Transformer ProtectionApplication Guide

About the Author

George Rockefeller is President of Rockefeller Associates, Inc. He has a BS in EE from LehighUniversity; a MS from New Jersey Institute of Technology and a MBA from Fairleigh DickinsonUniversity. Mr. Rockefeller is a Fellow of IEEE and Past Chairman of IEEE Power Systems RelayingCommittee. He holds nine U.S. Patents and is co-author of Applied Protective Relaying (1st Edition).

Mr. Rockefeller worked for Westinghouse Electric Corporation for twenty-one years in application andsystem design of protective relaying systems. He worked for Consolidated Edison Company for tenyears as a System Engineer. He has also served as a private consultant since 1982.

This Guide contains a summary of information for the protection of various types of electricalequipment. Neither Basler Electric Company nor anyone acting on its behalf makes any warranty orrepresentation, express or implied, as to the accuracy or completeness of the information containedherein, nor assumes any responsibility or liability for the use or consequences of use of any of thisinformation.

Revised 8/03

1

Transformer ProtectionApplication Guide

This guide focuses primarily on electricallyactuated relays for the more prevalent applica-tions. Principles are emphasized. The refer-ences provide a source for additional informa-tion. Reference 1 includes extensive referencesand bibliographies. References 2 & 3 contain achapter on transformer protection.

This guide was prepared to assist in the selec-tion of relays to protect power transformers. Thepurpose of each relay is described and relatedto one or more power system examples.

The engineer must balance the expense ofapplying a particular relay against the conse-quences of relying on other protection or sacri-ficing the transformer. Allowing a protracted faultwould increase the damage to the transformerand the possibility of tank rupture with a conse-quent oil fire. An increase in damage would notnecessarily have significant economic impact,depending upon whether the initial damage canbe repaired on site. For example, a tap changerflashover can ordinarily be repaired in the field,but if this fault is allowed to evolve into a windingfault, the economic impact can be substantial.Transformers used in a unit-connected genera-tor unit are particularly critical, since the unavail-ability of the transformer can create largegeneration-replacement costs. Similar economicimpacts may also exist at industrial sites. Thisexplains why the MVA rating of the transformermay not be the pivotal aspect in choosing theappropriate protection.

Setting procedures are not included; refer tospecific instruction manuals. Fuse protection isonly briefly addressed. Grounding transformersand 3 phase banks of single-phase transformersare not considered here, but are treated inReference 1.

Table I (page 18) provides Basler model,function, description and style number. It alsoreferences the figures where the relays areindicated by their ANSI numbers.

1. Failure Statistics

Table II (page 3) lists failures for six categoriesof faults (Reference 1). Winding and tap chang-ers account for 70% of failures. Loose connec-tions are included as the initiating event, as wellas insulation failures. The miscellaneouscategory includes CT failure, external faults,overloads and damage in shipment. An undis-closed number of failures start as incipientproblems. These failures can be detected bysophisticated on-line monitoring devices (e.g.gas-in-oil analyzer) before a serious eventoccurs. Such devices will probably see increas-ing use on larger transformers, to supplementmore conventional relays (Reference 8).

2. Fuses

Fuses are economical, require little maintenanceand do not need an external power source toclear a fault. However, they introduce single-phasing conditions when just one or two

FIGURE 1. (See Legend, next page).

fuses blow, which can cause overheating of3 phase motors. Also, fuses have a somewhatlimited interrupting capability and provide lesssensitive protection than that of a differential orground relay. Fuses should not be employed onresistance-grounded systems, since they mustcarry the maximum load current and, therefore,cannot blow for low-current ground faults. Fusesare probably the predominant choice for trans-formers below 10 MVA.

Where a fused transformer uses a low-sidecircuit breaker, the breaker should be equippedwith phase and ground overcurrent relays asbackup of downstream devices. However, theserelays will not respond to a transformer fault.

3. Protection Example

Fig. 1 shows extensive use of relays representa-tive of a large industrial load. There are two 115kV feeds to 30 MVA transformers that are

resistance grounded on the 13 kV side. Adetailed discussion of this application is prema-ture, but the following is an introductory treat-ment. The phase differential (87), grounddifferential (87N) and sudden pressure relay (63)provide the primary transformer fault protection.Note that the 51N-2 relay serves primarily asback-up rather than as transformer protection.The 51 and 51N-3 relays function as partialdifferential relays to protect the bus and back upthe downstream relays and breakers. The 67Nrelay offers an alternative to the 87N function.The 50/51 phase overcurrent relays providetransformer backup. Also note the redundantlockout relays (86), with the trip connectionsarranged such that complete protection isavailable even with a failure of one 86 relay or itsdc feed.

If such an installation involves local generation,frequency and voltage relays might also sensethe islanding of the station. The 67 directionalovercurrent relays respond to circulating loadcurrent through the 13 kV busses if the 115 kVbreaker A opens. The 67 relays also providebackup for the 115 kV line relays, as well asbackup for transformer-zone faults. This is inaddition to the backup provided by the 50/51relays.

This example will be revisited after presentingsome principles and concepts.

4. Differential Relaying

Differential relays sense the unbalance in theflow of currents in various apparatus or busses.In the absence of a fault in the protected zone,this unbalance tends to be small because the

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flows into the zone are cancelled by the flowsleaving. Accordingly, such relays can be moresensitive than phase overcurrent relays andneed not be delayed to coordinate with otherrelays during external faults.

The simplest implementation of differentialprotection merely parallels the CTs on all theconnections to the zone, per Fig. 2. However,more sophisticated means are usually employedto provide faster, more sensitive and reliableschemes.

Transformer differential relays utilize a restraintcurrent in addition to the operating current ofFig. 2. This produces a percentage differentialcharacteristic, by separately measuring the inputcurrents, per Fig. 3. Fig. 4 shows such acharacteristic for the BE1-87T phase-differentialrelay, where operating (or “differential”) currentis plotted against the maximum (or larger)restraint current. The scaling is in “multiples oftap”. The ratio matching taps will be explained inthe next section. The slope of the character-

istic can be set from 15 to 60%. The relaybecomes desensitized at the higher currents inorder to remain secure in the presence ofdissimilar CT performance. This creates falseoperating current. In contrast, the characteristicof the relay in Fig. 2 is a horizontal line. Therestraint current can be derived in a number ofways. In the BE1-87T, the maximum of the inputcurrents provides the restraint, yielding aconsistent method regardless of the number ofinputs. Up to 5 inputs per phase can be sepa-rately measured, depending upon the relaystyle.

Transformers present differential relays withdistinctive problems, which affect their designand application. These are:• Unequal secondary currents, because of

the different turns ratios of the powertransformer windings and the cts.

• Phase shift of wye-delta banks.• Tap changing under load.• Magnetizing inrush.• Unmeasured grounded neutral current.

4.1 Current Matching

The matching of unequal currents requires eitherauxiliary CTs or a means of scaling within therelay. Fig. 5 shows the use of taps on the relaywindings to match a 2-to-1 difference in thelevels of the CT secondary currents under non-fault conditions. For this difference the 10Acurrent flows through just half the number ofturns in restraint winding R1 as does the 5Acurrent in restraint winding R2, so that theampere-turns of the two windings are equal.

FIGURE 3.

FIGURE 4. FIGURE 5.

This tap position also connects to the midpointof the operating winding, so that the net opera-ting ampere-turns is zero. Thus, by ratio match-ing, the input currents are normalized and theoperating signal is reduced to zero. Fig. 5applies generally to electromechanical relays.

Fig. 6 shows the BE1-87T’s matching taps onthe secondary of the relay’s input CTs. Ratherthan use an operating CT, this relay developsthe operating signal electronically. The BE1-87Thas a matching range of 2 to 8.9A in 0.1A steps.The taps are selected to be in proportion to thecurrents to be matched.

Matching of three winding transformer applica-tions must in effect be done two windings at atime, rather than assuming some arbitrarycurrent distribution among the three windings.The procedure can be streamlined by assumingidentical power in all three windings. While this isa physical impossibility, it allows proper currentmatching for all current distributions.

4.2 Phase Shift Compensation

The phase shift developed in a wye-delta powertransformer can be handled by connecting theCTs in wye on one side and in delta on the otherside, per Fig. 7. The relay current input from thedelta CTs is the phasor difference of two phasecurrents. The BE1-87T can perform thisdifferencing electronically, preventing the

need to connect the main CTs in delta. Withwye CTs a ground relay also can be connected.A wye connection also reduces lead burden fora phase fault. The worst case is for a 3-phasefault with delta cts, per Fig. 8; the lead burdenvoltage is magnified to three times the 3 phase-fault value with wye cts.

Note in Fig. 7 that the delta CTs are on the wye-grounded side of the transformer. The phaseshift can be accommodated with the delta CTson either side. However, it is essential to put the

FIGURE 6.

FIGURE 7.

FIGURE 8.

5

delta CTs on the wye side in order to preventincorrect tripping for an external ground fault,shown in Fig. 9. Here, the delta CTs are on thewrong side. The three units of current flowentering from the grounded wye are not mea-sured, so they produce an unbalance. (Thedelta-CT ratio is assumed to be 3/1 to providebalancing for phase faults.) In contrast, in Fig.10 delta CTs on the wye side produce a bal-ance. Since the unbalance on the primary of the

wye-side CTs is caused by zero-sequencecurrent, the delta CTs filter out this unbalance inFig. 10.

There are two ways to form the CT delta. Theconnections must mirror those of the powertransformer to provide the proper balance.

4.3 Tap Changing Under Load

Current matching should occur for the conditionwhere the load tap changer is in its neutralposition. Then, the relay must accomodate theunbalance with the taps at the full boost or buckposition. The percentage differential characteristicprovides this accomodation, per Fig. 11. The“total mismatch” line represents the sum of theimperfect relay-tap match plus the power trans-former tap contribution. The slope of this line isapproximately the total % mismatch. The mis-match line is offset by the transformer excitingcurrent, which produces its own unbalance. In theBE1-87T, available taps limit the maximummismatch to 2.5%. Fig. 11 also shows the BE1-87T characteristics at the twoextremes of slope setting (15 and 60%), as wellas the related safety margins at the critical points.The relay characteristic contains the flat sectionin order to maintain good sensitivity forlow-current faults where the load current is non-negligible. The total current flowing is the pre-faultcurrent plus the current produced by the fault.Accordingly, for small fault currents the loadcurrent introduces a significant restraint bias.

4.4 Magnetizing Inrush

Inrush is the transient exciting current resultingfrom a sudden change in the exciting voltage.

FIGURE 9.

FIGURE 11.

FIGURE 10.

7

This occurs at the instant of energization, theclearing of an external fault (recovery inrush) orduring the inrush period of another transformer(sympathetic inrush). (Reference 4)

Since inrush current appears as operatingcurrent to a differential relay, the relay musthave sufficient delay and insensitivity to thedistorted wave or take advantage of the inrush’sdistinctive waveform by using harmonic restraintor some other form of pattern recognition. Thesecond harmonic predominates in inrush cur-rents (Reference 4) and is used in most trans-former differential relays, either alone or incombination with other non-fundamental compo-nents. The relays restrain if the harmonic(s)exceed(s) a percentage of the fundamentalcomponent. Historically, this percentage hasbeen fixed by design. Some newer designsprovide for a user setting.

Current transformer saturation also generatesharmonics. Under symmetrical conditions, CTdistortion produces only odd harmonics.Under assymetrical conditions CT distortionproduces both even and odd harmonics. CTsaturation under assymetrical conditions candelay a harmonically restrained element. Ac-cordingly, an unrestrained element, set abovethe maximum inrush level complementsthe restrained unit. It is important to provide CTswith sufficient quality to provide good waveformlong enough to allow either the restrained orunrestrained element operation.

Reference 5 provides means to evaluate CTadequacy. Appendix I (page 19) of this guideprovides an example of such an evaluation.

The unrestrained element responds to theoperating or differential current and must be setto override the largest expected inrush pulses. Itmust also override similar pulses caused bydissimilar dc saturation of the CTs during highcurrent external faults. For these reasons thiselement is set two orders of magnitude higherthan the restrained element pickup.

4.4.1 Energizing Inrush

This transient results from remanence (residualflux) in the core. If the instantaneous voltage atenergization calls for flux of the same polarity

as the remanence, the core is driven intosaturation, creating peak exciting currents thatcan exceed ten times rated peak. This compareswith a normal steady-state exciting current of0.01 to 0.02 times rated. Inrush current appearsas relay operating current.

In Fig. 12 the steady-state flux at the instant ofenergization matches the residual flux, so notransient current flows. In contrast, in Fig. 13 thesteady-state flux at energization is at its negativepeak. Combined with a positive remanence, thiscondition produces the maxi-mum level of transient current. The inrushcurrent is actually much larger in relation tosteady-state current i

e than indicated by Fig. 13.

Fig. 14 shows a typical inrush waveform. Notethe “dead spot”, where almost no current isflowing as the core exits the saturated region.

FIGURE 12.

FIGURE 13.

However, this “dead spot” disappears on subse-quent cycles because of CT saturation (Refer-ence 5). In extreme cases the CT can saturateduring the first cycle, eliminating the “dead spot”.The decay rate of successive primary-currentpeaks depends upon the amount of resistance inthe source and the non-linear inductance of thetransformer. In Fig. 14, the negative peaks arereduced further by CT saturation. The primarycurrent peaks will not decay as fast as indicatedby the CT output of Fig. 14.

4.4.2 Recovery Inrush

A recovery inrush occurs at the clearing of anexternal fault as a result of the sudden increasein voltage from the depressed level during thefault. This voltage transient causes a fluxtransient, with accompanying abnormally highexciting current. The current level will be lessthan that of an energizing case.

4.4.3 Sympathetic Inrush

Current Ip in Fig. 15 shows sympathetic inrushcurrent in transformer T1, resulting from theenergization of an adjacent transformer T2. Thedecaying dc component of current Ie flowing inT2 develops a drop in the source resistance Rs,producing pulses of inrush current Ip on thealternate half cycles. Note the delayed buildup ofIp. The severity of the sympathetic inrush is afunction of the level of dc voltage drop acrossthe source resistance. A common set of differen-tial relays should not be used to protect both T1and T2 transformers in Fig. 15 if they can beswitched separately. The sum of the two trans-former currents, Is, may not contain sufficientharmonics to restrain the relays once trans-former T1 saturates severely.

4.5 Overexcitation

Overexcitation results from excessive voltage orbelow-normal frequency or a combination of thetwo such that the volts/Hz exceed rated. Fig. 16shows three situations where overexcitation canoccur: a unit-connected generator isolated fromthe system or a transformer connected on theopen end of a long line. In addition, an intercon-nected system can experience a dynamicovervoltage following a protracted fault as aresult of generator fields at ceiling or followingload shedding. All of these scenarios involveessentially balanced conditions. Substantialphase-to-ground overvoltages can also occur onsound phases during a ground fault on imped-ance-grounded systems. In these cases deltawindings or wye-ungrounded windings will notbe overexcited, since the line-line voltages willnot increase.

The dashed curve in Fig. 17 illustrates theincrease in transformer exciting current withincreased excitation, resulting in thermal stress.This exciting current produces operating currentin the differential relay, but an operation of thisrelay is not desirable, since immediate responseis not necessary. For a dynamic overvoltagecondition, the power system should be allowedtime to correct itself. Also, a differentialoperation indicates a transformer failure, requir-ing unnecessary investigation and delayedrestoration of the transformer. Accordingly,where sustained overexcitation is a concern, aseparate volts/Hz relay should be applied (24).

FIGURE 14.

FIGURE 15.

The solid curves of Fig. 17 illustrate the variationin harmonic content with voltage changes as apercentage of the fundamental value for abalanced excitation. The presence of a thirdharmonic component indicates that the wye-grounded winding was energized. When a deltawinding is energized all triplen frequencycurrents (i.e. third, ninth, etc.) are blocked,because they are in phase on a fundamentalbasis. With a wye-delta bank, the CTs areconnected in delta on the wye side (or the wyecurrents are electronically differenced). Thus,third harmonic component in the relay currentsis cancelled. Accordingly, the lowest harmonicavailable to the relay for restraint is the fifth. TheBE1-87T restrains if the fifth harmonic exceeds35% of the fundamental. In Fig. 17, this relay willrestrain over the voltage range of

104 to 138% of rated excitation.

If the transformer is unloaded, as per Fig. 16(a)and (b), the relay operating current will be theexciting current less its third harmonic compo-nent; then, based on Fig. 17, the fifth harmoniccontent exceeds 35% over the range of about104 to 138% of rated excitation. Should thetransformer become faulted, the relay willoperate if the fault current is sufficient to reducethe fifth harmonic component below the relay’srestraint level. Such a reduction occurs bothbecause of the reduced excitation level and dueto the fundamental-frequency fault current.

If the transformer is loaded (e.g. Fig. 16(c)), anymismatch current will reduce the fifth harmoniclevel of the operating current; the relay may notbe restrained by the fifth harmonic. However, thetransformer loading will reduce theoverexcitation to a level where the operatingcurrent will be below pickup. For example, if thetransformer is at 115% excitation, Fig. 17indicates a magnetizing current of 3% (including3rd harmonic); this plus mismatch current shouldbe insufficient to operate a relay.

With normal system connections the powersystem could be operated at 105% continuouslyand dynamically as high as about 115% during asevere disturbance. Under these conditions thethird harmonic may be sufficient to restrain therelay; should the transformer become faulted,the fault current will swamp out the excitingcurrent to allow the relay to trip.

Voltages in excess of 138% can follow full-loadrejection of hydro units. However, generatorspeed will be correspondingly high, so the volts/Hz value will not significantly exceed normal.

4.6 Connection Examples

Fig. 18 provides application examples for two-,three- and five-restraint cases. The relayderives restraint signals separately from eachset of CT inputs. In Fig. 18(a) the relay protectsa delta-wye transformer, with the CTs connectedin delta on the wye-winding side. These CTscould be connected in wye when using a 3phase style BE1-87T by selecting the electronicdifferencing option. This differencing option

FIGURE 16.

FIGURE 17.

9

10

duplicates the effect of a delta-CT connection.The operating signal is obtained by connectingthe operating coil to measure the sum of therelay input currents or electronically as is thecase in the BE1-87T. A three-input relayprotects the autotransformer in Fig. 18(b). All

CTs must be connected in delta (or equivalentelectronic differencing with a 3 phase relay),since the autotransformer is a zero-sequencecurrent source. Otherwise, any current flowing inthe transformer ground connection will unbal-ance the differential relay. This current isnot measured and inputted to the relay. Therelay Fig. 18(c) protects the combination of abus and transformer.

A transformer differential relay can be appliedfor bus or combination bus/transformer protec-tion. CTs can be paralleled and connected to acommon restraint input. Radial feeder CTs canbe paralleled as long as the continuous rating ofthe relay winding is not exceeded. Sourcecircuit CTs can also be paralleled, but it must bedone judiciously. Fig. 19 shows the use of a two-restraint relay for the bus/transformer combina-tion. Here four sets of source CTs are paralleledand connected to a common restraint windingR1. Such paralleling might produce a current inexcess of the continuous rating of the restraintwinding. Also, incorrect operation may occurduring an external fault as illustrated in Fig.19(a) and (b), where the faulted-circuit CTsaturates severely. The secondary current oncircuit 2 should be 70A, but is only 50A due toCT saturation. The CT deficiency of 20A causesthe flow in restraint winding R1 and in theoperating circuit. Since no current flows in R2,the relay is operating along the “single-feed line”in Fig. 19(b). This is an operating condition,even though the fault is external to the relayzone of protection.

Paralleling of CTs on non-source circuits can besafe, within the thermal limitations of the relay. Inthis case there is no loss of restraint for externalfaults, since these circuits contribute no faultcurrent. Again, source CTs can also be paral-leled, but it must be done judiciously. Forexample, in Fig. 19(a), if CTs 1 and 2 wereparalleled on R1 and CTs 3 and 4 on a thirdinput R3, the 40A flow in R3 would be sufficientto prevent incorrect tripping if the relay is setwith a 60% slope.

4.7 Phasing Example

Fig. 20 shows a procedure for phasing the CTconnections for a wye-delta transformer. There

FIGURE 18.

11

wye CTs (on the delta side) and to one side ofthe delta-connected CTs, as shown in Fig. 20(a).Step 2 is to show the currents flowing tothe wye power transformer winding: Ia, Ib, Ic.Step 3 develops the currents flowing out of thedelta power transformer winding—these dependupon the actual transformer delta connections.Step 4 shows the relay currents resulting fromthe wye CT primary currents which are deter-mined from the polarities of the CTs. Step 5duplicates the currents from step 4 and dictates

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are two ways to make the delta connection ofthe power transformer for either a 30 degreelead or lag. The delta CTs (or relay differencing)must compensate for this power transformerphase shift. The circled numbers in Fig. 20(a)represent the steps in the phasing process. Thefirst step completes the relay connections to the

FIGURE 19.

FIGURE 20.

how the CT delta windings must be completedas shown in step 6 of Fig. 20(b). For example,in order to produce IA-IC in the direction shown,the non-polarity side of the phase “C” CT mustconnect to the phase “A” polarity side. With thedelta CT connection, the relay currents on eachphase are in phase. Any difference in magnitudeis handled by selecting current taps approxi-mately in proportion to the current inputproportion. The delta CT connection also servesto filter any zero-sequence component from therelay. This component circulates in the CT delta,but does not appear in the relay.

4.8 Ground Differential

Where impedance grounding limits the groundfault current to levels below the sensitivity of thephase differential, this relay can be comple-mented with a separate ground differential relay.This can be a differentially-connected

overcurrent relay, shown as 87N-1 in Fig. 21.However, such protection must use a delay (e.g.25 cycles) to ride through the false residualcurrent resulting from the dissimilar performanceof the phase CTs during a phase fault. Thephase fault current can be 100 times the maxi-mum level of current during a ground fault. Thus,it does not take much difference in the perfor-mance of the phase CTs to create a large falseresidual current. For the same reason, a per-centage differential relay for the ground differen-tial function can be insecure during externalphase faults, since the neutral current contrib-utes negligible restraint during phase faults.

With the 13.8kV bus tie normally closed in Fig.1, either a ground differential or directionalground relay is needed. Otherwise, the neutralovercurrent relays on both transformers willoperate for a 13.8kV winding or lead fault,resulting in an unnecessary interruption of thestation.

The amount of current for a ground fault in thewye winding tends to be a function of the faultlocation in relation to the winding neutral. Agood objective is to provide sufficient sensitivityto detect a fault 10% from the neutral end,where the current will be about 10% of themaximum current. In Fig. 21, the 20 ohm resistorlimits the transformer ground current to about(13,800/1.73)/20= 400A for a lead or transformerterminal fault. A 10% fault, then, yields 40Aprimary and 0.67A in the secondary of the 300/5neutral CT. This current is matched by theresidual current from the 2000/5 CTs by theauxiliary CTs (ACT) with a step-up current ratioof 1 to 6.7A. The secondary burden on the ACTwill be magnified by the square of the currentratio or 44 times. However, while the ohmicburden can be very high, the ground currentlevel is limited by the grounding impedance. Forexample, a 0.5 ohm secondary burden reflectsto a 22 ohm primary burden, but the maximumcurrent is just 400/400= 1A for an external line-ground fault, yielding a burden voltage on the2000/5 CTs of 1*22= 22V.

The 87N-1 relay pickup in Fig. 21 is set for 0.5Abased on a neutral current contribution of 0.67Arelay current for a ground fault 10% from the

FIGURE 21.

A wye connection for the 2000/5 CTs on the lowside facilitates the auxiliary ct (ACT) connection.With the conventional delta connection of theseCTs for a 3-phase 87T relay, 3 ACTs must beplaced inside the delta, requiring the running ofall six CT leads to the relay location.

In Fig. 21, the BE1-87T relay (3 phase model)allows a wye connection with electronicdifferencing duplicating the phase shift otherwiseprovided by the delta CT connection. The 4.3Atap of the 87T on the low-side is selected as ifthe CTs were connected in delta. This tapmatches the currents within 1%.

Fig. 22 shows the development of false residualcurrent by the phase CTs during an external“AB” fault due to dissimilar CT performance. Thephase A CT performs well, but the phase B CTcurrent of 28A is deficient by 2A. This deficiencyappears as residual current and develops 13.3Ain the 87N relay, producing 27 times pickup.

Fig. 23 shows the application of a currentpolarized directional ground-overcurrent relay forthe 87N-2 ground differential relay function. Thepolarizing winding of the directional elementmeasures the neutral current, while the differen-tial current supplies the directional elementoperating signal and the overcurrent signals.Fig. 23 shows that the auxiliary CT in theresidual circuit over-mismatches the neutralcurrent. For a 400A line-ground fault the differ-ential current is 1.3A of the polarity to provide abias in the non-trip direction, providing addedsecurity.

The directional element provides security duringmulti-phase external faults, where dissimilarphase CT performance develops false residualcurrent, as shown in Figure 22. Because theresidual current is highly distorted and the waveform varies from cycle to cycle, directionaloperation is intermittent. Each time the direc-tional element resets, it resets the time-overcurrent element. Accordingly, theovercurrent element delay can be set for afraction of the fault duration.

neutral end of the wye winding. By comparison,the 87T phase differential relay sees the trans-former contribution for a phase fault as 0.05Acompared to a pickup of 0.7A. The 87T pick-upcurrent is based on a high side tap setting of 2and a relay pickup of 35% of tap. Other 13.8 kVground sources, where available, will increasethe level of relay current for an internal fault.However, the protection must cover the casewith no added current contribution.

In Fig. 21 the transformation of the 40A low-sidecurrent to the high-side requires multiplication bythe transformer turns ratio, rather than by theline-line voltage ratio. The per unit current on thedelta side is 57.7% of the per unit current on thewye side for a line-ground fault on the wye side.

FIGURE 22.

FIGURE 23.

13

5. Turn-to-Turn Faults

Phase differential relays may not detect a turn-to-turn fault and ground differential relays do notrespond to such faults. A neutral overcurrentrelay will see fault current if an external groundsource exists. However, for an impedancegrounded system most of the fault currentprobably will be contributed by the delta-sidesource. A single turn fault may produce a totalless than rated current (Reference 6). Accord-ingly, a sudden pressure relay (SPR) should beapplied to complement the differential protection.The SPR will detect any abnormality that gener-ates a sudden increase in pressure due to gasgeneration (e.g. arcing due to a loose connec-tion).

6. Sudden-Pressure Relays (63)

Fig. 24(a) shows a SPR that detects an increasein gas pressure, applied on gas-cushionedtransformers of about 5 MVA and up. The gaspressure is generated by an arc under the oil,producing decomposition of the oil into gasproducts. The change in pressure actuates

bellows 5 closing microswitch contact 7. Equal-izer port 8, much smaller than the main port 4,prevents bellows movement for slow changes ingas pressure due to ambient temperaturechanges and load cycling.

Fig. 24(b) shows use of the break contact of themicroswitch (63) in conjunction with auxiliaryrelay 63X. This circuit prevents tripping for aflashover of the make contact of 63.

A design similar to that of Fig. 24(a) is mountedwithin the oil either in gas-cushioned or inconservator-type transformers.

The SPR will respond only to arcs within the oil.While more sensitive than a differential relay, theSPR is not as fast as the electrical relay, so bothrelays should be applied.

Because these relays have experienced asubstantial number of undesired operations,many users connect them only to alarm. Theirreliabililty has improved by installing them onstiffer sections of the tank and by blockingtripping for high current faults. During high-current external faults, winding movementgenerates an oil pressure wave which has atendency to cause relay operation. In fact, therehave been cases where a relay operation hasbeen a precursor to transformer failure due toexcessive winding movement.

Conservator-type power transformers do nothave a gas cushion within the main tank. In-stead, the cushion resides in a separate auxil-iary tank. A gas accumulator relay (“Bucholz”)can be installed in the pipe connecting the mainand auxiliary tank to detect the generation ofgas. This relay has two elements, an accumula-tor alarm and a trip function. The accumulator,which stores a portion of the gas, provides analarm for slowly developing conditions. A bafflein the pipe actuates the trip element for relativelyfast gas flow to the auxiliary tank.

7. Monitoring for Incipient Problems

A number of on-line devices have been devel-oped in recent years to detect incipient condi-tions which threaten serious consequences.

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FIGURE 24.

These include: gas-in-oil analysis, acousticpartial-discharge detection, moisture sensor,tap-changer-operation supervision and pump/fansupervision (Reference 8).

8. Overcurrent Relays

Fig. 1 shows a number of overcurrent relays:50/51, 51, 51N-1, 51N-2, 51N-3, 67 and 67N.With the possible exception of the 51 and 51N-3relays, the overcurrent relays serve as back-upfunctions.

8.1 50/51 Relay

The 50/51 phase relay time element in Fig. 1(Page 2) must be set to carry the maximumexpected load current. Since a transformer iscapable of carrying considerable overload for ashort period, a high pickup is normally called for(e.g. twice the forced-cooled rating). The timeunit should coordinate with the 51 partial-differential relay; otherwise, both transformerswould be tripped for a fault downstream from the51 relay. In the absence of a low-side trans-former or bus-tie overcurrent relay the high-siderelay should be coordinated with the feeder orline protection. The use of partial-differentialrelays introduces an added coordination step.An alternative is to utilize bus-differential protec-tion, although a failure of this type of protectionwill result in the loss of all feeders to the station.This is a low-probability scenario, particularlywith metalclad switchgear.

The 50/51 operating time needs to be faster thanthe through-fault (external fault) withstandcapability of the transformer (Reference 1,Appendix). Limits have been established for 4MVA ranges, based on thermal and mechanicalstresses. Fig. 25 illustrates both “frequent” and“infrequent” limits and recognizes the cumulativeeffect of these stresses. Feeder or line relaytimes should fall under the frequent curves,while the 50/51 times should fall under theinfrequent curve. This is based upon the relativeprobability of these two classes of faults.

The 50/51 instantaneous element should be setfor about 160% of the current for a low-side 3phase fault. This setting not only preventsincorrect operation for a low-side bus fault, but

also should prevent operation during transformerenergization. This element provides importantfast backup of 87T for high-side faults.

Because of its high pickup and slow operation,the time element provides poor protection fortransformer winding and tap changer faults.Accordingly, this relay (and the groundovercurrent protection) is not a substitute fordifferential and gas relays except for transform-ers smaller than about 3 MVA. The conse-quences of a slow cleared fault include thethreat of an oil fire due to a ruptured tank orbushing explosion and the necessity of having toremove the transformer for repair. Removal isgenerally necessary for even a fast clearedwinding fault. This is not the case for a tap-changer flashover that is cleared before windingdamage.

8.2 51 Relay

The partial differential relay 51 in Fig. 1 mea-sures the sum of the transformer and bus-tiebreaker currents. Such a connection is appropri-ate with a normally-closed bus-tie breaker, toavoid unwanted transformer breaker tripping foran adjacent bus fault. This relay serves asprimary bus protection or backs up the busdifferential protection. It also backs up for line orfeeder faults. This relay must be set to coordi-nate with the feeder or line protection. It trips thetransformer and bus-tie breakers.

If the transformer and bus-tie breakers areinterlocked to prevent both from being closed, asingle set of overcurrent relays on the bus-tiebreaker will suffice, rather than a set of partialdifferential relays on both busses.

8.3 51N-1 Relay

The 51N-1 relay in Fig. 1 provides sensitiveback-up of 63 and 87T for high-side groundfaults, but no response to turn-turn faults. Thehigh-side ground overcurrent unit in the Fig. 1application has no coordination requirementbecause the delta winding blocks ground currentflow for a low-side fault. However, it must bedelayed to ride through false residual currentthat can be developed during low-side phasefaults (see Fig. 22).

15

8.4 51N-2 Relay

The neutral overcurrent relay in Fig. 1 primarilybacks up the 51N-3 partial differential protectionfor bus faults and it backs up 87N as well. In theabsence of the 87N application, 51N-1 providesthe primary ground fault protection for thetransformer low-side zone. It also backs up 87T,depending upon the sensitivity of the 87T. The51N-2 relay must coordinate with 51N-3 to allowthe latter to clear a bus fault without tripping bothtransformers.

If the 13.8kV bus tie can be closed with bothtransformers in service, as shown in Fig. 1, the51N-2 relays on both transformers will operatefor a 13.8kV winding or lead fault, unless a 67Nor 87N relay is provided for faster clearing.

8.5 51N-3 Relay

Section 8.2 also applies to the 51N-3 relayexcept that this relay provides the ground faultcoverage.

8.6 67 Relay

The 67 relay operates for power flow from thetransformer low side toward the high side. Suchflow could occur with the 115 kV tie breakeropen, either for a 115 kV fault or under loadconditions. Reversed flow can also occur withthe 115 kV tie breaker closed, with local genera-tion. This relay will respond to high-side groundfaults, because of the phase current flow (posi-tive- and negative-sequence). This is valid onlyas long as a remote high-side ground sourceremains connected. 50/51 is the only other relayin Fig. 1 responsive to a high-side ground faultbeyond the transformer high-side bushings.Because normal load flow is toward the low side,67 can be set more sensitively than 50/51 andmay also be faster. Relays associated with the115kV breaker "A" will trip the high side circuitswitcher. However, if the circuit switcher fails toopen, the 67 relay tripping the circuit switchesand the 13.8kV breaker "B" functions as backupto de-energize the circuit.

8.7 67N Relay

The 67N relay serves as fast back-up protectionfor the 87N relay. Unless 87N is not applied,

67N provides just marginal value, since 51N-2backs up 87N. Because ground fault current islimited, the need for fast backup is less impel-ling. Relays 67N and 51N-2 offer an alternativeto 87N. However, the advantage of the 87Napplication is that it provides fast response withthe low-side breaker open or with no externalground source.

9.0 49 Thermal Protection

Conventional thermal relays measure the oiltemperature and transformer current to estimatethe hot-spot temperature. They provide anindication and means for controlling pumps andfans. Typically these devices provide twotemperature sensing levels for control, and athird, higher temperature sensing for alarm ortripping.

Recently developed fiber-optic sensors, incorpo-rated in the transformer winding, provide a directmethod of measuring the hot-spot temperature.About four of these sensors would provide goodcoverage.

References

1. ANSI/IEEE C37.91-1985, IEEE Guide forProtective Relay Applications to PowerTransformers

2. Lewis Blackburn, “Protective Relaying:Principles and Applications”, Marcel Dekker,Inc. 1987

3. S. Horowitz and A. Phadke, “Power SystemRelaying”, John Wiley & Sons, Inc., 1992

4. W. K. Sonnemann, C.L. Wagner and G.D.Rockefeller, “Magnetizing Inrush Phenom-ena in Transformer Banks”, AIEE Transac-tions, Vol. 77, pt. III, pp 884-892, Oct. 1958

5. IEEE Committee Report, “Transient Re-sponse of Current Transformers”, IEEESpecial Publication, 76CH1130-4PWR

6. Klingshorn, H.R. Moore, E.C. Wentz,“Detection of Faults in Power Transfor-mers”, AIEE Transactions, Vol. 76, pt. III,Apr. 1957, pp 87-98

7. ANSI/IEEE C37.95-1989 “IEEE Guide forProtective Relaying of Utility-ConsumerInterconnections”

8. “On-Line Transformer Monitoring,” ElectricalWorld, Oct. 1995, pp. 19-26.

FIGURE 25.

17

Table I Relays and Typical Settings for 60 Hz Models

ANSINo.

Qty. Basler Model/Function Description Basler Style No. Typical Settings &

RemarksFigureNo.

24 1 BE1-24Overexcitation

1-3.99 V/Hz ACXF1XX0SXX Inverse:2.05 V/Hz(107%), TD=2, Reset:2s/% FS; Alarm: 2.26V/Hz(118%)

--

49 1 Thermal 1

50/5 3 BE1-50/51B1 phaseovercurrent

0.5-15.9A., 1 ph.1-99A inst.

50/51B-1XX P.U.: 9A; TD:2 (VI);Instantaneous reset;60A instantaneous

1

51 3 BE1-50/51Bpartialdifferential

0.5-15.9A, 1 ph. 50/51B-1XX P.U.: 9A; TD: 1 (VI);Instantaneous reset;Disconnect instantaneous

1

51N-1 1 BE1-50/51Bgroundovercurrent

0.1-3.18A, 1 ph. 50/51B-1XX P.U.: 0.25A; TD: 4 (VI);Instantaneous reset;Disconnect instantaneous

1

51N-2 1 BE1-50/51BNeutralovercurrent

0.1-3.18A, 1 ph. 50/51B-1XX P.U.: 0.5A; TD: 5 (VI);Instantaneous reset;Disconnect instantaneous

1

51N-3 1 BE1-50/51BGround partialdifferential

0.1-3.18A, 1 ph. 50/51B-1XX P.U.: 0.1A; TD: 2 (VI)Instantaneous reset;Disconnect instantaneous

1

63 Sudden pressure orBucholz Gas Accum.

1,23

67 1 BE1-67 PhaseDirectionalovercurrent

0.5-12A; inst.1-40 times; 3 ph.

B1XZ2XX3C6X TOC: 1A, 02 TD, B6 (VI)Inst.: 15A

1

67N 1 BE1-67NDirectionalovercurrent

0.25-6A; directionalinstant, 2-100A

A1XZ2XX3CXX Inst.: Not connected TOC:0.25A, 01 TD, B3 (Def.)

1

86-1/86-2

2 Lockout Aux. 1

87N-1 1 BE1-50/51M 0.1-3.18A TOC0.2-19.8A inst.

BE1-50/51M-2 Inst.: not connectedTOC: 0.5A, 2 TD, D (Def.)

20

87N-2 1 BE-67NGrounddifferential

0.25-6A TOC;2-100A dir. inst.

A1XZ2XX3CXX Inst: 2A, polar. p.u.: 2A;TOC: 0.25A, 07 TD,B1(Short)

1,22

87T 3 BE-87TTransformerdifferential

2-8.9A, 3 phase E1EA1XX1XXX See Setting section of IM 1,17,2

FIGURE I-2.

Appendix I:Time to Ct SaturationFor the application in Fig. 1, assume a high-side,wye-connected, multiratio 600/5 CT on the 300/5tap and an ANSI accuracy class of C200. Theunrestrained element pickup is 22A on thesecondary of the 300/5 CTs. The maximum timeconstant of the fault current is 0.02s. Two waylead burden (for ground fault) and CT windingresistance is 0.4 ohms. Assume an internal faultproducing 33A, which is 150% of pickup.

Ks = (ct knee pt. voltage)/(burden voltage) =(0.6*Effective Accuracy Class)/(22*1.5*0.4) =(0.6*200*300/600)/13.2 = 60/13.2 = 4.5

[The effective accuracy class voltage is100V, since only half the total CT turnsare in use. The knee point is at about0.6 times the effective accuracy class.Checking at 1.5 times the unrestrainedunit pickup.]

From Fig. I-1 (Reference 5), the time to satura-tion is 13ms (3/4 cycle). This applies for a fullyoffset current of 33A rms symmetrical andassumes the CT saturates at the knee point, asomewhat conservative assumption.

This result indicates marginally acceptable CTperformance. Fig. I-2 shows CT waveformsimilar to that expected for the above example,although the dc time constant is much longer inFig. I-2 than the assumed 0.02s. Note that theCT delivers considerable energy even afteronset of severe saturation, including the nega-tive excursions. At higher levels of current theCT will saturate sooner; however, the negativeexcursions, during which interval the CT recov-ers from saturation, produce increased energy.Fast response depends upon the relay’s reac-tion to this distorted waveform.

Use of a higher CT ratio will improve ct perfor-mance, but the reduced current levels will resultin desensitizing the unrestrained element unlessthe relay taps are lowered in proportion to thedrop in secondary current level.

FIGURE I-1.

19

Appendix II:Harmonics During CtSaturationCTs experience both “ac” and “dc” saturation.Ac saturation results under symmetrical currentconditions. Dc saturation occurs when thecurrent contains a “dc” component, during afault, magnetizing inrush, motor starting orgenerator synchronizing. CTs that producenegligible distortion under symmetrical condi-tions can become severely distorted when a dccomponent exists (Reference 5). While faultsgenerally produce the most current, otherconditions such as a motor starting producemuch slower dc decay than occurs for a fault. Asmaller dc current that persists longer can alsoproduce dc saturation. For these externaldisturbances, unequal times to saturation invarious CTs results in false operating current.Either the harmonic-restraint or the percentagedifferential restraint (fundamental frequencycharacteristic) prevents unwanted tripping forthis condition.

Under symmetrical current conditions, CTdistortion generates odd harmonics, but no evenharmonics. A CT experiencing dc saturationduring an assymetrical fault develops both evenand odd harmonics. Relays that restrain on oddharmonics may fail to operate if the harmoniccontent exceeds the relays’ threshold for re-straint. Relays that restrain on just even harmon-ics may be temporarily restrained until the CTsrecover from the effects of the dc transient.High-set unrestrained elements (instantaneous)supplement the restrained elements, so that highcurrent faults, where CT saturtion can besevere, can be cleared independent of anyharmonic restraint. These elements must be setabove the maximum inrush level and above themaximum false operating current produced bydissimilar ct performance during external faults.For satisfactory protection, harmonic generationby the cts should not exceed the restraint levelfor a current below the unrestrained elementpickup. Poor CT quality can materially detractfrom the reliability of the differential relay. Agood objective is Ks=8 or higher for a current at

the unrestrained pickup level (see Appendix I).Ks is the ratio of the CT knee-point voltage tothe burden voltage. The higher the Ks value, thebetter the CT performance.

Revised 8/03

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