17-Generator and Generator Transf Prot

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    Introduction 17.1

    Generator earthing 17.2

    Stator winding faults 17.3

    Stator winding protection 17.4

    Differential protection of direct-connected generators 17.5

    Differential protection of generatortransformer units 17.6

    Overcurrent protection 17.7

    Stator earth fault protection 17.8

    Overvoltage protection 17.9

    Undervoltage protection 17.10

    Low forward power/reversepower protection 17.11

    Unbalanced loading 17.12

    Protection against inadvertent energisation 17.13

    Under/Overfrequency/Overfluxing protection 17.14

    Rotor faults 17.15

    Loss of excitation protection 17.16

    Pole slipping protection 17.17

    Overheating 17.18Mechanical faults 17.19

    Complete generator protection schemes 17.20

    Embedded generation 17.21

    Examples of generator protection settings 17.22

    1 7 G e n e r a t o r a n d G e n e r a t o r T r a n s f o r m e r P r o t e c t i o n

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    17.1 INTRODUCTION

    The core of an electric power system is the generation.With the exception of emerging fuel cell and solar-celltechnology for power systems, the conversion of thefundamental energy into its electrical equivalentnormally requires a 'prime mover' to develop mechanicalpower as an intermediate stage.

    The nature of this machine depends upon the source of energy and in turn this has some bearing on the designof the generator. Generators based on steam, gas, wateror wind turbines, and reciprocating combustion enginesare all in use. Electrical ratings extend from a fewhundred kVA (or even less) for reciprocating engine andrenewable energy sets, up to steam turbine setsexceeding 1200MVA.

    Small and medium sized sets may be directly connectedto a power distribution system. A larger set may beassociated with an individual transformer, throughwhich it is coupled to the EHV primary transmissionsystem.

    Switchgear may or may not be provided between thegenerator and transformer. In some cases, operationaland economic advantages can be attained by providinga generator circuit breaker in addition to a high voltagecircuit breaker, but special demands will be placed onthe generator circuit breaker for interruption of generator fault current waveforms that do not have an

    early zero crossing.A unit transformer may be tapped off theinterconnection between generator and transformer forthe supply of power to auxiliary plant, as shown inFigure 17.1. The unit transformer could be of the orderof 10% of the unit rating for a large fossil-fuelled steamset with additional flue-gas desulphurisation plant, butit may only be of the order of 1% of unit rating for ahydro set.

    17 Generator and

    Generator-Transformer Protection

    N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e 2 8 1

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    Industrial or commercial plants with a requirement forsteam/hot water now often include generating plantutilising or producing steam to improve overalleconomics, as a Combined Heat and Power (CHP)scheme. The plant will typically have a connection to thepublic Utility distribution system, and such generation is

    referred to as embedded generation. The generatingplant may be capable of export of surplus power, orsimply reduce the import of power from the Utility. Thisis shown in Figure 17.2.

    A modern generating unit is a complex systemcomprising the generator stator winding, associatedtransformer and unit transformer (if present), the rotorwith its field winding and excitation system, and theprime mover with its associated auxiliaries. Faults of many kinds can occur within this system for whichdiverse forms of electrical and mechanical protection are

    required. The amount of protection applied will begoverned by economic considerations, taking intoaccount the value of the machine, and the value of itsoutput to the plant owner.

    The following problems require consideration from thepoint of view of applying protection:

    a. stator electrical faultsb. overload

    c. overvoltage

    d. unbalanced loading

    e. overfluxing

    f. inadvertent energisation

    e. rotor electrical faults

    f. loss of excitation

    g. loss of synchronism

    h. failure of prime mover

    j. lubrication oil failure

    l. overspeeding

    m. rotor distortion

    n. difference in expansion between rotating andstationary parts

    o. excessive vibration

    p. core lamination faults

    17.2 GENERATOR EARTHING

    The neutral point of a generator is usually earthed tofacilitate protection of the stator winding and associatedsystem. Earthing also prevents damaging transientovervoltages in the event of an arcing earth fault orferroresonance.

    For HV generators, impedance is usually inserted in thestator earthing connection to limit the magnitude of earth fault current. There is a wide variation in the earthfault current chosen, common values being:

    1. rated current2. 200A-400A (low impedance earthing)

    3. 10A-20A (high impedance earthing)

    The main methods of impedance-earthing a generatorare shown in Figure 17.3. Low values of earth faultcurrent may limit the damage caused from a fault, butthey simultaneously make detection of a fault towardsthe stator winding star point more difficult. Except forspecial applications, such as marine, LV generators arenormally solidly earthed to comply with safetyrequirements. Where a step-up transformer is applied,

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    Generator Main transformer

    HV busbars

    Unit transformer

    Auxiliarysupplies switchboard

    Figure 17.1: Generator-transformer unit

    Utility

    PCC

    Industrial plantmain busbar

    Plant feeders - totaleman : xM

    When plant generator is running:If y>x, Plant may export to Utility across PCCIf x>y, Plant max demand from Utility is reduced

    PCC: Point of Common Coupling

    GeneratorRating: yMW

    Figure 17.2: Embedded generation

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    the generator and the lower voltage winding of thetransformer can be treated as an isolated system that isnot influenced by the earthing requirements of thepower system.

    An earthing transformer or a series impedance can beused as the impedance. If an earthing transformer isused, the continuous rating is usually in the range 5-250kVA. The secondary winding is loaded with a resistorof a value which, when referred through the transformerturns ratio, will pass the chosen short-time earth-faultcurrent. This is typically in the range of 5-20A. Theresistor prevents the production of high transientovervoltages in the event of an arcing earth fault, which

    it does by discharging the bound charge in the circuitcapacitance. For this reason, the resistive component of fault current should not be less than the residualcapacitance current. This is the basis of the design, andin practice values of between 3-5 I co are used.

    It is important that the earthing transformer neverbecomes saturated; otherwise a very undesirablecondition of ferroresonance may occur. The normal riseof the generated voltage above the rated value caused bya sudden loss of load or by field forcing must beconsidered, as well as flux doubling in the transformerdue to the point-on-wave of voltage application. It is

    sufficient that the transformer be designed to have aprimary winding knee-point e.m.f. equal to 1.3 times thegenerator rated line voltage.

    17.3 STATOR WINDING FAULTS

    Failure of the stator windings or connection insulationcan result in severe damage to the windings and statorcore. The extent of the damage will depend on themagnitude and duration of the fault current.

    17.3.1 Earth Faults

    The most probable mode of insulation failure is phase toearth. Use of an earthing impedance limits the earthfault current and hence stator damage.

    An earth fault involving the stator core results in burningof the iron at the point of fault and welds laminations

    together. Replacement of the faulty conductor may notbe a very serious matter (dependent on setrating/voltage/construction) but the damage to the corecannot be ignored, since the welding of laminations mayresult in local overheating. The damaged area cansometimes be repaired, but if severe damage hasoccurred, a partial core rebuild will be necessary. Aflashover is more likely to occur in the end-windingregion, where electrical stresses are highest. Theresultant forces on the conductors would be very largeand they may result in extensive damage, requiring thepartial or total rewinding of the generator. Apart from

    burning the core, the greatest danger arising from failureto quickly deal with a fault is fire. A large portion of theinsulating material is inflammable, and in the case of anair-cooled machine, the forced ventilation can quicklycause an arc flame to spread around the winding. Firewill not occur in a hydrogen-cooled machine, providedthe stator system remains sealed. In any case, the lengthof an outage may be considerable, resulting in majorfinancial impact from loss of generation revenue and/orimport of additional energy.

    17.3.2 Phase-Phase Faults

    Phase-phase faults clear of earth are less common; theymay occur on the end portion of stator coils or in theslots if the winding involves two coil sides in the sameslot. In the latter case, the fault will involve earth in avery short time. Phase fault current is not limited by themethod of earthing the neutral point.

    17.3.3 Interturn Faults

    Interturn faults are rare, but a significant fault-loopcurrent can arise where such a fault does occur.

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    Typical setting(% of earthingresistor rating)

    10

    5

    (b) Resistance earthing

    (c) Distribution transformer earthingwith overvoltage relay.

    (d) Distribution transformer earthing

    with overcurrent relay

    (a) Direct earthing

    Loadingresistor

    Loadingresistor

    I>

    I>>

    U>

    I>

    Figure 17.3: Methods of generator earthing

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    Conventional generator protection systems would beblind to an interturn fault, but the extra cost andcomplication of providing detection of a purely interturnfault is not usually justified. In this case, an interturnfault must develop into an earth fault before it can becleared. An exception may be where a machine has anabnormally complicated or multiple windingarrangement, where the probability of an interturn faultmight be increased.

    17.4 STATOR WINDING PROTECTION

    To respond quickly to a phase fault with damaging heavycurrent, sensitive, high-speed differential protection isnormally applied to generators rated in excess of 1MVA.For large generating units, fast fault clearance will alsomaintain stability of the main power system. The zoneof differential protection can be extended to include anassociated step-up transformer. For smaller generators,IDMT/instantaneous overcurrent protection is usually theonly phase fault protection applied. Sections 17.5-17.8detail the various methods that are available for statorwinding protection.

    17.5 DIFFERENTIAL PROTECTION OF DIRECTCONNECTED GENERATORS

    The theory of circulating current differential protection isdiscussed fully in Section 10.4.

    High-speed phase fault protection is provided, by use of the connections shown in Figure 17.4. This depicts thederivation of differential current through CT secondarycircuit connections. This protection may also offer earthfault protection for some moderate impedance-earthedapplications. Either biased differential or highimpedance differential techniques can be applied. Asubtle difference with modern, biased, numericalgenerator protection relays is that they usually derive thedifferential currents and biasing currents by algorithmic

    calculation, after measurement of the individual CTsecondary currents. In such relay designs, there is fullgalvanic separation of the neutral-tail and terminal CTsecondary circuits, as indicated in Figure 17.5(a). This isnot the case for the application of high-impedancedifferential protection. This difference can impose somespecial relay design requirements to achieve stability forbiased differential protection in some applications.

    17.5.1 Biased Differential Protection

    The relay connections for this form of protection areshown in Figure 17.5(a) and a typical bias characteristicis shown in Figure 17.5(b). The differential currentthreshold setting I s1 can be set as low as 5% of ratedgenerator current, to provide protection for as much of the winding as possible. The bias slope break-pointthreshold setting I s2 would typically be set to a valueabove generator rated current, say 120%, to achieveexternal fault stability in the event of transientasymmetric CT saturation. Bias slopeK 2 setting wouldtypically be set at 150%.

    17.5.2 High Impedance Differential Protection

    This differs from biased differential protection by themanner in which relay stability is achieved for externalfaults and by the fact that the differential current mustbe attained through the electrical connections of CTsecondary circuits. If the impedance of each relay inFigure 17.4 is high, the event of one CT becomingsaturated by the through fault current (leading to a

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    (a): Relay connections for biased differential protection

    Operate

    Restrain

    (b) Biased differential operating characteristic

    I 1

    I diff = I 1+I 2

    I 2

    I S1

    I S2

    K 1

    K

    I BIAS =I 1+ 2

    Figure 17.5: Typical generator biased differential protection

    C

    A

    B

    I > I d> I d>

    Stator

    Figure 17.4: Stator differential protection

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    relatively low CT impedance), will allow the current fromthe unsaturated CT to flow mainly through the saturatedCT rather than through the relay. This provides therequired protection stability where a tuned relay elementis employed. In practice, external resistance is added tothe relay circuit to provide the necessary highimpedance. The principle of high-impedance protectionapplication is illustrated in Figure 17.6, together with asummary of the calculations required to determine thevalue of external stabilising resistance.

    In some applications, protection may be required to limitvoltages across the CT secondary circuits when the

    differential secondary current for an internal phase faultflows through the high impedance relay circuit(s), butthis is not commonly a requirement for generatordifferential applications unless very high impedancerelays are applied. Where necessary, shuntconnected,non-linear resistors, should be deployed, as shown inFigure 17.7.

    To calculate the primary operating current, the followingexpression is used:

    I op = N x (I s1 + nI e)

    where:

    I op = primary operating current

    N = CT ratioI s1 = relay setting

    n = number of CTs in parallel with relay element

    I e = CT magnetising current at V sI s1 is typically set to 5% of generator rated secondarycurrent.

    It can be seen from the above that the calculations forthe application of high impedance differential protectionare more complex than for biased differential protection.However, the protection scheme is actually quite simple

    and it offers a high level of stability for through faultsand external switching events.

    With the advent of multi-function numerical relays andwith a desire to dispense with external components, highimpedance differential protection is not as popular asbiased differential protection in modern relayingpractice.

    17.5.3 CT Requirements

    The CT requirements for differential protection will varyaccording to the relay used. Modern numerical relaysmay not require CTs specifically designed for differentialprotection to IEC 60044-1 class PX (or BS 3938 class X).However, requirements in respect of CT knee-pointvoltage will still have to be checked for the specificrelays used. High impedance differential protection maybe more onerous in this respect than biased differentialprotection.

    Many factors affect this, including the other protectionfunctions fed by the CTs and the knee-pointrequirements of the particular relay concerned. Relaymanufacturers are able to provide detailed guidance onthis matter.

    17.6 DIFFERENTIAL PROTECTION OFGENERATOR-TRANSFORMERS

    A common connection arrangement for large generatorsis to operate the generator and associated step-uptransformer as a unit without any intervening circuitbreaker. The unit transformer supplying the generatorauxiliaries is tapped off the connection betweengenerator and step-up transformer. Differentialprotection can be arranged as follows.

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    tNLR = Non-linear resistance

    (Metrosil)

    NLR

    V

    Figure 17.7: Relay connections for highimpedance differential protection

    Healthy CT Saturated CTProtected zone

    I d >

    Z m

    RCT1 RCT2

    RL1

    Rst

    RL3

    RL2 RL4

    I f

    V r

    Voltage across relay circuit V r = I f (RCT + 2R L ) and V s = KV r where 1.0 < K 1.5

    Stabilising resistor,Rst , limits spill current to < I s (relay setting)

    when RR = relay burden

    V sI s

    Rst = -RR

    Figure 17.6: Principle of high impedance differential protection

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    17.6.1 Generator/Step-up TransformerDifferential Protection

    The generator stator and step-up transformer can beprotected by a single zone of overall differentialprotection (Figure 17.8). This will be in addition todifferential protection applied to the generator only. The

    current transformers should be located in the generatorneutral connections and in the transformer HV connections. Alternatively, CTs within the HV switchyard may be employed if the distance is nottechnically prohibitive. Even where there is a generatorcircuit breaker, overall differential protection can still beprovided if desired.

    The current transformers should be rated according toSection 16.8.2. Since a power transformer is includedwithin the zone of protection, biased transformerdifferential protection, with magnetising inrush restraintshould be applied, as discussed in Section 16.8.5.Transient overfluxing of the generator transformer mayarise due to overvoltage following generator loadrejection. In some applications, this may threaten thestability of the differential protection. In such cases,consideration should be given to applying protectionwith transient overfluxing restraint/blocking (e.g. basedon a 5 th harmonic differential current threshold).

    Protection against sustained overfluxing is covered inSection 17.14.

    17.6.2 Unit Transformer Differential Protection

    The current taken by the unit transformer must beallowed for by arranging the generator differentialprotection as a three-ended scheme. Unit transformercurrent transformers are usually applied to balance thegenerator differential protection and prevent the unittransformer through current being seen as differentialcurrent. An exception might be where the unit

    transformer rating is extremely low in relation to thegenerator rating, e.g. for some hydro applications. Thelocation of the third set of current transformers isnormally on the primary side of the unit transformer. If located on secondary side of the unit transformer, theywould have to be of an exceptionally high ratio, orexceptionally high ratio interposing CTs would have tobe used. Thus, the use of secondary side CTs is not to berecommended. One advantage is that unit transformerfaults would be within the zone of protection of thegenerator. However, the sensitivity of the generatorprotection to unit transformer phase faults would beconsidered inadequate, due to the relatively low rating of the transformer in relation to that of the generator.Thus, the unit transformer should have its owndifferential protection scheme. Protection for the unittransformer is covered in Chapter 16, including methodsfor stabilising the protection against magnetising inrushconditions.

    17.7 OVERCURRENT PROTECTION

    Overcurrent protection of generators may take twoforms. Plain overcurrent protection may be used as theprinciple form of protection for small generators, andback-up protection for larger ones where differentialprotection is used as the primary method of generatorstator winding protection. Voltage dependentovercurrent protection may be applied where differentialprotection is not justified on larger generators, or whereproblems are met in applying plain overcurrentprotection.

    17.7.1 Plain Overcurrent Protection

    It is usual to apply time-delayed plain overcurrentprotection to generators. For generators rated less than1MVA, this will form the principal stator windingprotection for phase faults. For larger generators,overcurrent protection can be applied as remote back-upprotection, to disconnect the unit from any unclearedexternal fault. Where there is only one set of differential

    main protection, for a smaller generator, the overcurrentprotection will also provide local back-up protection forthe protected plant, in the event that the mainprotection fails to operate. The general principles of setting overcurrent relays are given in Chapter 9.

    In the case of a single generator feeding an isolatedsystem, current transformers at the neutral end of themachine should energise the overcurrent protection, toallow a response to winding fault conditions. Relaycharacteristics should be selected to take into accountthe fault current decrement behaviour of the generator,with allowance for the performance of the excitation

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    GeneratorMain

    transformer

    HV busbars

    I >

    Protected zone

    Figure 17.8: Overall generator-transformer differential protection

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    system and its field-forcing capability. Without theprovision of fault current compounding from generatorCTs, an excitation system that is powered from anexcitation transformer at the generator terminals willexhibit a pronounced fault current decrement for aterminal fault. With failure to consider this effect, thepotential exists for the initial high fault current to decayto a value below the overcurrent protection pick-upsetting before a relay element can operate, unless a lowcurrent setting and/or time setting is applied. Theprotection would then fail to trip the generator. Thesettings chosen must be the best compromise betweenassured operation in the foregoing circumstances anddiscrimination with the system protection and passageof normal load current, but this can be impossible withplain overcurrent protection.

    In the more usual case of a generator that operates inparallel with others and which forms part of an extensiveinterconnected system, back-up phase fault protectionfor a generator and its transformer will be provided by HV overcurrent protection. This will respond to the higher-level backfeed from the power system to a unit fault.Other generators in parallel would supply this currentand, being stabilised by the system impedance, it will notsuffer a major decrement. This protection is usually arequirement of the power system operator. Settings mustbe chosen to prevent operation for external faults fed bythe generator. It is common for the HV overcurrentprotection relay to provide both time-delayed andinstantaneous high-set elements. The time-delayedelements should be set to ensure that the protected itemsof plant cannot pass levels of through fault current inexcess of their short-time withstand limits. Theinstantaneous elements should be set above themaximum possible fault current that the generator cansupply, but less than the system-supplied fault current inthe event of a generator winding fault. This back-upprotection will minimise plant damage in the event of main protection failure for a generating plant fault andinstantaneous tripping for an HV-side fault will aid therecovery of the power system and parallel generation.

    17.7.2 Voltage-Dependent Overcurrent ProtectionThe plain overcurrent protection setting difficultyreferred to in the previous section arises becauseallowance has to be made both for the decrement of thegenerator fault current with time and for the passage of full load current. To overcome the difficulty of discrimination, the generator terminal voltage can bemeasured and used to dynamically modify the basic relaycurrent/time overcurrent characteristic for faults close tothe generating plant. There are two basic alternativesfor the application of voltage-dependent overcurrentprotection, which are discussed in the following sections.

    The choice depends upon the power systemcharacteristics and level of protection to be provided.

    Voltage-dependent overcurrent relays are often foundapplied to generators used on industrial systems as analternative to full differential protection.

    17.7.2.1 Voltage controlled overcurrent protection

    Voltage controlled overcurrent protection has twotime/current characteristics which are selected accordingto the status of a generator terminal voltage measuringelement. The voltage threshold setting for the switchingelement is chosen according to the following criteria.

    1. during overloads, when the system voltage issustained near normal, the overcurrent protectionshould have a current setting above full load currentand an operating time characteristic that will preventthe generating plant from passing current to a remoteexternal fault for a period in excess of the plant short-time withstand limits

    2. under close-up fault conditions, the busbar voltagemust fall below the voltage threshold so that thesecond protection characteristic will be selected. Thischaracteristic should be set to allow relay operationwith fault current decrement for a close-up fault atthe generator terminals or at the HV busbars. Theprotection should also time-grade with externalcircuit protection. There may be additional infeeds toan external circuit fault that will assist with grading

    Typical characteristics are shown in Figure 17.9.

    17.7.2.2 Voltage restrained overcurrent protection

    The alternative technique is to continuously vary therelay element pickup setting with generator voltagevariation between upper and lower limits. The voltage issaid to restrain the operation of the current element.

    The effect is to provide a dynamic I.D.M.T. protectioncharacteristic, according to the voltage at the machine

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    Current pick-up level

    I >

    KI>

    V s Voltage level

    Figure 17.9: Voltage controlled relay characteristics

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    terminals. Alternatively, the relay element may beregarded as an impedance type with a long dependenttime delay. In consequence, for a given fault condition,the relay continues to operate more or lessindependently of current decrement in the machine. Atypical characteristic is shown in Figure 17.10.

    17.8 STATOR EARTH FAULT PROTECTION

    Earth fault protection must be applied where impedanceearthing is employed that limits the earth fault currentto less than the pick-up threshold of the overcurrentand/or differential protection for a fault located down tothe bottom 5% of the stator winding from the star-point. The type of protection required will depend on the

    method of earthing and connection of the generator tothe power system.

    17.8.1 Direct-Connected Generators

    A single direct-connected generator operating on anisolated system will normally be directly earthed.However, if several direct-connected generators areoperated in parallel, only one generator is normallyearthed at a time. For the unearthed generators, asimple measurement of the neutral current is notpossible, and other methods of protection must be used.

    The following sections describe the methods available.17.8.1.1 Neutral overcurrent protection

    With this form of protection, a current transformer in theneutral-earth connection energises an overcurrent relayelement. This provides unrestricted earth-faultprotection and so it must be graded with feederprotection. The relay element will therefore have a time-delayed operating characteristic. Grading must becarried out in accordance with the principles detailed inChapter 9. The setting should not be more than 33% of the maximum earth fault current of the generator, and alower setting would be preferable, depending on grading

    considerations.

    17.8.1.2 Sensitive earth fault protection

    This method is used in the following situations:

    a. direct-connected generators operating in parallel

    b. generators with high-impedance neutral earthing,the earth fault current being limited to a few tensof amps

    c. installations where the resistance of the groundfault path is very high, due to the nature of theground

    In these cases, conventional earth fault protection asdescribed in Section 17.8.1.1 is of little use.

    The principles of sensitive earth fault protection aredescribed in Sections 9.17.1, 9.18 and 9.19. The earthfault (residual) current can be obtained from residualconnection of line CTs, a line-connected CBCT, or a CT inthe generator neutral. The latter is not possible if directional protection is used. The polarising voltage isusually the neutral voltage displacement input to therelay, or the residual of the three phase voltages, so asuitable VT must be used. For Petersen Coil earthing, awattmetric technique (Section 9.19) can also be used.

    For direct connected generators operating in parallel,directional sensitive earth fault protection may benecessary. This is to ensure that a faulted generator willbe tripped before there is any possibility of the neutralovercurrent protection tripping a parallel healthygenerator. When being driven by residually-connectedphase CTs, the protection must be stabilised againstincorrect tripping with transient spill current in the eventof asymmetric CT saturation when phase fault ormagnetising inrush current is being passed. Stabilisingtechniques include the addition of relay circuitimpedance and/or the application of a time delay. Wherethe required setting of the protection is very low incomparison to the rated current of the phase CTs, itwould be necessary to employ a single CBCT for the earthfault protection to ensure transient stability.

    Since any generator in the paralleled group may be

    earthed, all generators will require to be fitted with bothneutral overcurrent protection and sensitive directionalearth fault protection.

    The setting of the sensitive directional earth faultprotection is chosen to co-ordinate with generatordifferential protection and/or neutral voltagedisplacement protection to ensure that 95% of the statorwinding is protected. Figure 17.11 illustrates thecomplete scheme, including optional blocking signalswhere difficulties in co-ordinating the generator anddownstream feeder earth-fault protection occur.

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    Current pick-up level

    I>

    KI>

    V 2 V S1 Voltage level

    Figure 17.10: Voltage restrained relay characteristics

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    For cases (b) and (c) above, it is not necessary to use adirectional facility. Care must be taken to use the correctRCA setting for instance if the earthing impedance ismainly resistive, this should be 0. On insulated or veryhigh impedance earthed systems, an RCA of -90 wouldbe used, as the earth fault current is predominatelycapacitive.

    Directional sensitive earth-fault protection can also beused for detecting winding earth faults. In this case, the

    relay element is applied to the terminals of the generatorand is set to respond to faults only within the machinewindings. Hence earth faults on the external system donot result in relay operation. However, current flowingfrom the system into a winding earth fault causes relayoperation. It will not operate on the earthed machine, sothat other types of earth fault protection must also beapplied. All generators must be so fitted, since any canbe operated as the earthed machine.

    17.8.1.3 Neutral voltage displacement protection

    In a balanced network, the addition of the three phase-earth voltages produces a nominally zero residualvoltage, since there would be little zero sequence voltagepresent. Any earth fault will set up a zero sequencesystem voltage, which will give rise to a non-zeroresidual voltage. This can be measured by a suitablerelay element. The voltage signal must be derived froma VT that is suitable i.e. it must be capable of transforming zero-sequence voltage, so 3-limb types andthose without a primary earth connection are notsuitable. This unbalance voltage provides a means of detecting earth faults. The relay element must beinsensitive to third harmonic voltages that may bepresent in the system voltage waveforms, as these will

    sum residually.

    As the protection is still unrestricted, the voltage settingof the relay must be greater than the effective setting of any downstream earth-fault protection. It must also betime-delayed to co-ordinate with such protection.Sometimes, a second high-set element with short time

    delay is used to provide fast-acting protection againstmajor winding earth-faults. Figure 17.12 illustrates thepossible connections that may be used.

    17.8.2 Indirectly-Connected Generators

    As noted in Section 17.2, a directly-earthed generator-

    transformer unit cannot interchange zero-sequencecurrent with the remainder of the network, and hence anearth fault protection grading problem does not exist.The following sections detail the protection methods forthe various forms of impedance earthing of generators.

    17.8.2.1 High resistance earthing neutral overcurrent protection

    A current transformer mounted on the neutral-earthconductor can drive an instantaneous and/or timedelayed overcurrent relay element, as shown in Figure17.13. It is impossible to provide protection for the wholeof the winding, and Figure 17.13 also details how thepercentage of winding covered can be calculated. For arelay element with an instantaneous setting, protection istypically limited to 90% of the winding. This is to ensurethat the protection will not maloperate with zerosequence current during operation of a primary fuse for a

    VT earth fault or with any transient surge currents thatcould flow through the interwinding capacitance of thestep-up transformer for an HV system earth fault.

    A time-delayed relay is more secure in this respect, and itmay have a setting to cover 95% of the stator winding.Since the generating units under consideration are usuallylarge, instantaneous and time delayed relay elements are

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    I > >>I

    Feeder

    Block*Block*

    ReRe

    Open

    * Optional interlockedearth-fault protectionif grading problems exist

    Minimum earth fault level = I F RV

    I

    I >>

    >U sdI

    I >>U sd

    Figure 17.11: Comprehensive earth-fault protection scheme for direct-connected

    generators operating in parallel V aV

    c

    V

    3

    2

    1

    Measured from earth impedance2

    Measured from broken delta VT

    Derived from phase neutral voltages1

    Figure 17.12: Neutral voltage displacement protection

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    often applied, with settings of 10% and 5% of maximumearth fault current respectively; this is the optimumcompromise in performance. The portion of the windingleft unprotected for an earth fault is at the neutral end.Since the voltage to earth at this end of the winding islow, the probability of an earth fault occurring is also low.

    Hence additional protection is often not applied.

    17.8.2.2 Distribution transformer earthing

    using a current element In this arrangement, shown in Figure 17.14(a), thegenerator is earthed via the primary winding of adistribution transformer. The secondary winding is fittedwith a loading resistor to limit the earth fault current.An overcurrent relay element energised from a currenttransformer connected in the resistor circuit is used tomeasure secondary earth fault current. The relay shouldhave an effective setting equivalent to 5% of themaximum earth fault current at rated generator voltage,in order to protect 95% of the stator winding. The relay

    element response to third harmonic current should belimited to prevent incorrect operation when a sensitivesetting is applied.

    As discussed in Section 17.8.2.1 for neutral overcurrentprotection, the protection should be time delayed whena sensitive setting is applied, in order to preventmaloperation under transient conditions. It also mustgrade with generator VT primary protection (for a VTprimary earth fault). An operation time in the range0.5s-3s is usual. Less sensitive instantaneous protectioncan also be applied to provide fast tripping for a heavierearth fault condition.

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    R

    I s

    I f

    a

    V

    I f =aV

    R

    I sRa in V %covered 1-a in ) x 1100%

    generator stator winding using a current element

    Figure 17.13: Earth fault protection of high-resistance earthed generator stator winding using a current element

    17.8.2.3 Distribution transformer earthing using a voltage element

    Earth fault protection can also be provided using a voltage-measuring element in the secondary circuit instead. Thesetting considerations would be similar to those for thecurrent operated protection, but transposed to voltage.The circuit diagram is shown in Figure 17.14(b).

    Application of both voltage and current operatedelements to a generator with distribution transformerearthing provides some advantages. The currentoperated function will continue to operate in the eventof a short-circuited loading resistor and the voltageprotection still functions in the event of an open-

    circuited resistor. However, neither scheme will operatein the event of a flashover on the primary terminals of the transformer or of the neutral cable between thegenerator and the transformer during an earth fault. ACT could be added in the neutral connection close to thegenerator, to energise a high-set overcurrent element todetect such a fault, but the fault current would probablybe high enough to operate the phase differentialprotection.

    17.8.2.4 Neutral voltage displacement protection

    This can be applied in the same manner as for direct-connected generators (Section 17.8.1.3). The only

    I >

    Loadingresistor

    Loadingresistor

    U >

    (a) Protection using a current element

    (b) Protection using a voltage element

    Figure 17.14: Generator winding earth-fault protection - distribution transformer earthing

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    difference is that the are no grading problems as theprotection is inherently restricted. A sensitive settingcan therefore be used, enabling cover of up to 95% of the stator winding to be achieved.

    17.8.3 Restricted Earth Fault Protection

    This technique can be used on small generators not fittedwith differential protection to provide fast acting earthfault protection within a defined zone that encompassesthe generator. It is cheaper than full differentialprotection but only provides protection against earthfaults. The principle is that used for transformer REFprotection, as detailed in Section 16.7. However, incontrast to transformer REF protection, both biased low-impedance and high-impedance techniques can be used.

    17.8.3.1 Low-impedance biased REF protection

    This is shown in Figure 17.15. The main advantage isthat the neutral CT can also be used in a modern relay toprovide conventional earth-fault protection and noexternal resistors are used. Relay bias is required, asdescribed in Section 10.4.2, but the formula forcalculating the bias is slightly different and also shownin Figure 17.15.

    The initial bias slope is commonly set to 0% to providemaximum sensitivity, and applied up to the rated currentof the generator. It may be increased to counter theeffects of CT mismatch. The bias slope above generatorrated current is typically set to 150% of rated value. Theinitial current setting is typically 5% of the minimumearth fault current for a fault at the machine terminals.

    17.8.3.2 High Impedance REF protection

    The principle of high impedance differential protection isgiven in Chapter 10 and also described further in Section17.5.2. The same technique can be used for earth-fault

    protection of a generator, using three residuallyconnected phase CTs balanced against a similar singleCT in the neutral connection. Settings of the order of 5%of maximum earth fault current at the generatorterminals are typical. The usual requirements in respectof stabilising resistor and non-linear resistor to guardagainst excessive voltage across the relay must be taken,where necessary.

    17.8.4 Earth Fault Protection forthe Entire Stator Winding

    All of the methods for earth fault protection detailed sofar leave part of the winding unprotected. In most cases,this is of no consequence as the probability of a faultoccurring in the 5% of the winding nearest the neutralconnection is very low, due to the reduced phase to earthvoltage. However, a fault can occur anywhere along thestator windings in the event of insulation failure due tolocalised heating from a core fault. In cases whereprotection for the entire winding is required, perhaps foralarm only, there are various methods available.

    17.8.4.1 Measurement of third harmonic voltage

    One method is to measure the internally generated thirdharmonic voltage that appears across the earthingimpedance due to the flow of third harmonic currentsthrough the shunt capacitance of the stator windingsetc. When a fault occurs in the part of the statorwinding nearest the neutral end, the third harmonicvoltage drops to near zero, and hence a relay elementthat responds to third harmonic voltage can be used todetect the condition. As the fault location movesprogressively away from the neutral end, the drop inthird harmonic voltage from healthy conditions becomesless, so that at around 20-30% of the winding distance,it no longer becomes possible to discriminate between ahealthy and a faulty winding. Hence, a conventionalearth-fault scheme should be used in conjunction with athird harmonic scheme, to provide overlapping coverof the entire stator winding. The measurement of thirdharmonic voltage can be taken either from a star-point

    VT or the generator line VT. In the latter case, the VTmust be capable of carrying residual flux, and thisprevents the use of 3-limb types. If the third harmonicvoltage is measured at the generator star point, anundervoltage characteristic is used. An overvoltagecharacteristic is used if the measurement is taken fromthe generator line VT. For effective application of thisform of protection, there should be at least 1% thirdharmonic voltage across the generator neutral earthingimpedance under all operating conditions.

    A problem encountered is that the level of thirdharmonic voltage generated is related to the output of the generator. The voltage is low when generator output

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    Neutral CT ratio200 1

    PhasePhase C

    Phase APhase CT ratio 1000 1

    I BIAS =(highest of I A B , I N x scaling factor)

    2

    where scaling factor = .21000I DIFF = I A I B I C (scaling factor I N )

    Figure 17.15: Low impedance biased REF protection of a generator

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    is low. In order to avoid maloperation when operating atlow power output, the relay element can be inhibitedusing an overcurrent or power element (kW, kvar or kVA)and internal programmable logic.

    17.8.4.2 Use of low-frequency voltage injection

    Another method for protecting the entire stator windingof a generator is to deploy signal injection equipment toinject a low frequency voltage between the stator starpoint and earth. An earth fault at any winding locationwill result in the flow of a measurable injection currentto cause protection operation. This form of protectioncan provide earth fault protection when the generator isat standstill, prior to run-up. It is also an appropriatemethod to apply to variable speed synchronousmachines. Such machines may be employed for variablespeed motoring in pumped-storage generation schemesor for starting a large gas turbine prime mover.

    17.9 OVERVOLTAGE PROTECTION

    Overvoltages on a generator may occur due to transientsurges on the network, or prolonged power frequencyovervoltages may arise from a variety of conditions.Surge arrestors may be required to protect againsttransient overvoltages, but relay protection may be usedto protect against power frequency overvoltages.

    A sustained overvoltage condition should not occur for amachine with a healthy voltage regulator, but it may becaused by the following contingencies:

    a. defective operation of the automatic voltageregulator when the machine is in isolated operation

    b. operation under manual control with the voltageregulator out of service. A sudden variation of theload, in particular the reactive power component,will give rise to a substantial change in voltagebecause of the large voltage regulation inherent ina typical alternator

    c. sudden loss of load (due to tripping of outgoingfeeders, leaving the set isolated or feeding a very smallload) may cause a sudden rise in terminal voltage dueto the trapped field flux and/or overspeed

    Sudden loss of load should only cause a transientovervoltage while the voltage regulator and governor actto correct the situation. A maladjusted voltage regulatormay trip to manual, maintaining excitation at the valueprior to load loss while the generator supplies little or noload. The terminal voltage will increase substantially,and in severe cases it would be limited only by thesaturation characteristic of the generator. A rise in speedsimply compounds the problem. If load that is sensitiveto overvoltages remains connected, the consequences interms of equipment damage and lost revenue can besevere. Prolonged overvoltages may also occur on

    isolated networks, or ones with weak interconnections,due to the fault conditions listed earlier.

    For these reasons, it is prudent to provide powerfrequency overvoltage protection, in the form of a time-delayed element, either IDMT or definite time. The timedelay should be long enough to prevent operation during

    normal regulator action, and therefore should takeaccount of the type of AVR fitted and its transientresponse. Sometimes a high-set element is provided aswell, with a very short definite-time delay orinstantaneous setting to provide a rapid trip in extremecircumstances. The usefulness of this is questionable forgenerators fitted with an excitation system other than astatic type, because the excitation will decay inaccordance with the open-circuit time constant of thefield winding. This decay can last several seconds. Therelay element is arranged to trip both the main circuitbreaker (if not already open) and the excitation; trippingthe main circuit breaker alone is not sufficient.

    17.10 UNDERVOLTAGE PROTECTION

    Undervoltage protection is rarely fitted to generators. Itis sometimes used as an interlock element for anotherprotection function or scheme, such as field failureprotection or inadvertent energisation protection, wherethe abnormality to be detected leads directly orindirectly to an undervoltage condition.

    A transmission system undervoltage condition may arise

    when there is insufficient reactive power generation tomaintain the system voltage profile and the conditionmust be addressed to avoid the possible phenomenon of system voltage collapse.

    However, it should be addressed by the deployment of system protection schemes. The generation should notbe tripped. The greatest case for undervoltage protectionbeing required would be for a generator supplying anisolated power system or to meet Utility demands forconnection of embedded generation (see Section 17.21).

    In the case of generators feeding an isolated system,

    undervoltage may occur for several reasons, typicallyoverloading or failure of the AVR. In some cases, theperformance of generator auxiliary plant fed via a unittransformer from the generator terminals could beadversely affected by prolonged undervoltage.

    Where undervoltage protection is required, it shouldcomprise an undervoltage element and an associatedtime delay. Settings must be chosen to avoidmaloperation during the inevitable voltage dips duringpower system fault clearance or associated with motorstarting. Transient reductions in voltage down to 80% orless may be encountered during motor starting.

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    17.11 LOW FORWARD POWER/REVERSEPOWER PROTECTION

    Low forward power or reverse power protection may berequired for some generators to protect the prime mover.Parts of the prime mover may not be designed toexperience reverse torque or they may become damaged

    through continued rotation after the prime mover hassuffered some form of failure.

    17.11.1 Low Forward Power Protection

    Low forward power protection is often used as aninterlocking function to enable opening of the maincircuit breaker for non-urgent trips e.g. for a statorearth fault on a high-impedance earthed generator, orwhen a normal shutdown of a set is taking place. This isto minimise the risk of plant overspeeding when theelectrical load is removed from a high-speed cylindrical

    rotor generator. The rotor of this type of generator ishighly stressed mechanically and cannot tolerate muchoverspeed. While the governor should control overspeedconditions, it is not good practice to open the maincircuit breaker simultaneously with tripping of the primemover for non-urgent trips. For a steam turbine, forexample, there is a risk of overspeeding due to energystorage in the trapped steam, after steam valve tripping,or in the event that the steam valve(s) do not fully closefor some reason. For urgent trip conditions, such asstator differential protection operation, the risk involvedin simultaneous prime mover and generator breakertripping must be accepted.

    17.11.2 Reverse Power Protection

    Reverse power protection is applied to prevent damageto mechanical plant items in the event of failure of theprime mover. Table 17.1 gives details of the potentialproblems for various prime mover types and the typicalsettings for reverse power protection. For applications

    where a protection sensitivity of better than 3% isrequired, a metering class CT should be employed toavoid incorrect protection behaviour due to CT phaseangle errors when the generator supplies a significantlevel of reactive power at close to zero power factor.

    The reverse power protection should be provided with a

    definite time delay on operation to prevent spuriousoperation with transient power swings that may arisefollowing synchronisation or in the event of a powertransmission system disturbance.

    17.12 UNBALANCED LOADING

    A three-phase balanced load produces a reaction fieldthat, to a first approximation, is constant and rotatessynchronously with the rotor field system. Anyunbalanced condition can be resolved into positive,negative and zero sequence components. The positive

    sequence component is similar to the normal balancedload. The zero sequence component produces no mainarmature reaction.

    17.12.1 Effect of Negative Sequence Current

    The negative sequence component is similar to thepositive sequence system, except that the resultingreaction field rotates in the opposite direction to the d.c.field system. Hence, a flux is produced which cuts therotor at twice the rotational velocity, thereby inducingdouble frequency currents in the field system and in the

    rotor body. The resulting eddy-currents are very largeand cause severe heating of the rotor.

    So severe is this effect that a single-phase load equal tothe normal three-phase rated current can quickly heatthe rotor slot wedges to the softening point. They maythen be extruded under centrifugal force until they standabove the rotor surface, when it is possible that they maystrike the stator core.

    A generator is assigned a continuous negative sequencerating. For turbo-generators this rating is low; standardvalues of 10% and 15% of the generator continuousrating have been adopted. The lower rating applies whenthe more intensive cooling techniques are applied, forexample hydrogen-cooling with gas ducts in the rotor tofacilitate direct cooling of the winding.

    Short time heating is of interest during system faultconditions and it is usual in determining the generatornegative sequence withstand capability to assume thatthe heat dissipation during such periods is negligible.Using this approximation it is possible to express theheating by the law:

    I t K 2 2 =

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    N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e 2 9 3

    Table 17.1: Generator reverse power problems

    Prime Mover Motoring Power Possible Damage Protection Setting(% of rated)

    Fire/explosion dueto unburnt fuel

    Mechanical damageto gearbox/shafts

    10-15(split shaft)

    >50%(single shaft)

    0.2-2

    (blades out of water) blade and runner>2 cavitation

    (blades in water)turbine blade damage

    gearbox damageon geared sets

    50%of motoring

    power

    gearbox damage

    Diesel Engine

    Gas Turbine

    Hydro

    Steam Turbine

    5-25

    0.5-6

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    where:

    I 2R = negative sequence component (per unit of MCR)

    t = time (seconds)

    K = constant proportional to the thermal capacity of the generator rotor

    For heating over a period of more than a few seconds, itis necessary to allow for the heat dissipated. From acombination of the continuous and short time ratings,the overall heating characteristic can be deduced to be:

    where:

    I 2R = negative phase sequence continuous rating in

    per unit of MCRThe heating characteristics of various designs of generator are shown in Figure 17.16.

    17.12.2 Negative Phase Sequence Protection

    This protection is applied to prevent overheating due tonegative sequence currents. Small salient-polegenerators have a proportionately larger negative

    M I I eR

    I t K R= =

    ( )2

    2

    1

    1 2 2

    sequence capacity and may not require protection.Modern numerical relays derive the negative sequencecurrent level by calculation, with no need for specialcircuits to extract the negative sequence component. Atrue thermal replica approach is often followed, to allowfor:

    a. standing levels of negative sequence current belowthe continuous withstand capability. This has theeffect of shortening the time to reach the criticaltemperature after an increase in negative sequencecurrent above the continuous withstand capability

    b. cooling effects when negative sequence currentlevels are below the continuous withstandcapability

    The advantage of this approach is that cooling effects aremodelled more accurately, but the disadvantage is thatthe tripping characteristic may not follow the withstand

    characteristic specified by the manufacturer accurately.The typical relay element characteristic takes the form of

    Equation 17.1

    where:

    K g = negative sequence withstand coefficient (Figure 17.16)

    I 2cmr = generator maximum continuous I 2 withstand

    I flc = generator rated primary current

    I p = CT primary current

    I N = relay rated current

    Figure 17.16 also shows the thermal replica timecharacteristic described by Equation 17.1, from which itwill be seen that a significant gain in capability isachieved at low levels of negative sequence current.Such a protection element will also respond to phase-earth and phase-phase faults where sufficient negativesequence current arises. Grading with downstreampower system protection relays is therefore required. Adefinite minimum time setting must be applied to thenegative sequence relay element to ensure correctgrading. A maximum trip time setting may also be usedto ensure correct tripping when the negative sequence

    t

    K K I I

    I I I I

    I

    g flc

    p

    set cmr flc

    pn

    =

    =

    =

    time to trip

    2

    2 2

    t K I

    I I set

    eset =

    2 2

    2

    2

    2

    1log

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    Time(sec)

    .01.01

    Negative sequence current (p.u.)

    .1

    1

    10

    100

    1000

    10000

    .1 1 10

    Indirectly cooled (air)Indirectly cooled (H2)50MW direct cooled

    660MW direct cooled1000MW irect coole

    UsingI 2 t mo eUsing true thermalmodel

    Figure 17.16: Typical negative phase sequence current withstand of cylindrical

    rotor generators

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    current level is only slightly in excess of the continuouswithstand capability and hence the trip time from thethermal model may depart significantly from the rotorwithstand limits.

    17.13 PROTECTION AGAINST INADVERTENTENERGISATION

    Accidental energisation of a generator when it is notrunning may cause severe damage to it. With thegenerator at standstill, closing the circuit breaker resultsin the generator acting as an induction motor; the fieldwinding (if closed) and the rotor solid iron/dampercircuits acting as rotor circuits. Very high currents areinduced in these rotor components, and also occur in thestator, with resultant rapid overheating and damage.Protection against this condition is therefore desirable.

    A combination of stator undervoltage and overcurrent

    can be used to detect this condition. An instantaneousovercurrent element is used, and gated with a three-phase undervoltage element (fed from a VT on thegenerator side of the circuit breaker) to provide theprotection. The overcurrent element can have a lowsetting, as operation is blocked when the generator isoperating normally. The voltage setting should be lowenough to ensure that operation cannot occur fortransient faults. A setting of about 50% of rated voltageis typical. VT failure can cause maloperation of theprotection, so the element should be inhibited underthese conditions.

    17.14 UNDER/OVERFREQUENCY/OVERFLUXING PROTECTION

    These conditions are grouped together because theseproblems often occur due to a departure fromsynchronous speed.

    17.14.1 Overfluxing

    Overfluxing occurs when the ratio of voltage tofrequency is too high. The iron saturates owing to the

    high flux density and results in stray flux occurring incomponents not designed to carry it. Overheating canthen occur, resulting in damage. The problem affectsboth direct-and indirectly-connected generators. Eitherexcessive voltage, or low frequency, or a combination of both can result in overfluxing, a voltage to frequencyratio in excess of 1.05p.u. normally being indicative of this condition. Excessive flux can arise transiently, whichis not a problem for the generator. For example, agenerator can be subjected to a transiently high powerfrequency voltage, at nominal frequency, immediatelyafter full load rejection. Since the condition would notbe sustained, it only presents a problem for the stability

    of the transformer differential protection schemesapplied at the power station (see Chapter 16 fortransformer protection). Sustained overfluxing can ariseduring run up, if excitation is applied too early with theAVR in service, or if the generator is run down, with theexcitation still applied. Other overfluxing instances haveoccurred from loss of the AVR voltage feedback signal,due to a reference VT problem. Such sustainedconditions must be detected by a dedicated overfluxingprotection function that will raise an alarm and possiblyforce an immediate reduction in excitation.

    Most AVRs have an overfluxing protection facilityincluded. This may only be operative when the generatoris on open circuit, and hence fail to detect overfluxingconditions due to abnormally low system frequency.However, this facility is not engineered to protectionrelay standards, and should not be solely relied upon toprovide overfluxing protection. A separate relay element

    is therefore desirable and provided in most modernrelays.

    It is usual to provide a definite time-delayed alarmsetting and an instantaneous or inverse time-delayedtrip setting, to match the withstand characteristics of the protected generator and transformer. It is veryimportant that the VT reference for overfluxingprotection is not the same as that used for the AVR.

    17.14.2 Under/Overfrequency

    The governor fitted to the prime mover normally providesprotection against overfrequency. Underfrequency mayoccur as a result of overload of generators operating onan isolated system, or a serious fault on the powersystem that results in a deficit of generation comparedto load. This may occur if a grid system suffers a majorfault on transmission lines linking two parts of thesystem, and the system then splits into two. It is likelythat one part will have an excess of generation over load,and the other will have a corresponding deficit.Frequency will fall fairly rapidly in the latter part, and thenormal response is load shedding, either by loadshedding relays or operator action. However, primemovers may have to be protected against excessively lowfrequency by tripping of the generators concerned.

    With some prime movers, operation in narrow frequencybands that lie close to normal running speed (eitherabove or below) may only be permitted for short periods,together with a cumulative lifetime duration of operation in such frequency bands. This typically occursdue to the presence of rotor torsional frequencies in suchfrequency bands. In such cases, monitoring of the periodof time spent in these frequency bands is required. Aspecial relay is fitted in such cases, arranged to providealarm and trip facilities if either an individual or

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    cumulative period exceeds a set time.

    17.15 ROTOR FAULTS

    The field circuit of a generator, comprising the fieldwinding of the generator and the armature of the exciter,

    together with any associated field circuit breaker if itexists, is an isolated d.c. circuit which is not normallyearthed. If an earth fault occurs, there will be no steady-state fault current and the need for action will not beevident.

    Danger arises if a second earth fault occurs at a separatepoint in the field system, to cause the high field currentto be diverted, in part at least, from the interveningturns. Serious damage to the conductors and possiblythe rotor can occur very rapidly under these conditions.

    More damage may be caused mechanically. If a largeportion of the winding is short-circuited, the flux mayadopt a pattern such as that shown in Figure 17.17. Theattracting force at the surface of the rotor is given by:

    where:

    A = area

    B = flux density

    It will be seen from Figure 17.17 that the flux isconcentrated on one pole but widely dispersed over theother and intervening surfaces. The attracting force is inconsequence large on one pole but very weak on theopposite one, while flux on the quadrature axis will

    F B A=2

    8

    produce a balancing force on this axis. The result is anunbalanced force that in a large machine may be of theorder of 50-100 tons. A violent vibration is set up thatmay damage bearing surfaces or even displace the rotorby an amount sufficient to cause it to foul the stator.

    17.15.1 Rotor Earth-Fault Protection

    Two methods are available to detect this type of fault.The first method is suitable for generators thatincorporate brushes in the main generator field winding.The second method requires at least a slip-ringconnection to the field circuit:

    a. potentiometer method

    b. a.c. injection method

    17.15.1.1 Potentiometer method

    This is a scheme that was fitted to older generators, and

    it is illustrated in Figure 17.18. An earth fault on thefield winding would produce a voltage across the relay,the maximum voltage occurring for faults at the ends of the winding.

    A blind spot' would exist at the centre of the fieldwinding. To avoid a fault at this location remainingundetected, the tapping point on the potentiometercould be varied by a pushbutton or switch. The relaysetting is typically about 5% of the exciter voltage.

    17.15.1.2 Injection methods

    Two methods are in common use. The first is based onlow frequency signal injection, with series filtering, asshown in Figure 17.19(a). It comprises an injectionsource that is connected between earth and one side of the field circuit, through capacitive coupling and themeasurement circuit. The field circuit is subjected to analternating potential at substantially the same levelthroughout. An earth fault anywhere in the field systemwill give rise to a current that is detected as anequivalent voltage across the adjustable resistor by therelay. The capacitive coupling blocks the normal d.c. fieldvoltage, preventing the discharge of a large directcurrent through the protection scheme. The combination

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    N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e 2 9 6

    Short CircuitField Winding

    Figure 17.17: Flux distribution on rotor with partial winding short circuit

    Fieldwinding I Exciter

    Figure 17.18: Earth fault protection of field circuit by potentiometer method

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    of series capacitor and reactor forms a low-pass tunedcircuit, the intention being to filter higher frequencyrotor currents that may occur for a variety of reasons.

    Other schemes are based on power frequency signalinjection. An impedance relay element is used, a fieldwinding earth fault reducing the impedance seen by the

    relay. These suffer the draw back of being susceptible tostatic excitation system harmonic currents when there issignificant field winding and excitation system shuntcapacitance.

    Greater immunity for such systems is offered bycapacitively coupling the protection scheme to both endsof the field winding, where brush or slip ring access ispossible (Figure 17.19(b)).

    The lowfrequency injection scheme is alsoadvantageous in that the current flow through the fieldwinding shunt capacitance will be lower than for apower frequency scheme. Such current would flowthrough the machine bearings to cause erosion of thebearing surface. For power frequency schemes, asolution is to insulate the bearings and provide anearthing brush for the shaft.

    17.15.2 Rotor Earth Fault Protectionfor Brushless Generators

    A brushless generator has an excitation systemconsisting of:

    1. a main exciter with rotating armature andstationary field windings

    2. a rotating rectifier assembly, carried on the mainshaft line out

    3. a controlled rectifier producing the d.c. fieldvoltage for the main exciter field from an a.c.source (often a small pilot exciter)

    Hence, no brushes are required in the generator fieldcircuit. All control is carried out in the field circuit of themain exciter. Detection of a rotor circuit earth fault isstill necessary, but this must be based on a dedicatedrotor-mounted system that has a telemetry link toprovide an alarm/data.

    17.15.3 Rotor Shorted Turn Protection

    As detailed in Section 17.15 a shorted section of fieldwinding will result in an unsymmetrical rotor fluxpattern and in potentially damaging rotor vibration.Detection of such an electrical fault is possible using aprobe consisting of a coil placed in the airgap. The fluxpattern of the positive and negative poles is measuredand any significant difference in flux pattern betweenthe poles is indicative of a shorted turn or turns.Automated waveform comparison techniques can beused to provide a protection scheme, or the waveformcan be inspected visually at regular intervals. Animmediate shutdown is not normally required unless theeffects of the fault are severe. The fault can be keptunder observation until a suitable shutdown for repaircan be arranged. Repair will take some time, since itmeans unthreading the rotor and dismantling thewinding.

    Since short-circuited turns on the rotor may causedamaging vibration and the detection of field faults forall degrees of abnormality is difficult, the provision of avibration a detection scheme is desirable this formspart of the mechanical protection of the generator.

    17.15.4 Protection against Diode Failure

    A short-circuited diode will produce an a.c. ripple in theexciter field circuit. This can be detected by a relaymonitoring the current in the exciter field circuit,however such systems have proved to be unreliable. Therelay would need to be time delayed to prevent an alarmbeing issued with normal field forcing during a powersystem fault. A delay of 5-10 seconds may be necessary.

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    N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e 2 9 7

    L.F. injectionsupply

    In ectionsupply

    ExciterGeneratorfieldwinding

    ExciterGeneratorfielwinding

    U

    (a) Low frequency a.c. voltage injection - current measurement

    Z

    (b) Power frequency a.c. voltage injection -impedance measurement

    Figure 17.19: Earth fault protectionof field circuit by a.c. injection

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    Fuses to disconnect the faulty diode after failure may befitted. The fuses are of the indicating type, and aninspection window can be fitted over the diode wheel toenable diode health to be monitored manually.

    A diode that fails open-circuit occurs less often. If thereis more than one diode in parallel for each arm of the

    diode bridge, the only impact is to restrict the maximumcontinuous excitation possible. If only a single diode perbridge arm is fitted, some ripple will be present on themain field supply but the inductance of the circuit willsmooth this to a degree and again the main effect is torestrict the maximum continuous excitation. The set canbe kept running until a convenient shutdown can bearranged.

    17.15.5 Field Suppression

    The need to rapidly suppress the field of a machine in

    which a fault has developed should be obvious, becauseas long as the excitation is maintained, the machine willfeed its own fault even though isolated from the powersystem. Any delay in the decay of rotor flux will extendthe fault damage. Braking the rotor is no solution,because of its large kinetic energy.

    The field winding current cannot be interruptedinstantaneously as it flows in a highly inductive circuit.Consequently, the flux energy must be dissipated toprevent an excessive inductive voltage rise in the fieldcircuit. For machines of moderate size, it is satisfactoryto open the field circuit with an air-break circuit breakerwithout arc blow-out coils. Such a breaker permits onlya moderate arc voltage, which is nevertheless highenough to suppress the field current fairly rapidly. Theinductive energy is dissipated partly in the arc and partlyin eddy-currents in the rotor core and damper windings.

    With generators above about 5MVA rating, it is better toprovide a more definite means of absorbing the energywithout incurring damage. Connecting a field dischargeresistorin parallel with the rotor winding before openingthe field circuit breaker will achieve this objective. Theresistor, which may have a resistance value of approximately five times the rotor winding resistance, isconnected by an auxiliary contact on the field circuitbreaker. The breaker duty is thereby reduced to that of opening a circuit with a low L/R ratio. After the breakerhas opened, the field current flows through the dischargeresistance and dies down harmlessly. The use of a fairlyhigh value of discharge resistance reduces the field timeconstant to an acceptably low value, though it may stillbe more than one second. Alternatively, generatorsfitted with static excitation systems may temporarilyinvert the applied field voltage to reduce excitationcurrent rapidly to zero before the excitation system istripped.

    17.16 LOSS OF EXCITATION PROTECTION

    Loss of excitation may occur for a variety of reasons. If the generator was initially operating at only 20%-30%of rated power, it may settle to run super-synchronouslyas an induction generator, at a low level of slip. In doingso, it will draw reactive current from the power system

    for rotor excitation. This form of response is particularlytrue of salient pole generators. In these circumstances,the generator may be able to run for several minuteswithout requiring to be tripped. There may be sufficienttime for remedial action to restore the excitation, but thereactive power demand of the machine during the failuremay severely depress the power system voltage to anunacceptable level. For operation at high initial poweroutput, the rotor speed may rise to approximately 105%of rated speed, where there would be low power outputand where a high reactive current of up to 2.0p.u. maybe drawn from the supply. Rapid automaticdisconnection is then required to protect the statorwindings from excessive current and to protect the rotorfrom damage caused by induced slip frequency currents.

    17.16.1 Protection against Loss of Excitation

    The protection used varies according to the size of generator being protected.

    17.16.1.1 Small generators

    On the smaller machines, protection againstasynchronous running has tended to be optional, but itmay now be available by default, where the functionalityis available within a modern numerical generatorprotection package. If fitted, it is arranged either toprovide an alarm or to trip the generator. If thegenerator field current can be measured, a relay elementcan be arranged to operate when this drops below apreset value. However, depending on the generatordesign and size relative to the system, it may well be thatthe machine would be required to operate synchronouslywith little or no excitation under certain systemconditions.

    The field undercurrent relay must have a setting belowthe minimum exciting current, which may be 8% of thatcorresponding to the MCR of the machine. Time delayrelays are used to stabilise the protection againstmaloperation in response to transient conditions and toensure that field current fluctuations due to pole slippingdo not cause the protection to reset.

    If the generator field current is not measurable, then thetechnique detailed in the following section is utilised.

    17.16.1.2 Large generators (>5MVA)

    For generators above about 5MVA rating, protectionagainst loss of excitation and pole slipping conditions isnormally applied.

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    Consider a generator connected to network, as shown inFigure 17.20. On loss of excitation, the terminal voltagewill begin to decrease and the stator current will increase,resulting in a decrease of impedance viewed from thegenerator terminals and also a change in power factor.

    A relay to detect loss of synchronism can be located atpoint A. It can be shown that the impedance presentedto the relay under loss of synchronism conditions (phaseswinging or pole slipping) is given by:

    Equation 17.2

    where:

    = angle by which E G leads E sIf the generator and system voltages are equal, the aboveexpression becomes:

    Z X X Z j

    X RG T S

    G =+ +( ) ( )

    1 2

    2

    cot

    n E E voltageG

    S= =

    generatedsystem

    Z X X Z n n j

    n

    X

    RG T S

    G

    =+ +( ) ( )

    ( ) +

    cos sin

    cos sin

    2 2

    The general case can be represented by a system of circles with centres on the line CD; see Figure 17.21.Also shown is a typical machine terminal impedancelocus during loss of excitation conditions.

    The special cases of E G =E S and E G =0 result in a

    straight-line locus that is the right-angled bisector of CD, and in a circular locus that is shrunk to point C ,respectively.

    When excitation is removed from a generator operatingsynchronously the flux dies away slowly, during whichperiod the ratio of E G /E S is decreasing, and the rotor angleof the machine is increasing. The operating conditionplotted on an impedance diagram therefore travels alonga locus that crosses the power swing circles. At the sametime, it progresses in the direction of increasing rotorangle. After passing the anti-phase position, the locusbends round as the internal e.m.f. collapses, condensing on

    an impedance value equal to the machine reactance. Thelocus is illustrated in Figure 17.21.

    The relay location is displaced from point C by thegenerator reactance X G . One problem in determining theposition of these loci relative to the relay location is thatthe value of machine impedance varies with the rate of slip. At zero slip X G is equal to X d, the synchronousreactance, and at 100% slip X G is equal to X

    d, the sub-transient reactance. The impedance in a typical case hasbeen shown to be equal to X d, the transient reactance,at 50% slip, and to 2X d with a slip of 0.33%. The sliplikely to be experienced with asynchronous running is

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    +jX

    -jX

    +R-R

    0.5

    0.6

    .7

    C

    5.0

    2.5

    2.0

    1.8

    Load point

    Loss of fieldlocus

    =1 E S

    E G

    =1.5 E

    S

    E G

    D

    Figure 17.21: Swing curves and loss of synchronism locus

    E G X G

    S

    R

    X T

    X G

    -jX

    A

    C

    Z S

    X G T + S

    +R-R

    E S X T

    +jX

    A

    D

    E G E S

    1

    Figure 17.20: Basic interconnected system

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    low, perhaps 1%, so that for the purpose of assessing thepower swing locus it is sufficient to take the value

    X G =2X

    d.

    This consideration has assumed a single value for X G .However, the reactance X q on the quadrature axis differsfrom the direct-axis value, the ratio of X d/ X g being

    known as the saliency factor. This factor varies with theslip speed. The effect of this factor during asynchronousoperation is to cause X G to vary at slip speed. Inconsequence, the loss of excitation impedance locusdoes not settle at a single point, but it continues todescribe a small orbit about a mean point.

    A protection scheme for loss of excitation must operatedecisively for this condition, but its characteristic mustnot inhibit stable operation of the generator. One limitof operation corresponds to the maximum practicablerotor angle, taken to be at 120 . The locus of operationcan be represented as a circle on the impedance plane,

    as shown in Figure 17.22, stable operation conditionslying outside the circle.

    On the same diagram the full load impedance locus forone per unit power can be drawn. Part of this circlerepresents a condition that is not feasible, but the pointof intersection with the maximum rotor angle curve canbe taken as a limiting operating condition for settingimpedance-based loss of excitation protection.

    17.16.2 Impedance-Based Protection Characteristics

    Figure 17.21 alludes to the possibility that a protection

    scheme for loss of excitation could be based onimpedance measurement. The impedance characteristicmust be appropriately set or shaped to ensure decisiveoperation for loss of excitation whilst permitting stablegenerator operation within allowable limits. One or twooffset mho under impedance elements (see Chapter 11for the principles of operation) are ideally suited forproviding loss of excitation protection as long as agenerator operating at low power output (20-30% P n)does not settle down to operate as an inductiongenerator. The characteristics of a typical two-stage lossof excitation protection scheme are illustrated in Figure17.23. The first stage, consisting of settings X a1 and X b1can be applied to provide detection of loss of excitationeven where a generator initially operating at low poweroutput (20-30% P n) might settle down to operate as aninduction generator.

    Pick-up and drop-off time delays t d1 and t do1 areassociated with this impedance element. Timer t d1 isused to prevent operation during stable power swingsthat may cause the impedance locus of the generator totransiently enter the locus of operation set by X b1.However, the value must short enough to preventdamage as a result of loss of excitation occurring. If pole-slipping protection is not required (see Section17.17.2), timer t do1 can be set to give instantaneousreset. The second field failure element, comprisingsettings X b1, X b2, and associated timers t d2 and t do2 canbe used to give instantaneous tripping following loss of excitation under full load conditions.

    17.16.3 Protection Settings

    The typical setting values for the two elements varyaccording to the excitation system and operating regimeof the generator concerned, since these affect thegenerator impedance seen by the relay under normal andabnormal conditions. For a generator that is never

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    N e t w o r k P r o t e c t i o n & A u t o m a t i o n G u i d e 3 0 0

    Normal machine operating impedance

    R

    X 1 X b2

    -X a1-X 2

    X

    Alarmangle

    Figure 17.23: Loss of excitation protectioncharacteristics

    +R-R

    +jX

    S

    X T

    X

    X d

    -jX

    Limitinggenerationpoint

    Relay

    Diameter = d /

    Locus of constant MV

    Locus of constant load angle

    Figure 17.22: Locus of limiting operating conditions of synchronous machine

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    operated at leading power factor, or at load angles inexcess of 90 th