6%

3%

12%

5%

10%10%

10%

8%

13%

6%

0%

1%1%

4%4%4%

13%

6%

13%

3%

0%

1%

8%

12%

15%

3%

10%

9%

1%1%

4%3%

8%

3%

9%

6%

8%

0%

3%3%

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%


Anaysispastresults

Voltagelevel

Typeofrelay

Constructionofrelay

Importanceofload

s

Complexrelays

Manufacturersrec

.

Manpowerlim

its

Outagetim

e

Operationsorm

is

ops.

Maintenancesch.

Age,type,style

Selftest

Regionalcriteria

Other

Ranked 1 Ranked 2 Ranked 3


15/35



5.2 Rationale for Shorter Test Intervals

Figure 21 shows that shorter test intervals were selected for relays protecting higher (EHV) voltage systems by 56 %

of the respondents. The particular type of relay being tested was also frequently chosen to be a basis for usingshorter test intervals.

Figure 21: Reasons for Selection of Shorter Test Intervals for Relays in T&D Substations

5.3 Rationale for Longer Test Intervals

Figure 22 shows that 65 % of the respondents assign longer test intervals to T&D substation relays with self-checking algorithms. Again, as in the previous question, the particular type of relay was also a significant factor inchoosing longer test intervals.

Figure 22: Reasons for Selection of Longer Test Intervals for Relays in T&D Substations

21.3%

56.0%

16.0%

30.7%

2.7%

20.0%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

Percen

tageo

fRespon

den

ts

Non-EM vs. EM Higher Voltage

(EHV)

Type of load Relay Types Self-checking Other

24.7%

6.8%

13.7%

26.0%38.4%

24.7%

0 .0%

5.0%

10 .0%

15 .0%

20 .0%

25 .0%

30 .0%

35 .0%

40 .0%


N o n - E M v s . E M H i g he r V o l ta g e

(EHV)

Ty pe o f l oad Re lay typ es Sel f-checki ng O th er


16/35



5.4 Basis for Test Intervals for In-Plant Relays (Generator, Switchgear, etc.)

Figure 23 shows that a clear majority of respondents (almost 59 %) selected Maintenance schedule of protected

equipment as a factor. The next two most frequently selected choices were Operations and misoperations andAnalysis of past results. All of the possible choices drew at least some selections, with More complex relaytypes least frequently selected, consistent with the results collected for T&D substations.

Figure 23: Basis for Test Intervals for In-Plant Relays

Figure 24 summarizes the most important factors for selection of test intervals for in-plant relays. The most

frequently selected choice was Maintenance schedule of protected equipment. 12 % of the respondents ranked itas their most important factor.

Figure 24: Most Important Factors in Selecting Test Intervals for In-Plant Relays

5.5 Test Intervals Actually Met in Practice

A majority of respondents, 65 %, reported that their scheduled relay test intervals are actually met in practice.

3 1 . 4 %

1 4 . 3 % 1 4 . 3 %

2 2 . 9 %

1 5 . 7 %

2 . 9 %

2 2 . 9 %

2 7 . 1 %2 7 . 1 %

3 2 . 9 %

5 8 . 6 %

4 . 3 %

1 5 . 7 %

1 8 . 6 %

1 4 . 3 %

0 . 0 %

1 0 . 0 %

2 0 . 0 %

3 0 . 0 %

4 0 . 0 %

5 0 . 0 %

6 0 . 0 %


Anaysispastresults

Voltagelevel

Typeofrelay

Constructionofrelay

Importanceofloads

Complexrelays

Manufacturersrec.

Manpowerlim

its

Outagetime

Operationsormisops.

Maintenancesch.

Age,type,style

Selftest

Regionalcriteria

Other

1 2 %

3 %

1 2 %

4 %

1 %

3 %

3 %

6 %

4 %

6 %

3 %

6 %

1 0 %

4 %

3 %

0 %

1 %

0 %

3 %4 %4 %

3 %

1 3 %

1 5 %

7 %

1 0 %

6 %7 %

9 %

1 2 %

2 7 %

2 2 %

9 %

0 %1 %

4 %3 %

6 %

4 %4 %

6 %

4 %

9 %

1 %

0 %

0 %

5 %

1 0 %

1 5 %

2 0 %

2 5 %

3 0 %

Percen

tageo

fRespon

den

ts

Anaysispastresults

Voltagelevel

Typeofrelay

Constructionofrelay

Importanceofloa

ds

Complexrelays

Manufacturersr

ec.

Manpowerlim

its

Outagetime

Operationsorm

isops.

Maintenancesch

.

Age,type,style

Selftest

Regionalcriteria

Other

Ranked 1

Ranked 2

Ranked 3


17/35



6. Relay Test Intervals

6.1 Actual Relay Test Intervals Presently Used

The purpose of this section is to determine the relay test intervals for both electromechanical and non-electromechanical relays used in transmission, distribution, main generator, auxiliary bus, cogeneration and large

industrial substations.

The complete responses are given by the bar charts shown in Figures 25 through 36.

Figure 25: Time Intervals between Scheduled Relay Testing (years) - Electromechanical Relays onTRANSMISSION Circuits

Figure 26: Time Intervals between Scheduled Relay Testing (years) - Electromechanical Relays onSUBTRANSMISSION Circuits

4% 3%3%

4%

6%

13%

21 %

22%22%

23%

24%

25 %

26%

28%

26%27%

26 %

22%21 %

18%19%19%

17%

18 %

12 %

14%14%

12%11%11%

4%7%

7%

4% 4%

2%

0% 0%

3%1% 1%

0%

12%

8%8%

9%11%

9%

0%

5%

10 %

15 %

20 %

25 %

30 %

Perc

entageofRespondents

7

Years

Overcurrent Impedance Different ia l Pi lot Remote Tr ip Schemes Frequency

4%

1%

1%

3%3%

10% 10%

16%14 %

13%

13%

24%

21 %

23%

24%

32%

29%

22% 22 %

23%

22%

18%

16%17%

21%

15%

16%

15 % 15%

9%

8%8%

9%

5%

6%

3%

1%3%3%

3% 3%3%

13%

10%11%

11%

15%

10 %

0%

5%

10 %

15 %

20 %

25 %

30 %

35 %


7

Years

Overcurrent Impedance Differential Pilot Remote Tr ip Schemes Frequency


18/35



Figure 27: Time Intervals between Scheduled Relay Testing (years) - Electromechanical Relays on

DISTRIBUTION Circuits

Figure 28: Time Intervals between Scheduled Relay Testing (years) - Non-Electromechanical Relays onTRANSMISSION Circuits

3%

0%0%0%

3%

10%

4%

13%

10%

6%

8%

29%

12%13%

16%

12%

13%

12%

25%

23%

23%

27%

18%

19%

15%

18%

15%

21%

18%

12%

15%

10%

11%

9%

13%

3%

8%

5%

8%9%

8%

5%

18%

18%

16%

15%

21%

10%

0%

5%

10%

15%

20%

25%

30%

PercentageofRe

spondents

7

Years

Overcurrent Impedance Differential Pilot Remote Trip Schemes Frequency

1%

0%0%1%

4%

9%

21 %

22 %

23 %

27 %

27 %

26 %

18 %18 %18 %

21 %

23 %

22 %

19 %

21 %

22 %

15 %

11 %

19 %

13 %

14 %

11 %

11 %

12 %

9%

7%

5%

4%

6%

5%

2% 3%

4%

7%7%

7%

0%

18 %

16 %

16 %

11 %

10 %

13 %

0%

5%

10%

15%

20%

25%

30%


7

Years



19/35



Figure 29: Time Intervals between Scheduled Relay Testing (years) - Non-Electromechanical Relays on

SUBTRANSMISSION Circuits

Figure 30: Time Intervals between Scheduled Relay Testing (years) - Non-Electromechanical Relays onDISTRIBUTION Circuits

1%0%0%

2% 2%

9%

15 %

16 %

18 %

19 %

21 %

26 %

18 %

16 %

16 %

19 %

20 %

19 %

17 %

17 %

19 %

17 %

15 %

11 %

15 %

19 %

15 %

16 %16 %

13 %

7%

9%

7%7%

8%

6%

7%7% 7%7% 7%

2%

18 %

17 %

18 %

14 %

11 %

15 %

0%

5%

10%

15%

20%

25%

30%


7

Years


3%

0%0%0%

3%

10 %

1%

9%

7%

14 %

19 %

23 %

10 %

12 %

14 %

7%

5%

15 %

20 %

18 %

21 %

28 %

22 %

16% 16%

18 %

16 %17 %

16 %

15 %14 %

12 %

11 %

14%14%

3%

10 %

3%

7%

3%

5%

5%

25 %

29 %

25 %

17 %

16 %

13 %

0%

5%

10%

15%

20%

25%

30%

Percentageof

Respondents

7

Years



20/35



Figure 31: Time Intervals between Scheduled Relay Testing (years) - Electromechanical Relays for GENERATORApplications at Non-Nuclear Power Stations

Figure 32: Time Intervals between Scheduled Relay Testing (years) - Electromechanical Relays for AUXILIARYBUS Applications at Non-Nuclear Power Stations

8%

7%

7%

8%

11 %

22 %

25 %25 %

22 %

27 %

29 %

28 %

27 %

31 %

29 %

20 %

19 %

20%20%

16 %

12 %

12 %

12 %

10 %

9%

2% 2%2%2%

0% 0%0%0% 0% 0%

7% 7%7% 7% 7%

0%

5%

10%

15%

20%

25%

30%

35%


7

Years

Overcurrent Impedance Differential Voltage Frequency

10 %

5%5%

8%9%

16 %

23 %

20 %

15 %

23 %23 %

20 %

25 %

24 %25 %

23 %23 %

22 %22 %

18 %

13 %

11 %

14 %14 %

16 %

5%

7%

3%

5%

0%

2%

0%

2% 2%

0%

10 %

11 %

8%

10 %9%

0%

5%

10%

15%

20%

25%

30%

Percentag

eofRespondents

7

Years



21/35



Figure 33: Time Intervals between Scheduled Relay Testing (years) - Non-Electromechanical Relays forGENERATOR Applications at Non-Nuclear Power Stations

Figure 34: Time Intervals between Scheduled Relay Testing (years) - Non-Electromechanical Relays for

AUXILIARY BUS Applications at Non-Nuclear Power Stations

7%

4%6%

8%

12 %

18 %

23 %22 %

21 %

24 %

29 %28 %

25 %

29 %

24 %

24 %

19 %

22 %

21 %

22 %

13 %

15 %

14 %

12%12%

2%2% 2%2%

0% 0% 0% 0%0%0%

7%

9%

10 %

8% 8%

0%

5%

10%

15%

20%

25%

30%


7

Years


9%

6%6%

10%

11%

17%

21%

17%

15%

22%

22%

21%

23%

19%19%

22%

18%

26%

23%

19%

11%

15%

13%

13%

14%

7%6%

2%

8%

5%

2%

0%

2% 2%0%

9%

15%

11%

10%

11%

0%

5%

10%

15%

20%

25%

30%

Percentag

eofRespondents

7

Years



22/35



Figure 35: Time Intervals between Scheduled Relay Testing (years) - Electromechanical and Non-Electromechanical Relays for Substations Serving a LARGE INDUSTRIAL CUSTOMER

Figure 36: Time Intervals between Scheduled Relay Testing (years) - Electromechanical and Non-Electromechanical Relays for Substations Serving an INDEPENDENT POWER PRODUCER or Dispersed Source

of Generation

6.2 Comparison of Relay Test Invervals with the 1991 Survey

Charts comparing maintenance and calibration intervals compiled during the 2001 survey as compared to the resultsof the 1991 survey is included in Figures 37 through 44.

5%

2%2%

4%

6%

2%

5%

11 %8%

7%

18 %

4%

16 %

22 %

20 %

20 %

22 %

20 %

29 %

25 %

24 %

22 %

24 %

29 %

15 %

16 %

17 %16 %

12 %

16 %15 %

11 %

12 %

13 %

8%

12 %

3%2%

5%5%

0%

4%

13 %

11 %

12 %

13 %

10 %

14 %

0%

5%

10%

15%

20%

25%

30%


7

Years

Overcurrent Impedance Differential Voltage Frequency Reverse Power

4%

2%2%

4%

10 %

2% 2%

14 %

17%17%

15 %

21 %

15 %

18 %

18 %

22 %

24 %

22 %

19 %

20 %

18 %

27 %

20 %

17 %

20 %

19 %

24 %

20 %

12 %

15 %

15 %

15 %

17 %

15 %

18 %

8%

7%

7%

7%

2%

7% 7%

0%

2%2% 2%

0%

2%

0%

16 %

15 %

15 %

15 %12 %

15 %

16 %

0%

5%

10%

15%

20%

25%

30%

Percentag

eofRespondents

7

Years

Overcurrent Impedance Differential Voltage Frequency Reverse Power Synchronizing


23/35



Over the ten-year interval, 1991 to 2001, one can see a shift in longer test intervals. For example, electromechanicalimpedance relays used for protection of transmission facilities were tested every five or more years by 28.9 % of theelectric utilities responding in the 2001 survey, as compared to only 10.1 % in 1991. A similar shift in maintenance

test intervals is found in comparisons of the data compiled in the two surveys for other relay types as well asindicated in Figures 37 through 44.

Figure 37: 1991 Survey Electromechanical Relays - Transmission

Figure 38: 2001 Survey Electromechanical Relays - Transmission

11 %

14 %

12 %

13 %

32 %

46 %47 %

48 %

50 %

38 %

20 %

20 %

20 % 19 %19 %

11 %8%

7%6%

4%

13 %

10 %

13 %

12 %

7%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%


5

Years

Overcurrent Impedance Differential Pilot Frequency

4%

3% 3%

4%

13 %

21 %

22 %

22 %

23 %

25 %26 %

28 %

26 %27 %

22% 21%

18 %

19 %19 %

18 %

29 % 29 %

31 %

27 %

22 %

0%

5%

10%

15%

20%

25%

30%

35%


5

Years



24/35



Figure 39: 1991 Survey Non-Electromechanical Relays - Transmission

Figure 40: 2001 Survey Non-Electromechanical Relays - Transmission

14 %

17 %

13 %

25 %

37 %

45 %

48 %

50 %

40 %

37 %

19 %

20 %

19 %

20 %

15 %

8%

6%6% 7%3%

14 %

9%

12 %

8% 9%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

PercentageofR

espondents

5

Years


1%

0% 0%

1%

9%

21 %

22 %

23 %

27 %

26 %

18 %

18 %

18 %

21 %

22 %

19 %

21 %22 %

15 %

19 %

40 %40 %

38 %

35 %

24 %

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%


5

Years



25/35



Figure 41: 1991 Survey Electromechanical Relays - Distribution

Figure 42: 2001 Survey Electromechanical Relays - Distribution

3%

6%7% 8%

37 %

25 %

32% 32%

28% 28%

21 %21 %

22 %

22 %

15 %

22 %

23 %

18 %

23 %

8%

29 %

18 %

21 %

19 %

12 %

0%

5%

10%

15%

20%

25%

30%

35%

40%


5

Years


3%

0%0%0%

10 %

4%

13 %

10 %

6%

29 %

12 %13 %

16 %

12 % 12 %

25 %23 % 23 %

27 %

19 %

56 %51 %

51 %

55 %

31 %

0%

10%

20%

30%

40%

50%

60%

Percenta

geofRespondents

5

Years



26/35



Figure 43: 1991 Survey Non-Electromechanical Relays - Distribution

Figure 44: 2001 Survey Non-Electromechanical Relays - Distribution

7% 6%7%

10 %

36 %

24 %

30 %

33 %

27 % 27 %

19 %

23 %

19 %

23 %

15 %

23%23%

19 %

22 %

7%

27 %

18 %

23 %

19 %

16 %

0%

5%

10%

15%

20%

25%

30%

35%

40%

PercentageofR

espondents

5

Years


3%

0%0%0%

10 %

1%

9%

7%

14 %

23 %

10 %

12 %14 %

7%

15 %

20 %

18 %

21 %

28 %

16 %

65 %

62 %

58 %

52 %

36 %

0%

10%

20%

30%

40%

50%

60%

70%


5

Years



27/35



7. Relay Test Equipment

The purpose of this section is to compare what type of test equipment is being used, and for what type ofapplications. In addition, desired maximum weight is considered for transportability.

7.1 Acquisition of Test Equipment

According to the survey, fewer companies are building their own test sets. Over 97 % of those surveyed said thatthey procure commercially available relay test sets. Less than 3 % said that they build their own test sets.

7.2 Passive vs. Solid State Relay Test Sets

Passive relay test sets are defined as manually operated test sets comprised of resistive loads, mechanical phaseshifters, variable autotransformers, or phantom loads. Solid state relay test sets include electronically regulatedvoltage and current sources. The survey showed that over 98 % of the respondents have two or more solid staterelay test sets. As shown in Figure 45, almost half of the respondents, 49 %, use both passive and solid state relay

test sets, while another 49 % use solid state test sets only. Less than 2 % use passive test sets only.

Figure 45: Percentage of Utilities that Use Passive and Solid State Test Sets

The ratio of passive vs. solid state test sets has dropped significantly since the 1991 survey. In 1991, 50 % of thetest sets in use were passive loads. Today, of those surveyed, 29 % of the total number of units in use are passiveloads (861 passive test sets out of a total of 2,965 units). Therefore, it is concluded that as the older passive units areretired they are being replaced with modern solid state relay test sets.

7.3 Dynamic Relay Test Equipment

Dynamic test equipment is defined as test sets capable of providing pre-fault, fault, and post-fault outputs, with dcand harmonic components. As shown in Figure 46, 80 % of the respondents have equipment with this type ofcapability. This is a significant increase from the 1991 survey, when only 50 % of respondents said that they haddynamic test equipment.

2%

49% 49%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%


Passive Only Passive and Sol id State Sol id State Only


28/35



Figure 46: Percentage of Utilities that Use Dynamic Test Sets

7.4 Power Swing Test Equipment

Utilities were asked if they have test sets capable of simulating power system disturbances such as power swings orfrequency excursions. As shown in Figure 47, 79 % of the respondents have at least 1 test set capable of performingthis type of test. This represents a 29 % increase from the 1991 survey.

Figure 47: Percentage of Utilities that Use Power Swing Capable Test Sets

50%

80%

0%

10%

20%

30%

40%

50%

60%

70%

80%


1991 Survey 2001 Survey

50%79%

0%

10%

20%

30%

40%

50%

60%

70%

80%




29/35


30/35



7.7 Portability of Test Equipment

Over 47 % of the respondents stated that they have relay test sets that require more than one person to carry. As

shown in Figure 50, 50 % of the respondents said that the maximum weight should be 50 pounds or less. Another47 % said that test sets that weighed from 50 to 80 pounds were acceptable, while 3 % said that test sets thatweighed 80 pounds or more were acceptable.

Figure 50: Desired Weights of Test Sets

8. Testing Protective Relays in a Particular Station

The purpose of this section is to determine how relay test crews are scheduled when relays are tested.

About 64 % of the respondents test all relays in a station with a single crew in one concentrated effort. Another27 % of the respondents test relays at different times by different crews according to voltage, criticality and relaycomplexity. The remaining 9 % use other methods to schedule relay testing. Utilities who use a single crew in oneeffort increased about 11 % since the 1991 survey, while utilities that use different crews at different timesdecreased about 6 % since the 1991 survey. This implies that relay testing at utilities is moving towardsperforming all relay testing in one effort. Figure 51 shows these results.

Figure 51: Utilities' Approach to Scheduling Relay Testing

5 0 %

4 7 %

3 %

0%

5%

1 0 %

1 5 %

2 0 %

2 5 %

3 0 %

3 5 %

4 0 %

4 5 %

5 0 %


U nd e r 5 0 L b s 5 0 t o 8 0 L b s 8 0 o r M o r e

W e i g h t

64.1%

3.8%

26.9%

5.1%

0%

10 %

20 %

30 %

40 %

50 %

60 %

70 %

Perce

ntageo

fRespon

den

ts

Al l re la ys , si ng le

crew, one effort.

Mul t ip le crews,

based on relay

criteria.

Di f ferent crews,

di f ferent t imes.

Other


31/35



9. Protective Relaying Scheme Operational Test Conditions and Intervals

The purpose of this section of the survey is to determine the conditions for which protective relaying schemes areoperationally tested and the intervals at which these tests are performed.

9.1 Operational Trip Testing

Most individuals responsible for power system protection consider operational trip testing necessary to verify that allrelays, power circuit breakers, station batteries and other equipment are performing correctly. This sectionaddresses when these operational checks are performed, how often are they performed and who performs theoperational check.

Power circuit breakers are trip tested with their protective relays during various routine maintenance tasks and whena malfunction or misoperation is suspected. If a misoperation is suspected, a majority of respondents said they

perform a trip check. For routine maintenance, operational trip checks of the power circuit breakers during bothrelay and breaker maintenance is a very common utility practice. The results are shown on Figure 52.

Figure 52: Other Testing Performed when Utilities Perform Operational Trip Testing

9.2 Operational Trip Test Intervals

The majority of relay schemes were operationally trip tested on a 1 to 3 year cycle. The results are shown on Figure53.

25.3%

11.4%74.7%

24.1%

22.8%

49.4%

0.0% 10.0% 20.0% 30.0% 40.0% 50.0% 60.0% 70.0% 80.0%

Percentage of Respondents

Other

Routine Interupting Device

Maintenance.

During SCADA Testing.

Af te r Mal fun cti on or

Misoperation.

Complete Maintenance

Shutdown of Facility.

Dedicated time, fixed

schedule.


32/35



Figure 53: Operational Testing Intervals

9.3 Personnel Who Perform Operational Trip Tests

As can be seen from Figure 54, maintenance and service personnel along with protection technicians are most likelyto be performing these trip tests.

Figure 54: Type of Personnel Who Perform Trip Testing

10. Maintenance Program Effectiveness

The purpose of this section was to determine how utilities decrease relay failures through their maintenanceprograms.

4.0%

21.3%21.3%

8.0%

12.0%

5.3%

0.0%

9.3%

18.7%

0%

5%

10%

15%

20%

25%

PercentageofResp

ondents

1 or

less

1-2 2-3 3-4 4-5 5-6 6-7 7+ NA

Years

3.8%

11.4%

77.2%

6.3%

1.3%

0% 10% 20% 30% 40% 50% 60% 70% 80%


Substation operators

Maintenance or service

personnel

Protection technicians

Protection engineers

Other


33/35



10.1 Criteria Used

As shown in Figure 55, Reliability was the chosen as the most common criteria used to measure maintenance

program effectiveness, while the second most common selection was Productivity and Performance.

Figure 55: Basis for Measurement Criteria to Determine Effectiveness of Maintenance Programs

10.2 Correlation between Measurements and Failure Rates

As shown in Figure 56, 25.3 % of the respondents said that there is a relationship between their measurements and areduction in failure rates. This is a 5.8 % increase from 1991 survey.

Figure 56: Percentage of Utilities Who Identify a Relationship Between Measurement and Failure Rate

6.3%

13.9%

25.3%

43.0%

7.6%

3.8%

0% 5% 10% 15% 20% 25% 30% 35% 40% 45%


Productivity

Performance

Productivity &

Performance

Reliability

None

Other

25.3%

74.7%

19.5%

80.5%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

2001 Survey

1991 SurveyNo Relationship

Relationship


34/35



10.3 Satisfaction of the Utilities Maintenance Programs

In rating the effectiveness of their utilitys maintenance program, 25.3 % of the respondents were very satisfied,

58.2 % were satisfied, 13.9 % were unsatisfied and 2.5 % were very unsatisfied. The satisfaction level seems to beslightly lower then in the 1991 survey. Figure 57 shows the survey results.

Figure 57: Utility Opinions on Effectiveness of Maintenance Programs in Reducing Relay Failures

2.5%0.5%

13.9%4.5%

58.2%62.0%

25.3%

33.0%

0% 10% 20% 30% 40% 50% 60% 70%


Very Unsatisfactory

Unsatisfactory

Satisfactory

Very Satisfactory



35/35

11. Bibliography

[1] A Survey of Relay Test Practices, IEEE Power Systems Relaying Committee Report, IEEE TransactionsPower Apparatus and Systems, Vol. 91, pp. 1191-1196, May/June 1972.

[2] A Survey of Relay Test Practices, IEEE Power Systems Relaying Committee Report, IEEE TransactionsPower Delivery, Vol. 9, No. 3, pp. 1339-1351, July 1994.

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