00368400_Distribution Line Protection

7/27/2019 00368400_Distribution Line Protection

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176

Voltage Class5 kV

15kV25 kV35kVTotal

EEE Transactions on Power Delivery, Vol. 10,No. 1, January 1995DISTRIBUTION LINE PROTECTION PRACTICESINDUSTRYSURVEYRESULTSIEEE POWER SYSTEM RELAYING COMMl lTEE REPORT

Working Group on Distribution Protection:W. M. Strang, Chairman, R. M. Westfall. Vice ChairmanT.L.Kaschalk, J. R. Latham, W. J.Marsh, M. J.McDonald,R. J . Moran, R. D. Pettigrew, R. P. Taylor, J.T. engdinContributing Members: A. N. Darlington, P. R. Drum, D. Fulton, E.Guro, J. D. Huddleston 11,

Load, MVA YoofTotal #of Utlites17,437 6.3 73

173,729 62.4 9854,808 19.7 4632,484 11.6 33

278,458 100.0

Kev Words - Distribution P rotection, P rotective Relaying,Reclosers, Reclosing, P hase P rotection, Ground Protection, HighImpedance Ground F ault.Abstract - This report presents the results of an extensive surveyof utility practices for the protection of distribution lines at thesubstation. Results of similar surveys were published n 1983 (Ref.1) and in 1988 (Ref.2). In this survey, the first eight sections werecomparable to the earlier surveys. In addition, these sections wereexpanded to collect more data on the reasons behind a practiceand on the methods used. A ninth section was added to addressthe impact of Dispersed Sources of G eneration (DSG) ondistribution protection. The responses to this survey have beencompared o the previous survey in an attempt to detect any trendsin the protection of distribution circuits.Introduction - The IEEE Power Systems Relaying Committee(PS RC) has the responsibility of reviewing and reporting on currentpractices in protective relaying. In the distribution area, the"EffectivenessOfDistribution Protection"Working Group of the LineProtection Subcommittee has the ongoing role to survey the utilityindustry at periodic intervals. The data collected through thissurvey, when compared to the previous surveys, indicates thatthere are some trends emerging. The advantages of thesechanging practices are discussed within this report. Furthersurveys will be conducted to determine the extent of these andfuture trends.About the Q uestionnaire - The questionnaire used for this surveywas based on the previous questionnaire with two expansions:1) emphasis was added in all sections asking for the rationaleand methodology of a practice, as well as what changes indistribution practices have taken place in the last five years,and 2) added a section to determine the impact of dispersedsources of generation on distribution protection.Where appropriate, the data was collected by major voltage class:5kV, 15kV, 25kV, and 35kV.

SECTION 1- GENERALThe questionnaire was sent to individuals invdved in distributionsystem protection for investor-owned, cooperative, and municipalutilities and for large industrials n the United States and Canada.Responses were received from 107 utilities. Of these, 67 hadresponded to the previous 1988 survey.The respondents were asked to limit their replies to ACTUALPR ESENT PR ACTICES . Past practices and policies for olderportions of the system are not of interest because they would notbe applied if that portion were to be installed today. Therespondents were requested not to guess at any of the answers.

This paper was presented at the 1994 IEEE PES Transmission andDistribution Conference and Exposition held in Chicago, Illinois,April 1G15, 1994.

If the des ired information was not readily available or could not beprovided in the form requested by the survey, respondents wereasked not to answer the question.The respondents were asked to provide a significant amount ofdescription with their answers. It was feared that this would havea negative impact on the completeness of the returns. This wasnot the case, as the respondents ncluded more discuss ion than inprevious surveys. This additional information was used in theanalysis of the data and preparation of the presented results.Survev Results - The results of the survey are given for eachsection. The actual survey questions are not included n this report,as the questionnaire was 46 pages long. In tabulating the results,the number of "yes" responses and "no" responsesare given whereappropriate, and may not total 107. Not all respondents answeredall the questions.This section of the survey requested general information about theutility. The respondent was also asked if the utility name could beused in conjunction with any of the results or specific questions. Inmost cases, the answer was "yes."

SECTION 2 - SYS TEM DATASvstem Load - Each utility was asked to state their totaldistribution load and distribution station supply transformer size byvoltage class, to assure that data was coming from a broad base.One hundred seven utilities reported distribution oad ranging froma few MVA to over20,000MVA.

TOTAL DISTRIBUTIONLOAD UTILITIES5,000MVAandabove1000 MVA to 4,999 MVA999 MVA and below 31I NoSize Given I 20 I

Voltacle Class - Most utilities had more than one distributionvoltage, with 15kV being the most common. From those reporting,the distribution load at each voltage is:

Transformer Size - The following table gives a breakdown, by thenumber of utilities, of the largest total substation transformercapacity (three-phase, self-cooled rating) bused together at onedistribution station.0885-8977/95/$04.000 994 IEEE


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177

MAXIMUMAVAILABLEFAULT CURRENT5 kV 3Phase

Phase-Gnd

TRANSFORMER SIZELess than 10 MVA

10to20 MVA20to 50 MVA 3 39 17 10

4OkA 1OkA to 20kA >20kA

19 22 823 20 5

I TotalResponses I 63 I 92 I 43 I 28 I15kV

25 kV

35 kVain Interruptincl Device - When asked what main interruptingdevices are used, the utilities gave the following replies, with manyusing more than one device:

~ ~ ~

3Phase 38 28 13Phase-Gnd 52 28 103Phase 25 8 5Phasdjnd 26 8 43Phase 17 4 4Phase-Gnd 17 9 1

I RelavedCircuitSwitcher I 41 IRe!ayed Recloser

Total Responses

I Relaved MotorOwratedDisconnect I 18 I10

189

RelayedCircuit BreakerRelayed RecloserElectronic Recloser

Grounded Neutrals - In every voltage class, the vast majority ofutilities (94-99%) use multi-grounded neutrals: At 5kV - 96% (70 of73); at 15kV - 99% (97 of 98); at 25kV - 98% (45of 46); and atFeeder lnterruptinq Devices - At the substation, a relayeddevice is most frequently used:35kV - 94% (31 Of 33).

I I I

922740

I FEEDER INTERRUPTING DEVICE I ResponsesI

5 kV 15kV 25kV 35 kV

I HvdtaulicRecloser I 28 II TotalRes~onsesI 187 IMulti-Function Relavs - One of the purposes of this survey is todetermine trends in distribution protection. This new category wasadded to determine if utilities are using packaged relay functions foreither transformer or feeder protection.

RESPONSESTransfomr ProtectkmFeeder P rotection

Nearly all of the multi-function relays incorporate three-phase andground instantaneous and time-overcurrent relaying and reclosing.Desicrn Fault Current Levels - The vast majority of utilitiesreported that their design level phase and ground fault currents areequal.Maximum Available Fault Current - Only 6 utilities use reactorsto limit fault current. The rest depend on the substation transformerand system impedance. Here are the fault current levels (numberof responses):

Only 6 of the 107 utilities reported that they measure fault currents.Load Unbalance Monitorinq - Nineteen utilities report they haveinstalled new equipment to monitor load unbalance and five moreare planning to add this.Harmonic Monitorinq - Thirteen utilities report they are usingportable equipment to monitor harmonics and five more are in theplanning stage.

SECTION 3 - PHASE PROTECTIONInstantaneousTrip (Usaqe) - Seventy-six of the 107 respondents(71%) apply phase-overcurrent protection devices withinstantaneous trips for the purpose of "fuse saving." In an earliersurvey initiated n 1988, the use of "fuse saving" fast trips was morepopular, with 91% of those respondents indicating their use. Thecause of this 20 point decline can only be speculated with the dataavailable.

HvdraulicRecloser~ ~

1nstantaneous 15% 17% 15% 12%2 instantaneous 16% 27% 20% 9%


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178As shown in the table, the use of one instantaneous trip isdominant where relays provide the trip intelligence. The secondfast trip operation becomes more prevalent n non-relayed recloserapplications (both electronic and hydraulic). Only one utility usedthree instantaneous trips. 5kV 15kV 25kVBetweenfeeder phase 74% 78% 83%

If YES, includingall 53% 59% 72%devicesrecloserswith differentreset timesBetween customerand 67% 78% 76%utilityowneddevces

Instantaneous TriDs (F use S avina) - Of the 76 utilities that useinstantaneous trips to save fuses, only 11 reported that they havedata to indicate the success level of their efforts. Of these 11utilities, only one was able to provide a percentage of successfulsaves (52%). Others are in the process of evaluating data. Oneutility indicates that the "fuse saving" effort has resulted in anumber of customer complaints due to the momentary nterruptions.

35kV97%

79%

97%

Instantaneous TriDs (Other PurDoses) - Thirty-four of the 76utilities (45%) using instantaneous trips for "fuse saving" reportedthat they also used instantaneous trips for purposes other than"fuse saving." Many utilities cited more than one purpose. Theadditional purposes were:Limit equipment damage 38Enhance coordination 30Minimize voltage dip duration 20Limit duration of flash bum 19Limit outage time 14

ather -otal responses 129

MULTIPLESINGLE

Personnel protection during live-line maintenance was one of theitems lis ted in the "othet" category.

5 k V 15kV 25kV 35kV22% 32% 33% 21%78% 68% 67% 79%

Instantaneous TriDs (Multiple) - Of those utilities utilizinginstantaneous tripping on their distribution systems, singleinstantaneous or fast trips are favored by at least a two to onemargin at all voltage levels.

FaultLevel 5kV 15kV 25kVHiah 15% 19% 17%

35kV6%

The majority of those using two fast trips are using reclosersas thefeeder protective device. Others are now applying both a low setand a high set instantaneous element, with reclosing only for thelow set unit.Instantaneous TriDDina (Modifications) - Thirty-nine utilitiesindicated that they had modified or eliminated their "fuse saving"efforts in an attempt to eliminate nuisance trips and customercomplaints due to the resultant momentary interruptions. Themodifications have been somewhat customer-complaint driven andhave varied from total removal on critical customer circuits to theblocking of instantaneous trips on urban customers and enablingthose trips by SCADA during storm conditions.

To promote complete coordination with customer-owned phaseprotective devices, the responding utilities employ a wide range ofmethods. These methods vary from:a) installing an additional device at the customer service pointto protect the other customers on the circuit frommiscoordination

to b) depending on nuisance trips to get the customer's attention.The most common methods are as follows:

Review of customer's equipment and settings 28Working with customer/contractor pre-construction 22Utility recommending settings andlor doing testing 12

Attitudes toward coordination have not changed significantly sincethe 1988 survey. The vast majority of the responding utilitiesexpected coordination then and still do. The relationship betweenthe utilities and their customers also appears to have remainedfairly stable in those areas concerning coordination.

If miscoordination of feeder phase protection is permitted, a fewutilities do so at different current levels, as shown here:

I I I II LOW 11% 10% 7% 15%Of those utilities permitting miscoordination, 70% pemit it at highfault current levels. The most common reason given is thesimultaneous fast feeder tripping and fuse blowing on high faultcurrents.

SECTION4 - GROUND PRO TECTIONGround Overcurrent - The majority of those responding applyground overcurrent protection on the main interrupting device aswell as on the feeder protection devices. This table, using theformat of maidfeeder, shows the basis for pickup settings.When compared to the previous survey, the relative numbers areessentially the same. The one exception is line C.3 a% of phasetrip pickup). In the previous survey, there was no comparableFeeder Coordination - Most utilities insist on complete feedertimeovercurrent phase protection coordination between the variousprotective devices. This includes customer-owned as well as question,utility-owneddevices.


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GROUNDPROTECTION

Between customer-ownedand utility-owned devicesBetween feedergrounddevicesIncluding all reclosers withdifferent reset times

B.AppyInstantaneousorFastTrpC. Basis of TOC DCkUDwhenaDD81. a % above estmated

load unbalancedue toswitching

5 kV 15 kV 25 kV 35 kV46 68 30 2535 61 27 2226 52 23 19

Number of Responses (Main

3.a % of the phasetrippickup

5kV I 15kV 1 g29/49 69/83 38/4433115 24/13-139 -169 -139

1114 1617 1313 1213

-120 -123 -16

%qqx

6. % of th e feedernormal load rating

2a 23

-126'

2/12 4/21 3/11 319

1 I 61- ~ :;4.a% Of the basetransformerfull loademergency loadratng5. a % of the feeder 6/11Svstem Unbalance - Most utilities who responded to this questionlimit the permissible unbalance to 50% or less.There is little relative change versus the previous survey. A largernumber of utilities permit unbalance of 26-50% of the feederground TO C minimum pickup, but hold the percent of total loadunbalance to less than 25%.

When outages are caused by load unbalance (other than cold loadpickup),90% of the respondents (8 4of93) said such outages arenot tolerable. In the last survey, it was 81% (67 of 83).Feeder Coordination - A significant number of utilities insist oncomplete eeder ground protection coordination between the variousfeeder protective devices, as well as with customer owned devices.A variety of methods are used to achieve complete coordinationwith customer-owned ground protective devices:

- review and approve customer's setting- mutual agreements with customers 2414- utility recommendlmake settings 7- checkkerify customer coordination 5

When miscoordination of feeder ground protection is permitted,more utilities allow it at low fault current than at high fault currentby a 60:40 ratio overall (ranging from 2:l at 5kV and 35kV toalmost 1:1 at 25kV. For customer-owned versus utility-ownedfeeder ground devices, miscoordinationwas accepted only whenthat customer load was affected and for cases in which the groundovercurrent relays would not coordinate with customer fuses.Several utilities noted that they set the utility devices to protect theutility system.

Feeder Ground Instantaneous Trip - These responses cover theapplication of instantaneous or fast-trip ground overcurrentprotection on various interrupting devices.When asked if hey had data toshow the success rate of their "fusesaving" program, 77 utilities said "no." Only 3 of the 5 who said"yes" gave success rates. They were 52% (analysis of operatingrecords), 60-70% (estimated), and 88% (from digital relay eventrecords).

Other than for "fuse saving," instantaneous or fast trip feederground protection was used to:- limit equipment damage 39 responses27enhance coordination 26limit duration of flash bum- minimize duration of voltage dip 1913limit outage time- other reasons 5

Personnel safety was not mentioned.P rotection Problems - The majority of responses indicated theyeither did not have either cold-load pickup (CLPU) due to excessiveunbalance, or magnetizing nrush using their present feeder ground


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180

OneTwo

ThreeFour

TotalResponses

protection settings. Those who indicated they were experiencingCLPU problems usually solved the problem by re-balancing ratherthan by increasing ground relay settings. There was no significantchange from the previous survey.4 7 5 316 29 24 133 4 4 8 15 127 8 4 4

61 92 48 32

FEEDER GROUND PROTECTION PROBLEMSI I Nurnberof ResDonses

0 1 second1 - 56-10

11 -2 021-60>61seconds

I Problmwith: I 5kV I 15kV I 25kV I 35kV I

11 22 7 54 7 4 429 42 25 1313 14 7 6

1

I I

FUSE SIZELess than 65 am^

lCo!dLoadPBkupDue 1 I { I I ; { 1Untransformed Service C ustomers - When the desired feederground trip sensitivity and coordination cannot bemaintained, 39of97respondents require that the untransformedservice customerinstall a main interrupting device with a ground trip. Of these, 11respondents have a published policy defining the limits beyondwhich a customer must install a main interrupting device. Only 1utility enclosed a copy of its policy. Most (67) reported they haveno published policy.Utilities without a published policy were asked "What is themaximum fuse size above which a customer is required to installservice entrance equipment with phase and ground trip?"Compared to the last survey, the practices at 5kV and 15kV areabout the same. At 25kV and 35kV, the maximum fuse size hasdecreased from 250Amp to 200Amp.

To UnbalanceMagnetizing Inrush Yes

No 52 82 37 30

Numberof Responses5kV 15kV 25kV 35kV

1 3 3 2

125 amp

250 amp300 mDI I I

I I I I I

SECTION 5 - RECLOSING AT THE SUBSTATIONOn Overhead Lines - Automatic reclosing continues to be auniversal practice among the 107 esponding utilities. All use atleast one reclosing attempt following a relay trip. The number ofattempts (trips) in each voltage class is essentially unchangedsince the last survey.The open intervals between reclosing attempts used by utilitiesbetween tripping and reclosing attempts also shows very littlechange from the last survey. The open intervals between trippingand reclosing attempts are tabulated by voltage level.

RECLOSING AllEMPTSNumberof Responses

5kV I 15kV I 25kV I 35kVt of RedosingAttempts

IOPENGERVALETWEENRECLOSING ATTEMPTS IOpen IntervalTime Numberof Responses

6 10~

11 -20 4 3 2

I >50semnds 1 7 1 11 1 3 1 - I4 0 econds10- 30 1 3 1 3 3I I I I I131-50- - 1 1 1 1 I - I - Ir >50seconds I l l 2 1 2 1 - I

OtherReclosins Practices - Sixty five utilities reported they usea different reclosing sequence for other than standard overheadlines. The questionnaire listed six reasons. Here are the replies:- to allow downstream sectionalizers time to trip 26- to limit feeder interrupting duty 17- to limit transformer through faults 12- the presence of SCADA at the substation 10- in subs fed directly from transmission 5- the presence of shield wires 1

Underqround Cables - Utilities were asked to state the largestpercentage of line which could be cable and still use normaloverhead line reclosing practices.


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UNDERGROUND CABLESCable Lengthas a I Number of ResponsesPercentage of Total LineLength 5 kV 15 kV 25 kV 35 kV, I II 20%orless 1 1 2 1 23 1 1 2 1 7 I

_ _ _60% or less 5 6 5 380% or less 9 18 5 4

100% or less 7 10 2 1

I 40% or less I 9 2 0 I 7 5I I I I I

Each explanation submitted appeared to be unique for that utilityspractices.Reset Interval - Essentially all (96%) employ a time delay resetafter successful reclosing. F or 76 respondents, the reset time isfixed. With a fixed reset time, only 16 of the 76 experienceexcessive interrupting operations due to repetitive faults - withoutreclosing lockout. The reset times reported were:

I INTERVAL I #of RESPONSESI II 120 seconds

Possible Chanqes To P resent P ractices - About 14% of theutilities (15) stated they are considering a change in their reclosingpractices. The objective stated in every case was improvedcustomer service, with each change tailored for that utility.Effectiveness Statistics - J ust 18 utilities reported they keepstatistics on the effectiveness of their automatic reclosingpractices. Only 3 utilities indicated a need to modify the presentreporting practices. One utility reported that83%of their faults arecleared with one reclose. In the 1988survey, 15 utilities reportedthat they kept these statistics, while in the 1984survey, none did.Reclosinq Practices Revised- Twenty-six percent of the utilitiesstated they have changed their reclosing practices n the last fiveyears. Some of the reasons given were to reduce customercomplaints of blinking lights, limit through fault exposure ofsubstation transformers, and to have uniform reclosing practicesacross the utility.

- Eight utilities commented that legal opinions orinterpretations had been made with regard to automatic reclosingon distribution feeders. No further explanations were given; nonehad been requested.Computer Reclosing- Thirteen utilities state they had a computeror programmable logic controller (PLC ) perform automaticreclosing. Also, 6 utilities report they are using computers as astandard or trial installation on their distribution system. Within thenext five years, 24 utilities stated they are planning to use acomputer or PLC for reclosing. In the 1988 survey, 10 utilitiesstated they had plans to use a computer for automatic reclosingwithin the next five years.Fault Monitoring - Twenty-four utilities reported they now haveequipment on their system (other than mechanical counters) tomonitor total interrupted current or the total number of trippingoperations of the interrupting device. Nine of these utilities stated

181the hope that this monitoring will aid them in schedulingmaintenance for the substation breakers. In addition,20 utilities areplanning to add such equipment to their system as a part of thesubstation protection and control package.

SECTION 6 - SYSTEM FAULTSFault Statistics - Seventy-eight of the 107 respondents keepstatistics on the number of outages on their distribution systems.Of these, 30 respondents keep statistics on the types of distributionsystem faults. Eighteen of these reported they record the numberof faults automatically cleared. Seven reported that they maintainrecords regarding faults that must be manually cleared (i.e., highimpedance ground faults). These manually cleared faults involveground, but do not include a broken conductor. Six utilities havestatistics for events involving broken conductors and not involvingground or other phase conductors.lnterruptina Duty - Only 3 of the respondents indicated theymonitor the accumulated symmetrical intempted current for abreaker, 92 said they do not.DetectionofHlGF - Utilities were asked if they had cases in whichfeeder relays, reclosers, or fuses did not detect high impedanceground faults (HIGF). To help define the severity of the problem,utilities were asked to state the percentage of their total recordedground faults that were not cleared automatically. The tabulationis the number of utilities answering yes to a question. To providea perspective, the number of utilities in this survey having eachvoltage class is also shown.The numbers n the following tabulation are essentially the same asin the past survey. A number of additional questions were askedabout HIGF, but with vely few responses as most utilities do nothave detailed data on HIGF.The respondent was asked to indicate whether a phase or groundrelay that was expected to see the fault did not respond to HIGF.The survey did not ask why the relay did not detect the HlGFcondition.

HlGF NOT DETECTED

Total Number of Utilities

Feederrelaysnotdetecting 1 I ; 9 1 ;y phase relaysby gmnd relays 22

17 7y neither phaseorgroundrelavs 13


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182

Dirt or G ~a sTES?

Pole or CrossarmConcrete

Utilities were asked about the type of surface contacted by anenergized conductor that resulted in a HlGF (high impedanceground fault). Here are the responses:TYPE OF SURFACE WITH HlGF

NumberofResponsesI 15 kV I 25 kV IkV 35kV17 44 7 318 42 12 421 36 10 519 36 8 1

hota l Numberof Utilities I 73 I 98 I 46 I 33 I

FEATUREFault current magnitude (phase and ground)Event recording and logging

Storage for a series of fault eventsRemote intermaation (data rettieval)

Faulttype(mulliphase, single phase-to-ground, etc.)

RESPONSES78TI706865

The report of an uncleared HlGF is generated by:

Texas A&M T rial InstallationOeen Conductor Detector

Line O perating Department 40%Line Truck 23%Engineering Department 12%Employee Recall 12%No O fficial Report 6%Other Sources 6%

11

HlGF Protection Schemes - Fourteen utilities responded hat theyhave tried to apply a protection scheme for the sole purpose ofdetecting HIG F. The questionnaire requested a description of thescheme used and asked if there were any coordination problemsassociated with the scheme. The respondents isted the followingfive schemes:

Total intempted current recording and alarmDemand level capabilityRemote intermation and settina manidation

SCHEME TYPE RESPONSESRelay Bias by Load CurrentLow P ickup Ground Relavs

383735

Ground Relay B locks Reset ofI Reclosina RelavSome of the responding utilities have tried more than one scheme.Eighty-eight of the responding utilities have not applied this type ofprotection.Coordination of HlGF Detection Schemes - Al l but one of thereported schemes (4of 5) had coordination or unbalance problems.Mos t appear to have been taken out of service because theproblems outweighed the benefits. The open conductor detector,while apparently satisfactory, requires a large number of detectortransmitters for complete coverage.

Conductor Burndown - Only a small percentage of distributionsystem faults (less than 3% in any voltage class) result inconductor bumdown. Some of the factors contributing to thebumdown problem were given by the respondents as:Lowcurrent levels and long fault timesGround conductor is not continuousSmall conductorCovered conductor

The most frequently cited corrective actions taken to reducebumdowns are:CORRECTIVE ACTION RESPONSES

Improve tree trimmingInstall larger conductorEliminate unfused taps 18Reduce feeder fuse size 15

New Products- Utilities were asked if they are evaluating or usingequipment which allows them to review recent distribution systemfaults. Thirty-two said they are in the evaluation stage, and another22 said they are using these devices at their most importantlocations. The following devices were named:I TYPE OF DEVICE I RESPONSES I

Microprocessorbased relays

Fault RecordersI Electronic controls for reclosers I 5 II SCADA systems I 2 IFrom a long list of features, utilities were asked to check those withthe most benefit to them. The request was to check all thatapplied. Ninety one utilities replied, with many multiple responses.The most frequently cited were:

I FaultlocationI Self diagnostics and alarm contacts I 51 ILocal displayofmeasured valuesPhasebalancemonitoringVoltage monitoringWatt and var monitoringMonitor breaker owrate time 42

I ~naloautDuts to intedace W/SCADA 1 41 II Digitaloutputs to interface w/SCADA I 39 - 1


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183

FOLLOWINGAN OUTAGE OF0 to15 minutes

15to 30minutes

SECTION7 - COLD LOAD P ICKUP (CLPU)AND MAGNETIZING NRUSHCold-Load Pickup (CLP U) - Of the 102 utilities responding to thissection, 77 (75%) stated they have had CLPU problems. Of the77,95% reported problems at 15kV,34% at 5kV, 25% at 25kV, and 8%at 35kV.

PERCENTOFRESPONSES5%19%

30 to45minutes45 to 60minutes

longerthan60minutes

14%33%29%

Residential load clearly dominates the CLPU problem, withcommercial load a distant second. When CLP U problems occur,77utilities said they sectionalize o pick up less load. This solutionwas cited by more than twice the number who reset relays or blocktripping.Only 9% of those reporting CLPU problems have attempted tomeasure cold load currents (magnitude and duration). Of those,using a clamp-on ammeter or station metering is the mostcommon, with SCADA and recording ammeters also used.Compared to the last survey, more utilities are reporting CLPUproblems. When they do occur, the trend is away from disablingtripping and more heavily into sectionalizing and increased relaysettings.Maqnetizina Inrush - Only 15% of the respondents reportmagnetizing nrush problems which cause feeder tripping. This isessentially unchanged rom the last survey. Less than half of those"yes" responses stated this is a recurring problem. The problemwas cited on res idential 15kV and 25kV circuits most frequently,followed by industrial and commercial 15kV and 25kV circuits.Raising the phase or ground instantaneous overcurrent setting isthe most common solution. A few utilities are installing harmonicrestraint nstantaneous overcurrent relays (phase and ground), anda few others are adding time delay to the instantaneousovercurrent relays.

PHASEPROTECTIONFeederDevice

SECTION8 - SYSTEM OPERATIONS

Number of ResponsesMinimumCoordinatonTime inCycles

40I I I I I

Overvoltaae - Six respondents indicated they had experiencedsustained overvoltages due to neutral shift on multi-groundedsystems. Three of these indicated the result was damage tocustomer equipment.

Electromech.Relays

SymDathetic Trippinq - Twenty-one respondents reportedsympathetic trips of breakers on unfaulted feeders. A variety ofcauses were suspected. In some cases, transformer connections,large motors, or large feeder capacitor banks were suspected ofcausing increased currents in the unfaulted feeder. The mostcommon cures were to alter relaying on the feeder by changingsettings or removing an instantaneous trip.Capacitor Switching -Ten respondentsspecifically cited capacitorbank switchingas he cause of undesirable eeder tripping. Curesincluded moving or reducing the size of the capacitor banks,removing fast trips from feeder overcurrent relays, and installingseries inductance.

9 21 35 7 3 1

Coordination Between Bus and Feeder Relays - The minimumcoordination margin between transformer or bus relays and thefeeder relays varied from a low of 3 cycles to a high of 60 cycles.Of the 93 responses to this question, 9 selected less than 12cycles, 54 use between 12 and 20 cycles, 16 were between 21and 30 cycles, and 14 were greater than 30 cycles.Only a few responses were made to the question of maximumcoordinating current levels. Typically, utilities used a currentbetween5 and 10 times the phase overcurrent relay pickup setting.Only 10 utilities indicated a requirement for all overcurrent relaysto be reset before a reclose is permitted. Roughly half (35 of 68)believe a fast reset of reclosing or overcurrent relays aids incoordination.Coordination Between Feeder Relays and Fuses - Minimumcoordination margins allowed between feeder overcurrent relaysand line fuse total clearing times are tabulated in the two tables forPHASE PR OTEC TION and GROUND PROTE CTION. n comparingthese tables, note that most utilities do not differentiate betweenphase and ground protection n setting minimum coordination time.

Sdid State

ElectronicReclosers iv0 2Fused Cutouts - Most utilities use fused cutouts with ratingssufficient to handle available fault currents on their distributionsystem. At 5kV, only 11% (6 of 56 utilities) use under-rated


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184cutouts; at 15kV, 20% (17 of 85); t 25kV, 5% (2 of 41); and atOf those using under-rated fused cutouts, 5 of 18 respondentsindicated unnecessary trips have occurred, but only 3 of these tripswere reported at 15kV. Eight respondents indicated minimaldamage at the point of the fault; 6 indicated moderate damage; 2indicated no damage. At the cutout location, 9 reported nodamage, 7 reported minimal damage, excessive damage wasreported by 3, and moderate damage was reported by2.Current-Limitinq Fuses fCLFs) - As shown in this table, a smallnumber of the respondents use CLFs:

35kV, 3% (1Of 34).

I CURRENT-LIMITINGFUSE USE - Numberof ResDonses I

I OnUG tine Laterals 1 5 1 8 1 9 1 6 IRespondents were allowed to choose multiple answers for theirreasons to use current-limiting fuses. Safety was cited by 53utilities. High fault currents n excess of expulsion fuse interruptingratings was the reason chosen by 32 respondents. The use CLFsto limit I2t let through was cited by 29. Locations requiringnon-expulsion fuse types was the reason selected by 23, and 7cited "Convenience."Fourteen (of 78) respondents reported coordination or applicationproblems in the use of CLFs. The types of problems reportedvaried, but several indicated coordination with upstream ordownstream fuses as the problem. The resolution of the problemmost often reported was to simply accept the miscoordination.When asked if CLFs are applied on the source side of CompletelySelf-Protecting (CSP) transformers, 27 respondents said "yes" and32 answered "no." No one uses CLFs on the load side of thesetransformers.The reasons given for the use of CLFs on the source side of CSPtransformers were predominantly to protect against catastrophictransformer failures.

Automatic Sectionalizers- Sixty-threepercent of the respondents(67 utilities) apply sectionalizerson distribution eeders. The surveylisted four specific types plus "Other". Here are the responses:Electronic three-phase 43 responsesHydraulic single-phase 38Hydraulic three-phase 26Dry-type single-phase 134

124 from 67 utilitiesOther * -Total responses:In the "Other" category, one utility uses single-phasehydraulic sectionalizers on 5kV feeders and three-phaseelectronic sectionalizers on 25kV feeders. Another utilityuses single-phase electronic dry type sectionalizers. Twoutilities use single-phase electronic sectionalizers. Inaddition, one utility is evaluating cut-out-door typesectionalizers. Twenty-eight percent reported no use ofautomatic sectionalizers.

Fifty-two percent of the respondents reported no problems withLONG reset times of sectionalizers as related to reclosing cycles.

A number of techniques were cited to resolve he problems that didoccur:--- alter breaker reset times-

change operating times in sectionalizer to coordinatewith breaker reclosinguse circuit reclosers on feeders with relayed breakersuse electronic reclosers with synchronizer

Two utilities have not resolved their problems, and two utilitiesreported removing sectionalizers from service to resolve theirproblems.Fifty-nine percent of the respondents reported no problems withSHORT reset times of sectionalizersas related o reclosingcycles.These techniques were cited to resolve problems:

-- use sectionalizers with 145 second reset timeuse electronic rather than hydraulic reclosersThere has been a decrease from 76% in the number of utilitiesreporting the use of sectionalizerssince 1988 (now 63%), and onlythe percentage of electronic sectionalizers held its own.Distance Relavs - Only 10 percent (11 utilities) report finding itnecessaryto use distance relays on distributioncircuits. This is anincrease from 6% reported in the 1988 survey. The followingsystem requirements dictated their application:

feeder phase reactorsleft over froma looped systemfault current comparableto load currentlong35kV feeders with sectionalizer tieslong, multi-looped34 kV systems with generationvery heavily loaded34.5 kV circuitsFive utilities use distance relays for torque controlling overcurrentrelays. Two utilities use distance relays for faster clearing, with thetime overcurrent relay operatingas independent backup. One utilityuses distance relays to allow higher oad capability. While anotheruses them for phase protection, with overcurrent relays for groundprotection.The following distance relays and schemes were reported:

three-phase, two or three zonesthree-phase, one zone (three utilities)phase and ground multi-zonesingle-phase, two or three zones

Transfer Buses - Forty percent of the respondents (43 utilities)reported the use of a separate transfer bus within distributionsubstation switchgear. Of the fifty percent which reported notinstalling a transfer bus, these alternatives were described:use field switching to bypass feeder breakersbreaker bypass onto main bususe mobile subs ortransformersvacuum switchgear with bypass breakersuse single or double synchronizing bus designuse line disconnect to tie linestogetheratsubstation

Forty-one percent (44 utilities) have the transfer bus or altematebus arranged so that it can be tied to any feeder. To protect thetransfer bus, a number of different primary protective devices areused:

25 incorporated with another feeder22 independent relayed interrupting devices6 incorporated with transformer overload protection3 dedicated to specific feeder1 fuses


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185

reportng100%coveragepercentof feeders,average

Forty-nine percent of the respondents require manual operation toactivate switching. Many switching schemes were reported, mostusing manual disconnects. A few reported the use of SC ADA.One utility uses automatic load transfer for bus or bank differential.Another utility uses a 5-second delayed load transfer when loss ofpotential occurs.In summary, there has been a decrease in the use of separatetransfer buses since 1988, down from 55% to 41%. The use ofSC ADA to activate switching has begun to occur.

27% 33% 46% 45%79% 70% 93% 06%

Differential Relavs - Eight-two percent (88 utilities) reported theuse of transformer differential schemes in distribution substations.The number of utilities installing these schemes were reported bycategory:

BUS DIFFERENTIAL RELAYCRITERIA

TRANSFORMER DIFFERENTIALRELAY CRITERIAsecondaryvoltage leveluse mnmumtransformersizeindude secondarybus

5 kV 15kV 25 kV 35kV

Minimum transformer size warranting differential schemes rangedfrom 5 MVA to 50 MVA, with most 10 MVA to 15 MVA.Respondents indicated that installation was dependent on thefollowing criteria:importance of station 32%incoming voltage 26%required for new stations 26 Yo

Other criteria cited were:more than one transformer at a stationreach of adjacent line relayingselectivity of fusestype of feeder switchgearnumber of feedersexistence of high-side switching deviceexistence of sudden pressure relay

The percentage of utilities reporting the use of transformerdifferential schemes is almost unchanged since 1988.Forty-four percent (47 utilities) reported the use of separatesecondary bus differential schemes in distribution substations. Thequestionnaire asked utilities to name all of the following whichapplied:

distributonvoltage levelmetalcladswitchgearopenoutdoor bususemnmumtmsfoner sizeusemnmumno. of feedersinstantaneousrelav 27time overcumntrelayvoltage class

9 1 7

46 I 33

Respondents indicated that the use of differential relays wasdependent on the following criteria:importance of station 20%required for new stations 20%incoming voltage 15%

Other criteria cited were:more than one transformer at a stationtype of feeder switchgearsize of transformersparallel feeders

Backup R elaving- Local backup relaying that covers 100% of thefeeder breakers is more common at 25 and 35 kV. On average,over W4 of feeders are covered by local backup relaying:I USELOCALBACKUPRELAYS I 5k V I 15kV I 25kV I 35kV IThe percentages of responding companies using a type of backuprelaying is:

transformer neutral overcurrent relaying 46%transformer low voltage overcurrent relaying 44%transformer high voltage overcurrent relaying 42%transformer distance relaying 3%

Other types listed in the responses were:transformer high voltage fusebus overcurrentpartial bus differentialoverlapping zonesfault bus relayingbackup (redundant) feeder relaysbus tie overcurrenthigh voltage circuit switchers

The percentageof utilities reporting the use of local backup relayingfor feeders is almost unchanged since 1988.Breaker Failure Protection- Only seventeen percent (18 utilities)reported using "breaker failure" protection on distribution feeders.The 18 utilities reported these percentages of feeders havingbreaker failure protection, by voltage class:

BREAKER FAILUREPROTECITONnumberofutlites reportngpercentof feeders

The breaker failure schemes which were described included:fault detectorstimersseparate dc supplytripping bus differential lockoutannunciator only

The percentage of utilities reporting the use of breaker failurerelaying for feeder breakers is almost unchanged since 1988.


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Total Capacity (MVA)0 - 22 - 5

Field Test Distribution Transformers Thirty percent (32 utilities)reported they test distribution transformers in the field when thereis evidence of an external fault.

5 V 15 kV 25 kV 35kV5 7 3 22 6 3 1

SECTION 9 - EFFECT OFDISPERSED SOURCES OF GENERATION (DSG)For the first time, utilities were asked about the effect DSG has hadon the protection practices for distribution circuits.Statistics About Presence of DSG - The section of the survey onDSG effects wa s completed by 100 of 107 total surveyrespondents. A majority of those responding (75 of 100) haveDSG on their systems; 25 have no DSG. Of the 100, 28 utilitiesstated they have DSG installations at several voltage levels. Inresponse to the question, "Do you have DSG on your distributionfeeders?", there were 115 "yes" and 95 "no" answers from the 100respondents, indicating multiple replies from many utilities.There was a wide dispersion of data regarding total capacity,number of installations, largest installations and maximumallowable MVA size. Each of these data items was classified byvoltage class. Not all utilities provided data in every area. Forexample, only 53 utilities provided the following data on total DSGcapacity:

5 1010 2020 50

I TOTAL DSG CAPACITY I

1 12 1 20 8 1 11 3 3 1

Total #Responses~

9 44 12 10I 50 UD 1 0 1 8 1 1 1 3

Mean TotalDSG Capacity (MVA) 3.8 26.9 29.5 46.8

Total # InstallaConsMean Installed Size (MVA)

In the survey, 822 DSG installations were reported on the 100survey respondents' systems. The vast majority of DSGinstallations were on 15kV distribution systems (631 of 822), asseen in this table:

~

59 631 65 67.44 3.5 3.7 5.4

may be connected to a feeder.Effects on Protectionof the Feeder- The most common changeson protection were:

1) Revised reclosing practices 36 responses2) Revised coordination of feeders 283) Added voltage relays 244) Added transfer trip 24Chanqes to Reclosing and Sectionalizinq Practices - Of thethirty-six respondents that have revised their reclosing practices,the primary changes were:

1) Extend reclose time 15responses2) Reclose to dead feeder only 103) Add live budlive line sync check reclosing 54) R educe the number of reclosing cycles 4Reclosing changes were generally to lengthen the "open"interval($, to reduce the number of reclosures on circuits withDSG, and to add voltage andlor sync check supervision in thereclosing scheme.The changes to sectionalizing devices were primarily to eliminatethe poss ibility of single-phase interruptions between the DSG andthe substation. This included removing fuses and other single-phase devices.Fault Current Contribution From the DSG - The phase faultcurrent contribution from the DSG is primarily determined bytransformer impedance and generator reactance, according tosurvey responses. Reactors were rarely used.Ground fault current is primarily determined by the transformerimpedance (70%). Neutral reactors or neutral resistors were usedby 13% of respondents and mainly in 15 kV systems.Fault current contribution from induction generators is included infault current calculations by 16% of the survey respondents.Load Unbalance Allowable - The majority of respondents (70%)permit 25% or less load unbalance with a DSG. This changedvery little from the data without a DSG. Thus, the presence of aDSG did not materially affect the permissible load unbalance.Recommended Transformer Connections- An equal number ofrespondents required grounded wye versus delta utility sidetransformer connections. Approximately 90% of all responsesutilized these two connections.Ferroresonance Problems - Only three of the survey responsesindicated poss ible ferroresonance or unexplained nsulation ailureson lines equipped with DS G. Sixty-seven respondents ndicated noproblems had been encountered.REFERENCES

Distribution Line Protection Practices - Industry SurveyAnalysis, IEE E PSRC Committee Report, IEE E Transactionson Power Apparatus and Systems, Vol. PAS-102, No. 10,October 1983, pp 3279 - 3287.Distribution L ine Protection Practices - Industry SurveyResults, IEEE PSRC Committee Report, IEEE Transactionson P ower Delively, Vol. 3, No. 2, April 1988, pp 514 - 524.

00368400_Distribution Line Protection

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