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Transformer Protection Application Guide

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Transformer ProtectionApplication Guide

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About the Author

George Rockefeller is President of Rockefeller Associates, Inc. He has a BS in EE from Lehigh University,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 ten yearsas a System Engineer. He has also served as a private consultant since 1982.

About the Guide

This guide contains a summary of information for the protection of various types of electrical equipment.Neither Basler Electric Company nor anyone acting on its behalf makes any warranty or representation,express or implied, as to the accuracy or completeness of the information contained herein, nor assumesany responsibility or liability for the use or consequences of use of any of this information.

Original issue date 05/96Revised 05/99, John Boyle; small updatesRevised 08/03, Larry Lawhead; small updatesRevised 04/07, John Horak; extensive rewriteRevised 06/07, John Horak; minor typographical and editorial corrections

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Transformer ProtectionApplication Guide

This guide focuses primarily on application ofprotective relays for the protection of powertransformers, with an emphasis on the mostprevalent protection schemes and transformers.Principles are emphasized. Setting proceduresare only discussed in a general nature in thematerial to follow. Refer to specific instructionmanuals for your relay. The references provide asource for additional theory and applicationguidance.

The engineer must balance the expense ofapplying a particular protection scheme againstthe consequences of relying on other protectionor sacrificing the transformer. Allowing a pro-tracted fault would increase the damage to thetransformer and the possibility of tank rupturewith a consequent oil fire and consequentpersonnel safety risks. There is no rule that sayswhat specific protection scheme is appropriatefor a given transformer application. There issome tendency to tie protection schemes to theMVA and primary kV of a transformer. Whilethere is some validity to this approach, there aremany other issues to be considered. Issues tobe considered include:

•The severity of personnel safety concernsand the possibility that a given protectionscheme can reduce these risks.

•The danger to nearby structures and pro-cesses if a transformer fails catastrophicallyand the possibility that a given protectionscheme can reduce the possibility of such afailure.

•An overall view of the economic impact of atransformer failure and what can be done toreduce the risk, including:· The direct economic impact of repairing

or replacing the transformer.· The indirect economic impact due to

production loss.· Repair time vs. complete replacement

time.· The availability of backup power feed or

emergency replacement transformers, andthe cost of each option.

· The possibility that a given protectionscheme can reduce the damage andresultant repair time, or that it can changea replacement into a repair.

Some specific applications that affect protectionare: A tap changer flashover can ordinarily berepaired in the field, but if this fault is allowed toevolve into a winding fault, the transformer willneed to be shipped to a repair facility; hence,protection that can rapidly sense a tap changefault is desirable. A high magnitude through fault(external fault fed by the transformer) shakes andheats a transformer winding, and the longer thethrough fault lasts, the greater the risk of itevolving into an internal transformer fault; hence,fast clearing for close-in external faults is part ofthe transformer protection scheme. Sometransformers are considered disposable andreadily replaced, reducing the need for ad-vanced protection schemes. Transformer protec-tion commonly includes some coverage of

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external bus and cable, and faults in these zonesmay expose personnel to arc flash hazards. Slowclearing protection schemes may be unaccept-able from an arc flash exposure perspective.Fires in an indoor transformer may have high riskof catastrophic facility damage and even higherpersonnel safety risks, increasing the need foradvanced high speed protection. The proximityof flammable process chemicals increases aneed for protection schemes that reduce the riskof a tank fire. The failure of a transformer used ina large base load unit-connected generator maycause extended generation-replacement costs;even the loss of a small station service trans-former can cause a notable disruption of genera-tion and high economic consequences. Similareconomic impacts may also exist at industrialsites. Some transformers are custom designsthat may have long lead times, increasing theneed for advanced protection schemes.

1. Failure Statistics

Table I lists failures for six categories of faults(IEEE C37.90, “Guide for Protective RelayApplications to Power Transformers, Ref. 1).Winding and tap changers account for 70% offailures. Loose connections are included as theinitiating event, as well as insulation failures. Themiscellaneous category includes CT failure,external faults, overloads, and damage inshipment. An undisclosed number of failuresstarts as incipient insulation breakdown prob-lems. These failures can be detected by sophis-ticated online monitoring devices (e.g. gas-in-oilanalyzer) before a serious event occurs.

Table I - Failure Rates, Ref. 1.

1955-1965 1975-1982 1983-1988

Percent of Percent of Percent of Number Total Number Total Number Total

Winding failures 134 51 615 55 144 37Tap changer failures 49 19 231 21 85 22Bushing failures 41 15 114 10 42 11Terminal board failures 19 7 71 6 13 3Core failures 7 3 24 2 4 1Miscellaneous failures 12 5 72 6 101 26

TOTAL 262 100 1127 100 389 100

2. Protection Example and General Concepts

The reader interested in additional information,advanced or unusual application advice, anddetailed settings guidance should refer to Ref. 1.This document includes extensive references andbibliographies. Also, Ref. 2 and 3, textbooks onprotective relaying, contain chapters on trans-former protection, and Ref. 4, another IEEEstandard, includes good overall protectionschemes where a transformer is the interfacepoint between a utility and an industrial customer.

There are three general categories of protectiverelay technology that arise in the discussions tofollow:

•Electromechanical: uses magnetic fluxcreated from current and voltage to createtorques on movable disks and relays, whichis the source of the term “relay.” Usuallysingle device number functionality.

•Solid State: uses low voltage analog signalscreated from sensed currents and voltages;uses discrete electronics and basic logiccircuits; may contain a basic microprocessorfor logic and some math. Usually single ordual device number functionality.

•Numeric: a multifunction, programmablelogic relay; digitizes sensed current andvoltage, then calculates an RMS or phasorequivalent value; uses a high-end micropro-cessor. Usually incorporates many devicenumber functions.

All Basler Electric relays are solid state ornumeric.

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Table II lists some common ANSI device num-bers associated with transformer protection. Anumeric relay generally contains many imple-mentations of these devices within its program-ming, and each instance of a device is referredto, herein, as an “element” in the relay. Forexample, while the Basler BE1-CDS220 isprimarily a transformer differential relay (hence,includes the 87 device in elements named 87Pand 87N), it also includes nine independentimplementations of the 51 overcurrent device,called the 51P, 151P, 251P, 51Q, 151Q, 251Q,51N, 151N, and 251N elements as well as manyother device functions.

Figure 1 shows extensive use of relays thatwould be representative of a large industrialload. This will be used for discussions in some ofthe material that follows. There are two 115 kVfeeds to two 30 MVA transformers that areresistance grounded on the 13 kV side, limitingground fault current to about 400A from eachtransformer. In other applications, a reactor isused, and in some applications, the ground faultcurrent is limited to less than 10A. In a typicalutility application, transformers are connecteddirectly to ground, but occasionally a smallreactor is placed in the transformer neutral thatlimits ground fault current to approximately thesame level as three phase faults. In this examplesystem, the protection scheme describedapplies to solidly grounded (as well as imped-ance grounded) systems, except the effect ofground impedance results in the addition ofprotection functions not required on a solidlygrounded system.

The phase and ground differential (87P and 87N,Section 4) and sudden pressure relay (63,Section 6) provide the primary transformer faultprotection. The suite of overcurrent elements(51, Section 8) is generally considered backuptransformer protection, or for protection of thebus and backup protection for the feeder relays.These elements are part of the transformerprotection in that they limit the accumulateddamage that occurs from a transformer feedinghigh current into downstream faults. The 67Nrelay offers an alternative to the 87N function.Hot spot monitoring (49, Section 9) is indicated,but is likely an alarm only scheme.

If there is a possibility of over voltage on theunits due to local generation or a transformerbeing placed at the end of a long line (the“Feranti” effect), voltage relays (24 and 59,Section 4.4.4) may be included. Another pos-sible backup protection scheme is low voltage(27) or unbalanced voltage detection (47). Ifthere is local generation, to help detectislanding conditions an over/under frequency(81, O/U) relay may be installed, though an 81may not be considered a transformer protectionelement.

Directional overcurrent relays and directionalpower (67/50, 67/51, and 32, respectively,Section 8.4) respond to load current circulatingthrough the 13 kV buses when the 115kVbreaker A is open and the 13.8kV tie is closed.The elements may also respond to faults in thetransformer near the secondary bushings. If thetransformers can be operated in parallel, theelements also provide a means to sense tapchangers that have become out of step with oneanother. If there is generation in the 13.8kVsystem, sensitive 67 elements can sense a smallgenerator backfeeding a 115kV fault.

The primary and secondary relaying wouldsometimes be configured to feed their ownlockout relays (86) to help ensure that protectionis available even with a failure of one 86 relay orits dc feed.

The protection scheme in Fig.1 does not utilizefuses. Fuses normally would be seen only onlower MVA transformers than indicated. SeeSection 3.

Transformers of the indicated MVA normallywould have their oil tested for dissolved gasses(Section 7) as part of routine maintenance.Larger transformers may have continuous on-linemonitoring equipment.

Tables III and IV (pages 29-30) provide BaslerElectric relay models and their device numbers.

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Figure 1 - Protection Example

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Device Description Comment24 Volts/Hz For overexcitation detection. Similar to 59 but the pickup is proportionate to

frequency.Typically an inverse time characteristic.27ll Undervoltage ll = line to line27ln ln = line to neutral (or line to ground. Note neutral may be isolated from ground in

some systems.)32 Power Element Used to sense power backfeed through transformer47 Negative Usually defined by: V2 = (Van+a2Vbn+aVcn)/3. (a=1∠120).

sequence It is also possible to define V2 in terms of Vll. Some relays define the 47 in terms ofovervoltage a manufacturer-specific voltage unbalance measurement rather than in terms of V2.

49 Thermal Typically top oil temperature RTD.51P Phase Time A 51 by itself usually refers to phase time overcurrent, but adding the P gives

Overcurrent additional clarity.51G Ground Time Herein: Ground refers to current on a transformer ground/neutral bushing or

Overcurrent, measured current from a window CT that wraps all three phases (and possibly also wrapsby dedicated window a neutral bus if one exists).CT, or CT ontransformer neutral

51N Neutral Time Neutral refers to the phase current summation (In = Ia+Ib+Ic), which is theOvercurrent equation used for 3Io in numeric relays and which is also the summation of the= 3Io 3 phase CTs ("residual").= Phase CTResidual

51Q Negative Defined by: I2=(Ia+a2Ib+aIc)/3Sequence TimeOvercurrent

50P, Instantaneous In some relays, a 50 has the option of being time delayed; hence, it becomes50G, Overcurrent. a definite time element and may be renamed 50TP, 50TG, 50TN, or 50TQ.50N, P, G, N, Q have50Q same meaning as

for the 51.59ll Overvoltage ll, ln = line-line or line to neutral/ground. N refers to V0 or 3V0 sensing, depending59ln on the manufacturer. V0=(Van+Vbn+Vcn)/3.59N63 Sudden Pressure There may be separate devices for the tap changer and main tank.67/50x Directional control, x refers to P, G, N, or Q. The 67 by itself is used inconsistently in the industry.67/51x directional Herein, for clarity, a 67 is a sensitive forward/reverse polarizing bit that

instantaneous, controls the 50 and 51 element, and the dual term 67/50x or 67/51 is used.directional timeovercurrent

86 Lockout Auxiliary Most transformer trips are directed to a lockout relay.87P Phase Differential Comprised of several functional elements. See text for description. Many variations

by relay and manufacturer.87U Unrestrained Monitors phase differential. Trips when magnitude is much greater than maximum

Differential inrush levels.87N Ground Differential Sometimes referred to as a "Restricted Earth Fault" sensing element. It is more

commonly applied on systems with impedance in the transformer neutral for thepurpose of limiting ground fault current.

Table II - ANSI Device Numbers (C37.2)

3. Fuses

Fuses are economical, require little mainte-nance, and do not need an external powersource to clear a fault, which is of great cost andmaintenance benefit. As discussed above, MVAof a transformer is an imperfect guide to theappropriate level of transformer protection, but itmay be noted that fuses are probably thepredominant choice for transformers below 10MVA. Under 3MVA, breakers on the high side

are seen only in special applications (e.g., somesmall generation sites may use a high sidebreaker).

The use of fuses creates some notable protec-tion compromises. Fuses are not as precise inoperating characteristics. Characteristics changeslightly with temperature, pre-fault loading, andreclose timing. Fuses are subject to gradualdamage from heavy through faults, leading to an

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eventual fast trip for a low magnitude fault.Usually only one or two fuses blow, whichintroduces single-phasing conditions to down-stream loads. Single phasing causes very highnegative sequence voltage and current and lowVln or Vll voltages. The resultant voltage may beworse than no voltage due to the overheatingthat it can cause to certain types of equipment,such as three phase motors.

Fuses are insensitive and relatively slow exceptat very high current levels. Fuses will not senselow level faults, such as near the neutral of thetransformer, and hence trip only after the faulthas evolved into a high current event. To allowshort overloads, a transformer fuse is typicallyselected to carry 150-300% of the transformerrated current (see NEC article 450, Ref. 5). Mostfuses can carry over 125% of rated current forvery long times, and just begin to reliably trip forfaults in the range of 150-200% of the fuse rating,and at this level generally take tens of secondsto trip. The effect is that a fuse might carrycurrent in the range of 3 to 5 times transformerrated current for an extended period. At moder-ate currents, fuses are still relatively slow. Forinstance, a fuse must be able to carry inrushcurrent without damage. A classical measure ofinrush current is 12x full load current for 0.1second. Due to slow clearing for faults at lowmagnitude, when a fuse is used, the transformeris at higher risk for being irreparable after aninternal fault and at higher risk of failing in somecatastrophic manner, such as a fire.

In some protection schemes, the transformerhigh side overcurrent protection scheme isconsidered backup protection for faults down-stream of the secondary protection elements.The low sensitivity of fuses means they are poorat backing up secondary overcurrent protectiondevices, especially for faults remote from thetransformer secondary and especially for groundfaults on delta/wye transformer banks. SeeSection 10.3 for a discussion on the currentratios seen across delta wye transformer banks.

A fuse has some protection benefits. If faultcurrent is extremely high, a fuse can be fasterthan a breaker and can clear faults within 0.5-2cycles after inception. The fastest type, called a“current limiting fuse” (CLF), available at medium

and low voltages, can clear a fault in half a cycleand can reduce the first half cycle peak currentto a level notably below the available faultcurrent. The CLF fuse can be damaged by inrushcurrent if not properly selected. If a fuse isselected that has fast clearing at peak currents,it can clear a fault faster than any circuit breaker;hence, at high fault currents, a fuse downstreamof a circuit breaker tends to coordinate withthe upstream breaker better than two breakersin series. This application is seen most com-monly in an industrial low voltage applicationwhere two breakers in series sometimes arefound to both be operating in an instantaneoustrip zone. In a transmission application, when ahigh voltage fused transformer is placed as a tapon a transmission line, coordination is not easilyachieved. The transmission line impedancerelay, operating in its Zone 1 reach, frequentlywill be committed to a trip within 1-1.5 cyclesafter a fault begins; hence, the transmission linemay trip ahead of or simultaneously with a fuseon a transformer.

It is recommended that, on fused transformers,protection should employ a low-side circuitbreaker with phase and ground overcurrentrelays for backup protection of secondary faults.Ideally, the relay also should have negativesequence overcurrent (46), negative sequenceovervoltage (47), and line to groundundervoltage (27ln), for sensing unbalancedsystem operation in the event of a single ordouble fuse operation on the transformerprimary. Be aware that, in a radial power flowapplication, relays on the transformer secondaryrelay will not respond to a transformer fault,except possibly a 27 or 47 relay can senseresultant voltage degradation.

4. Differential Relaying (87)

Differential relays sense the unbalance in the flowof currents in various apparatus or buses. In theabsence of a fault in the protected zone, thisunbalance tends to be small and the flows intothe zone are closely matched to the flowsleaving. Accordingly, such relays can be moresensitive than phase overcurrent relays and neednot be delayed to coordinate with other relaysduring external faults, except for some issuesassociated with transient CT saturation, to bediscussed below.

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Figure 2 - Basic Differential Concept

The simplest implementation of differentialprotection, as seen in Fig. 2, merely parallels theCTs on all the connections to the zone, and therelay monitors the current summation. Thisconcept is applied on basic bus protectionschemes. The 87 device for this applicationfeasibly can be simply a 51 device, though a 51normally would be configured to be neitherextremely sensitive nor fast due to issues with CTtransient performance under the presence of DCoffset in the primary current.

The basic differential concept above will notwork with transformers. When the protectedzone in Fig. 2 is a transformer, there are severaladditional components, seen in Fig. 3, that arerequired, or at least commonly implemented, forproper performance:

•Current Matching Scheme•Through Current Restraint and Minimum

Operate Logic•Delta/Wye Compensation Logic (may be

implemented in CT connections rather thanin the relay)

•Magnetizing Inrush Blocking Scheme,commonly using harmonics

•Unrestrained Differential Scheme (not insome basic or early electromechanicalrelays, but found in all Basler relays)

Figure 3 - Transformer Differential Concept

4.1 Current Matching Scheme

The relay’s current matching scheme allowsdifferent currents on each input to the relay to beseen as effectively the same current. In electro-mechanical relays, the scheme uses tappedtransformers (hence, the source of the term“tap”), where each tap adjusts the number ofturns used on the input transformer, so that, forinstance, 4.6A on input 1 (at a tap of 4.6) givesjust as much magnetic flux as 3.5A on input 2 (ata tap of 3.5). In solid state relays, the tap,typically (as in the BE1-87T) is composed ofswitches that change the resistance on thesecondary of the sensing CT circuit. For in-stance, a two input solid state relay set at taps4.6 and 3.5 might be designed so that 4.6A and3.5A on each respective input will both cause a100MV internal voltage signal. Hence, 4.6A =3.5A as far as the remainder of the relay circuitryis concerned. On numeric relays (i.e., micropro-cessor based relays that convert incomingcurrents to digital signals), the current matchingscheme uses mathematics and varying multipli-cation factors.

A typical concept for setting the taps for a twowinding transformer is to analyze the currentseen at the relay for the peak power rating of thetransformer. For instance, in Fig. 1, assume theCT ratios as shown (discussed further in Section10.2) and, the Full Load Amps(FLA) in the linesat 30MVA is 151A at 115kV, and 1255A at13.8kV, and the CT secondary current is 1.883Aand 3.138A, respectively. Depending on therelay design, the delta compensation mayrequire that the current on the Wye side bemultiplied by sqrt(3) (e.g. the CDS-2x0 relays donot require the sqrt(3) factor, but the BE1-87T

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does). For this example, let us assume a BE1-CDS220 is in use, so we do not need the factor.The ratio of the taps is the critical factor, not thespecific taps. The minimum tap of the BE1-CDS220 is 2, so we use taps of 2.00 and 3.33.The ratio of currents (3.138/1.883) is 1.667, andthe ratio of taps (3.33/2.00) is 1.665, so the errorthat the relay sees due to tap ratio not matchingthe current ratio will be quite small. In electrome-chanical relays, the tap selection is much morelimited, and resultant error seen by the relaytends to be substantially more significant.

Current matching in three winding transformerapplications must, in effect, be analyzed twowindings at a time. One assumes identical powerin windings 1 and 2 (and 0 in winding 3), whichsets taps 1 and 2, and then one assumesidentical power in windings 1 and 3 (and 0 inwinding 2), which sets tap 3. This will forcewinding 2 and 3 taps to work correctly for thecase of power flowing from winding 2 to winding3. In this approach, the constant power that isassumed can appear to be more than winding 2or 3 can handle, but since this power level doesnot flow in actual application, the high currentflow seen in the calculations does not affect thevalidity of the setting.

Figure 4 shows the conceptual implementationof current matching in the BE1-87T for a singlephase transformer. Relays of other designs willuse parallel concepts appropriate for theirdesign. When installed per the relay instructionmanual, the current will flow in opposite polarityon input 1 and input 2. The taps will be set sothat the magnitude of the voltage presented tothe op-amps is the same RMS value. Thevoltage at point C, the summation point, will beat the midpoint between A and B, and in normaloperation, since A and B are opposite in polaritybut equal in magnitude, the voltage at C will be0 throughout the current sine wave, indicating noerror current. If current at input 1 increases,voltage at A increases, but not B, and now pointC sees a voltage above 0. Depending on therelay settings, the relay may trip.

Current matching settings normally are calcu-lated under the assumption that the load tapchanger is at the nominal / neutral position. Therelay percentage restraint and minimum operate

settings then are configured to accommodatethe unbalance current that the relay will seewhen the load tap changer is at the full boost orbuck position, and commonly with someadditional accommodation for the no-load tapbeing changed from nominal.

The BE1-87T has a current matching ("tap")range of 2 to 8.9A. The BE1-CDS relays havematching ranges from 2 to 20A. The wider rangeof the numeric relay can be helpful in installa-tions where small transformers are placed onbuses with high short circuit duty (the high shortcircuit duty forces one to use higher CT ratiosthan would be chosen just on load current levelcriteria).

4.2 Percentage Restraint and MinimumOperate

Typically, there is some small difference in thesummation of the sensed currents so that, evenafter appropriate tap settings, currents sensedby the relay do not sum to an effective 0A. Theerror (or difference) current becomes the operatecurrent which, if it rises too high, will cause relayoperation. The operate current arises due todissimilar CT performance during a through faultor large load inrush (especially during transientCT saturation due to DC offset); differences inthe transformer no-load tap that is in use vs. theno-load tap assumed when the relay settingswere calculated; the operation of the transformer

Figure 4 - Current Matching in a Solid State Relay

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auto tap changer (if there is one); transformersteady state excitation requirements; and inrushexcitation current that has decreased below theharmonic excitation blocking levels but has notactually decayed to a negligible value. Severalof these types of errors create an operate currentthat rises proportionately with through current.Because the error rises with load current, a fixedlevel for the operate pickup generally is notacceptable.

To compensate for operate current rising duringhigh load currents or through faults, the 87 logicincludes a restraint function. As through currentincreases, the restraint function causes anincrease in the level of operate current requiredfor a trip. Each current input is monitored andbecomes part of the overall restraint of the relay.The concept is referred to in many documentsas a percentage restraint characteristic becausethe logic can be described by: "The operatecurrent must be ##% of the restraint currentbefore a differential trip is declared."

The concept as implemented in the BE1-87T isseen in Fig. 5, where operating (or "differential")current is plotted against the maximum (i.e.,largest) restraint current. The scaling is in"multiples of tap." The slope of the characteristiccan be set from 15 to 60%. The relay becomesdesensitized at the higher restraint currents inorder to remain secure in the presence of thevarious sources of error previously mentioned.

Figure 5 - BE1-87T Restraint vs. Operate(BE1-CDS-2x0 similar).

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Note in Fig. 5 the horizontal axis is in "maximumrestraint current." This allows the best-performingCT to be used for the restraint decision. TheBE1-CDS2x0 has the option to use averagerestraint rather than maximum restraint, thoughmaximum restraint is the preferred setting.

Relays from other manufacturers use otherrestraint algorithms. For instance, some relayson the market desensitize the relay at a greaterslope during very high through current, using a"dual slope" approach. The BE1-CDS2x0 relaysuse an alternative approach via an algorithm thatdesensitizes the relay during high currents, butonly when a CT saturation detection logicscheme is declared true.

Figure 5 also shows the minimum operatefeature. Independent of the through currentrestraint, there must be a certain magnitude ofoperate current before a trip is issued. Thisfeature helps prevent false tripping due toseveral issues, such as when inrush excitationcurrent has decreased below the harmonicexcitation blocking levels. The minimum operatecurrent is fixed in the BE1-87T and adjustable inthe BE1-CDS2x0.

The "total mismatch" line in Fig. 6 represents thesum of the imperfect relay-tap match (i.e., thediscrete increments available for the relay tapsmay not be the ideal setting) plus the effect ofthe power transformer no-load and load (i.e.,auto) taps not being at the setting used whencalculating settings. The mismatch line is offsetby the transformer exciting current, whichproduces its own unbalance. Fig. 6 shows theBE1-87T slope characteristics at the twoextemes of slope setting (15 and 60%), as wellas the related safety margins at the critical pointwhere the slope characteristic meets the mini-mum operate current. The two lines intersect atapproximately full load current on the restraintaxis, but the meeting point reduces with in-creased slope setting and increases with mini-mum operate current. A side issue to be awareof is that, if high prefault load is flowing throughthe transformer, some of the load currentcontinues to flow during the fault and acts toincrease the restraint level.

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Figure 6 - Percentage Restraint Margin

4.3 Delta/Wye Compensation

A delta wye bank introduces a phase shift inbalanced voltages and currents of typically±30°, depending on system rotation andtransformer connections. In electromechanicalrelays, the common approach to the delta wyewinding compensation is to connect the CTs inwye-delta, as seen in Fig. 7. Note the CT on thedelta transformer winding is connected in wye,and the CT on the wye transformer winding isconnected in delta. The same concept could beused with solid state and numeric relays, butnormally such relays have internal delta wyecompensation logic. The preferred approach isto connect CTs in wye and allow the relay toperform the delta wye compensation. The BE1-87T relay performs the delta wye compensationelectronically via analog circuitry, and the BE1-CDS2x0 performs the compensation via math-ematical processes, thereby removing the needto connect any CTs in delta.

Figure 7 - Delta Wye Compensation with CTConnections

There are several benefits to connecting the CTsin wye. With wye CTs, metering and eventreports give actual line currents, rather than thesummation of two phases as seen in delta CTs.Power metering is more accurate when CTs arein wye. Wye connections allow monitoringground current in the lines and the use of groundrelays. A wye connection also reduces leadburden for a phase fault. The worst case is for a3-phase fault with delta CTs. Per Fig. 8, the leadburden voltage as seen by delta CTs is magni-fied by a factor of three times relative to theburden that would be seen with wye CTs (notecurrent in the leads is higher by 1.732 factor,and that the CT is across two phase leads,hence seeing higher voltage compared to beingacross phase to neutral). See Appendix A of theBE1-87T instruction manual for a more in-depthanalysis of this issue.

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Figure 8 - Increased CT Burden from Delta CTConnection

It is essential that the delta compensation ineither the CT connection or internal to the relay'salgorithms be of a type that matches the trans-former connection. For example, if a "DAB" deltais used, the compensation needs to be DAB, notDAC. Incorrect selection of DAB vs. DAC com-pensation is a common source of trouble duringthe commissioning stage and, on lightly loadedtransformers, can be a source of misoperationsseen long after initial startup. The differencebetween a DAB and DAC delta is seen in Fig. 9.The figure is drawn to show delta connectionsbut also to represent the phasor diagrams ofsystem voltages with balanced ABC phaserotation (i.e., the secondary wye windings aredrawn in a direction that represents ABC positivesequence phase rotation phasors, and theprimary delta windings are then drawn in phasewith their corresponding wye windings). Note inthe two cases, the polarity of the A phaseelement is either a) connected to the non-polarity of phase B (referred to as a DAB con-nection) or b) connected to the non-polarity ofphase C (referred to as a DAC connection). Forbalanced voltages as seen in the figure, theresultant Van phasor on the wye side either a)lags the delta Van phasor (DAB connection), orb) leads the delta Van phasor (DAC connection).

Figure 9 - DAB vs. DAC Delta

These two methods to connect a delta have verylarge effects on which phases on the delta sidesee current during a wye side fault. For example,examine the wye side faults seen in Fig. 10. Notethat, for the DAB delta, the wye side A phase toground fault creates current in the lines A and Bon the delta side, but for a DAC delta, the wyeside A phase to ground fault creates currents inlines A and C on the delta side.

Figure 10 - DAB vs. DAC during a Wye Side Fault

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The difference between DAB and DAC deltas is,to some extent, the result of how one assignsphase names to the lines connected to thetransformer. In Fig. 10, the difference betweenthe DAB and DAC transformers is simply createdby swapping the B and C phases on the wyeside, which also changed phase naming on thedelta side. Hence, though no internal wiring waschanged on the transformer, how one named thephase leads and windings was changed, andthis renaming causes long-ranging conse-quences on transformer phase shift and exten-sive confusion for the relay and substationengineer. Delta/wye compensation as seen inFig. 9 is the most common type of transformerphase shift found in the industry, but there aremany other three phase transformer windingconfigurations. Section 4.7 discusses the matterfurther.

An example using CTs for compensation is seenin Fig. 11. Note that the delta is connected DACand that the CTs on the wye side are alsoconnected DAC.

Figure 11 - DAC Compensation Using CTConnections

Figure 11 adds a valuable insight into how asolid state or numeric differential relay compen-sates for transformer delta/wye connections. It isa common misunderstanding that delta/wye

compensation involves a phase shifting algo-rithm in the relay that simply reverses the 30°phase shift seen in balanced currents. Anothermisconception occasionally seen is that therelay compensation involves removing zerosequence current from the wye side currents.Neither is true.

The numeric and solid state relay is actuallydoing, in math or electronics, the same thingbeing done with CT connections in Fig. 11. Notethe differential element does not see the actualcurrent in any one winding of the transformer,but all three differential comparators monitorcurrent in two phases of the transformer at atime. Let us name Ia1, Ib1, and Ic1 as thecurrents in the transformer delta (not the leads tothe transformer), and Ia2, Ib2, and Ic2 are thecurrents in the wye windings. Note the relay's A,B, and C comparators monitor these sets ofcurrents:

• A comparator: Ia1-Ic1 to Ia2-Ic2• B comparator: Ib1-Ia1 to Ib2-Ia2• C comparator: Ic1-Ib1 to Ic2-Ib2

The numeric and solid state relay performs thesame compensation by adding and subtractingcurrents in a process that mimics the effect ofthe delta CT connections seen in Fig. 11. Notethere is no deliberate phase shift or zero se-quence removal algorithm, though, in effect, thishappens. For a more complete description ofcompensation in numeric relays, see Ref. 6.

4.4 Inrush Detection and Trip Blocking

Transformer inrush refers to the transient excitingcurrent resulting from a sudden change in theexciting voltage. This occurs at the instant ofenergization, after the clearing of an externalfault (recovery inrush), or during the inrushperiod of another nearby transformer (sympa-thetic inrush) (Ref. 7).

Inrush current appears as operate current to adifferential relay so the relay must either a) havesufficient time delay and insensitivity to thedistorted wave so as to not see the event (ofcourse, this is the undesirable answer) or b) takeadvantage of the inrush's distinctive waveform tosense the event and block tripping. The mostcommon means to sense inrush is via the use ofharmonic content in the operate quantity. The

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second harmonic predominates in inrush cur-rents (Ref. 7) and is used in most transformerdifferential relays, either alone or in combinationwith other nonfundamental components, thoughthere are other waveshape monitoring schemesin a couple relays in the market. The harmonicsensing relays most commonly block operationif the harmonic(s) in the operate leg exceed(s) agiven percentage of the fundamental compo-nent, though some relays on the market use theharmonic to increase the restraint current. Somerelays (e.g. Basler products) use a scheme thatuses total harmonic current in all three phases inthe analysis of every phase, and some use across blocking scheme, where if one phase isblocked, all phases are blocked. In the BE1-87T,the percentage settings are fixed, but in the BE1-CDS2x0, the harmonic restraint level is a usersetting.

4.4.1 Energizing Inrush

Energization inrush is caused by remanence(residual flux) in the core and the point in thevoltage waveform when a transformer breakercloses. If the instantaneous voltage atenergization calls for flux of the same polarity asthe remanence, the core is driven into saturation,creating peak exciting currents that can exceedten times rated exciting current. As a compari-son, normal steady-state excitation current isabout 0.01 to 0.03 times rated.

In Fig. 12 the steady-state flux at the instant ofenergization matches the residual flux, so notransient current flows.

Figure 12 - Energization without Inrush

In contrast, in Fig. 13, the steady-state flux atenergization is at its negative peak. Combinedwith a positive remanence, this conditionproduces the maximum level of transient current.

The inrush current is actually much larger inrelation to steady-state current than indicated byFig. 13, in order to keep the figure to a reason-able size.

Figure 13 - Energization with Inrush

Figure 14 shows a typical inrush waveform. Notethe dead/flat spot where almost no current isflowing as the core exits and then re-enters thesaturated region. The alternating flat to highpeak current contains the second harmonic thata relay uses to recognize the existence of aninrush condition.

Figure 14 - Energization Waveform

Note in the first two to three cycles of Fig. 14'swaveform, there is an effective DC component ofthe waveform. This DC is causing a flux buildupin the CT steel and a partial saturation of thecore. After about 3 cycles, the flat/dead spotrises above the 0 current axis, and the compo-nent of current above the 0 current axis isroughly equal to current below the axis, indicat-ing the CT is no longer producing any DC offset(even though DC may exist on the primary), butit is still reproducing at least some of the AC

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components, though in a possibly distortedfashion. In extreme cases, the CT can saturateduring the first cycle, so the flat spot in thecurrent waveform never remains at the 0 currentlevel for any duration. The decay rate of succes-sive primary-current peaks depends upon theamount of resistance in the source and thenonlinear inductance of the transformer.

In three phase transformer differential relays, thedifferential relay has the ability to monitorharmonic levels in all three phase differentialcomparators at the same time; hence, it makesa decision that an inrush condition exists on athree phase basis, rather than on a per phasebasis. This feature is found in the Basler BE1-87Tand BE1-CDS2x0.

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 and unbalancedlevel that exists during the fault. This voltagetransient causes a flux transient, with accompa-nying abnormally high exciting current. Thecurrent level is less than that seen during trans-former energization.

4.4.3 Sympathetic Inrush

The current Ip in Fig. 15 shows sympatheticinrush current 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 impedance Rsand Xs, producing pulses of inrush current Ip onthe alternate half cycles. Note the delayedbuildup of Ip. The severity of the sympatheticinrush is a function of the level of DC voltagedrop across the source impedance. A commonset of differential relays should not be used toprotect both T1 and T2 transformers in Fig. 15 ifthey can be switched separately. The sum of thetwo transformer currents, Is, may not containsufficient harmonics to restrain the relays oncetransformer T1 saturates severely.

Figure 15- Sympathetic Inrush

4.4.4 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: short line and a long line unloadedtransformer condition and long line with loadconnected. In addition, an interconnectedsystem can experience a dynamic overvoltagefollowing a protracted fault as a result of genera-tor fields going to their ceiling or following loadshedding. All of these scenarios involve essen-tially balanced conditions, so phase to phaseand phase to ground voltages increase. Sub-stantial phase to ground overvoltages can alsooccur on sound phases during a ground fault onimpedance grounded systems. In these cases,delta windings or wye-ungrounded windings willnot be overexcited, since the line to line volt-ages will not increase.

Figure 16 - Systems with Transformer OvervoltageRisk

The increase in transformer exciting current withincreased excitation voltage is illustrated in the

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dashed curve in Fig. 17. The transformer willtend to become overheated due to increasedexcitation current, hysteresis losses, and eddycurrents. The increased exciting current pro-duces operating current in the differential relay,but an operation of this relay is not desirable,since immediate response is not necessary. Thepower system should be allowed time to correctitself. Also, a differential operation indicates atransformer failure, requiring unnecessaryinvestigation and delayed restoration of thetransformer. Accordingly, where sustainedoverexcitation is a concern, a separate volts/Hzrelay should be applied (24). The volts/Hzfunction is available in the BE1-CDS240, BE1-1051,BE1-951 and BE1-IPS relays.

Figure 17 - Transformer Excitation Current vs.Excitation Voltage

The solid curves of Fig. 17 illustrate the variationin fundamental frequency excitation current (I1)as a percentage of total current (Im), and har-monic content (I3 to I7) as a percentage of thefundamental current (I1), as voltage rises, forbalanced system voltages. If the transformer isconnected in delta, the third harmonic wouldexist but remain within the delta windings as a"circulating current" that would not be seen byCTs on the lines to the transformer. When a deltawinding is energized, all triplen frequencycurrents (triplen = odd multiples of 3, such asthird, ninth) are blocked from exiting the deltabecause they are in phase with each other,similar to the manner in which a delta cannotsupply fundamental frequency zero sequencecurrent. Accordingly, the lowest odd harmonic

available to a relay monitoring the lines outsidethe delta is the fifth. The BE1-87T restrains if thefifth harmonic exceeds 35% of the fundamental,and the fifth harmonic restraint is a user setting inthe BE1-CDS2x0. In Fig. 17, a setting of 35% willrestrain the relay from operation over the voltagerange of about 104 to 138% of nominal voltage.With normal system operation, the powersystem could be operated continuously at 105%and dynamically as high as about 115% during asevere disturbance, so the 5th harmonic block-ing will prevent tripping for these high systemvoltages.

If there is load current in the transformer, e.g.Fig. 16(c), any mismatch current will increase thefundamental component of operate current and,hence, will reduce the percent of fifth harmoniclevel in the operating current. The relay may notbe restrained by the fifth harmonic. However, thetransformer loading increases the throughcurrent restraint level and tends to bring downthe overexcitation to a level where the operatingcurrent is below pickup.

Should the transformer become faulted duringthe high excitation condition, the relay willoperate if the operate current is sufficient toreduce the fifth harmonic component below therelay's restraint level. Such a reduction occursboth because of the reduced excitation levelcaused by the fault current and the increasedfundamental-frequency operate current.

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.

4.5 Unrestrained Differential Element

The unrestrained element, commonly referred toas an 87U, responds to the operating or differen-tial current but with no restraint functionality. Itacts as a high speed trip during severe internalfaults. Its only means of differentiating an internalfault from inrush is the magnitude of the currentinvolved; therefore, it must be set above thelargest expected inrush current. It must also notoperate for dissimilar saturation of CTs causedby DC offset during high current external faults.For these reasons, the unrestrained elementsetting is set fairly insensitive. For example, the

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87U typically is set to trip for differential currentthat is on the order of 30-100 times the minimumoperate setting of the restrained differentialelement.

In some relays, the 87U element respondsstrictly to fundamental frequency currents in theoperate leg, yet other relays may respond to thefull spectrum of frequencies in the operate leg,including the DC component. Since the 87Uneeds to be set above inrush, and the inrush isrich in harmonics and DC, one needs to knowhow the relay is designed in order to make anappropriate setting for the 87U element. Forinstance, the current fed to the 87U element inthe BE1-87T relay is not filtered to remove DC orharmonic content and so it responds to allcurrents that come into the relay. However, the87U in the BE1-CDS2x0 responds only to thefundamental frequency component in theoperate leg, which means the 87U in the BE1-CDS2x0 typically is set lower compared to the87U in the BE1-87T. The appropriate settings forthe 87U element are discussed in the respectiveinstruction manuals.

4.6 Connection Examples

Fig. 18 provides application examples for two-,three-, and four-restraint cases. The relay derivesrestraint signals separately from each set of CTinputs. In Fig. 18(a) the relay protects a delta-wye transformer, with the CTs connected in deltaon the wye-winding side. These CTs could beconnected in wye when using a BE1-CDS2x0 ora 3 phase style BE1-87T when using the internaldelta compensation functions of the relay.

A three-input relay protects the autotransformerin Fig. 18(b). All CTs should be connected indelta, or the relay internal compensation shouldbe set up in delta, since the autotransformercontains an internal unmonitored delta windingthat couples the phases. Due to the deltawinding, for a phase to ground fault, the deltacan cause current to flow on an unfaulted phase.For example, assume a 230/115kV transformerwith an A phase to ground 115kV external fault.Due to the delta winding, current may flow on Band C at the 115kV level and possibly not at allat the 230kV level. This will look like a B and C

phase internal fault to the relay if no deltacompensation is applied. Delta compensationprevents the misoperation.

In autotransformer applications, the tertiary isprimarily used to create a zero sequence source,but it is used in some applications for stationservice power. The tertiary commonly is notincluded in the transformer differential CTsummation, because the station service load istoo small to be sensed by the transformerdifferential relay and with the intent that fuses willonly operate for a station service transformerfault. Since the tertiary is ungrounded, a groundfault on the tertiary leads or load is sensed byvoltage based relays that monitor line to groundvoltages or V0 voltage. Sometimes no tertiaryground fault detection scheme is applied underthe anticipation that the risk is low, and that theVTs and relay needed to sense a ground faultwould cause more problems and faults than willever occur in the transformer. When a secondground fault occurs, it is seen as a phase tophase fault. The resulting phase to phase faulton the tertiary leads or loads is sensed as aninternal transformer fault and, hence, is clearedby an 87 or 51 element trip.

Note the high voltage winding in the autotrans-former in Fig. 18(b) is connected to two break-ers, and each breaker is brought to its ownrestraint, R1 and R2. This is a desirable practicewhen large through-faults from one side of thesubstation to the next, flowing through the twobreakers, could possibly cause unequal CTperformance. The unequal CT performancewould appear as 100% operate current to therelay. If each CT were on its own restraint, therelay would see high restraint and not trip.

However, only the summation of the CTs shouldbe used for restraint when a low MVA transformeris placed on a bus with relatively heavy throughcurrent in the high voltage breakers seen in Fig.18(b). For example, if the full load current for thetransformer in Fig. 18(b) was only 20% of thenormal load flowing in each of the high voltagebreakers, going from one side of the figure tothe other, a relay that restrains based on theindividual breaker currents as seen by R1 andR2 could see 5pu restraint just from load flow(assuming the load flow was not affected by the

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fault) and tend toward non-operation except forvery high magnitude transformer faults. Toaddress this issue, the BE1-CDS240 has theoption to restrain on either the individual cur-rents seen in R1 and R2 or on the summation ofcurrent in R1 and R2.

The relay Fig. 18(c) protects the combination ofa bus and transformer. In this application, anyradial load feeders may have their CTs con-nected in parallel and connected to a commonrestraint input. Paralleling of CTs on non-sourcecircuits can be safe, within the thermal limitationsof the relay. In this case there is no loss ofrestraint for external faults, since these circuitscontribute no fault current.

Source circuit CTs can also be paralleled, but itmust be done judiciously. Ideally, any breakerthat could be a substantial source to throughfault current should be on a dedicated restraintwinding. Hence, in Fig. 18(c), the bus tie, thefeeder to the generator bus, and the lead to thehigh side of the transformer all have their ownrestraint windings.

Figure 18 - Connection Examples

Fig. 19 shows a poor application of CT parallel-ing, using a two-restraint relay for the bus/transformer combination. Here three sets of CTsare paralleled and connected to a commonrestraint winding R1, but where line 1 is a sourceto the bus (e.g., a bus tie). Suppose CT 1misperforms and delivers 50A rather than theideal 60A. The relay sees 10A of restraint and10A of operate; hence, it trips (Fig. 19b). Ifbreaker 1 had been on its own restraint andcircuits 2 and 3 had been in parallel, the relaywould have seen 60A restraint and 10A operate,and it would not have tripped (Fig. 19c).

17

Note 1: CTs that are shown in delta may beconnected in wye, and then have the relayperform the delta compensation internally.Note 2: Relays are shown in simplisticfashion for conceptual purposes. See Fig. 3for more complete internal diagram.

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Figure 19 - Improper CT Paralleling

4.7 Alternate Transformer Connections andAssociated Compensation

The proper configuration of the CT compensa-tion connection was the major difficulty intransformer installations through the mid 1990s.However, with the advent of solid state andnumeric relays that perform the compensationinternally, the difficulty has moved to inside therelay. To complicate the matter, modern relayshave been made flexible enough to compensatefor more than the common delta-wye transformerwith ±30° phase shifts. There are many trans-formers that are connected in alternate methods,especially outside the U.S., creating any phaseshift in 30° increments. For instance, Zig-Zagwindings, seen mainly in grounding banks in theU.S. market, are sometimes used as powertransformer windings to introduce phase shiftsthat may be unusual to some engineers. Modernnumeric relays need to be able to compensatefor any physically possible phase shift in aprocess sometimes referred to as "around theclock compensation." Reference 6 analyzes thevarious arrangements possible for transformerconnections and reviews the mathematics ofhow numeric relays, such as the BE1-CDS240,

compensate for these multiple possible sce-narios.

4.8 Ground Fault Sensing

Ground faults on delta windings connected to asolidly grounded power system are relativelyeasy to sense, but time delays must be usedwhen set highly sensitive. Transient CT saturationdue to DC offset during inrush and high throughfault currents tends to create a false residualcurrent, so a time delay is needed that isappropriate for the expected inrush duration andsensitivity setting. Ground faults on ungroundedsystems must be detected via zero sequencevoltage (59N) and phase to ground voltagerelays (27ln and 59ln).

On wye windings, where impedance groundinglimits the ground fault current to levels below thesensitivity of the phase differential, ground faultsin the transformer need special detectionschemes. The concept is sometimes referred toas "restricted earth fault" protection. Two classi-cal approaches for a sensitive ground faultprotection scheme are a) differentially connectedovercurrent relay that monitors ground currentsflowing into the two sides of a wye winding, andb) a directional ground relay that compares thephase relationship of ground current on eachside of the winding. Both concepts are availablein numeric relays such as the BE1-CDS2x0(concept a), and the BE1-951/IPS (concept b).However, the classical approaches are beneficialbecause they give a more immediate under-standing of the technical concepts.

In the classical approach to a differentiallyconnected overcurrent relay, the auxiliary CTsare required to balance the residual groundcurrent from the phase CTs and the groundcurrent as seen on the neutral of the transformer.In Fig. 20, the 20Ω resistor limits ground faultcurrent to 400A. The 2000:5 CT has 1A in itsresidual connection. The aux CT multiplies thecurrent by 6.7. The 300:5 CT on the transformerneutral also has 6.7A secondary but is wired tobe opposite in polarity so that the summation ofcurrents is 0 (approximately, given normal errorlevels in the CTs). The relay does not operate. Ifthe fault had been internal, the summation wouldhave been above 0.

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Figure 20 - Ground Differential, ClassicalApproach

The 51/87N relay pickup in Fig. 20 possibly isset for 0.5A based on a neutral current contribu-tion of 0.67A relay current for a ground fault 10%from the neutral end of the wye winding. Such afault will yield 40A primary and 0.67A secondary.For this 40A fault, the 2000:5 CTs will only push0.10A into the 87P relay, well below the allowedminimum pickup of the 87P relay. Other 13.8 kVground sources, where available, increase thelevel of relay current for an internal fault. How-ever, the protection must cover the case with noadded current contribution.

One must keep track of burdens quite closelywhen using aux CTs. The secondary burden onthe aux CT in Fig. 20 will be magnified by thesquare of the current ratio, or 44 times, as seenon the primary. 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 on the 2000:5 CTs is just400A/400:1 CTR= 1A secondary for an externalline-ground fault, yielding a burden voltage onthe 2000/5 CTs of 1*22= 22V.

An overcurrent relay used for the 87N functionwill move toward tripping if the fault is internal,for which the currents will no longer balance.Such protection must use a delay (e.g. 30cycles) to ride through the false residual currentresulting from the dissimilar performance of thephase CTs during a phase fault, especiallyduring the DC offset period of a through faultand during transformer inrush. In an impedance

grounded system, the phase fault current can be100 times the maximum level of ground faultcurrent. Thus, it does not take much difference inthe performance of the phase CTs to create arelatively substantial false residual current. Forexample, in Fig. 21, a 1200 Amp phase A to Bexternal fault generates only 28A rather than theideal 30A in one of the CTs. The aux CT multi-plies this to 13.3A in the 51/87N relay. If thepickup of the 51 element had been the afore-mentioned 0.5A, this false residual of 13.3Awould become 27 times pickup, giving a fast buterroneous trip.

Figure 21 - Example False Ground DifferentialDuring Phase to Phase Fault

The 51/87N function in Fig. 21 could be re-placed with a percentage differential function forincreased security against CT misoperations,which is effectively done in a modern numericdifferential relay, such as the BE1-CDS2x0. Anumeric relay would also negate the need for theaux CT. Such relays have the capability tocalculate 3I0 current from the phase CTs inputsand multiply by the appropriate factor to allowcomparison to the current from a CT in theneutral of the transformer without the use of anaux CT, and to perform the percentage differen-tial function. Using a percentage differentialapproach gives added security to the tripdecision, but a percentage differential relay forthe ground differential function still can beinsecure during external phase to phase faultsand must be set with some level of time delay,since the neutral current contributes negligiblerestraint during phase faults.

An alternate method to sense internal groundfaults is to compare the phase relationship of 3I0

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in the phase CTs to the ground current on thetransformer neutral. An internal ground fault andan external ground fault will be marked by a 180°phase shift of the two currents in relation to oneanother. A BE1-67N relay is used to comparethe two currents in Fig. 22. Because the residualcurrent is highly distorted and the waveformvaries from cycle to cycle, directional operationis intermittent. Each time the directional elementresets, it resets the time-overcurrent element.The operate leg, terminals 7 and 8, may have apickup and time delay set to keep false opera-tions from occurring. Classically, a solid stateBE1-67N has been used, but a numeric BE1-951or BE1-IPS relay also can perform the function.

In Fig. 22, the aux CT is used to bring theground current as measured by the phase CTsto a level that is measurable by a 5A nominalrelay. In a modern numeric relay such as theBE1-951 and BE1-IPS, the ground/aux CT inputmay be selected to be rated at 1A and con-nected to monitor the phase residual, and thephase CT inputs can be selected to be rated at5A and connected to the transformer neutral CT.In this approach, the aux CT could be eliminatedfrom the scheme.

Figure 22 - BE1-67N as ground directional relay

5. Turn-to-Turn Faults

Phase differential relays may detect a turn-to-turnfault because the fault changes the transformerturns ratio. Ground differential relays do notrespond to such faults. A neutral overcurrentrelay may see fault current if an external groundsource exists and the resultant voltage unbal-ance creates an excessive load unbalance.

For an impedance grounded system, most ofthe fault current probably will be contributed bythe delta-side source. A single turn fault mayproduce a total less than rated current (Ref. 8). Aturn-to-turn fault may not be detectable initially.However, a sudden pressure relay (SPR) maygive early detection. The SPR will detect anyabnormality that generates a sudden increase inpressure due to gas generation (e.g. arcing dueto a loose connection).

6. Sudden-Pressure Relays (63)

Figure 23(a) shows a SPR that detects anincrease in gas pressure, typically applied ongas-cushioned transformers of about 5 MVA andhigher. The gas pressure is generated by an arcunder the oil, producing decomposition of theoil into gas products. The change in pressureactuates bellows 5 closing microswitch contact7. Equalizer port 8, much smaller than the mainport 4, prevents bellows movement for slowchanges in gas pressure due to ambient tem-perature changes and load cycling.

Figure 23(b) shows use of the break contact ofthe microswitch (63) in conjunction with auxiliaryrelay 63X. This circuit prevents tripping for aflashover of the make contact of 63.

Figure 23 - Sudden Pressure Relay

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An alternate design similar to that of Fig. 23(a)mounts the relay within the oil either in gas-cushioned or in conservator-type transformers.

There are separate sudden pressure devices foruse in auto tap changer compartments, but suchdevices need to be designed so they do notoperate under the presence of the normal arcingand mechanical operations that occur within thetap changer.

The SPR is designed to respond only to arcswithin the oil. While more sensitive than adifferential relay, the SPR is not as fast as thedifferential relay for some faults. Since redun-dancy of protection is the mark of a goodprotection scheme, both relays should beapplied.

Some users have experienced misoperations ofsudden pressure relays. During high-currentexternal faults, winding movement generates anoil pressure wave that can tend to cause relayoperation. Earthquakes have been reported tocause operation. As a result, some users con-nect them only to alarm. Their security hasimproved by installing them on stiffer sections ofthe tank and by adding current supervision logic(e.g., block 63 trip for any high current level thatmay be indicative of an external fault that couldcause high winding movements; if the fault isinternal, differential relays can be assumed totrip rapidly). Security can also be improved byperforming regular maintenance to ensure theyare calibrated properly and not failing or driftingin a manner that makes them excessively sensi-tive. There have been cases where a relayoperation has been a precursor to transformerfailure; e.g., a relay that operates for an externalfault may be an indication of winding stabiliza-tion blocks that have come loose.

Conservator-type power transformers do nothave a gas cushion within the main tank. In-stead, the cushion resides in a separate auxiliarytank. A gas accumulator relay ("Bucholz") can beinstalled in the pipe connecting the main andauxiliary tank to detect the generation of gas.This relay has two elements, an accumulatoralarm and a trip function. The accumulator,which stores a portion of the gas, provides analarm for slowly developing conditions. A baffle

in the pipe actuates the trip element for relativelyfast gas flow to the auxiliary tank.

7. Monitoring for Incipient Problems

The oil in large transformers is normallychecked, as part of routine maintenance, for theexistence of abnormal chemicals and gassesthat are created as a result of oil contamination,insulation breakdown, and internal arcing. Anumber of on-line devices has been developedin recent years to detect incipient conditionsthat threaten serious consequences. Theseinclude gas-in-oil analysis, acoustic partial-discharge detection, moisture sensor, tap-changer-operation supervision, and pump/fansupervision.

Reference 9 reviews gas in oil analysis, and Ref.10 reviews online monitoring schemes. Thewebsite where these articles are found has anextensive collection of other good articles on oilanalysis and transformer operation.

8. Overcurrent Relays

Fig. 1 shows a number of overcurrent relays.When an 87P is in place in this application, the50/51P on the primary side is consideredbackup protection. In a radial distributionapplication, the overcurrent relays on feedersand buses are also part of the transformerprotection scheme since they limit the durationof out of zone faults.

The discussions below include references to50/51Q elements. The Q refers to elements thatrespond to negative sequence current compo-nents. See Section 8.5.

8.1 50/51 Transformer Backup

The CTR for this application is a compromisebetween full load current and limiting current inthe CT during faults near the transformer bush-ings. See Section 10.2 for a discussion on theCT selection in this case.

In Fig. 1, the 50P and 50Q elements would beset at approximately 150% to 200% of thecurrent that will be sensed at 115kV for a 13.8kVthree phase and phase to phase fault. Theseelements must not trip for low side faults. Asetting in this range normally would be above

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the inrush current of the transformer. For in-stance, assume an impedance of 7%, implying asecondary fault will cause, at most, 14.3pu faultcurrent. A setting of 150% would imply a 50Psetting of 21.4pu. This is higher than the typicalinrush current. Some resources mention inrushcurrent reaching as high as 25xFLA, but this istypically only the first half cycle, is very harmoni-cally rich and contains a high DC offset. Relaysresponding strictly to fundamental frequencycurrents (e.g., most modern numeric relays) willsee an inrush that is less than a relay thatresponds to the harmonic and DC component ofinrush. The relay sensing algorithms need to bepart of the setting thought process. This sameconcept was also previously discussed inreference to the 87U element, Section 4.5.

Since the 115kV winding on T1 is delta, noground current should be seen at the transformerbackup, so 50/51N elements in the relay can beset fairly sensitive and fast. However, there maybe some transient false residual due to CT errorduring transformer inrush or 13.8kV faults, so the50/51N elements need to be time delayedsomewhat, possibly about 4 times the systemL/R time constant. Due to the long duration ofinrush current and its associated DC offsetcomponent, highly sensitive ground currentpickup levels should be delayed substantiallylonger. In power system cycles, the L/R timeconstant is: T.C., cycles = (X/R ratio of Zfault)/(2*π)where Zfault refers to the system source imped-ance looking back from the high side of thetransformer.

The 51P relay time element must be set to carrythe maximum expected load current. Since atransformer is capable of carrying considerableoverload for a short period, a high pickup isnormally called for (e.g. twice the forced-cooledrating). The time unit should coordinate with the51P Bus Backup relay or the 51P Partial Differen-tial relay (Section 8.2), depending on which is inuse.

The 50/51P operating time needs to be fasterthan the through-fault (external fault) withstandcapability of the transformer (Fig. 26). See Ref. 1for additional transformer damage curves. Figure26 illustrates both "frequent" and "infrequent"

limits and recognizes the cumulative effect ofthese stresses. Transformers on systems withunderground feeders likely have fewer faultsrelative to systems with long overhead wires.Higher magnitude faults would be less common,and lower magnitude faults would be morecommon, especially on systems with longfeeders.

Because of its high pickup and slow operation,the 51P element provides relatively poor protec-tion (compared to other relaying schemes) fortransformer winding and tap changer faults.Accordingly, this element is not a good substi-tute for differential and sudden pressure relays.The consequences of a slow cleared faultinclude the threat of an oil fire due to a rupturedtank or bushing explosion and the higher internaldamage that will occur. Removal generally isnecessary for even a fast cleared winding fault.This is not the case for a tap-changer flashoverthat is cleared before winding damage.

8.2 Bus Backup, Bus Tie, and PartialDifferential 51 Relays (and 50T)

The overcurrent element at this level does notdirectly protect the transformer, but it performs aservice of limiting the duration of faults that willcause cumulative damage to the transformer, asdiscussed in the previous section relative to thetransformer damage curve.

Breaker D, Fig. 1, would be considered the BusMain breaker, but the 51 relay on this breakerwould be considered the Bus Backup relayunder the understanding that there would besome dedicated bus protection scheme inplace, such as a bus differential (87B) or theinterlocked 50 elements discussed below.

A 50 element normally is not used in these relaysdue to coordination issues with feeder relays.However, a 50T (a 50 element with a small timedefinite time delay) is sometimes used in the busbackup relay in a bus protection scheme thatinterlocks the bus and feeder relays. In thescheme, the bus backup 50 element is delayedlong enough for a feeder relay to communicateback to the bus relay, telling it, "Do not trip, Isee a fault on my feeder."

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The partial differential 51 element in Fig. 1measures the sum of the transformer and bus-tiebreaker currents. Such a connection is appropri-ate with a normally-closed bus-tie breaker. Whenthe bus tie is closed, the partial differential seesthe full current going to a feeder fault; hence, itmore directly coordinates with the feeder relaysthan a relay that only monitors the current in asingle transformer. A relay such as the busbackup or bus tie that sees only a portion of thecurrent will trip slow relative to the partialdifferential relay given the same pickup level.

If the bus main and bus-tie breakers are inter-locked to prevent the secondary of bothtransformers from being tied together, the bustie overcurrent relay is coordinated to be slowerthan a feeder relay but faster than the busbackup relay. This adds an extra level ofovercurrent protection in the TCC curve thateffectively makes either the transformer relayslower or the feeder relay faster, which adds acompromise to the TCC coordination scheme.If a dedicated high speed bus protectionscheme is in place (e.g., bus differential or theaforementioned interlocked bus 50 elementscheme), the coordination compromise associ-ated with including the bus tie in the TCC issubject to question.

In substations with multiple operating modes,such as run with and without the tie closed,smart relays that can change settings on the flycan be utilized. This feature is found in modernnumeric overcurrent relays with multiple settingsgroups, such as the BE1-951, BE1-IPS, BE1-851,and BE1-700C.

8.3 Transformer Neutral Overcurrent

The transformer neutral overcurrent relay in Fig. 1primarily backs up the bus and transformerprotection scheme and faults on the leadbetween the transformer and the 13.8kV bus. Inthe absence of the 87N application, in imped-ance grounded systems the relay provides theprimary ground fault protection for faults closeto the neutral on the transformer low voltagewinding. The relay also backs up the 87T,depending upon the sensitivity of the 87T toground faults. The relay must coordinate with thebus backup 51N to allow the latter to clear a bus

fault first without tripping one or both transform-ers.

If the 13.8kV bus tie can be closed with bothtransformers in service, the transformer neutralrelays on both transformers will operate for a13.8kV winding or lead fault, unless a 67N or87N, Section 4.8, is provided that is configuredfor faster clearing.

8.4 67/51 and 32 Relays

The 67/51P relay operates for current (and, tosome extent, power) flowing from the transformerlow side toward the high side, i.e., backfeed.Such flow could occur if the 115kV tie breakeropens and both transformers remain energized,and the 13.8kV bus tie is closed. Reverse flowalso can occur with or without the 115kV tiebreaker closed, with local 13.8kV generation.Reverse current flow also can occur during atransformer fault. When backfeed under faultconditions is the concern, the 67/51P element isthe appropriate element to use (rather than a32). A 67/50P element also may be appropriate,but the 50 element should be time delayedslightly if there is any chance of transientbackfeed during load swings or when parallelingwith the other transformer. Since normal loadflow is toward the low side, the 67/51P can beset more sensitively than bus backup 50/51 andmay also be faster.

A reverse looking 67/51P has some ability to tripfor forward faults and load flow. The element'smaximum torque angle (MTA) typically isskewed for fault detection, as seen in Fig. 24. InFig. 24, the MTA of the relay has been set verylow, maybe 10°. Note the relay sees ±90° fromthe MTA as a forward current flow. In this ex-ample, the 67/51P element reaches very littleinto the opposite plane. If the relay MTA hadbeen set at the more typical 45° to 80° setting,the reverse looking element would reach wellinto the plane of forward power flow and, hence,would be at greater risk of tripping for normalload flow. To prevent this risk, one practice is toset the 67/51P element pickup high enough sothat it will not pick up for any normal load flowconditions or use a directional power element,the 32, to sense actual power flow toward thetransformer.

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Figure 24 - 67 Element MTA vs. Load Flow

The 32 device is designed to be very selective inthe direction of power flow. Ideally it is nonre-sponsive to VAR flow, though heavy VAR flow insome relay designs can swamp the relay sensingalgorithms and reduce sensitivity to true powerflow. In fault conditions, watt flow may be lowand the sensed current may be mostly VARs.Coupled with the reduced sensitivity of the 32element to watt flow in some designs under thepresence of high VAR flow, a 32 may respondpoorly to fault conditions, so a 32 elementnormally is not used for fault detection. Hence,the overall solution to sensing currentbackfeeding into the transformer is both a67/51P and a 32 element. Both of the 67/51 and32 functions may be found in the BE1-IPS andBE1-951.

Numeric relays such as the BE1-951 and BE1-IPS relays do not have the limitation mentionedabove relative to sensing watt flow under thepresence of high VAR flow.

Recall also that a 67N, looking for groundcurrent flowing toward the transformer, asdiscussed previously in Section 4.8, is a meansof sensing transformer ground faults. In Section4.7, the directional element used the phaseangle relationship of 3I0 in the phase leads vs.Ig in the transformer neutral. However, a 67Nrelay more commonly is configured in thedesign stage to see only local phase voltages(l-l or l-n, depending on design or configuration)and phase currents and may not have access totransformer neutral current. The directionaldecision for current flow is most commonlyeither current vs. quadrature voltage (solid staterelays) or V2 vs. I2 (numeric relays). See Refs. 2and 11 for a technical description of how these

two directional elements are designed, as wellas other supporting information in regard to the67 element.

8.5 Negative Sequence Overcurrent

The advent of and high use of numeric relaysthat readily calculate negative sequence current(I2) has resulted in an increased use of negativesequence overcurrent relaying. The device isnamed 50/51Q herein, but sometimes referred toas the 46 device. The problem with the term 46is that it is unclear as to whether a 51 or 50device is referred to.

The benefit of a 51Q in delta wye transformerapplications is that the I2 component of faultcurrent is identical, on a per unit basis, on bothsides of a delta/wye transformer (see Section10.3 and Fig. 25). The 51Q on the high side of adelta/wye transformer easily can be coordinatedwith 51Q elements on the low side for phase tophase and phase to ground faults. Unlike phaseovercurrent elements, the 51Q does not need tobe set above load current levels and insteadwould have a pickup similar, on a per unit basis,to a ground overcurrent element on a solidlygrounded system.

The drawback of the 50/51Q is that it adds somelevel of work to the coordination analysis. If setbelow load current, recall a 51Q may need tocoordinate with downstream phase overcurrentdevices that do not monitor I2, and that will onlytrip when current rises above normal loadcurrent, such as fuses. One must compare the51Q response to the 51N relays as well as thesephase overcurrent elements.

9. Thermal Protection (49)

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 two tem-perature sensing levels for control and a third,higher temperature, sensing level 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.

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10 Associated Issues10.1 Harmonics During CT Saturation

Saturation of CTs happens in terms of AC andDC components of current. The AC saturationeffect refers to the ability of a CT to reproducesymmetrical current conditions. The DC satura-tion effect refers to the saturation that occurswhen the current contains the decaying DCcomponent associated with a fault, magnetizinginrush, motor starting, or generator synchroniz-ing. A CT that experiences negligible distortionunder symmetrical AC conditions might becomesaturated and give a severely distorted outputwhen a DC component exists (Reference 12 is agood resource but hard to access. Reference 13provides a somewhat more accessible but lessdetailed discussion of the matter).

While faults generally produce the most current,other conditions, such as a motor starting,produce much slower DC decay than occurs fora fault. A smaller DC current that persists longercan also produce DC saturation. For theseexternal disturbances, unequal times to satura-tion, and saturation level, in various CTs resultsin false operating current. Either the harmonic-restraint or the percentage differential restraint(fundamental frequency characteristic) preventsunwanted tripping for this condition.

Under high symmetrical current conditions thatdrive a CT to AC saturation (e.g., an attempt bya CT to drive current that in turn causes voltageabove the CT's kneepoint), CT distortion gener-ates odd harmonics but no even harmonics. ACT experiencing DC saturation during an asym-metrical fault develops both even and oddharmonics. If a relay is designed to restrain onodd harmonics (e.g. 5th), it may fail to operate ifthe harmonic content from the saturated CTexceeds the relay's threshold for restraint. Relaysthat restrain on even harmonics may be tempo-rarily restrained until the DC decays enough toallow the CT to perform again correctly. High-setunrestrained elements (87U) supplement therestrained elements, so that high current faults,where CT saturation can be severe, can becleared independent of any harmonic restraint.For satisfactory protection, harmonic generationby the CTs should not exceed the restraint levelfor a current below the unrestrained element

pickup. Poor CT quality can detract materiallyfrom the reliability of the differential relay.

10.2 CT Ratio and CT Accuracy Selection

Let "Ks" be the ratio of a CT kneepoint to theburden voltage. The knee point herein refers tothe 45° slope point on the CT excitation curve.The burden voltage in this ratio is the RMS (AConly, no DC) voltage in the CT loop during amaximum level fault, and where the CT internalresistance is included in the CT loop resistance.If one does not have CT excitation curves, alikely satisfactory substitute for the knee point isto assume that the knee point is equal to the Cclass of the CT (though in practice, the kneepoint ranges from about 70-150% of the Cclass). The higher the Ks value, the better the CTperformance. The purpose is to give a high levelof margin in the CT rating so that it can providereasonable ability to reproduce the DC offset ina fault.

For differential protection, a good objective isKs=8 or higher for a current at the unrestrainedpickup level during all out-of-zone faults. For in-zone faults, a Ks of 2 is desirable. Some re-sources suggest a Ks of "1+X/R" (where X/R isfound from the system impedance looking backfrom the fault location) will give reasonably goodassurance of limited risk of DC offset inducedsaturation. Reference 13 contains a derivation ofthe 1+X/R factor. High Ks values called for bythe 1+X/R factor can create a demand for CTperformance that is sometimes difficult to meet.

It is difficult to generalize about when it isimportant for CTs to be highly rated for anapplication and, hence, have a high Ks. It isalways very desirable to have a Ks well above 1,but obtaining a CT resistant to DC offset effectsmay be hard to justify. For instance, in a phaseovercurrent application, transient CT saturationdue to DC offset will cause only a small delay intripping speed, so the effect of CT error isgenerally small; hence, a low Ks is likely satisfac-tory. However, if a sensitive ground overcurrentrelay is connected in the residual of the phaseCTs, the effect of CT saturation is to false trip, soa selected CT must be very well rated and ableto reproduce substantial DC offset withoutsaturating, hence calling for a high Ks.

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10.2.1 Selection of CT ratio in Figure 1

Issues with CT performance under fault currentcommonly arise when a relatively low MVAtransformer is placed on a powerful bus. Thiscause is an incongruent demand betweenselecting a CT ratio that allows good reproduc-tion of full fault current without excessive CTsecondary current, and selecting a CT ratio thatallows the secondary current to be some mea-surable level during normal load conditions.

For instance, in the system seen in Fig. 1, theload current at 30MVA and 115kV is 151A,implying a CTR of about 200:5 would work well.However, suppose the fault duty at 115kV was15,000A. If we wish to limit CT secondary currentto maybe 100A, a CTR of about 800:5 would beselected. However, at 800:5, the FLA from theCT would only be 0.94A, which implies measur-ing accuracy would suffer at light load condi-tions. A CT actually can carry quite a bit morethan 100A for a short period, so a compromiseselection of 400:5 was chosen for the example.

The burden and CT voltage rating must bechecked during peak fault currents. Assume a1200:5 CT is used but tapped at 400:5. Assumethe full winding C class is C400, and the internalresistance is 0.6 ohms. At a tap of 400:5, theeffective C class is C133, and one can assumethat the kneepoint is roughly 130V for lack of anappropriate excitation curve. Since we are usingonly 1/3 of the CT windings, the internal resis-tance is 0.2 ohms. Assume external burden is 0.4ohms. Given our assumed 15,000A fault, thesecondary current, if the CT operates ideally, is187.5A. This is quite high, but most CTs canwithstand it for short periods. The short timerating of CTs may not be published in commonliterature, and the manufacturer should beconsulted on the short time current rating of theCT (typically given for maximum primary currentfor 1 second with a shorted secondary), espe-cially if fault current rises above 100A secondaryand delayed tripping will be utilized at thiscurrent level. The voltage drop in the CT resis-tance and external burden is187.5*(0.2+0.4) or 112.5V. This gives a Ks ofabout 1.15. The CT is at risk of entering intosaturation, especially if any DC exists in thecurrent. We have a relatively weak CT for theapplication. Our choice is to either raise the CT

ratio and limit accuracy during normal loads,raise the CT C class to C800, or accept the Ksvalue with the assumption that the CT is ratedwell enough to reproduce the current to allowthe unrestrained differential element to rapidlyclear the fault. This becomes an engineeringjudgment decision beyond the scope of thisdocument.

Next, we need to analyze what occurs in thesame CT during an out of zone secondary fault.Assume the transformer impedance is 8% on theunit's 18MVA base. For a three phase fault, thecurrent at 115kV will be about 1/0.08pu, or1130A at 115kV. This gives us 14.1A from the CTat 400:5, and the voltage in the CT loop (at 0.6ohms) is only 8.5V and, given a knee point of130V, the Ks is about 15, which should work wellunder very high DC offset conditions. This givesadded reason to accept the CT as is.

10.3 Delta-Wye Winding Effects on PrimaryCurrent

For delta/wye transformers, fault current as seenon the primary for secondary ground faults issubstantially lower than for secondary phase tophase and three phase faults. As those who haveworked in fault analysis are aware, lines on thedelta side of delta/wye banks see 0.577 per unitcurrent for secondary ground faults, comparedto the current seen by the line during threephase faults on the secondary of the samemagnitude. The 0.577 factor for ground faultsoccurs because ground faults are single phaseevents; hence, the current is multiplied acrossthe transformer by the transformer turns ratio,rather than by the line-line voltage ratio (theturns ratio on a delta wye bank is 1/sqrt(3)relative to the line to line voltage ratio).

Figure 25 shows the per unit phase and se-quence component currents seen on the deltaside for various wye side faults, for a DAB deltatransformer. Note that positive and negativesequence magnitudes are the same on bothsides of the transformer but shifted in oppositedirections.

References

Reference 1 provides a reference and bibliogra-phy section of almost 100 articles and IEEEStandards on almost every topic associated with

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transformer protection and is recommended forreview for one who is making a career in protec-tive relaying. Web searches will invariably findeven more references. The IEEE Xplore ware-house of technical articles is another resource forone who has appropriate subscriptions to IEEE.

One should also review the instruction manualsfor various Basler relays, and the variety ofApplication Notes and Technical papers avail-able at www.basler.com. Besides Basler'sresources, other manufacturers, engineeringcompanies, and government agencies providearticles and application guides associated withtransformer protection.

Publication dates and/or revision levels of thetexts and standards listed are not supplied, asthese are routinely updated; the latest revisionshould generally be sought out.

1. ANSI/IEEE C37.91, IEEE Guide for ProtectiveRelay Applications to Power Transformers.

2. Lewis Blackburn, "Protective Relaying:Principles and Applications," Marcel Dekker,Inc.

3. S. Horowitz and A. Phadke, "Power SystemRelaying," John Wiley & Sons, Inc.

4. ANSI/IEEE C37.95 "IEEE Guide for ProtectiveRelaying of Utility-Consumer Interconnec-tions."

5. National Electric Code, published by NFPA.6 "Three Phase Transformer Winding

Configurations and Differential RelayCompensation", available in the technicalresource library of www.basler.com.

7. W. K. Sonnemann, C.L. Wagner and G.D.Rockefeller, "Magnetizing Inrush Phenomenain Transformer Banks," AIEE Transactions,Vol. 77, pt. III, pp 884-892, Oct. 1958.

8. Klingshorn, H.R. Moore, E.C. Wentz,"Detection of Faults in Power Transformers,"AIEE Transactions, Vol. 76, pt. III, Apr. 1957,pp 87-98.

9. "Dissolved Gas Analysis - Past, Present andFuture," F. Jacob, Weidman-ACTI. Availableat http://www.weidmann-acti.com/knowledge_center/.

10. "An Overview of Online Oil MonitoringTechnologies." 4th Annual (2005) Weidmann-ACTI Technical Conference. Available atsame site as Ref. 9.

11. "Directional Overcurrent Relaying Concepts."Available in the technical resource library ofwww.basler.com.

12. IEEE Committee Report, "TransientResponse of Current Transformers," IEEESpecial Publication, 76CH1130-4PWR.

13. "Bus Protective Relaying, Methods andApplication," available in the technicalresource library of www.basler.com.

Figure 25 - Delta Side Currents for Wye Side Faults

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Figure 26 - Example Transformer Damage Curve

Basler Electric Numeric RelaysThe numeric relays contain too many features and capabilities to be well represented in a simple listing offeatures. Some of the functions listed are optional and dependent upon the relay style that is purchased.Refer to the product bulletins and instruction manuals for a more complete listing of capabilities andordering options. Some of the relays listed would not normally be used directly with a transformerprotection scheme, but they may exist in the scheme due to other equipment in the area of the trans-former; hence, are included due to possible general interest to the protection engineer. The relays listedare available in cases designed for either 19" rack mount or 19" half rack, depending on the relay model,and many are also available in cases designed for fitting into the cutout of older GE and ABB/WH relays,a particular feature of Basler Electric products that may notably reduce installation costs.

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FunctionModel (ANSI Device if applicable) Comments

BE1-CDS220 87P, 87U, 87N Targets a three phase, two winding transformerInternal phase compensation for common delta/wye bank design

50P/Q/N, 51P/N/Q 3 independent copies of each 50 and 51 element, assignable to any input.BF Breaker FailureOther Features Programmable logic

Metering, detailed event reporting, oscillography, remote monitoring, multiple I/O,4 setting groups

BE1-CDS240 87P, 87U, 87N Three phase, up to 4 windings87 elements can monitor summation of any set of CT inputs.Internal phase compensation for any transformer connection configuration.Two copies of 87N for monitoring two independent wye windings

50P/Q/N, 51P/N/Q, BF 4 independent copies of each 51P/Q, 5 for 51N, 8 for 50P, 4 for 50Q, 5 for 50NCurrent elements can monitor summation of any set of CT inputs.

50BF Advanced Breaker Failure, 4 copies24, 27, 47, 59, 59N, 81 Voltage monitoring standard in all models. Multiple independent copies of several

elements.Other Features Programmable logic

Metering, detailed event reporting, oscillography, remote monitoring, multiple I/O,4 setting groups

BE1-851 50P/Q/N, 51P/Q/N General purpose overcurrent monitoring. Two copies of each 50 element.BF Breaker Failure79 4 shot reclosingOther Features Programmable logic

Metering, detailed event reporting, oscillography, remote monitoring, multiple I/O,4 setting groups

BE1-951 50P/Q/N, 51P/Q/N General purpose overcurrent monitoring. Two copies of each 50 element.67 control of all elementsBF Breaker Failure24, 25, 27, 47, 59, 59N, 81 Multiple independent copies of several elements.32 Forward/reverse over power79 4 shot reclosingOther Features Programmable logic

Metering, detailed event reporting, oscillography, remote monitoring, multiple I/O,4 setting groups

BE1-IPS100 50P/Q/N, 51P/Q/N General purpose overcurrent monitoring, ideal for intertie protection67 control of all elements Two copies of 51P, 51N

Two copies of each 50 elementBF Breaker Failure24, 25, 27, 47, 59, 59N, 81 Multiple independent copies of several elements. 81 has rate of change.32 Two copies 32 Forward/reverse, over/under power79 4 shot reclosing (PI and RI)Other Features Programmable logic

Metering, detailed event reporting, oscillography, remote monitoring, multiple I/O,2 setting groups

BE1-700C 50P/Q/N, 51P/Q/N General purpose overcurrent monitoring. Two copies of each 50 element.BF Breaker Failure79 4 shot reclosing (optional)Other Features Programmable logic

Metering, detailed event reporting, oscillography, remote monitoring, multiple I/O,2 setting groupsEthernet/Internet access

BE1-700V 24, 25, 27, 47, 59, 59N, 81 Multiple independent copies of several elements.79 4 shot reclosingOther Features Programmable logic

Metering, detailed event reporting, oscillography, remote monitoring, multiple I/O,2 setting groupsEthernet/Internet access

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Table III - Basler Numeric Relays

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Solid State Relays

The list below is not an exhaustive list of Basler solid state relays, but it shows the relays of most commoninterest. Some of these relays are not directly applicable to transformer protection, but they are includeddue to possible general interest to the protection engineer.

ANSI DeviceRelay Model Function Comments

BE1-25 25 Synchronism checkBE1-27 27 Single phase, connected line to line or line to neutralBE1-32 32 Wide range of sensitivities available; see options table.

Available as over or over/underBE1-40Q 40 Generator Loss of ExcitationBE1-46 46/51 Inverse time using an I2t curveBE1-47 47 Definite timeBE1-50 50 Single or multiple phaseBE1-50/51B 50/51 CT powered; ideal for AC powered switchgear.

Available as a direct GE IAC and ABB/WH CO retrofit.BE1-51 50/51 Wide variety of models available; single phase, three phase, three

phase and neutral.BE1-51/27R/C 51 Similar to BE1-51 but has voltage control and voltage restrained

function; generally used in generator protection.BE1-59 59 Single phase, connected line to line or line to neutralBE1-59N 59 Design used for monitoring generator neutral and broken delta VTBE1-59NC 59 Design for use in capacitor neutral voltage monitoring schemeBE1-64F 64 Generator field ground.BE1-67 67/51P Similar in functionality to the BE1-51 but uses quadrature voltage

technique for phase overcurrent directional controlBE1-67N 67/51N Similar in functionality to a single phase BE1-51 but uses Vo and Ig

inputs for directional controlBE1-79M 79 4 shot reclosing relayBE1-81O/U 81 Main application is load shedding and islanding detection.BE1-87B 87 High impedance bus differentialBE1-87G 87 Generator differentialBE1-87T 87T Transformer differential. Available in single phase up to 5 input

or three phase up to 3 input.

Table IV - Basler Solid State Relays

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Revised 06/07