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Generator Protection Application Guide

Generator Protection Applicatin Guide Basler Electric

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Page 1: Generator Protection Applicatin Guide Basler Electric

Generator ProtectionApplication Guide

Page 2: Generator Protection Applicatin Guide Basler Electric

About the Original Author

George Rockefeller is a private consultant. He has a BS in EE from Lehigh University; MS from NewJersey Institute of Technology and a MBA from Fairleigh Dickinson University. Mr. Rockefeller is aFellow of IEEE and Past Chairman of IEEE Power Systems Relaying Committee. He holds nine U.S.Patents and is co-author of Applied Protective Relaying (1st Edition). Mr. Rockefeller worked forWestinghouse Electric Corporation for twenty-one years in application and system design of protectiverelaying systems. He worked for Consolidated Edison Company for ten years as a System Engineer.He has served as a private consultant since 1982.

Updates and additions performed by various Basler Electric Company employees.

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

First printing April 1994Revision C.0 June 2001

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Generator ProtectionApplication Guide

Introduction

This guide was developed to assist in theselection of relays to protect a generator. Thepurpose of each relay is described and related toone or more power system configurations. Alarge number of relays is available to protect fora wide variety of conditions. These relays protectthe generator or prime mover from damage. Theyalso protect the external power system or theprocesses it supplies. The basic principlesoffered here apply equally to individual relaysand to multifunction numeric packages.

The engineer must balance the expense ofapplying a particular relay against the con-sequences of losing a generator. The total lossof a generator may not be catastrophic if itrepresents a small percentage of the investmentin an installation. However, the impact on servicereliability and upset to loads supplied must beconsidered. Damage to and loss of product incontinuous processes can represent the domi-nating concern rather than the generator unit.Accordingly, there is no standard solution basedon the MW rating. However, it is rather expectedthat a 500kW, 480V, standby reciprocatingengine will have less protection than a 400MWbase load steam turbine unit. One possiblecommon dividing point is that the extra CTsneeded for current differential protection are lesscommonly seen on generators less than 2MVA,generators rated less than 600V, and generatorsthat are never paralleled to other generation.

This guide simplifies the process of selectingrelays by describing how to protect against eachtype of fault or abnormal condition. Then,suggestions are made for what is considered tobe minimum protection as a baseline. Afterestablishing the baseline, additional relays, asdescribed in the section on ExtendedProtection, may be added.

The subjects covered in this guide are asfollows:

• Ground Fault (50/51-G/N, 27/59, 59N, 27-3N,87N)

• Phase Fault (51, 51V, 87G)• Backup Remote Fault Detection (51V, 21)• Reverse Power (32)• Loss of Field (40)• Thermal (49)• Fuse Loss (60)• Overexcitation and Over/Undervoltage

(24, 27/59)• Inadvertent Energization (50IE, 67)• Negative Sequence (46, 47)• Off-Frequency Operation (81O/U)• Sync Check (25) and Auto Synchronizing (25A)• Out of Step (78)• Selective and Sequential Tripping• Integrated Application Examples• Application of Multifunction Numerical Relays• Typical Settings• Basler Electric Products for Protection

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The references listed on Page 22 provide morebackground on this subject. These documentsalso contain Bibliographies for further study.

Ground Fault Protection

The following information and examples coverthree impedance levels of grounding: low,medium, and high. A low impedance groundedgenerator refers to a generator that has zero orminimal impedance applied at the Wye neutralpoint so that, during a ground fault at the genera-tor HV terminals, ground current from the genera-tor is approximately equal to 3 phase faultcurrent. A medium impedance grounded genera-tor refers to a generator that has substantial im-pedance applied at the wye neutral point so that,during a ground fault, a reduced but readily de-tectable level of ground current, typically on theorder of 100-500A, flows. A high impedancegrounded generator refers to a generator with alarge grounding impedance so that, during aground fault, a nearly undetectable level of faultcurrent flows, necessitating ground fault monitor-ing with voltage based (e.g., 3rd harmonic volt-age monitoring and fundamental frequency neu-tral voltage shift monitoring) relays. The locationof the grounding, generator neutral(s) or trans-former, also influences the protection approach.

The location of the ground fault within the gen-erator winding, as well as the grounding imped-ance, determines the level of fault current.Assuming that the generated voltage along eachsegment of the winding is uniform, the prefaultline-ground voltage level is proportional to thepercent of winding between the fault location andthe generator neutral, V

FG in Fig. 1. Assuming an

impedance grounded generator where (Z0, SOURCE

and ZN)>>Z

WINDING, the current level is directly

proportional to the distance of the point from thegenerator neutral [Fig. 1(a)], so a fault 10% fromneutral produces 10% of the current that flowsfor a fault on the generator terminals. While thecurrent level drops towards zero as the neutral isapproached, the insulation stress also drops,tending to reduce the probability of a fault nearthe neutral. If a generator grounding impedanceis low relative to the generator winding imped-ance or the system ground impedance is low, thefault current decay will be non-linear. For I

1 in

Fig. 1, lower fault voltage is offset by lower

generator winding resistance. An example isshown in Fig. 1(b).

The generator differential relay (87G) may besensitive enough to detect winding ground faultswith low-impedance grounding per Fig. 2. Thiswould be the case if a solid generator-terminalfault produces approximately 100% of ratedcurrent. The minimum pickup setting of thedifferential relays (e.g., Basler BE1-CDS220 orBE1-87G, Table 2) should be adjusted to sensefaults on as much of the winding as possible.However, settings below 10% of full load current(e.g., 0.4A for 4A full load current) carry in-creased risk of misoperation due to transient CTsaturation during external faults or during step-uptransformer energization. Lower pickup settingsare recommended only with high-quality CTs(e.g., C400) and a good CT match (e.g., identicalaccuracy class and equal burden).

FIGURE 1. EFFECTS OF FAULT LOCATION WITHINGENERATOR ON CURRENT LEVEL.

If 87G relaying is provided per Fig. 2, relay 51N(e.g., Basler relays per Table 2) backs up the87G, as well as external relays. If an 87G is notprovided or is not sufficiently sensitive for ground

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winding from the neutral, the 51N current will be0.5A, with a 1000/5 CT.

Fig. 3 shows multiple generators with the trans-former providing the system grounding. Thisarrangement applies if the generators will not beoperated with the transformer out of service. Thescheme will lack ground fault protection beforegenerator breakers are closed. The transformercould serve as a step-up as well as a groundingtransformer function. An overcurrent relay 51N ora differential relay 87G provides the protectionfor each generator. The transformer shouldproduce a ground current of at least 50% ofgenerator rated current to provide about 95% ormore winding coverage.

faults, then the 51N provides the primary protec-tion for the generator. The advantage of the 87Gis that it does not need to be delayed to coordi-nate with external protection; however, delay isrequired for the 51N. One must be aware of theeffects of transient DC offset induced saturationon CTs during transformer or load energizationwith respect to the high speed operation of 87Grelays. Transient DC offset may induce CTsaturation for many cycles (likely not more than10), which may cause false operation of an 87Grelay. This may be addressed by not block load-ing the generator, avoiding sudden energizationof large transformers, providing substantialllyoverrated CTs, adding a very small time delay tothe 87G trip circuit, or setting the relay fairlyinsensitively.

FIGURE 2. GROUND-FAULT RELAYING -GENERATOR LOW-IMPEDANCE GROUNDING.

The neutral CT should be selected to produce asecondary current of at least 5A for a solidgenerator terminal fault, providing sufficientcurrent for a fault near the generator neutral. Forexample, if a terminal fault produces 1000A inthe generator neutral, the neutral CT ratio shouldnot exceed 1000/5. For a fault 10% from theneutral and assuming I

1 is proportional to percent

FIGURE 3. SYSTEM GROUNDED EXTERNALLY WITHMULTIPLE GENERATORS.

Fig. 4 shows a unit-connected arrangement(generator and step-up transformer directlyconnected with no low-side breaker), using high-resistance grounding. The grounding resistor andvoltage relays are connected to the secondary ofa distribution transformer. The resistance isnormally selected so that the reflected primaryresistance is approximately equal to one-third ofthe single phase line-ground capacitive reactanceof the generator, bus, and step-up transformer.This will limit fault current to 5-10A primary.Sufficient resistor damping prevents ratcheting upof the sound-phase voltages in the presence of anintermittent ground. The low current level mini-mizes the possibility of sufficient iron damage torequire re-stacking. Because of the low currentlevel, the 87G relay will not operate for single-phase ground faults.

FIGURE 4. UNIT-CONNECTED CASE WITH HIGH-RESISTANCE GROUNDING.

Protection in Fig. 4 consists of a 59N overvoltagerelay and a 27-3N third-harmonic undervoltagerelay (e.g., Basler relays per Table 2). As shown

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in Fig. 5, a ground fault at the generator highvoltage bushings elevates the sound phase line toground voltages to a nominal 173% of normal lineto neutral voltages. Also, the neutral to groundvoltage will rise to the normal phase-groundvoltage levels. The closer the ground fault is tothe generator neutral, the less the neutral toground voltage will be. One method to sense thisneutral shift is with the 59N relay (Fig. 4) monitor-ing the generator neutral. The 59N will sense andprotect the generator for ground faults over about95% of the generator winding. The selected 59N(Basler relays per Table 2) relay should beselected so as to not respond to third harmonicvoltage produced during normal operation. The59N will not operate for faults near the generatorneutral because of the reduced neutral shift duringthis type of fault.

FIGURE 5. NEUTRAL SHIFT DURING GROUND FAULTON HIGH IMPEDANCE GROUNDED SYSTEM.

Faults near the generator neutral may be sensedwith the 27-3N. When high impedance groundingis in use, a detectable level of third harmonicvoltage will usually exist at the generator neutral,typically 1-5% of generator line to neutral funda-mental voltage. The level of third harmonic isdependent on generator design and may be verylow in some generators (a 2/3 pitch machine willexperience a notably reduced third harmonicvoltage). The level of harmonic voltage will likelydecrease at lower excitation levels and lower loadlevels. During ground faults near the generatorneutral, the third harmonic voltage in the generatorneutral is shorted to ground, causing the 27-3N todrop out (Fig. 6). It is important that the 27-3Nhave high rejection of fundamental frequencyvoltage.

FIGURE 6. GROUND FAULT NEAR GENERATORNEUTRAL REDUCES THIRD-HARMONIC VOLTAGE INGENERATOR NEUTRAL, DROPPING OUT 27-3N.

The 27-3N performs a valuable monitoringfunction aside from its fault detection function; ifthe grounding system is shorted or an openoccurs, the 27-3N drops out.

The 59P phase overvoltage relay in Fig. 4supervises the 27-3N relay, so that the 86lockout relay can be reset when the generator isout of service; otherwise, the field could not beapplied. Once the field is applied and the 59Poperates, the 27-3N protection is enabled. The59P relay should be set for about 90% of ratedvoltage. An “a” contact of the unit breaker can beused instead of the 59P relay to supervise 27-3Ntripping. Blocking the 27-3N until some level offorward power exists also has been done.However, use of the 59P relay allows the 27-3Nto provide protection prior to synchronization(i.e., putting the unit on line), once the field hasbeen applied.

In order to provide 100% stator winding cover-age, the undervoltage (27-3N) and overvoltage(59N) settings should overlap. For example, if agenerator-terminal fault produces 240V, 60 Hzacross the neutral voltage relay (59N), a 1Vpickup setting (a fairly sensitive setting) wouldallow all but the last (1/240)*100 = 0.416% of thewinding to be covered by the overvoltagefunction. If 20V third harmonic is developedacross the relay prior to a fault, a 1V third-harmonic drop-out setting would provide dropoutfor a fault up to (1/20)*100= 5% from the neutral.Setting the 59N pickup too low or the 27Ndropout too low may result in operation of theground detection system during normal operatingconditions. The third harmonic dropout level maybe hardest to properly set, since its level isdependent on machine design and generatorexcitation and load levels. It may be advisable to

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measure third harmonic voltages at the generatorneutral during unloaded and loaded conditionsprior to selecting a setting for the 27-3N dropout.In some generators, the third harmonic at theneutral may become almost unmeasurably lowduring low excitation and low load levels, requir-ing blocking the 27-3N tripping mode with asupervising 32 underpower element when thegenerator is running unloaded.

There is also some level of third harmonicvoltage present at the generator high voltageterminals. A somewhat predictable ratio of(V

3RD-GEN.HV.TERM)/(V

3RD-GEN.NEUTRAL) will exist under

all load conditions, though this ratio may changeif loading can induce changes in third harmonicvoltages. A ground fault at the generator neutralwill change this ratio, and this ratio change isanother means to detect a generator groundfault. Two difficulties with this method are:problems with developing means to accuratelysense low third harmonic voltages at the genera-tor high voltage terminals in the presence oflarge fundamental frequency voltages, andproblems with dealing with the changes in thirdharmonic ratio under some operating conditions.

If the 59N relay is only used for alarming, thedistribution transformer voltage ratio should beselected to limit the secondary voltage to themaximum continuous rating of the relay. If therelay is used for tripping, the secondary voltagecould be as high as the relay’s ten-secondvoltage rating. Tripping is recommended to min-imize iron damage for a winding fault as well asminimizing the possibility of a multi-phase fault.

Where wye-wye voltage transformers (VTs) areconnected to the machine terminals, the sec-ondary VT neutral should not be grounded inorder to avoid operation of 59N for a secondaryground fault. Instead, one of the phase leadsshould be grounded (i.e., "corner ground"),leaving the neutral to float. This connectioneliminates any voltage across the 59N relay for asecondary phase-ground fault. If the VT second-ary neutral is grounded, a phase-ground VT sec-ondary fault pulls little current, so the secondaryfuse sees little current and does not operate. Thefault appears to be a high impedance phase toground fault as seen by the generator neutralshift sensing relay (59N), leading to a generator

trip. Alternatively, assume that the VT corner(e.g., phase A) has been grounded. If phase B orC fault to ground, the fault will appear as aphase-phase fault, which will pull high secondarycurrents and will clear the secondary fuse rapidlyand prevent 59N operation. A neutral to groundfault will tend to operate the 59N, but this is alow likelihood event. An isolation VT is required ifthe generator VTs would otherwise be galvani-cally connected to a set of neutral-groundedVTs. Three wye VTs should be applied where aniso-phase bus (phase conductors separatelyenclosed) is used to protect against phase-phasefaults on the generator terminals.

The 59N relay in Fig. 4 is subject to operation fora ground fault on the wye side of any powertransformer connected to the generator. Thisvoltage is developed even though the generatorconnects to a delta winding because of thetransformer inter-winding capacitance. Thiscoupling is so small that its effect can ordinarilybe ignored; however, this is not the case with the59N application because of the very high ground-ing resistance. The 59N overvoltage elementtime delay allows the relay to override external-fault clearing.

The Basler BE1-GPS100, BE1-951, BE1-1051,and BE1-59N relays contain the required neutralovervoltage (59N), undervoltage (27-3N), andphase overvoltage (59P) units.

Fig. 4 shows a 51GN relay as a second meansof detecting a stator ground fault. The use of a51GN in addition to the 59N and 27-3N is readilyjustified, since the most likely fault is a statorground fault. An undetected stator ground faultwould be catastrophic, eventually resulting in amultiphase fault with high current flow, which per-sists until the field flux decays (e.g., for 1 to 4s).The CT shown in Fig. 4 could be replaced with aCT in the secondary of the distribution trans-former, allowing use of a CT with a lower voltagerating. However, the 51GN relay would then beinoperative if the distribution transformer primarybecomes shorted. The CT ratio for the second-ary-connected configuration should provide for arelay current about equal to the generator neutralcurrent (i.e., 5:5 CT). In either position, the relaypickup should be above the harmonic currentflow during normal operation. (Typically harmoniccurrent will be less than 1A but the relay may be

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set lower if the relay filters harmonic currentsand responds only to fundamental currents.)Assuming a maximum fault current of 8A primaryin the neutral and a relay set to pick up at 1Aprimary, 88% of the stator winding is covered.As with the 59N relay, the 51GN delay will allowit to override clearing of a high-side ground fault.An instantaneous overcurrent element can alsobe employed, set at about three times the time-overcurrent element pickup, although it may notcoordinate with primary vt fuses that are con-nected to the generator terminals.

Multiple generators, per Fig. 7, can be high-resistance grounded, but the 59N relays will notbe selective. A ground fault anywhere on thegeneration bus or on the individual generators willbe seen by all 59N relays, and the tendency willbe for all generators to trip. The 51N relay, whenconnected to a flux summation CT, will provideselective tripping if at least three generators arein service. In this case, the faulted generator51N relay will then see more current than theother 51N relays. The proper 51N will operatebefore the others because of the inverse charac-teristic of the relays. Use of the flux summationCT is limited to those cases where the CTwindow can accommodate the three cables.Fault currents are relatively low, so care must beexercised in selecting appropriate nominal relaycurrent level (e.g., 5A vs. 1A) and CT ratio. Forexample, with a 30A fault level and a 50 to 5ACT, a 1A nominal 51N with a pickup of 0.1Amight be used. With two generators, eachcontributing 10A to a terminal fault in a thirdgenerator, the faulted-generator 51N relay sees2*10/(50/5) = 2A. Then the relay protects downto (0.1/2)*100 = 5% from the neutral.

When feeder cables are connected to the gen-erator bus, the additional capacitance dictates amuch lower level of grounding resistance thanachieved with a unit-connected case. A lower re-sistance is required to minimize transient over-voltages during an arcing fault.

FIGURE 7. 59N RELAY OPERATION WITH MULTIPLEUNITS WILL NOT BE SELECTIVE; 51N RELAYS PRO-VIDE SELECTIVE PROTECTION IF AT LEAST THREEGENERATORS ARE IN SERVICE.

Ground differential (Fig. 8) is a good method tosense ground faults on low and medium imped-ance grounded units. It would more commonly beseen on generators that have the CTs requiredfor phase differential relaying. In Fig. 8, theprotective function is labeled 87N, but the BaslerBE1-CDS220 or the BE1-67N is applied. TheBE1-CDS220 approach is more applicable to lowand medium impedance grounded generatorswith ground faults as low as 50% of phase faultcurrent. The BE1-67N approach is more appli-cable to medium impedance generators with lowground fault current levels. The BE1-CDS220 islimited in sensitivity to ground faults in excess of10% of the phase CT tap setting, but the use ofthe auxiliary CT in the BE1-67N approach allowsfor amplification of the ground current in thephase CTs, yielding increased sensitivity.Whichever approach is used, an effort should bemade to select relay settings to trip for faults aslow as 10% of maximum ground fault currentlevels. During external phase faults, considerable87N operating current can occur when there isdissimilar saturation of the phase CTs due tohigh AC current or due to transient DC offseteffects, while the generator neutral current stillwill be zero, assuming balanced conductorimpedances to the fault. One method to compen-sate for transient CT saturation is to havesufficient delay in the relay to ride throughexternal high-current two-phase-ground faults.

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Fig. 10 shows an example of generator currentdecay for a 3 phase fault and a phase-phasefault. For a 3 phase fault, the fault currentdecays below the pickup level of the 51 relay inapproximately one second. If the time delay ofthe 51 can be selectively set to operate beforethe current drops to pickup, the relay will provide3 phase fault protection. The current does notdecay as fast for a phase-phase or a phase-ground fault and, thereby, allows the 51 relaymore time to trip before current drops belowpickup. Fig. 10 assumes no voltage regulatorboosting, although the excitation system re-sponse time is unlikely to provide significantfault current boosting in the first second of thefault. It also assumes no voltage regulatordropout due to loss of excitation power during thefault. If the generator is loaded prior to the fault,prefault load current and the associated higherexcitation levels will provide the fault with ahigher level of current than indicated by the Fig.10 curves. An estimate of the net fault current ofa pre-loaded generator is a superposition of loadcurrent and fault current without pre-loading. Forexample, assuming a pre-fault 1pu rated load at30 degree lag, at one second the 3 phase faultvalue would be 2.4 times rated, rather than 1.75times rated (1@30°+1.75@90°=2.4@69°). Underthese circumstances, the 51 relay has more timeto operate before current decays below pickup.

FIGURE 10. GENERATOR FAULT CURRENT DECAYEXAMPLE FOR 3 PHASE AND PHASE-PHASE FAULTSAT GENERATOR TERMINALS - WITH NO REGULATORBOOSTING OR DROPOUT DURING FAULT AND NOPREFAULT LOAD.

FIGURE 8. MEDIUM-LEVEL GROUNDING WITH 87NGROUND DIFFERENTIAL PROTECTION.

Phase-Fault Protection

Fig. 9 shows a simple means of detectingphase faults, but clearing is delayed, since the51 relay must be delayed to coordinate withexternal devices. Since the 51 relay operates forexternal faults, it is not generator zone selective.It will operate for abnormal external operatingconditions such as remote faults that are notproperly cleared by remote breakers. The 51pickup should be set at about 175% of ratedcurrent to override swings due to a slow-clearingexternal fault, the starting of a large motor, or there-acceleration current of a group of motors.Energization of a transformer may also subjectthe generator to higher than rated current flow.

FIGURE 9. PHASE-OVERCURRENT PROTECTION (51)MUST BE DELAYED TO COORDINATE WITHEXTERNAL RELAYS.

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Figure 9 shows the CTs on the neutral side ofthe generator. This location allows the relay tosense internal generator faults but does notsense fault current coming into the generatorfrom the external system. Placing the CT on thesystem side of the generator introduces aproblem of the relay not seeing a generatorinternal fault when the main breaker is open andwhen running the generator isolated from othergeneration or the utility. If an external sourcecontributes more current than does the genera-tor, using CTs on the generator terminals, ratherthan neutral-side CTs, will increase 51 relaysensitivity to internal faults due to higher currentcontribution from the external source; however,the generator is unprotected should a fault occurwith the breaker open or prior to synchronizing.

Voltage-restrained or voltage-controlled time-overcurrent relays (51VR, 51VC) may be used asshown in Fig. 11 to remove any concerns aboutability to operate before the generator currentdrops too low. The voltage feature allows therelays to be set below rated current. The BaslerBE1-951, BE1-1051, BE1-GPS100, andBE1-51/27R voltage restrained approach causesthe pickup to decrease with decreasing voltage.For example, the relay might be set for about175% of generator rated current with ratedvoltage applied; at 25% voltage the relay picksup at 25% of the relay setting (1.75*0.25=0.44times rated). The Basler BE1-951, BE1-GPS,and BE1-51/27C voltage controlled approachinhibits operation until the voltage drops below apreset voltage. It should be set to function belowabout 80% of rated voltage with a current pickupof about 50% of generator rated. Since thevoltage-controlled type has a fixed pickup, it canbe more readily coordinated with external relaysthan can the voltage-restrained type. Thevoltage-controlled type is recommended since itis easier to coordinate. However, the voltage-restrained type will be less susceptible tooperation on swings or motor starting conditionsthat depress the voltage below the voltage-controlled undervoltage unit dropout point.

FIGURE 11. VOLTAGE-RESTRAINED OR VOLTAGE-CONTROLLED TIME-OVERCURRENT PHASE FAULTPROTECTION.

Fig. 12 eliminates concerns about the decay rateof the generator current by using an instanta-neous overcurrent relay (50) on a flux summationCT, where the CT window can accommodatecable from both sides of the generator. The relaydoes not respond to generator load current nor toexternal fault conditions. The instantaneousovercurrent relay (50) acts as a phase differentialrelay (87) and provides high-speed sensitive pro-tection. This approach allows for high sensitivity.For instance, it would be feasible to sense faultcurrents as low as 1-5% of generator full loadcurrent. It is common to use 50/5 CTs and touse 1A nominal relaying. A low CT ratio intro-duces critical saturation concerns (e.g., a 5,000Aprimary fault may try to drive a 500A secondaryon a 50/5 CT). The CT burden must be low toprevent saturation of the CT during internal faultsthat may tend to highly overdrive the CT second-ary. The 51 relay shown in Fig. 12 is applied for

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back-up of external faults and as back-up for the50 relay.

FIGURE 12. FLUX SUMMATION RELAY (50) PROVIDESSENSITIVE, HIGH-SPEED, SELECTIVE DIFFERENTIALPROTECTION (87).

The 87G relay in Fig. 13 is connected to respondto phase differential currents from two sets ofCTs. In some applications it may include a unitdifferential that includes the step-up transformer.In contrast to a 51 or 51V relay that monitorsonly one CT, the 87G relay responds to both thegenerator and external contributions to a genera-tor fault. Because of the differential connection,the relay is immune, except for transient CTsaturation effects, to operation due to generatorload flow or external faults and, therefore, canprovide sensitive, high speed protection. Whilethe CTs must be of the same ratio, they do notneed to be matched in performance, but theminimum pickup of the Basler BE1-CDS220 orBE1-87G must be raised as the degree ofperformance mismatch increases. (See the BE1-CDS220 and BE1-87G instruction manuals forspecifics on settings.) A minimum pickup of 0.1times tap (CDS220) or 0.4A (87G) is representa-tive of a recommended setting for a moderatemismatch in CT quality and burden. Fig. 13 alsoshows 51V relays to back up the 87G andexternal relays and breakers.

FIGURE 13. 87G PROVIDES SENSITIVE, HIGH-SPEEDCOVERAGE; 51V PROVIDES BACK-UP FOR 87G ANDFOR EXTERNAL RELAYS. 87G MAY WRAP STEP UPTRANSFORMER (UNIT DIFFERENTIAL).

Another means to detect external faults is withimpedance relaying. Impedance relaying dividescurrent by voltage on a complex number plane(Z = V/I using phasor math) (Figs. 14, 15). Suchrelaying is inherently faster than time-overcurrentrelaying. In the most common format of imped-ance relaying, the tripping zone is the areacovered by a "mho" circle on the R-X plane thathas a diameter from the origin (the CT, VTlocation) to some remote set point on the R-Xplane. If a fault impedance falls within the zone,the relay trips. Multiple zones may be used, withdelays on all zones as appropriate for coordinat-ing with line relays. Impedance relaying is highlydirectional. In Fig. 14, however, because the CTis on the neutral rather than at the VT, the relaywill see faults both in the generator and in theremote system.

FIGURE 14. IMPEDANCE RELAY, LOOKING FORGENERATOR AND REMOTE LINE FAULTS.

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FIGURE 15. IMPEDANCE RELAY, LOOKING FORREMOTE LINE FAULTS.

Reverse Power Protection

The reverse-power relay (32) in Fig. 16 sensesreal power flow into the generator, which willoccur if the generator loses its prime-moverinput. Since the generator is not faulted, CTs oneither side of the generator would provide thesame measured current.

FIGURE 16. ANTI-MOTORING (32), LOSS-OF-FIELD(40), PROTECTION.

In a steam-turbine, the low pressure blades willoverheat with the lack of steam flow. Diesel andgas-turbine units draw large amounts of motoringpower, with possible mechanical problems. In thecase of diesels, the hazard of a fire and/orexplosion may occur due to unburnt fuel. There-fore, anti-motoring protection is recommendedwhenever the unit may be connected to a sourceof motoring power. Where a non-electrical type ofprotection is in use, as may be the case with asteam turbine unit, the 32 relay provides ameans of supervising this condition to preventopening the generator breaker before the primemover has shut down. Time delay should be setfor about 5-30 seconds, providing enough timefor the controls to pick up load upon synchroniz-

ing when the generator is initially slower than thesystem.

Since motoring can occur during a largereactive-power flow, the real power componentneeds to be measured at low power factors. TheBE1-32R measures real power down to 0.1 pf.The BE1-951, BE1-1051, and BE1-GPS measurereal power down to below 0.01 pf, depending oncurrent magnitude.

Fig. 17 shows the use of two reverse-powerrelays: 32-1 and 32-2. The 32-1 relay supervisesthe generator tripping of devices that can waituntil the unit begins to motor. Overspeeding onlarge steam-turbine units can be prevented bydelaying main and field breaker tripping untilmotoring occurs for non-electrical and selectedelectrical conditions (e.g., loss-of-field andovertemperature). Relay 32-1 should be delayedmaybe 3 seconds, while relay 32-2 should bedelayed by maybe 20 seconds. Time delaywould be based on generator response duringgenerator power swings. Relay 32-2 trips directlyfor cases of motoring that were not initiated bylockout relay 86NE — e.g., governor controlmalfunction.

FIGURE 17. REVERSE-POWER RELAY 32-1 PREVENTSLOAD REJECTION BEFORE PRIME MOVERSHUTDOWN FOR SELECTED TRIPS; RELAY 32-2OPERATES IF MOTORING IS NOT ACCOMPANIED BYAN 86NE OPERATION.

Loss-of-Field Protection

Loss of excitation can, to some extent, besensed within the excitation system itself by

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monitoring for loss of field voltage or current. Forgenerators that are paralleled to a power system,the preferred method is to monitor for loss offield at the generator terminals. When a genera-tor loses excitation power, it appears to thesystem as an inductive load, and the machinebegins to absorb a large amount of VARs. Lossof field may be detected by monitoring for VARflow or apparent impedance at the generatorterminals.

The power diagram (P-Q plane) of Fig. 18 showsthe Basler BE1-GPS100 and BE1-40Q character-istic with a representative setting, a representa-tive generator thermal capability curve, and anexample of the trajectory following a loss ofexcitation. The first quadrant of the diagramapplies for lagging power factor operation(generator supplies VARs). The trajectory startsat point A and moves into the leading powerfactor zone (4th quadrant) and can readilyexceed the thermal capability of the unit. A tripdelay of about 0.2-0.3 seconds is recommendedto prevent unwanted operation due to othertransient conditions. A second high speed tripzone might be included for severeunderexcitation conditions.

FIGURE 18. FOR LOSS OF FIELD THE POWERTRAJECTORY MOVES FROM POINT A INTO THEFOURTH QUADRANT.

When impedance relaying is used to sense lossof excitation, the trip zone typically is marked bya mho circle centered about the X axis, offsetfrom the R axis by X'd/2. Two zones sometimesare used: a high speed zone and a time delayedzone.

FIG. 19. LOSS OF EXCITATION USING IMPEDANCERELAY.

With complete loss of excitation, the unit willeventually operate as an induction generator witha positive slip. Because the unit is running abovesynchronous speed, excessive currents can flowin the rotor, resulting in overheating of elementsnot designed for such conditions. This heatingcannot be detected by thermal relay 49, which isused to detect stator overloads.

Rotor thermal capability can also be exceeded fora partial reduction in excitation due to an operatorerror or regulator malfunction. If a unit is initiallygenerating reactive power and then draws reactivepower upon loss of excitation, the reactive swingscan significantly depress the voltage. In addition,the voltage will oscillate and adversely impactsensitive loads. If the unit is large compared tothe external reactive sources, system instabilitycan result.

Thermal Protection

Fig. 20 shows the Basler MPS200, BE3-49R, orBE1-49 relay connected to a resistance-tempera-ture detector, embedded in a stator slot. Relaymodels are available for either copper or platinumRTDs. The relay provides a constant-currentsource to produce a voltage across the RTD andincludes the means to measure that voltage(proportional to temperature) using separate leads.The relays have trip and alarm set points, and theMPS200 can provide readout of present tempera-ture.

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12

FIGURE 20. STATOR TEMPERATURE PROTECTION.

Loss of VT Detection

Two methods in common use to detect loss ofVTs are voltage balance between two VTs andvoltage-current comparison logic. Fig. 21 showsthe use of two sets of VTs on the generatorterminals, with the 60FL (Basler BE1-60) com-paring the output of the two VTs. One setsupplies the voltage regulator, the other, therelays. If the potential decreases or is lost fromVT No. 1, the BE1-60 disables the voltageregulator; if source No. 2 fails, the BE1-60blocks relay tripping of the 21, 27, 59N, and 47.In some applications 25, 32, and 40 elementsare also blocked. Overexcitation relay (24),phase overvoltage (59), and frequency relaying(81), do not need to be blocked, since loss ofpotential leads toward non-operation of thesefunctions.

FIGURE 21. VARIOUS VOLTAGE PROTECTIONELEMENTS. VOLTAGE-BALANCE RELAY (60)DETECTS POTENTIAL SUPPLY FAILURE.

A second means of detecting fuse loss is bycomparing voltage and current (Fig. 22). In asingle phase or two phase fuse loss, voltageimbalance exists without the correspondingcurrent imbalance that would exist during a fault.In a three phase fuse loss, complete voltageloss occurs without the corresponding threephase current flow that would occur during afault. To prevent a 60FL from being declaredduring loss of station power, it may be necessaryto allow a 3 phase 60F to be declared only whensome low level of load current exists.

FIGURE 22. LOSS OF FUSE DETECTION, ALTERNATEMETHOD.

Overexcitation and Over/Under VoltageProtection

Overexcitation can occur due to higher thanrated voltage, or rated or lower voltage at lessthan rated frequency. For a given flux level, thevoltage output of a machine will be proportionalto frequency. Since maximum flux level isdesigned for normal frequency and voltage, whena machine is at reduced speed, maximumvoltage is proportionately reduced. A volts/hertzrelay (24) responds to excitation level as itaffects thermal stress to the generator (and toany transformer tied to that generator). IEEEC50.13 specifies that a generator should continu-ously withstand 105% of rated excitation at fullload.

With the unit off line, and with voltage-regulatorcontrol at reduced frequency, the generator canbe overexcited if the regulator does not includean overexcitation limiter. Overexcitation can alsooccur, particularly with the unit off line, if theregulator is out of service or defective. If voltage-balance supervision (60) is not provided and afuse blows on the regulator ac potential input, theregulator would cause overexcitation. Loss of acpotential may also fool the operator into develop-ing excessive excitation. The 24 relay can only

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protect for overexcitation resulting from anerroneous voltage indication if the 24 relay isconnected to an ac potential source differentthan that used for the regulator.

Fig. 23 shows the relation among the BaslerBE1-GPS100, BE1-951, BE1051, and BE1-24relay inverse squared characteristics and anexample of a generator and transformer with-stand capability. The generator and transformermanufacturers should supply the specificcapabilities of these units.

FIGURE 23. COMBINED GENERATOR/TRANSFORMEROVEREXCITATION PROTECTION USING BOTH THEINVERSE SQUARED TRIPPING. EQUIPMENTWITHSTAND CURVES ARE EXAMPLES ONLY.

Phase over (59) and under (27) voltage relayingalso acts as a backup for excitation systemproblems. Undervoltage relaying also acts asfault detection relaying, because faults tend todepress voltage.

Off-Frequency Operation

Diesel engines can be safely operated off normalfrequency, and minimal protection is required.Turbine controls generally provide protection foroff frequency conditions, but relaying should beprovided to protect the turbine and generatorduring control system failure. Frequency relays

are frequently applied with steam-turbine units,particularly to minimize turbine blade fatiguing.IEEE C37.106, Ref. 3 specifically addressesabnormal frequency operation and shows typicalfrequency operating limits specified by variousgenerator manufacturers. The simplest relayapplication would be a single underfrequencystage, but a multiple stage and multiple set pointarrangement may be advantageous. Each setpoint may be set to recognize either over-frequency or underfrequency. Multiple frequencyset points are available in the BE1-81O/U, BE1-GPS100, BE1-951, and BE1-1051.

Another common need for frequency relaying isthe detection of generation that has becomeisolated from the larger utility system grid. Whena generator is connected to the utility, generatorfrequency is held tightly to system frequency.Upon islanding, the generator frequency variesconsiderably as the governor works to adjustgenerator power output to local load. If thegenerator frequency varies from nominal,islanding is declared and either the generator istripped or the point of common coupling with theutility is opened.

Inadvertent Energization Protection

Inadvertent energization can result from abreaker interrupter flashover or a breaker closeinitiation while the unit is at standstill or at lowspeed. The rapid acceleration can do extensivedamage, particularly if the generator is notpromptly de-energized. While relays applied forother purposes may eventually respond, they arenot generally considered dependable for respond-ing to such an energization.

Figs. 24 and 25 show two methods of detectingthe energization of a machine at standstill or at aspeed significantly lower than rated. This couldbe caused by single-phase energization due tobreaker-interrupter flashover or 3 phaseenergization due to breaker closure. The unit,without excitation, will accelerate as aninduction motor with excessive current flow inthe rotor. Both Fig. 24 and 25 schemes willfunction properly with the VT fuses at thegenerator terminal removed. With the generatoroff line, safety requirements may dictate theremoval of these VT fuses. In the case of Fig.

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14

24, the overcurrent protection is enabled byundervoltage units and works as long as 60FLlogic does not block the trip path. In Fig. 25 thepotential is taken from bus VTs, rather than unitVTs, so the scheme will function even if the VTfuses were removed during unit maintenance.

In Fig. 24 the terminal voltage will be zero priorto energization, so the 27 and 81U relay contactswill be closed to energize the timer (62). Theinstantaneous overcurrent relay (50) trip circuit isestablished after timer 62 operates. Uponinadvertent generator energization, the under-voltage and underfrequency relay contacts mayopen up due to the sudden application of nominalvoltage and frequency, but the delayed dropoutof 62 allows relay 50 to initiate tripping. The useof a 60FL function or two 27 relays on separateVT circuits avoids tripping for a VT fuse failure.Alternatively, a fuse loss detection or voltage-balance relay (60FL) could be used in conjunc-tion with a single 27 relay to block tripping.

FIGURE 24. INADVERTENT ENERGIZATIONPROTECTION USING INSTANTANEOUSOVERCURRENT RELAY (50).

In Fig. 24 the 5 sec pickup delay on timer 62prevents tripping for external disturbances thatallow dropout of the 27 relays. The 27 relaysshould be set at 85% voltage (below the operat-

ing level under emergency conditions). The Fig.25 scheme could be employed where protectionindependent of the plant is desired. In this casethe 67 relays would be placed in the switchyardrather than in the control room. While directionalovercurrent relay (67) should be delayed to ridethrough synchronizing surges, it can still providefast tripping for generator faults, since the 67relays need not be coordinated with externalprotection. Fig. 25 shows the operating range forphase A current (Ia) with respect to phase B to Cvoltage (V

BC). This range is fixed by the 60

degree characteristic angle and the ±45 degreelimits set on the operating zone.

FIGURE 25. BE1-67 DIRECTIONAL OVERCURRENTRELAYS DETECT INADVERTENT ENERGIZATION.

Negative Sequence Protection

Negative sequence stator currents, caused byfault or load unbalance, induce double-frequency currents into the rotor that mayeventually overheat elements not designed to besubjected to such currents. Series unbalances,such as untransposed transmission lines,produce some negative-sequence current (I

2)

flow. The most serious series unbalance is anopen phase, such as an open breaker pole. ANSIC50.13-1977 specifies a continuous I

2 withstand

of 5 to 10% of rated current, depending upon thesize and design of the generator. These valuescan be exceeded with an open phase on aheavily-loaded generator. The BaslerBE1-GPS100, BE1-951, BE1-1051, or BE1-46Nrelay protects against this condition, providingnegative sequence inverse-time protectionshaped to match the short-time withstandcapability of the generator should a protracted

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fault occur. This is an unlikely event, becauseother fault sensing relaying tends to clear faultsfaster, even if primary protection fails.

Fig. 26 shows the 46 relay connection. CTs oneither side of the generator can be used, sincethe relay protects for events external to thegenerator. The Basler BE1-46N alarm unit willalert the operator to the existence of a dangerouscondition.

FIGURE 26. NEGATIVE-SEQUENCE CURRENT RELAY(46) PROTECTS AGAINST ROTOR OVERHEATINGDUE TO A SERIES UNBALANCE OR PROTRACTEDEXTERNAL FAULT. NEGATIVE SEQUENCE VOLTAGERELAY (47) (LESS COMMONLY APPLIED) ALSORESPONDS.

Negative sequence voltage (47) protection, whilenot as commonly used, is an available means tosense system imbalance as well as, in somesituations, a misconnection of the generator to asystem to which it is being paralleled.

Out of Step Protection

When a generator pulls out of synchronism withthe system, current will rise relatively slowlycompared to the instantaneous change in currentassociated with a fault. The out-of-step relayuses impedance techniques to sense thiscondition. The relay will see an apparent loadimpedance swing as impedance moves fromZone 1 to Zone 2 (Fig. 27). The time it takes forthe load impedance to traverse from Zone 1 toZone 2 is used to decide if an out of step

FIGURE 27. OUT OF STEP RELAYING (78)

condition is occurring. A moving impedance isidentified as a swing rather than a fault, soappropriate fault detection relaying may beblocked.

Selective Tripping and Sequential Tripping

It is a practice at some generators to selectivelytrip the prime mover, the field, and the generatorbreaker, depending on the type of fault that isdetected. For instance, if the generator isprotected by a 51V and an 87G, and only the51V trips, it may be assumed that the fault isexternal to the generator and, hence, the 51Vonly trips the generator breaker and rapidly pullsback the excitation governor and prime moverset points. However, if there is no 87G, the 51Vtrips the entire unit. Associated with this conceptis sequential tripping used for orderly shutdown.To prevent overspeeding a generator duringshutdown, it is sometimes the practice first totrip the prime mover and trip the main breakerand field only after a reverse power relay verifiesthe prime mover has stopped providing torque tothe generator.

Synchronism Check and Auto Synchronizing

Before connecting a generator to the powersystem, it is important that the generator andsystem frequency, voltage magnitude, andphase angle be in alignment, referred to assynchronism checking (25). Typical parametersare shown in Fig. 28. Typical applications call forno more than 6RPM error, 2% voltage magnitudedifference, and no more than 10° phase angleerror before closing the breaker. The BaslerBE1-951, BE1-GPS, and BE1-25 all can performthe sync check function.

Auto synchronizing (25A) refers to a system toautomatically bring a generator into synchronismwith the power system. It involves sendingvoltage and speed raise and lower commands tothe voltage regulator and prime mover governor.When the system is in synchronism, theautosync relay is sometimes designed to send aclose command in advance of the zero phaseangle error point to compensate for breaker closedelays. The 25 relay, which usually is set tosupervise the 25A and manual sync function,usually is set less tight than the 25A so as tocoordinate with the actions of the 25A.

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FIGURE 28. SYNCHRONIZING PARAMETERS: SLIP,ADVANCE ANGLE, AND BREAKER CLOSING TIME.

Integrated Application Examples

Figs. 29 through 33 show examples ofprotection packages.

Fig. 29 represents bare-minimum protection, withonly overcurrent protection. Generators with suchminimum protection are uncommon in an era ofmicroprocessor-based multifunction relays. Suchprotection likely would be seen only on verysmall (<50kVA) generators used for standbypower that is never paralleled with the utility gridor other generators. It may appear to be adisadvantage to use CTs on the neutral side asshown, since the relays may operate faster withCTs on the terminal side. The increase in speedwould be the result of a larger current contribu-tion from external sources. However, if the CTsare located on the terminal side of the generator,there will be no protection prior to putting themachine on line. This is not recommended,because a generator with an internal faultcould be destroyed when the field is applied.

FIGURE 29. EXAMPLE OF BARE-MINIMUMPROTECTION (LOW-IMPEDANCE GROUNDING).

Fig. 30 shows the suggested minimum protectionwith low-resistance grounding. It includesdifferential protection, which provides fast,selective response, but differential protectionbecomes less common as generator sizedecreases below 2MVA, on 480V units andbelow, and on generators that are never paral-leled with other generation. The differential relayresponds to fault contributions from both thegenerator and the external system. While thedifferential relay is fast, the slow decay of thegenerator field will cause the generator tocontinue feeding current into a fault. However,fast relay operation will interrupt the external-source contribution, which may be greater thanthe generator contribution. Fast disconnectionfrom the external source allows prompt restora-tion of normal voltage to loads and may reducedamage and cost of repairs.

FIGURE 30. SUGGESTED MINIMUM PROTECTIONEXAMPLE (LOW-IMPEDANCE GROUNDING).

The differential relay (87G) may protect forground faults, depending upon the groundingimpedance. The 51N relay in Fig. 30 providesback-up protection for the 87G or will be theprimary protection if the differential relay (87G) is

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not sufficiently sensitive to the ground currentlevel.

The 51V voltage-controlled or voltage-restrainedtime overcurrent relay in Fig. 30 is shown on theCT on the high voltage/system side of thegenerator. This allows the relay to see systemcontributions to a generator fault. It providesback-up for the differential relay (87G) and forexternal relays and breakers. Since it is monitor-ing CTs on the system side of the generator, itwill not provide any back-up coverage prior tohaving the unit on line. If there is no externalsource, no 87G, or if it is desired that the 51Vprovide generator protection while the breaker isopen, connect the 51V to the neutral-side CTs.

Fig. 30 shows three relays sharing the same CTswith a differential relay. This is practical withsolid state and numeric relays, because their lowburden will not significantly degrade the quality ofdifferential relay protection. The common CT isnot a likely point of failure of all connectedrelaying. A CT wiring error or CT short is unlikelyto disable both the 87G and 51V relays. Rather,a shorted CT or defective connection will unbal-ance the differential circuit and cause the 87G totrip. Independent CTs could be used to provideimproved back-up protection, although thisseems to be a minimal advantage here. How-ever, a separate CT is used for the 51N relaythat provides protection for the most likely typeof fault.

The reverse power relay (32) in Fig. 30 protectsthe prime mover against forces from a motoredgenerator and could provide important protectionfor the external system if the motoring powersignificantly reduces voltage or overloads equip-ment. Likewise, the loss-of-field relay (40) hasdual protection benefits—against rotor overheat-ing and against depressed system voltage due toexcessive generator reactive absorption. Ther-mal relay (49) protects against stator overheatingdue to protracted heavy reactive power demandsand loss of generator cooling. Even if theexcitation system is equipped with a maximumexcitation limiter, a failure of the voltage regula-tor or a faulty manual control could causeexcessive reactive power output. Frequencyrelaying (81O/U) protects the generator from offnominal frequency operation and senses genera-

tor islanding. The under and overvoltage function(27/59) detects excitation system problems andsome protracted fault conditions.

Fig. 31 shows minimum basic protection for amedium impedance grounded generator. It differsfrom Fig. 30 only in the use of a ground differen-tial relay (87N, part of CDS220 or BE1-67N). Thisprotection provides faster clearing of groundfaults where the grounding impedance is too highto sense ground faults with the phase differentialrelay (87G). The relay compares ground currentseen at the generator high voltage terminals toground current at the generator neutral. The 51Nrelay provides backup for the ground differential(87N) and for external faults, using the currentpolarizing mode. The polarizing winding mea-sures the neutral current.

FIGURE 31. SUGGESTED MINIMUM PROTECTIONEXAMPLE (MEDIUM-IMPEDANCE GROUNDED).

Fig. 32 shows minimum basic protection for ahigh impedance grounded generator. It differsfrom Fig. 30 only in the ground relay protectionand the method of grounding. The voltage units59N/27-3N provide the only ground protection,since the ground fault current is too small forphase differential relay (87G) operation. The 59Nrelay will not be selective if other generators arein parallel, since all the 59N relays will see aground fault and nominally operate at the sametime. If three Phase-Ground Y-Y VTs wereapplied in Fig. 32, the 27 and 59 could provideadditional ground fault protection, and an addi-tional generator terminal 59N ground shift relaycould be applied.

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18

FIGURE 32. SUGGESTED MINIMUM PROTECTIONEXAMPLE (HIGH-RESISTANCE GROUNDING).

The Basler BE1-951, BE1-1051, BE1-GPS100,and BE1-59N include a third harmonic under-voltage function (27-3N), that provides supervi-sion of the grounding system, protects for faultsnear the generator neutral, and detects a shortedor open connection in the generator groundconnection or in the distribution transformersecondary circuit.

FIGURE 33. EXTENDED PROTECTION EXAMPLE (HIGH-RESISTANCE GROUNDING).

Fig. 33 shows the application of additional relaysfor extended protection: overexcitation relay (24),negative sequence overcurrent and overvoltagerelay (46 and 47), ground-overcurrent relay(51GN), voltage-balance relay (60), field-groundrelay (64F), frequency relay (81) and the 27/50/62 relay combination for inadvertent energizationprotection. Relay 51GN provides a secondmeans of detecting stator ground faults or faultsin the generator connections or faults in the deltatransformer windings. Differential relay 87T andsudden-pressure relay 63 protect the unit step-uptransformer. Relay 51N provides backup for ex-ternal ground faults and for faults in the high-voltage transformer windings and leads. Thisrelay may also respond to an open phase con-dition or a breaker-interrupter flashover that ener-gizes the generator. The 51N relay will be veryslow for the flashover case, since it must be setto coordinate with external relays and is a last-resort backup for external faults.

Figure 33 shows wye-connected VTs, appropri-ate with an isolated-phase bus.

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Application of Numerical ProgrammableRelays

Numerical programmable relays contain many ofthe functions discussed in this guideline in asingle package. Figures 34 through 37 show theBE1-GPS100 and BE1-CDS220 applied togenerator protection. Due to logic complexity, fulldetails are not shown. Details of these applica-tions may be found in the respective instructionmanual.

FIGURE 34. BE1-GPS100 APPLIED TO LOW-IMPEDANCE GROUNDED GENERATOR(LOW-Z-W25 PREPROGRAMMED LOGIC; SEE INSTRUCTION MANUAL FOR LOGIC DETAILS).

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20

FIGURE 35. BE1-GPS100 APPLIED TO HIGH-IMPEDANCE GROUNDED GENERATOR(HI_Z_GND PREPROGRAMMED LOGIC; SEE INSTRUCTION MANUAL FOR LOGIC DETAILS).

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FIGURE 36. BE1-CDS220 APPLIED TO GENERATOR FOR 87 PHASE, 87 NEUTRAL, AND 51 PHASE, NEUTRAL,GROUND, AND NEGATIVE SEQUENCE.

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FIGURE 37. INTERCONNECTION OF BE1-GPS100 AND BE1-CDS220, AND SHOWING SOME ALTERNATE USES OFBE1-GPS100 IG INPUT.

Bibliography

1. IEEE C37.101, IEEE Guide forGenerator Ground Protection

2. IEEE C37.102, IEEE Guide for ACGenerator Protection

3. IEEE C37.106, IEEE Guide for AbnormalFrequency Protection for GeneratingPlants

4. J. Lewis Blackburn, “ProtectiveRelaying: Principles and Applications”,2nd Edition, Marcel Dekker, Inc., 1998.

5. S. Horowitz and A. Phadke, “PowerSystem Relaying”, John Wiley & Sons,Inc., 1992.

Typical Settings and Relays

Table 1 lists the applicable relays discussedherein. The right column provides typical settingsfor use as a starting point in the setting determi-nation procedure. The proper settings are heavilyinfluenced by the specifics of each application.Typical settings are also used as an aid inselecting the relay range where a choice isavailable.

Table 2 lists typical Basler relays applicable togenerator protection. There are 3 classes ofrelays presented in Table 2. The classical singlefunction "utility grade" (i.e., tested to IEEEC37.90 standards) BE1-XXX relays are listed,followed by the single function "industrial grade"BE3-XXX relays. (Except the multifunctionBE3-GPR is tested to full IEEE C37.90 stan-dards.) Finally, the multifunction utility gradenumerical relays are listed. Additional informationon each relay is available on the Basler Electricweb site, www.basler.com.

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Table 1 - Typical Settings

IEEE No. Fig. Function Typical Settings and Remarks

24 21, Overexcitation PU: 1.1*VNOM/60; TD: 0.3; reset TD: 523 alarm P.U.: 1.18*VNOM/60

alarm delay: 2.5s

25 21, Synchronism Check Max Slip: 6RPM; Max phase angle error: 10°28 Max VMAG error: 2.5% VNOM

32 16, Reverse Power PU: turbine 1% of rated; 15 s17 (one stage) PU: Reciprocating engine: 10% of rated; 5 s

32-1 17 Reverse Power PU: same as 32; 3 sNonelectrical TripSupervision

40 16, Loss-of-field (VAR Flow Level 1 PU: 60% VA rating; Delay: 0.2s;18 Approach) Level 2 PU: 100% VA rating: 0.1s

46 26 Negative Sequence I2 PU: 10% Irated; K=10Overcurrent

49 20 Stator Temperature (RTD) Lower: 95°C; upper: 105°C

50/87 12 Differential via flux PU:10% INOM or less if 1A relay may be usedsummation CTs

50/27 IE 24 Inadvertent Energization 50: 0.5A (10% INOM)Overcurrent with 27, 81 27: 85% VNOM (81: Similar)Supervision

51N 3 Stator Ground Over- PU: 10% INOM; curve: EI; TD: 4. Inst: none. Higher PUcurrent (Low, Med Z Gnd, required to coordinate with load.Phase CT Residual) No higher than 25% INOM.

50/51N 2 Stator Ground Over- P.U.: 10% INOM; Curve EI, TD4; Inst 100% INOM. Higher PUcurrent (Low, Med Z Gnd, if required to coordinate with load. No higher thanNeutral CT or Flux 25% INOM.Summation CT)

51GN, 4, Stator Ground Over- PU: 10% IFAULTat HV Term.; Curve: VI; TD:4.51N 7 current (High Z Gnd)

51VC 11 Voltage Controlled PU: 50% INOM; Curve: VI; TD: 4.Overcurrent Control voltage: 80%VNOM.

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Table 1 - Typical Settings

IEEE No. Fig. Function Typical Settings and Remarks

51VR 11 Voltage Restrained PU: 175% INOM; Curve: VI; TD: 4.Overcurrent Zero Restraint Voltage: 100% VNOM L-L

59N, 4 Ground Overvoltage 59N: 5% VNEU during HV terminal fault;27-3N, 27-3N: 25% V3rd during normal operation; TD: 10s59P 59P: 80% VNOM

67IE 25 Directional O/C for PU: 75-100% INOM GEN; Definite Time (0.1-0.25 sec.)Inadvertent Energization Inst: 200% INOM GEN

81 21 Over/under frequency Generator protection: 57, 62Hz, 0.5s;Island detection: 59, 61Hz, 0.1s

87G 13 Generator Phase BE1-87G: 0.4A;Differential BE1-CDS220: Min P.U.: 0.1 * Tap;

Tap: INOM; Slope: 15%

87N 8 Generator Ground BE1-CDS220: Min P.U.: 0.1 times tap; Slope 15%;Differential Time delay: 0.1s; choose low tap

BE1-67N: current polarization; time: 0.25A; Curve: VI;TD: 2; Instantaneous: disconnect

87UD 13 Unit Differential BE1-87T or CDS220 Min PU:0.35*Tap;Tap: INOM; Slope 30%

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IEEE Single Function Single Function Multifunction (3) Number BE1- BE3-

24 24 X X X

25 25 25 ◊ ◊ ◊ ◊ ◊

25A 25A 25A

27 27 27 X X X X X X

27/50IE 50/51B, 50, 27 27, 51 X X X

27/59 27/59 27/59 X X X X X

32 32R, 32O/U 32 X X X ◊ ◊ X

40 40Q X ◊ ◊

46 46N X X X X X X

47 47N 47N X X X ◊ ◊ X

49 49 49R, 49TH X

49/51

50/51G (1) 50/51B, 51 51 X ◊ ◊ ◊ ◊ 50T X

50/51N (2) X X X X

50/87 50/51B, 50 51 X X X X X

51P 50/51B, 51 51 X X X X X

51VC 51/27C X X X

51VR 51/27R X X X X

59P 59 59 X X X X X X

59N, 27-3N, 59N ◊ ◊ ◊59P (4) (4) (4)

60FL 60 X X X

67IE 67 X X

81 81O/U 81O/U X X X X X

87G 87G X

87N 67N ◊ ◊

87UD 87T X

(1) 50/51G - Indicates a relay that monitors a ground CT source.(2) 50/51N - Indicates a relay that calculates residual (3I0) from phase currents.(3) Not all functions in relays are shown. Relays also may include multiple set points and setting groups.(4) BE1-951, -1051, and -GPS have standard capability to calculate 3V0 from wye-connected phase CTs. VAUX input is optional.

BE

1-85

1

BE

1-95

1

BE

1-10

51

BE

1-G

PS

BE

1-C

DS

BE

3-G

PR

50T

N

BE

3-G

PR

51

Ph

MP

S20

0

X=Included ◊=Optional

Table 2 - Basler Electric Relay Application Matrix

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Revision C.0 June 2001

Basler Electric HeadquartersRoute 143, Box 269,Highland Illinois USA 62249Phone +1 618.654.2341Fax +1 618.654.2351

Basler Electric InternationalP.A.E. Les Pins, 67319 Wasselonne CedexFRANCEPhone +33 3.88.87.1010Fax +33 3.88.87.0808

If you have any questions or needadditional information, please contact

Basler Electric Company.Our web site is located at:

http://www.basler.come-mail: [email protected]