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Chap17-280-315 17/06/02 10:43 Page 280 • 17 • Generator and Generator Transformer Protection 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 generator –transformer units 17.6 Overcurrent protection 17.7 Stator earth fault protection 17.8 Overvoltage protection 17.9 Undervoltage protection 17.10 Low forward power/reverse power 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 17.18 Mechanical faults 17.19 Complete generator protection schemes 17.20 Embedded generation 17.21 Examples of generator protection settings 17.22 Chap17-280-315 17/06/02 10:44 Page 281 • 17 • Generator and Generator-Transformer P rotection 17.1 INTRODUCTION The core of an electric power system is the generation. With the exception of emerging fuel cell and solar-cell technology for power systems, the conversion of the fundamental energy into its electrical equivalent normally requires a 'prime mover' to develop mechanical power as an intermediate stage. The nature of this machine depends upon the source of energy and in turn this has some bearing on the design of the generator. Generators based on steam, gas, water or wind turbines, and reciprocating combustion engines are all in use. Electrical ratings extend from a few hundred kVA (or even less) for reciprocating engine and renewable energy sets, up to steam turbine sets exceeding 1200MVA. Small and medium sized sets may be directly connected to a power distribution system. A larger set may be associated with an individual transformer, through which it is coupled to the EHV primary transmission system. Switchgear may or may not be provided between the generator and transformer. In some cases, operational and economic advantages can be attained by providing a generator circuit breaker in addition to a high voltage circuit breaker, but special demands will be placed on the 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 the interconnection between generator and transformer for the supply of power to auxiliary plant, as shown in Figure 17.1. The unit transformer could be of the order of 10% of the unit rating for a large fossil-fuelled steam set with additional flue-gas desulphurisation plant, but it may only be of the order of 1% of unit rating for a hydro set. Network Protection & Automation Guide • 281 • Chap17-280-315 17/06/02 10:44 Page 282 required. The amount of protection applied will be Generator Main transformer governed by economic considerations, taking into account the value of the machine, and the value of its output to the plant owner. HV busbars The following problems require consideration from the Unit transformer point of view of applying protection: a. stator electrical faults Auxiliary b. overload supplies switchboard c. overvoltage Figure 17.1: Generator-transformer unit d. unbalanced loading Industrial or commercial plants with a requirement for e. overfluxing steam/hot water now often include generating plant f. inadvertent energisation Generator and Generator-Transfor mer P rotection utilising or producing steam to improve overall e. rotor electrical faults economics, as a Combined Heat and Power (CHP) scheme. The plant will typically have a connection to the f. loss of excitation public Utility distribution system, and such generation is g. loss of synchronism referred to as 'embedded' generation. The generating plant may be capable of export of surplus power, or h. failure of prime mover simply reduce the import of power from the Utility. This j. lubrication oil failure is shown in Figure 17.2. l. overspeeding Utility m. rotor distortion n. difference in expansion between rotating and stationary parts o. excessive vibration PCC Generator p. core lamination faults Rating: yMW 17.2 GENERATOR EARTHING Industrial plant The neutral point of a generator is usually earthed to main busbar facilitate protection of the stator winding and associated system. Earthing also prevents damaging transient overvoltages in the event of an arcing earth fault or ferroresonance. • 17 • For HV generators, impedance is usually inserted in the Plant feeders - total stator earthing connection to limit the magnitude of demand: xMW earth fault current. There is a wide variation in the earth PCC: Point of Common Coupling fault current chosen, common values being: When plant generator is running: If y>x, Plant may export to Utility across PCC 1. rated current If x>y, Plant max demand from Utility is reduced 2. 200A-400A (low impedance earthing) Figure 17.2: Embedded generation 3. 10A-20A (high impedance earthing) The main methods of impedance-earthing a generator A modern generating unit is a complex system are shown in Figure 17.3. Low values of earth fault comprising the generator stator winding, associated current may limit the damage caused from a fault, but transformer and unit transformer (if present), the rotor they simultaneously make detection of a fault towards with its field winding and excitation system, and the the stator winding star point more difficult. Except for prime mover with its associated auxiliaries. Faults of special applications, such as marine, LV generators are many kinds can occur within this system for which normally solidly earthed to comply with safety diverse forms of electrical and mechanical protection are requirements. Where a step-up transformer is applied, • 282 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:44 Page 283 the generator and the lower voltage winding of the sufficient that the transformer be designed to have a transformer can be treated as an isolated system that is primary winding knee-point e.m.f. equal to 1.3 times the not influenced by the earthing requirements of the generator rated line voltage. power system. 17.3 STATOR WINDING FAULTS Failure of the stator windings or connection insulation can result in severe damage to the windings and stator (a) Direct earthing core. The extent of the damage will depend on the magnitude and duration of the fault current. Typical setting (% of earthing resistor rating) I>> 10 17.3.1 Earth Faults I> 5 The most probable mode of insulation failure is phase to Generator and Generator-Transfor mer P rotection earth. Use of an earthing impedance limits the earth (b) Resistance earthing fault current and hence stator damage. An earth fault involving the stator core results in burning of the iron at the point of fault and welds laminations Loading together. Replacement of the faulty conductor may not U> resistor be a very serious matter (dependent on set rating/voltage/construction) but the damage to the core (c) Distribution transformer earthing with overvoltage relay. cannot be ignored, since the welding of laminations may result in local overheating. The damaged area can sometimes be repaired, but if severe damage has occurred, a partial core rebuild will be necessary. A Loading flashover is more likely to occur in the end-winding resistor region, where electrical stresses are highest. The resultant forces on the conductors would be very large I> and they may result in extensive damage, requiring the (d) Distribution transformer earthing partial or total rewinding of the generator. Apart from with overcurrent relay burning the core, the greatest danger arising from failure to quickly deal with a fault is fire. A large portion of the Figure 17.3: Methods of generator earthing insulating material is inflammable, and in the case of an air-cooled machine, the forced ventilation can quickly An earthing transformer or a series impedance can be cause an arc flame to spread around the winding. Fire used as the impedance. If an earthing transformer is will not occur in a hydrogen-cooled machine, provided used, the continuous rating is usually in the range 5- the stator system remains sealed. In any case, the length 250kVA. The secondary winding is loaded with a resistor of an outage may be considerable, resulting in major of a value which, when referred through the transformer turns ratio, will pass the chosen short-time earth-fault financial impact from loss of generation revenue and/or • 17 • import of additional energy. current. This is typically in the range of 5-20A. The resistor prevents the production of high transient overvoltages in the event of an arcing earth fault, which 17.3.2 Phase-Phase Faults it does by discharging the bound charge in the circuit capacitance. For this reason, the resistive component of Phase-phase faults clear of earth are less common; they fault current should not be less than the residual may occur on the end portion of stator coils or in the capacitance current. This is the basis of the design, and slots if the winding involves two coil sides in the same in practice values of between 3-5 Ico are used. slot. In the latter case, the fault will involve earth in a very short time. Phase fault current is not limited by the It is important that the earthing transformer never method of earthing the neutral point. becomes saturated; otherwise a very undesirable condition of ferroresonance may occur. The normal rise of the generated voltage above the rated value caused by 17.3.3 Interturn Faults a sudden loss of load or by field forcing must be considered, as well as flux doubling in the transformer Interturn faults are rare, but a significant fault-loop due to the point-on-wave of voltage application. It is current can arise where such a fault does occur. Network Protection & Automation Guide • 283 • Chap17-280-315 17/06/02 10:44 Page 284 Conventional generator protection systems would be calculation, after measurement of the individual CT blind to an interturn fault, but the extra cost and secondary currents. In such relay designs, there is full complication of providing detection of a purely interturn galvanic separation of the neutral-tail and terminal CT fault is not usually justified. In this case, an interturn secondary circuits, as indicated in Figure 17.5(a). This is fault must develop into an earth fault before it can be not the case for the application of high-impedance cleared. An exception may be where a machine has an differential protection. This difference can impose some abnormally complicated or multiple winding special relay design requirements to achieve stability for arrangement, where the probability of an interturn fault biased differential protection in some applications. might be increased. 17.5.1 Biased Differential Protection 17.4 STATOR WINDING PROTECTION The relay connections for this form of protection are To respond quickly to a phase fault with damaging heavy shown in Figure 17.5(a) and a typical bias characteristic current, sensitive, high-speed differential protection is is shown in Figure 17.5(b). The differential current Generator and Generator-Transfor mer P rotection normally applied to generators rated in excess of 1MVA. threshold setting Is1 can be set as low as 5% of rated For large generating units, fast fault clearance will also generator current, to provide protection for as much of maintain stability of the main power system. The zone the winding as possible. The bias slope break-point of differential protection can be extended to include an threshold setting Is2 would typically be set to a value associated step-up transformer. For smaller generators, above generator rated current, say 120%, to achieve IDMT/instantaneous overcurrent protection is usually the external fault stability in the event of transient only phase fault protection applied. Sections 17.5-17.8 asymmetric CT saturation. Bias slope K2 setting would detail the various methods that are available for stator typically be set at 150%. winding protection. I1 I2 17.5 DIFFERENTIAL PROTECTION OF DIRECT CONNECTED GENERATORS The theory of circulating current differential protection is discussed fully in Section 10.4. Stator A (a): Relay connections for biased differential protection B C Idiff ff = I1+I2 I Operate K2 IS1 K1 Restrain • 17 • Id> Id> Id> IS2 I1+ IBIAS = 2 (b) Biased differential operating characteristic Figure 17.4: Stator differential protection Figure 17.5: Typical generator biased differential protection High-speed phase fault protection is provided, by use of the connections shown in Figure 17.4. This depicts the 17.5.2 High Impedance Differential Protection derivation of differential current through CT secondary circuit connections. This protection may also offer earth This differs from biased differential protection by the fault protection for some moderate impedance-earthed manner in which relay stability is achieved for external applications. Either biased differential or high faults and by the fact that the differential current must impedance differential techniques can be applied. A be attained through the electrical connections of CT subtle difference with modern, biased, numerical secondary circuits. If the impedance of each relay in generator protection relays is that they usually derive the Figure 17.4 is high, the event of one CT becoming differential currents and biasing currents by algorithmic saturated by the through fault current (leading to a • 284 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:44 Page 285 relatively low CT impedance), will allow the current from To calculate the primary operating current, the following the unsaturated CT to flow mainly through the saturated expression is used: CT rather than through the relay. This provides the Iop = N x (Is1 + nIe) required protection stability where a tuned relay element is employed. In practice, external resistance is added to where: the relay circuit to provide the necessary high Iop = primary operating current impedance. The principle of high-impedance protection application is illustrated in Figure 17.6, together with a N = CT ratio summary of the calculations required to determine the Is1 = relay setting value of external stabilising resistance. n = number of CT's in parallel with relay element Ie = CT magnetising current at Vs Healthy CT Saturated CT Protected zone Is1 is typically set to 5% of generator rated secondary Zm current. Generator and Generator-Transfor mer P rotection RCT1 RCT2 It can be seen from the above that the calculations for the application of high impedance differential protection RL1 If RL3 are more complex than for biased differential protection. Rst However, the protection scheme is actually quite simple Vr and it offers a high level of stability for through faults Id > RL2 RL4 and external switching events. Voltage across relay circuit Vr = If (RCT + 2RL) and Vs = KVr With the advent of multi-function numerical relays and where 1.0<K≤1.5 with a desire to dispense with external components, high Stabilising resistor, Rst, limits spill current to <Is (relay setting) V impedance differential protection is not as popular as Rst = s -RR Is biased differential protection in modern relaying when RR = relay burden practice. Figure 17.6: Principle of high impedance differential protection 17.5.3 CT Requirements In some applications, protection may be required to limit voltages across the CT secondary circuits when the The CT requirements for differential protection will vary differential secondary current for an internal phase fault according to the relay used. Modern numerical relays flows through the high impedance relay circuit(s), but may not require CT's specifically designed for differential this is not commonly a requirement for generator protection to IEC 60044-1 class PX (or BS 3938 class X). differential applications unless very high impedance However, requirements in respect of CT knee-point relays are applied. Where necessary, shunt–connected, voltage will still have to be checked for the specific non-linear resistors, should be deployed, as shown in relays used. High impedance differential protection may Figure 17.7. be more onerous in this respect than biased differential protection. Many factors affect this, including the other protection • 17 • functions fed by the CT's and the knee-point requirements of the particular relay concerned. Relay manufacturers are able to provide detailed guidance on this matter. NLR NLR V 17.6 DIFFERENTIAL PROTECTION OF GENERATOR-TRANSFORMERS Rst A common connection arrangement for large generators NLR = Non-linear resistance (Metrosil) is to operate the generator and associated step-up transformer as a unit without any intervening circuit Figure 17.7: Relay connections for high breaker. The unit transformer supplying the generator impedance differential protection auxiliaries is tapped off the connection between generator and step-up transformer. Differential protection can be arranged as follows. Network Protection & Automation Guide • 285 • Chap17-280-315 17/06/02 10:44 Page 286 17.6.1 Generator/Step-up Transformer transformer rating is extremely low in relation to the Differential Protection generator rating, e.g. for some hydro applications. The location of the third set of current transformers is The generator stator and step-up transformer can be protected by a single zone of overall differential normally on the primary side of the unit transformer. If protection (Figure 17.8). This will be in addition to located on secondary side of the unit transformer, they differential protection applied to the generator only. The would have to be of an exceptionally high ratio, or current transformers should be located in the generator exceptionally high ratio interposing CT's would have to neutral connections and in the transformer HV be used. Thus, the use of secondary side CT's is not to be connections. Alternatively, CT's within the HV recommended. One advantage is that unit transformer switchyard may be employed if the distance is not faults would be within the zone of protection of the technically prohibitive. Even where there is a generator generator. However, the sensitivity of the generator circuit breaker, overall differential protection can still be protection to unit transformer phase faults would be provided if desired. considered inadequate, due to the relatively low rating of the transformer in relation to that of the generator. Generator and Generator-Transfor mer P rotection Thus, the unit transformer should have its own differential protection scheme. Protection for the unit Main Generator transformer transformer is covered in Chapter 16, including methods for stabilising the protection against magnetising inrush conditions. Protected zone HV busbars Id> 17.7 OVERCURRENT PROTECTION Overcurrent protection of generators may take two forms. Plain overcurrent protection may be used as the principle form of protection for small generators, and back-up protection for larger ones where differential protection is used as the primary method of generator Figure 17.8: Overall generator-transformer stator winding protection. Voltage dependent differential protection overcurrent protection may be applied where differential protection is not justified on larger generators, or where problems are met in applying plain overcurrent The current transformers should be rated according to protection. Section 16.8.2. Since a power transformer is included within the zone of protection, biased transformer differential protection, with magnetising inrush restraint 17.7.1 Plain Overcurrent Protection should be applied, as discussed in Section 16.8.5. Transient overfluxing of the generator transformer may It is usual to apply time-delayed plain overcurrent arise due to overvoltage following generator load protection to generators. For generators rated less than rejection. In some applications, this may threaten the 1MVA, this will form the principal stator winding • 17 • stability of the differential protection. In such cases, protection for phase faults. For larger generators, consideration should be given to applying protection overcurrent protection can be applied as remote back-up with transient overfluxing restraint/blocking (e.g. based protection, to disconnect the unit from any uncleared on a 5th harmonic differential current threshold). external fault. Where there is only one set of differential Protection against sustained overfluxing is covered in main protection, for a smaller generator, the overcurrent Section 17.14. protection will also provide local back-up protection for the protected plant, in the event that the main protection fails to operate. The general principles of 17.6.2 Unit Transformer Differential Protection setting overcurrent relays are given in Chapter 9. The current taken by the unit transformer must be In the case of a single generator feeding an isolated allowed for by arranging the generator differential system, current transformers at the neutral end of the protection as a three-ended scheme. Unit transformer machine should energise the overcurrent protection, to current transformers are usually applied to balance the allow a response to winding fault conditions. Relay generator differential protection and prevent the unit characteristics should be selected to take into account transformer through current being seen as differential the fault current decrement behaviour of the generator, current. An exception might be where the unit with allowance for the performance of the excitation • 286 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:44 Page 287 system and its field-forcing capability. Without the The choice depends upon the power system provision of fault current compounding from generator characteristics and level of protection to be provided. CT's, an excitation system that is powered from an Voltage-dependent overcurrent relays are often found excitation transformer at the generator terminals will applied to generators used on industrial systems as an exhibit a pronounced fault current decrement for a alternative to full differential protection. terminal fault. With failure to consider this effect, the 220.127.116.11 Voltage controlled overcurrent protection potential exists for the initial high fault current to decay to a value below the overcurrent protection pick-up Voltage controlled overcurrent protection has two setting before a relay element can operate, unless a low time/current characteristics which are selected according current setting and/or time setting is applied. The to the status of a generator terminal voltage measuring protection would then fail to trip the generator. The element. The voltage threshold setting for the switching settings chosen must be the best compromise between element is chosen according to the following criteria. assured operation in the foregoing circumstances and 1. during overloads, when the system voltage is discrimination with the system protection and passage sustained near normal, the overcurrent protection of normal load current, but this can be impossible with Generator and Generator-Transfor mer P rotection should have a current setting above full load current plain overcurrent protection. and an operating time characteristic that will prevent In the more usual case of a generator that operates in the generating plant from passing current to a remote parallel with others and which forms part of an extensive external fault for a period in excess of the plant short- interconnected system, back-up phase fault protection time withstand limits for a generator and its transformer will be provided by HV 2. under close-up fault conditions, the busbar voltage overcurrent protection. This will respond to the higher- must fall below the voltage threshold so that the level backfeed from the power system to a unit fault. second protection characteristic will be selected. This Other generators in parallel would supply this current characteristic should be set to allow relay operation and, being stabilised by the system impedance, it will not with fault current decrement for a close-up fault at suffer a major decrement. This protection is usually a the generator terminals or at the HV busbars. The requirement of the power system operator. Settings must protection should also time-grade with external be chosen to prevent operation for external faults fed by circuit protection. There may be additional infeeds to the generator. It is common for the HV overcurrent an external circuit fault that will assist with grading protection relay to provide both time-delayed and instantaneous high-set elements. The time-delayed Typical characteristics are shown in Figure 17.9. elements should be set to ensure that the protected items of plant cannot pass levels of through fault current in excess of their short-time withstand limits. The Current pick-up level instantaneous elements should be set above the maximum possible fault current that the generator can supply, but less than the system-supplied fault current in I> the event of a generator winding fault. This back-up protection will minimise plant damage in the event of main protection failure for a generating plant fault and instantaneous tripping for an HV-side fault will aid the KI> • 17 • recovery of the power system and parallel generation. 17.7.2 Voltage-Dependent Overcurrent Protection Vs Voltage level The plain overcurrent protection setting difficulty Figure 17.9: Voltage controlled relay referred to in the previous section arises because characteristics allowance has to be made both for the decrement of the generator fault current with time and for the passage of 22.214.171.124 Voltage restrained overcurrent protection full load current. To overcome the difficulty of The alternative technique is to continuously vary the discrimination, the generator terminal voltage can be relay element pickup setting with generator voltage measured and used to dynamically modify the basic relay variation between upper and lower limits. The voltage is current/time overcurrent characteristic for faults close to said to restrain the operation of the current element. the generating plant. There are two basic alternatives for the application of voltage-dependent overcurrent The effect is to provide a dynamic I.D.M.T. protection protection, which are discussed in the following sections. characteristic, according to the voltage at the machine Network Protection & Automation Guide • 287 • Chap17-280-315 17/06/02 10:46 Page 288 terminals. Alternatively, the relay element may be considerations. regarded as an impedance type with a long dependent 22.214.171.124 Sensitive earth fault protection time delay. In consequence, for a given fault condition, the relay continues to operate more or less This method is used in the following situations: independently of current decrement in the machine. A a. direct-connected generators operating in parallel typical characteristic is shown in Figure 17.10. b. generators with high-impedance neutral earthing, the earth fault current being limited to a few tens of amps Current pick-up level c. installations where the resistance of the ground fault path is very high, due to the nature of the I> ground In these cases, conventional earth fault protection as described in Section 184.108.40.206 is of little use. Generator and Generator-Transfor mer P rotection KI> The principles of sensitive earth fault protection are described in Sections 9.17.1, 9.18 and 9.19. The earth fault (residual) current can be obtained from residual connection of line CT's, a line-connected CBCT, or a CT in VS2 VS1 Voltage level the generator neutral. The latter is not possible if directional protection is used. The polarising voltage is Figure 17.10: Voltage restrained relay usually the neutral voltage displacement input to the characteristics relay, or the residual of the three phase voltages, so a 17.8 STATOR EARTH FAULT PROTECTION suitable VT must be used. For Petersen Coil earthing, a wattmetric technique (Section 9.19) can also be used. Earth fault protection must be applied where impedance earthing is employed that limits the earth fault current For direct connected generators operating in parallel, to less than the pick-up threshold of the overcurrent directional sensitive earth fault protection may be and/or differential protection for a fault located down to necessary. This is to ensure that a faulted generator will the bottom 5% of the stator winding from the star- be tripped before there is any possibility of the neutral point. The type of protection required will depend on the overcurrent protection tripping a parallel healthy method of earthing and connection of the generator to generator. When being driven by residually-connected the power system. phase CT's, the protection must be stabilised against incorrect tripping with transient spill current in the event of asymmetric CT saturation when phase fault or 17.8.1 Direct-Connected Generators magnetising inrush current is being passed. Stabilising techniques include the addition of relay circuit A single direct-connected generator operating on an impedance and/or the application of a time delay. Where isolated system will normally be directly earthed. the required setting of the protection is very low in However, if several direct-connected generators are • 17 • comparison to the rated current of the phase CT's, it operated in parallel, only one generator is normally would be necessary to employ a single CBCT for the earth earthed at a time. For the unearthed generators, a fault protection to ensure transient stability. simple measurement of the neutral current is not possible, and other methods of protection must be used. Since any generator in the paralleled group may be The following sections describe the methods available. earthed, all generators will require to be fitted with both 18.104.22.168 Neutral overcurrent protection neutral overcurrent protection and sensitive directional earth fault protection. With this form of protection, a current transformer in the neutral-earth connection energises an overcurrent relay The setting of the sensitive directional earth fault element. This provides unrestricted earth-fault protection is chosen to co-ordinate with generator protection and so it must be graded with feeder differential protection and/or neutral voltage protection. The relay element will therefore have a time- displacement protection to ensure that 95% of the stator delayed operating characteristic. Grading must be winding is protected. Figure 17.11 illustrates the carried out in accordance with the principles detailed in complete scheme, including optional blocking signals Chapter 9. The setting should not be more than 33% of where difficulties in co-ordinating the generator and the maximum earth fault current of the generator, and a downstream feeder earth-fault protection occur. lower setting would be preferable, depending on grading • 288 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:46 Page 289 sum residually. Feeder * Optional interlocked I > I >> earth-fault protection As the protection is still unrestricted, the voltage setting if grading problems exist of the relay must be greater than the effective setting of any downstream earth-fault protection. It must also be time-delayed to co-ordinate with such protection. Sometimes, a second high-set element with short time delay is used to provide fast-acting protection against major winding earth-faults. Figure 17.12 illustrates the I > Ursd I > Ursd > Block* Block* possible connections that may be used. I > I > Open Re Re Generator and Generator-Transfor mer P rotection V 2 Minimum earth fault level = IF Re Figure 17.11: Comprehensive earth-fault 3 1 protection scheme for direct-connected Va generators operating in parallel Vb c For cases (b) and (c) above, it is not necessary to use a Vn directional facility. Care must be taken to use the correct 1 Derived from phase neutral voltages RCA setting – for instance if the earthing impedance is 2 Measured from earth impedance mainly resistive, this should be 0°. On insulated or very 3 Measured from broken delta VT high impedance earthed systems, an RCA of -90° would be used, as the earth fault current is predominately Figure 17.12: Neutral voltage displacement capacitive. protection 17.8.2 Indirectly-Connected Generators Directional sensitive earth-fault protection can also be used for detecting winding earth faults. In this case, the As noted in Section 17.2, a directly-earthed generator- relay element is applied to the terminals of the generator transformer unit cannot interchange zero-sequence and is set to respond to faults only within the machine current with the remainder of the network, and hence an windings. Hence earth faults on the external system do earth fault protection grading problem does not exist. not result in relay operation. However, current flowing The following sections detail the protection methods for from the system into a winding earth fault causes relay the various forms of impedance earthing of generators. operation. It will not operate on the earthed machine, so 22.214.171.124 High resistance earthing – neutral overcurrent that other types of earth fault protection must also be protection applied. All generators must be so fitted, since any can be operated as the earthed machine. A current transformer mounted on the neutral-earth • 17 • conductor can drive an instantaneous and/or time 184.108.40.206 Neutral voltage displacement protection delayed overcurrent relay element, as shown in Figure In a balanced network, the addition of the three phase- 17.13. It is impossible to provide protection for the whole earth voltages produces a nominally zero residual of the winding, and Figure 17.13 also details how the voltage, since there would be little zero sequence voltage percentage of winding covered can be calculated. For a present. Any earth fault will set up a zero sequence relay element with an instantaneous setting, protection is system voltage, which will give rise to a non-zero typically limited to 90% of the winding. This is to ensure residual voltage. This can be measured by a suitable that the protection will not maloperate with zero relay element. The voltage signal must be derived from sequence current during operation of a primary fuse for a a VT that is suitable – i.e. it must be capable of VT earth fault or with any transient surge currents that transforming zero-sequence voltage, so 3-limb types and could flow through the interwinding capacitance of the those without a primary earth connection are not step-up transformer for an HV system earth fault. suitable. This unbalance voltage provides a means of A time-delayed relay is more secure in this respect, and it detecting earth faults. The relay element must be may have a setting to cover 95% of the stator winding. insensitive to third harmonic voltages that may be Since the generating units under consideration are usually present in the system voltage waveforms, as these will large, instantaneous and time delayed relay elements are Network Protection & Automation Guide • 289 • Chap17-280-315 17/06/02 10:46 Page 290 often applied, with settings of 10% and 5% of maximum earth fault current respectively; this is the optimum compromise in performance. The portion of the winding left unprotected for an earth fault is at the neutral end. Since the voltage to earth at this end of the winding is low, the probability of an earth fault occurring is also low. Hence additional protection is often not applied. Loading resistor V I> (a) Protection using a current element Generator and Generator-Transfor mer P rotection a If Is R aV Loading U> If = R resistor IsR amin = V %covered 1-a in ) x 1100% (b) Protection using a voltage element generator stator winding using a current element Figure 17.14: Generator winding earth-fault protection - distribution transformer earthing Figure 17.13: Earth fault protection of high-resistance earthed generator stator winding using a current element 184.108.40.206 Distribution transformer earthing 22.214.171.124 Distribution transformer earthing using a voltage element using a current element Earth fault protection can also be provided using a voltage- In this arrangement, shown in Figure 17.14(a), the measuring element in the secondary circuit instead. The generator is earthed via the primary winding of a setting considerations would be similar to those for the distribution transformer. The secondary winding is fitted current operated protection, but transposed to voltage. with a loading resistor to limit the earth fault current. The circuit diagram is shown in Figure 17.14(b). An overcurrent relay element energised from a current Application of both voltage and current operated transformer connected in the resistor circuit is used to elements to a generator with distribution transformer • 17 • measure secondary earth fault current. The relay should earthing provides some advantages. The current have an effective setting equivalent to 5% of the operated function will continue to operate in the event maximum earth fault current at rated generator voltage, of a short-circuited loading resistor and the voltage in order to protect 95% of the stator winding. The relay protection still functions in the event of an open- element response to third harmonic current should be circuited resistor. However, neither scheme will operate limited to prevent incorrect operation when a sensitive in the event of a flashover on the primary terminals of setting is applied. the transformer or of the neutral cable between the generator and the transformer during an earth fault. A As discussed in Section 18.104.22.168 for neutral overcurrent CT could be added in the neutral connection close to the protection, the protection should be time delayed when generator, to energise a high-set overcurrent element to a sensitive setting is applied, in order to prevent detect such a fault, but the fault current would probably maloperation under transient conditions. It also must be high enough to operate the phase differential grade with generator VT primary protection (for a VT protection. primary earth fault). An operation time in the range 0.5s-3s is usual. Less sensitive instantaneous protection 18.104.22.168 Neutral voltage displacement protection can also be applied to provide fast tripping for a heavier This can be applied in the same manner as for direct- earth fault condition. connected generators (Section 188.8.131.52). The only • 290 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:46 Page 291 difference is that the are no grading problems as the protection of a generator, using three residually protection is inherently restricted. A sensitive setting connected phase CT's balanced against a similar single can therefore be used, enabling cover of up to 95% of CT in the neutral connection. Settings of the order of 5% the stator winding to be achieved. of maximum earth fault current at the generator terminals are typical. The usual requirements in respect of stabilising resistor and non-linear resistor to guard 17.8.3 Restricted Earth Fault Protection against excessive voltage across the relay must be taken, This technique can be used on small generators not fitted where necessary. with differential protection to provide fast acting earth fault protection within a defined zone that encompasses the generator. It is cheaper than full differential 17.8.4 Earth Fault Protection for protection but only provides protection against earth the Entire Stator Winding faults. The principle is that used for transformer REF All of the methods for earth fault protection detailed so protection, as detailed in Section 16.7. However, in far leave part of the winding unprotected. In most cases, Generator and Generator-Transfor mer P rotection contrast to transformer REF protection, both biased low- this is of no consequence as the probability of a fault impedance and high-impedance techniques can be used. occurring in the 5% of the winding nearest the neutral 220.127.116.11 Low-impedance biased REF protection connection is very low, due to the reduced phase to earth voltage. However, a fault can occur anywhere along the This is shown in Figure 17.15. The main advantage is stator windings in the event of insulation failure due to that the neutral CT can also be used in a modern relay to localised heating from a core fault. In cases where provide conventional earth-fault protection and no protection for the entire winding is required, perhaps for external resistors are used. Relay bias is required, as alarm only, there are various methods available. described in Section 10.4.2, but the formula for calculating the bias is slightly different and also shown 22.214.171.124 Measurement of third harmonic voltage in Figure 17.15. One method is to measure the internally generated third harmonic voltage that appears across the earthing Phase CT ratio 1000/1 Phase A impedance due to the flow of third harmonic currents Phase B through the shunt capacitance of the stator windings Phase C etc. When a fault occurs in the part of the stator Neutral CT ratio winding nearest the neutral end, the third harmonic 200/1 / voltage drops to near zero, and hence a relay element that responds to third harmonic voltage can be used to detect the condition. As the fault location moves progressively away from the neutral end, the drop in third harmonic voltage from healthy conditions becomes less, so that at around 20-30% of the winding distance, it no longer becomes possible to discriminate between a (highest of IA B, I Nx scaling factor) healthy and a faulty winding. Hence, a conventional IBIAS = 2 200 earth-fault scheme should be used in conjunction with a where scaling factor = = 1000 = 0.2 third harmonic scheme, to provide overlapping cover • 17 • IDIFF = IA IB IC (scaling factor IN ) of the entire stator winding. The measurement of third harmonic voltage can be taken either from a star-point Figure 17.15: Low impedance biased REF protection of a generator VT or the generator line VT. In the latter case, the VT must be capable of carrying residual flux, and this The initial bias slope is commonly set to 0% to provide prevents the use of 3-limb types. If the third harmonic maximum sensitivity, and applied up to the rated current voltage is measured at the generator star point, an of the generator. It may be increased to counter the undervoltage characteristic is used. An overvoltage effects of CT mismatch. The bias slope above generator characteristic is used if the measurement is taken from rated current is typically set to 150% of rated value. The the generator line VT. For effective application of this initial current setting is typically 5% of the minimum form of protection, there should be at least 1% third earth fault current for a fault at the machine terminals. harmonic voltage across the generator neutral earthing 18.104.22.168 High Impedance REF protection impedance under all operating conditions. The principle of high impedance differential protection is A problem encountered is that the level of third given in Chapter 10 and also described further in Section harmonic voltage generated is related to the output of 17.5.2. The same technique can be used for earth-fault the generator. The voltage is low when generator output Network Protection & Automation Guide • 291 • Chap17-280-315 17/06/02 10:46 Page 292 is low. In order to avoid maloperation when operating at isolated networks, or ones with weak interconnections, low power output, the relay element can be inhibited due to the fault conditions listed earlier. using an overcurrent or power element (kW, kvar or kVA) For these reasons, it is prudent to provide power and internal programmable logic. frequency overvoltage protection, in the form of a time- 184.108.40.206 Use of low-frequency voltage injection delayed element, either IDMT or definite time. The time Another method for protecting the entire stator winding delay should be long enough to prevent operation during of a generator is to deploy signal injection equipment to normal regulator action, and therefore should take inject a low frequency voltage between the stator star account of the type of AVR fitted and its transient point and earth. An earth fault at any winding location response. Sometimes a high-set element is provided as will result in the flow of a measurable injection current well, with a very short definite-time delay or to cause protection operation. This form of protection instantaneous setting to provide a rapid trip in extreme can provide earth fault protection when the generator is circumstances. The usefulness of this is questionable for at standstill, prior to run-up. It is also an appropriate generators fitted with an excitation system other than a method to apply to variable speed synchronous static type, because the excitation will decay in Generator and Generator-Transfor mer P rotection machines. Such machines may be employed for variable accordance with the open-circuit time constant of the speed motoring in pumped-storage generation schemes field winding. This decay can last several seconds. The or for starting a large gas turbine prime mover. relay element is arranged to trip both the main circuit breaker (if not already open) and the excitation; tripping the main circuit breaker alone is not sufficient. 17.9 OVERVOLTAGE PROTECTION Overvoltages on a generator may occur due to transient surges on the network, or prolonged power frequency 17.10 UNDERVOLTAGE PROTECTION overvoltages may arise from a variety of conditions. Undervoltage protection is rarely fitted to generators. It Surge arrestors may be required to protect against is sometimes used as an interlock element for another transient overvoltages, but relay protection may be used protection function or scheme, such as field failure to protect against power frequency overvoltages. protection or inadvertent energisation protection, where A sustained overvoltage condition should not occur for a the abnormality to be detected leads directly or machine with a healthy voltage regulator, but it may be indirectly to an undervoltage condition. caused by the following contingencies: A transmission system undervoltage condition may arise a. defective operation of the automatic voltage when there is insufficient reactive power generation to regulator when the machine is in isolated operation maintain the system voltage profile and the condition b. operation under manual control with the voltage must be addressed to avoid the possible phenomenon of regulator out of service. A sudden variation of the system voltage collapse. load, in particular the reactive power component, However, it should be addressed by the deployment of will give rise to a substantial change in voltage 'system protection' schemes. The generation should not because of the large voltage regulation inherent in be tripped. The greatest case for undervoltage protection a typical alternator • 17 • being required would be for a generator supplying an c. sudden loss of load (due to tripping of outgoing isolated power system or to meet Utility demands for feeders, leaving the set isolated or feeding a very small connection of embedded generation (see Section 17.21). load) may cause a sudden rise in terminal voltage due In the case of generators feeding an isolated system, to the trapped field flux and/or overspeed undervoltage may occur for several reasons, typically Sudden loss of load should only cause a transient overloading or failure of the AVR. In some cases, the overvoltage while the voltage regulator and governor act performance of generator auxiliary plant fed via a unit to correct the situation. A maladjusted voltage regulator transformer from the generator terminals could be may trip to manual, maintaining excitation at the value adversely affected by prolonged undervoltage. prior to load loss while the generator supplies little or no load. The terminal voltage will increase substantially, Where undervoltage protection is required, it should and in severe cases it would be limited only by the comprise an undervoltage element and an associated saturation characteristic of the generator. A rise in speed time delay. Settings must be chosen to avoid simply compounds the problem. If load that is sensitive maloperation during the inevitable voltage dips during to overvoltages remains connected, the consequences in power system fault clearance or associated with motor terms of equipment damage and lost revenue can be starting. Transient reductions in voltage down to 80% or severe. Prolonged overvoltages may also occur on less may be encountered during motor starting. • 292 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:46 Page 293 17.11 LOW FORWARD POWER/REVERSE where a protection sensitivity of better than 3% is POWER PROTECTION required, a metering class CT should be employed to avoid incorrect protection behaviour due to CT phase Low forward power or reverse power protection may be angle errors when the generator supplies a significant required for some generators to protect the prime mover. level of reactive power at close to zero power factor. Parts of the prime mover may not be designed to experience reverse torque or they may become damaged The reverse power protection should be provided with a through continued rotation after the prime mover has definite time delay on operation to prevent spurious suffered some form of failure. operation with transient power swings that may arise following synchronisation or in the event of a power transmission system disturbance. 17.11.1 Low Forward Power Protection Low forward power protection is often used as an 17.12 UNBALANCED LOADING interlocking function to enable opening of the main circuit breaker for non-urgent trips – e.g. for a stator A three-phase balanced load produces a reaction field Generator and Generator-Transfor mer P rotection earth fault on a high-impedance earthed generator, or that, to a first approximation, is constant and rotates when a normal shutdown of a set is taking place. This is synchronously with the rotor field system. Any to minimise the risk of plant overspeeding when the unbalanced condition can be resolved into positive, electrical load is removed from a high-speed cylindrical negative and zero sequence components. The positive rotor generator. The rotor of this type of generator is sequence component is similar to the normal balanced highly stressed mechanically and cannot tolerate much load. The zero sequence component produces no main overspeed. While the governor should control overspeed armature reaction. conditions, it is not good practice to open the main circuit breaker simultaneously with tripping of the prime mover for non-urgent trips. For a steam turbine, for 17.12.1 Effect of Negative Sequence Current example, there is a risk of overspeeding due to energy The negative sequence component is similar to the storage in the trapped steam, after steam valve tripping, positive sequence system, except that the resulting or in the event that the steam valve(s) do not fully close reaction field rotates in the opposite direction to the d.c. for some reason. For urgent trip conditions, such as field system. Hence, a flux is produced which cuts the stator differential protection operation, the risk involved rotor at twice the rotational velocity, thereby inducing in simultaneous prime mover and generator breaker double frequency currents in the field system and in the tripping must be accepted. rotor body. The resulting eddy-currents are very large and cause severe heating of the rotor. 17.11.2 Reverse Power Protection So severe is this effect that a single-phase load equal to the normal three-phase rated current can quickly heat Prime Mover Motoring Power Possible Damage Protection Setting the rotor slot wedges to the softening point. They may (% of rated) then be extruded under centrifugal force until they stand Fire/explosion due 5-25 to unburnt fuel above the rotor surface, when it is possible that they may Diesel Engine Mechanical damage strike the stator core. to gearbox/shafts • 17 • 10-15 A generator is assigned a continuous negative sequence (split shaft) 50% Gas Turbine >50% gearbox damage rating. For turbo-generators this rating is low; standard of motoring (single shaft) power values of 10% and 15% of the generator continuous 0.2-2 rating have been adopted. The lower rating applies when (blades out of water) blade and runner Hydro the more intensive cooling techniques are applied, for >2 cavitation (blades in water) example hydrogen-cooling with gas ducts in the rotor to turbine blade damage facilitate direct cooling of the winding. Steam Turbine 0.5-6 gearbox damage on geared sets Short time heating is of interest during system fault Table 17.1: Generator reverse power problems conditions and it is usual in determining the generator negative sequence withstand capability to assume that the heat dissipation during such periods is negligible. Reverse power protection is applied to prevent damage Using this approximation it is possible to express the to mechanical plant items in the event of failure of the heating by the law: prime mover. Table 17.1 gives details of the potential problems for various prime mover types and the typical I 2t = K 2 settings for reverse power protection. For applications Network Protection & Automation Guide • 293 • Chap17-280-315 17/06/02 10:46 Page 294 where: sequence capacity and may not require protection. I2R = negative sequence component Modern numerical relays derive the negative sequence (per unit of MCR) current level by calculation, with no need for special t = time (seconds) circuits to extract the negative sequence component. A true thermal replica approach is often followed, to allow K = constant proportional to the thermal capacity for: of the generator rotor a. standing levels of negative sequence current below For heating over a period of more than a few seconds, it the continuous withstand capability. This has the is necessary to allow for the heat dissipated. From a effect of shortening the time to reach the critical combination of the continuous and short time ratings, temperature after an increase in negative sequence the overall heating characteristic can be deduced to be: current above the continuous withstand capability b. cooling effects when negative sequence current I 1 levels are below the continuous withstand M = 2 = 1 − e ( 2R ) I2R − I2 t K Generator and Generator-Transfor mer P rotection capability The advantage of this approach is that cooling effects are where: modelled more accurately, but the disadvantage is that I2R = negative phase sequence continuous rating in the tripping characteristic may not follow the withstand per unit of MCR characteristic specified by the manufacturer accurately. The heating characteristics of various designs of The typical relay element characteristic takes the form of generator are shown in Figure 17.16. I 2 K 2 set t = − 2 log e 1 − 10000 I 2 set I2 …Equation 17.1 where: 1000 t = time to trip 2 I flc K = K g × Ip 100 Indirectly cooled (air) I flc Indirectly cooled (H2) I 2 set = I 2 cmr × ×I n Ip Time (sec) 350MW direct cooled 10 660MW direct cooled 1000MW direct cooled Kg = negative sequence withstand coefficient (Figure 17.16) 1 Using I2 t model 2 I2cmr = generator maximum continuous I2 withstand • 17 • Using true thermal model Iflc = generator rated primary current 0.1 Ip = CT primary current IN = relay rated current Figure 17.16 also shows the thermal replica time 0.01 characteristic described by Equation 17.1, from which it 0.01 0.1 1 10 Negative sequence current (p.u.) will be seen that a significant gain in capability is achieved at low levels of negative sequence current. Figure 17.16: Typical negative phase sequence Such a protection element will also respond to phase- current withstand of cylindrical earth and phase-phase faults where sufficient negative rotor generators sequence current arises. Grading with downstream 17.12.2 Negative Phase Sequence Protection power system protection relays is therefore required. A definite minimum time setting must be applied to the This protection is applied to prevent overheating due to negative sequence relay element to ensure correct negative sequence currents. Small salient-pole grading. A maximum trip time setting may also be used generators have a proportionately larger negative to ensure correct tripping when the negative sequence • 294 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:46 Page 295 current level is only slightly in excess of the continuous of the transformer differential protection schemes withstand capability and hence the trip time from the applied at the power station (see Chapter 16 for thermal model may depart significantly from the rotor transformer protection). Sustained overfluxing can arise withstand limits. during run up, if excitation is applied too early with the AVR in service, or if the generator is run down, with the excitation still applied. Other overfluxing instances have 17.13 PROTECTION AGAINST INADVERTENT occurred from loss of the AVR voltage feedback signal, ENERGISATION due to a reference VT problem. Such sustained Accidental energisation of a generator when it is not conditions must be detected by a dedicated overfluxing running may cause severe damage to it. With the protection function that will raise an alarm and possibly generator at standstill, closing the circuit breaker results force an immediate reduction in excitation. in the generator acting as an induction motor; the field Most AVRs' have an overfluxing protection facility winding (if closed) and the rotor solid iron/damper included. This may only be operative when the generator circuits acting as rotor circuits. Very high currents are is on open circuit, and hence fail to detect overfluxing Generator and Generator-Transfor mer P rotection induced in these rotor components, and also occur in the conditions due to abnormally low system frequency. stator, with resultant rapid overheating and damage. However, this facility is not engineered to protection Protection against this condition is therefore desirable. relay standards, and should not be solely relied upon to A combination of stator undervoltage and overcurrent provide overfluxing protection. A separate relay element can be used to detect this condition. An instantaneous is therefore desirable and provided in most modern overcurrent element is used, and gated with a three- relays. phase undervoltage element (fed from a VT on the It is usual to provide a definite time-delayed alarm generator side of the circuit breaker) to provide the setting and an instantaneous or inverse time-delayed protection. The overcurrent element can have a low trip setting, to match the withstand characteristics of setting, as operation is blocked when the generator is the protected generator and transformer. It is very operating normally. The voltage setting should be low important that the VT reference for overfluxing enough to ensure that operation cannot occur for protection is not the same as that used for the AVR. transient faults. A setting of about 50% of rated voltage is typical. VT failure can cause maloperation of the protection, so the element should be inhibited under 17.14.2 Under/Overfrequency these conditions. The governor fitted to the prime mover normally provides protection against overfrequency. Underfrequency may 17.14 UNDER/OVERFREQUENCY/ occur as a result of overload of generators operating on OVERFLUXING PROTECTION an isolated system, or a serious fault on the power These conditions are grouped together because these system that results in a deficit of generation compared problems often occur due to a departure from to load. This may occur if a grid system suffers a major synchronous speed. fault on transmission lines linking two parts of the system, and the system then splits into two. It is likely that one part will have an excess of generation over load, and the other will have a corresponding deficit. • 17 • 17.14.1 Overfluxing Frequency will fall fairly rapidly in the latter part, and the Overfluxing occurs when the ratio of voltage to normal response is load shedding, either by load frequency is too high. The iron saturates owing to the shedding relays or operator action. However, prime high flux density and results in stray flux occurring in movers may have to be protected against excessively low components not designed to carry it. Overheating can frequency by tripping of the generators concerned. then occur, resulting in damage. The problem affects both direct-and indirectly-connected generators. Either With some prime movers, operation in narrow frequency excessive voltage, or low frequency, or a combination of bands that lie close to normal running speed (either both can result in overfluxing, a voltage to frequency above or below) may only be permitted for short periods, ratio in excess of 1.05p.u. normally being indicative of together with a cumulative lifetime duration of this condition. Excessive flux can arise transiently, which operation in such frequency bands. This typically occurs is not a problem for the generator. For example, a due to the presence of rotor torsional frequencies in such generator can be subjected to a transiently high power frequency bands. In such cases, monitoring of the period frequency voltage, at nominal frequency, immediately of time spent in these frequency bands is required. A after full load rejection. Since the condition would not special relay is fitted in such cases, arranged to provide be sustained, it only presents a problem for the stability alarm and trip facilities if either an individual or Network Protection & Automation Guide • 295 • Chap17-280-315 17/06/02 10:48 Page 296 cumulative period exceeds a set time. produce a balancing force on this axis. The result is an unbalanced force that in a large machine may be of the order of 50-100 tons. A violent vibration is set up that 17.15 ROTOR FAULTS may damage bearing surfaces or even displace the rotor The field circuit of a generator, comprising the field by an amount sufficient to cause it to foul the stator. winding of the generator and the armature of the exciter, together with any associated field circuit breaker if it 17.15.1 Rotor Earth-Fault Protection exists, is an isolated d.c. circuit which is not normally earthed. If an earth fault occurs, there will be no steady- Two methods are available to detect this type of fault. state fault current and the need for action will not be The first method is suitable for generators that evident. incorporate brushes in the main generator field winding. The second method requires at least a slip-ring Danger arises if a second earth fault occurs at a separate connection to the field circuit: point in the field system, to cause the high field current to be diverted, in part at least, from the intervening a. potentiometer method Generator and Generator-Transfor mer P rotection turns. Serious damage to the conductors and possibly b. a.c. injection method the rotor can occur very rapidly under these conditions. 220.127.116.11 Potentiometer method More damage may be caused mechanically. If a large portion of the winding is short-circuited, the flux may This is a scheme that was fitted to older generators, and adopt a pattern such as that shown in Figure 17.17. The it is illustrated in Figure 17.18. An earth fault on the attracting force at the surface of the rotor is given by: field winding would produce a voltage across the relay, the maximum voltage occurring for faults at the ends of B2A the winding. F= 8π A 'blind spot' would exist at the centre of the field winding. To avoid a fault at this location remaining where: undetected, the tapping point on the potentiometer A = area could be varied by a pushbutton or switch. The relay setting is typically about 5% of the exciter voltage. B = flux density Field Winding Short Circuit Field winding I > Exciter • 17 • Figure 17.18: Earth fault protection of field circuit by potentiometer method 126.96.36.199 Injection methods Two methods are in common use. The first is based on low frequency signal injection, with series filtering, as shown in Figure 17.19(a). It comprises an injection source that is connected between earth and one side of the field circuit, through capacitive coupling and the measurement circuit. The field circuit is subjected to an Figure 17.17: Flux distribution on rotor alternating potential at substantially the same level with partial winding short circuit throughout. An earth fault anywhere in the field system It will be seen from Figure 17.17 that the flux is will give rise to a current that is detected as an concentrated on one pole but widely dispersed over the equivalent voltage across the adjustable resistor by the other and intervening surfaces. The attracting force is in relay. The capacitive coupling blocks the normal d.c. field consequence large on one pole but very weak on the voltage, preventing the discharge of a large direct opposite one, while flux on the quadrature axis will current through the protection scheme. The combination • 296 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:48 Page 297 of series capacitor and reactor forms a low-pass tuned 17.15.2 Rotor Earth Fault Protection circuit, the intention being to filter higher frequency for Brushless Generators rotor currents that may occur for a variety of reasons. A brushless generator has an excitation system Other schemes are based on power frequency signal consisting of: injection. An impedance relay element is used, a field 1. a main exciter with rotating armature and winding earth fault reducing the impedance seen by the stationary field windings relay. These suffer the draw back of being susceptible to static excitation system harmonic currents when there is 2. a rotating rectifier assembly, carried on the main significant field winding and excitation system shunt shaft line out capacitance. 3. a controlled rectifier producing the d.c. field Greater immunity for such systems is offered by voltage for the main exciter field from an a.c. capacitively coupling the protection scheme to both ends source (often a small 'pilot' exciter) of the field winding, where brush or slip ring access is Hence, no brushes are required in the generator field possible (Figure 17.19(b)). Generator and Generator-Transfor mer P rotection circuit. All control is carried out in the field circuit of the The low–frequency injection scheme is also main exciter. Detection of a rotor circuit earth fault is advantageous in that the current flow through the field still necessary, but this must be based on a dedicated winding shunt capacitance will be lower than for a rotor-mounted system that has a telemetry link to power frequency scheme. Such current would flow provide an alarm/data. through the machine bearings to cause erosion of the bearing surface. For power frequency schemes, a solution is to insulate the bearings and provide an 17.15.3 Rotor Shorted Turn Protection earthing brush for the shaft. As detailed in Section 17.15 a shorted section of field winding will result in an unsymmetrical rotor flux pattern and in potentially damaging rotor vibration. Detection of such an electrical fault is possible using a probe consisting of a coil placed in the airgap. The flux pattern of the positive and negative poles is measured and any significant difference in flux pattern between Generator field Exciter the poles is indicative of a shorted turn or turns. winding Automated waveform comparison techniques can be used to provide a protection scheme, or the waveform can be inspected visually at regular intervals. An L.F. injection immediate shutdown is not normally required unless the supply effects of the fault are severe. The fault can be kept ∼ U> ∼ under observation until a suitable shutdown for repair can be arranged. Repair will take some time, since it means unthreading the rotor and dismantling the (a) Low frequency a.c. voltage injection - current measurement winding. • 17 • Since short-circuited turns on the rotor may cause Generator damaging vibration and the detection of field faults for field Exciter winding all degrees of abnormality is difficult, the provision of a vibration a detection scheme is desirable – this forms part of the mechanical protection of the generator. Injection supply < Z< 17.15.4 Protection against Diode Failure A short-circuited diode will produce an a.c. ripple in the exciter field circuit. This can be detected by a relay (b) Power frequency a.c. voltage injection - monitoring the current in the exciter field circuit, impedance measurement however such systems have proved to be unreliable. The relay would need to be time delayed to prevent an alarm Figure 17.19: Earth fault protection of field circuit by a.c. injection being issued with normal field forcing during a power system fault. A delay of 5-10 seconds may be necessary. Network Protection & Automation Guide • 297 • Chap17-280-315 17/06/02 10:48 Page 298 Fuses to disconnect the faulty diode after failure may be 17.16 LOSS OF EXCITATION PROTECTION fitted. The fuses are of the indicating type, and an Loss of excitation may occur for a variety of reasons. If inspection window can be fitted over the diode wheel to the generator was initially operating at only 20%-30% enable diode health to be monitored manually. of rated power, it may settle to run super-synchronously A diode that fails open-circuit occurs less often. If there as an induction generator, at a low level of slip. In doing is more than one diode in parallel for each arm of the so, it will draw reactive current from the power system diode bridge, the only impact is to restrict the maximum for rotor excitation. This form of response is particularly continuous excitation possible. If only a single diode per true of salient pole generators. In these circumstances, bridge arm is fitted, some ripple will be present on the the generator may be able to run for several minutes main field supply but the inductance of the circuit will without requiring to be tripped. There may be sufficient smooth this to a degree and again the main effect is to time for remedial action to restore the excitation, but the restrict the maximum continuous excitation. The set can reactive power demand of the machine during the failure be kept running until a convenient shutdown can be may severely depress the power system voltage to an arranged. unacceptable level. For operation at high initial power Generator and Generator-Transfor mer P rotection output, the rotor speed may rise to approximately 105% of rated speed, where there would be low power output 17.15.5 Field Suppression and where a high reactive current of up to 2.0p.u. may be drawn from the supply. Rapid automatic The need to rapidly suppress the field of a machine in disconnection is then required to protect the stator which a fault has developed should be obvious, because windings from excessive current and to protect the rotor as long as the excitation is maintained, the machine will from damage caused by induced slip frequency currents. feed its own fault even though isolated from the power system. Any delay in the decay of rotor flux will extend the fault damage. Braking the rotor is no solution, 17.16.1 Protection against Loss of Excitation because of its large kinetic energy. The protection used varies according to the size of The field winding current cannot be interrupted generator being protected. instantaneously as it flows in a highly inductive circuit. Consequently, the flux energy must be dissipated to 18.104.22.168 Small generators prevent an excessive inductive voltage rise in the field On the smaller machines, protection against circuit. For machines of moderate size, it is satisfactory asynchronous running has tended to be optional, but it to open the field circuit with an air-break circuit breaker may now be available by default, where the functionality without arc blow-out coils. Such a breaker permits only is available within a modern numerical generator a moderate arc voltage, which is nevertheless high protection package. If fitted, it is arranged either to enough to suppress the field current fairly rapidly. The provide an alarm or to trip the generator. If the inductive energy is dissipated partly in the arc and partly generator field current can be measured, a relay element in eddy-currents in the rotor core and damper windings. can be arranged to operate when this drops below a preset value. However, depending on the generator With generators above about 5MVA rating, it is better to design and size relative to the system, it may well be that provide a more definite means of absorbing the energy the machine would be required to operate synchronously • 17 • without incurring damage. Connecting a 'field discharge with little or no excitation under certain system resistor' in parallel with the rotor winding before opening conditions. the field circuit breaker will achieve this objective. The resistor, which may have a resistance value of The field undercurrent relay must have a setting below approximately five times the rotor winding resistance, is the minimum exciting current, which may be 8% of that connected by an auxiliary contact on the field circuit corresponding to the MCR of the machine. Time delay breaker. The breaker duty is thereby reduced to that of relays are used to stabilise the protection against opening a circuit with a low L/R ratio. After the breaker maloperation in response to transient conditions and to has opened, the field current flows through the discharge ensure that field current fluctuations due to pole slipping resistance and dies down harmlessly. The use of a fairly do not cause the protection to reset. high value of discharge resistance reduces the field time If the generator field current is not measurable, then the constant to an acceptably low value, though it may still technique detailed in the following section is utilised. be more than one second. Alternatively, generators fitted with static excitation systems may temporarily 18.104.22.168 Large generators (>5MVA) invert the applied field voltage to reduce excitation For generators above about 5MVA rating, protection current rapidly to zero before the excitation system is against loss of excitation and pole slipping conditions is tripped. normally applied. • 298 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:48 Page 299 Consider a generator connected to network, as shown in The general case can be represented by a system of Figure 17.20. On loss of excitation, the terminal voltage circles with centres on the line CD; see Figure 17.21. will begin to decrease and the stator current will increase, Also shown is a typical machine terminal impedance resulting in a decrease of impedance viewed from the locus during loss of excitation conditions. generator terminals and also a change in power factor. +jX EG =1.5 XG XT ZS ES EG ES 1.8 2.0 A Load point 2.5 +jX D 5.0 Loss of field ZS locus XG+ T+ZS D Generator and Generator-Transfor mer P rotection EG -R +R 1 XT ES EG =1 θ ES ZR C -R +R A XG 0.5 0.6 C 0.7 -jX -jX Figure 17.21: Swing curves and loss of synchronism locus Figure 17.20: Basic interconnected system The special cases of EG=ES and EG=0 result in a A relay to detect loss of synchronism can be located at straight-line locus that is the right-angled bisector of point A. It can be shown that the impedance presented CD, and in a circular locus that is shrunk to point C, to the relay under loss of synchronism conditions (phase respectively. swinging or pole slipping) is given by: When excitation is removed from a generator operating synchronously the flux dies away slowly, during which ZR = ( X G + X T + Z S )n (n − cos θ − j sin θ) period the ratio of EG/ES is decreasing, and the rotor angle (n − cos θ) 2 + sin 2 θ of the machine is increasing. The operating condition plotted on an impedance diagram therefore travels along −XG a locus that crosses the power swing circles. At the same • 17 • time, it progresses in the direction of increasing rotor …Equation 17.2 angle. After passing the anti-phase position, the locus where: bends round as the internal e.m.f. collapses, condensing on an impedance value equal to the machine reactance. The generated locus is illustrated in Figure 17.21. n = EG = voltage ES system The relay location is displaced from point C by the generator reactance XG. One problem in determining the θ = angle by which EG leads Es position of these loci relative to the relay location is that the value of machine impedance varies with the rate of If the generator and system voltages are equal, the above slip. At zero slip XG is equal to Xd, the synchronous expression becomes: reactance, and at 100% slip XG is equal to X''d, the sub- transient reactance. The impedance in a typical case has ZR = ( X G + X T + Z S )(1 − j cotθ 2 ) − X been shown to be equal to X'd, the transient reactance, G 2 at 50% slip, and to 2X'd with a slip of 0.33%. The slip likely to be experienced with asynchronous running is Network Protection & Automation Guide • 299 • Chap17-280-315 17/06/02 10:48 Page 300 low, perhaps 1%, so that for the purpose of assessing the scheme for loss of excitation could be based on power swing locus it is sufficient to take the value impedance measurement. The impedance characteristic XG=2X'd. must be appropriately set or shaped to ensure decisive operation for loss of excitation whilst permitting stable This consideration has assumed a single value for XG. generator operation within allowable limits. One or two However, the reactance Xq on the quadrature axis differs offset mho under impedance elements (see Chapter 11 from the direct-axis value, the ratio of Xd/Xg being for the principles of operation) are ideally suited for known as the saliency factor. This factor varies with the providing loss of excitation protection as long as a slip speed. The effect of this factor during asynchronous generator operating at low power output (20-30%Pn) operation is to cause XG to vary at slip speed. In does not settle down to operate as an induction consequence, the loss of excitation impedance locus generator. The characteristics of a typical two-stage loss does not settle at a single point, but it continues to of excitation protection scheme are illustrated in Figure describe a small orbit about a mean point. 17.23. The first stage, consisting of settings Xa1 and Xb1 A protection scheme for loss of excitation must operate can be applied to provide detection of loss of excitation decisively for this condition, but its characteristic must Generator and Generator-Transfor mer P rotection even where a generator initially operating at low power not inhibit stable operation of the generator. One limit output (20-30%Pn) might settle down to operate as an of operation corresponds to the maximum practicable induction generator. rotor angle, taken to be at 120°. The locus of operation can be represented as a circle on the impedance plane, X as shown in Figure 17.22, stable operation conditions Normal machine operating impedance lying outside the circle. R X -Xa2 X -Xa1 +jX Alarm Locus of constant MVA angle ZS Xb2 Xb1 -R XT +R 'd 2X'd Xd Figure 17.23: Loss of excitation protection Limiting characteristics generation point Pick-up and drop-off time delays td1 and tdo1 are associated with this impedance element. Timer td1 is used to prevent operation during stable power swings Relay that may cause the impedance locus of the generator to Locus of constant load angle Diameter = d/2 • 17 • transiently enter the locus of operation set by Xb1. However, the value must short enough to prevent -jX damage as a result of loss of excitation occurring. If Figure 17.22: Locus of limiting operating pole-slipping protection is not required (see Section conditions of synchronous machine 17.17.2), timer tdo1 can be set to give instantaneous reset. The second field failure element, comprising settings Xb1, Xb2, and associated timers td2 and tdo2 can On the same diagram the full load impedance locus for be used to give instantaneous tripping following loss of one per unit power can be drawn. Part of this circle excitation under full load conditions. represents a condition that is not feasible, but the point of intersection with the maximum rotor angle curve can be taken as a limiting operating condition for setting 17.16.3 Protection Settings impedance-based loss of excitation protection. The typical setting values for the two elements vary according to the excitation system and operating regime of the generator concerned, since these affect the 17.16.2 Impedance-Based Protection Characteristics generator impedance seen by the relay under normal and Figure 17.21 alludes to the possibility that a protection abnormal conditions. For a generator that is never • 300 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:48 Page 301 operated at leading power factor, or at load angles in 17.17.1 Protection using Reverse Power Element excess of 90° the typical settings are: During pole-slipping, there will be periods where the impedance element diameter Xb1 = Xd direction of active power flow will be in the reverse impedance element offset Xa1 = -0.5X'd direction, so a reverse power relay element can be used to detect this, if not used for other purposes. However, time delay on pick-up, td1 = 0.5s – 10s since the reverse power conditions are cyclical, the time delay on drop-off, tdo1 = 0s element will reset during the forward power part of the cycle unless either a very short pick-up time delay and/or If a fast excitation system is employed, allowing load a suitable drop-off time delay is used to eliminate angles of up to 120° to be used, the impedance diameter resetting. must be reduced to take account of the reduced generator impedance seen under such conditions. The The main advantage of this method is that a reverse offset also needs revising. In these circumstances, power element is often already present, so no additional typical settings would be: relay elements are required. The main disadvantages are the time taken for tripping and the inability to control Generator and Generator-Transfor mer P rotection impedance element diameter Xb1 = 0.5Xd the system angle at which the generator breaker trip impedance element offset Xa1 = -0.75X'd command would be issued, if it is a requirement to limit the breaker current interruption duty. There is also the time delay on pick-up, td1 = 0.5s – 10s difficulty of determining suitable settings. time delay on drop-off, tdo1 = 0s Determination of settings in the field, from a deliberate The typical impedance settings for the second element, if pole-slipping test is not possible and analytical studies used, are: may not discover all conditions under which pole- slipping will occur. impedance element diameter kV 2 17.17.2 Protection using an Under Impedance Xb2 = MVA Element With reference to Figure 17.21, a loss of excitation under Xa2 = -0.5X'd impedance characteristic may also be capable of The time delay settings td2 and tdo2 are set to zero to give detecting loss of synchronism, in applications where the instantaneous operation and reset. electrical centre of the power system and the generator lies 'behind' the relaying point. This would typically be the case for a relatively small generator that is 17.17 POLE SLIPPING PROTECTION connected to a power transmission system (XG >> (XT + A generator may pole-slip, or fall out of synchronism XS)). With reference to Figure 17.23; if pole-slipping with the power system for a number of reasons. The protection response is required, the drop-off timer tdo1 of principal causes are prolonged clearance of a heavy fault the larger diameter impedance measuring element on the power system, when the generator is operating at should be set to prevent its reset of in each slip cycle, a high load angle close to the stability limit, or partial or until the td1 trip time delay has expired. • 17 • complete loss of excitation. Weak transmission links As with reverse power protection, this would be an between the generator and the bulk of the power system elementary form of pole-slipping protection. It may not aggravate the situation. It can also occur with be suitable for large machines where rapid tripping is embedded generators running in parallel with a strong required during the first slip cycle and where some Utility network if the time for a fault clearance on the control is required for the system angle at which the Utility network slow, perhaps because only IDMT relays generator circuit breaker trip command is given. Where are provided. Pole slipping is characterised by large and protection against pole-slipping must be guaranteed, a rapid oscillations in active and reactive power. Rapid more sophisticated method of protection should be used. disconnection of the generator from the network is A typical reset timer delay for pole-slipping protection required to ensure that damage to the generator is might be 0.6s. For generator transformer units, the avoided and that loads supplied by the network are not additional impedance in front of the relaying point may affected for very long. take the system impedance outside the under impedance Protection can be provided using several methods. The relay characteristic required for loss of excitation choice of method will depend on the probability of pole protection. Therefore, the acceptability of this pole- slipping occurring and on the consequences should it slipping protection scheme will be dependent on the occur. application. Network Protection & Automation Guide • 301 • Chap17-280-315 17/06/02 10:48 Page 302 17.17.3 Dedicated Pole-Slipping Protection 126.96.36.199 Use of lenticular characteristic Large generator-transformer units directly connected to A more sophisticated approach is to measure the grid systems often require a dedicated pole-slipping impedance of the generator and use a lenticular protection scheme to ensure rapid tripping and with impedance characteristic to determine if a pole-slipping system angle control. Historically, dedicated protection condition exists. The lenticular characteristic is shown in schemes have usually been based on an ohm-type Figure 17.25. The characteristic is divided into two halves impedance measurement characteristic. by a straight line, called the blinder. 220.127.116.11 Pole slipping protection by impedance The inclination, θ, of the lens and blinder is determined by measurement the angle of the total system impedance. The impedance of the system and generator-transformer determines the Although a mho type element for detecting the change forward reach of the lens, ZA, and the transient reactance in impedance during pole-slipping can be used in some of the generator determines the reverse reach ZB. applications, but with performance limits, a straight line ohm characteristic is more suitable. The protection Generator and Generator-Transfor mer P rotection principle is that of detecting the passage of the Blinder generator impedance through a zone defined by two X such impedance characteristics, as shown in Figure ZA 17.24. The characteristic is divided into three zones, A, P B, and C. Normal operation of the generator lies in zone A. When a pole-slip occurs, the impedance traverses zones B and C, and tripping occurs when the impedance characteristic enters zone C. P' α θ +jX R ZS g Relaying point Lens T ZB XG Slip locus EG=ES C B A Figure 17.25: Pole-slipping protection using lenticular characteristic and blinder -R +R The width of the lens is set by the angle α and the line -jX PP', perpendicular to the axis of the lens, is used to • 17 • Ohm relay 2 determine if the centre of the impedance swing during a Ohm relay 1 transient is located in the generator or power system. Operation in the case of a generator is as follows. The Figure 17.24: Pole slipping detection by ohm relays characteristic is divided into 4 zones and 2 regions, as shown in Figure 17.26. Tripping only occurs if all zones are traversed Normal operation is with the measured impedance in sequentially. Power system faults should result in the zone R1. If a pole slip develops, the impedance locus will zones not being fully traversed so that tripping will not traverse though zones R2, R3, and R4. When entering be initiated. The security of this type of protection zone R4, a trip signal is issued, provided the impedance scheme is normally enhanced by the addition of a plain lies below reactance line PP' and hence the locus of under impedance control element (circle about the origin swing lies within or close to the generator – i.e. the of the impedance diagram) that is set to prevent tripping generator is pole slipping with respect to the rest of the for impedance trajectories for remote power system system. faults. Setting of the ohm elements is such that they lie parallel to the total system impedance vector, and enclose it, as shown in Figure 17.24. • 302 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:48 Page 303 windings and to issue an alarm or trip to prevent X damage. Z Left-lens Right-lens Although current-operated thermal replica protection A B cannot take into account the effects of ambient P ZS Power Swing In System temperature or uneven heat distribution, it is often O applied as a back-up to direct stator temperature P' R4 R3 S R2 R1 measuring devices to prevent overheating due to high M XT a stator current. With some relays, the thermal replica T2 temperature estimate can be made more accurate 1 Pole Slipping through the integration of direct measuring resistance Characteristic temperature devices. X Stable Power Swing Irrespective of whether current-operated thermal replica protection is applied or not, it is a requirement to ZB monitor the stator temperature of a large generator in Generator and Generator-Transfor mer P rotection Blinder order to detect overheating from whatever cause. Temperature sensitive elements, usually of the resistance type, are embedded in the stator winding at hot-spot locations envisaged by the manufacturer, the number Figure 17.26: Definition of zones for lenticular characteristic used being sufficient to cover all variations. The elements are connected to a temperature sensing relay If the impedance locus lies above line PP', the swing lies element arranged to provide alarm and trip outputs. The far out in the power system – i.e. one part of the power settings will depend on the type of stator winding system, including the protected generator, is swinging insulation and on its permitted temperature rise. against the rest of the network. Tripping may still occur, but only if swinging is prolonged – meaning that the power system is in danger of complete break-up. Further 17.19 MECHANICAL FAULTS confidence checks are introduced by requiring that the Various faults may occur on the mechanical side of a impedance locus spends a minimum time within each generating set. The following sections detail the more zone for the pole-slipping condition to be valid. The trip important ones from an electrical point of view. signal may also be delayed for a number of slip cycles even if a generator pole-slip occurs – this is to both provide confirmation of a pole-slipping condition and 17.19.1 Failure of the Prime Mover allow time for other relays to operate if the cause of the pole slip lies somewhere in the power system. Should When a generator operating in parallel with others loses the impedance locus traverse the zones in any other its power input, it remains in synchronism with the sequence, tripping is blocked. system and continues to run as a synchronous motor, drawing sufficient power to drive the prime mover. This condition may not appear to be dangerous and in some 17.18 STATOR OVERHEATING circumstances will not be so. However, there is a danger • 17 • of further damage being caused. Table 17.1 lists some Overheating of the stator may result from: typical problems that may occur. i. overload Protection is provided by a low forward power/reverse ii. failure of the cooling system power relay, as detailed in Section 17.11 iii. overfluxing iv. core faults 17.19.2 Overspeed Accidental overloading might occur through the The speed of a turbo-generator set rises when the steam combination of full active load current component, input is in excess of that required to drive the load at governed by the prime mover output and an abnormally nominal frequency. The speed governor can normally high reactive current component, governed by the level control the speed, and, in any case, a set running in of rotor excitation and/or step-up transformer tap. With parallel with others in an interconnected system cannot a modern protection relay, it is relatively simple to accelerate much independently even if synchronism is provide a current-operated thermal replica protection lost. However, if load is suddenly lost when the HV element to estimate the thermal state of the stator circuit breaker is tripped, the set will begin to accelerate Network Protection & Automation Guide • 303 • Chap17-280-315 17/06/02 10:50 Page 304 rapidly. The speed governor is designed to prevent a event of loss of vacuum, as this would cause rapid dangerous speed rise even with a 100% load rejection, overheating of the low-pressure turbine blades. but nevertheless an additional centrifugal overspeed trip device is provided to initiate an emergency mechanical shutdown if the overspeed exceeds 10%. 17.20 COMPLETE GENERATOR PROTECTION SCHEMES To minimise overspeed on load rejection and hence the mechanical stresses on the rotor, the following sequence From the preceding sections, it is obvious that the is used whenever electrical tripping is not urgently protection scheme for a generator has to take account of required: many possible faults and plant design variations. Determination of the types of protection used for a i. trip prime mover or gradually reduce power input to zero particular generator will depend on the nature of the plant and upon economic considerations, which in turn ii. allow generated power to decay towards zero is affected by set size. Fortunately, modern, multi- iii. trip generator circuit breaker only when generated function, numerical relays are sufficiently versatile to Generator and Generator-Transfor mer P rotection power is close to zero or when the power flow include all of the commonly required protection starts to reverse, to drive the idle turbine functions in a single package, thus simplifying the decisions to be made. The following sections provide illustrations of typical protection schemes for generators 17.19.3 Loss of Vacuum connected to a grid network, but not all possibilities are A failure of the condenser vacuum in a steam turbine illustrated, due to the wide variation in generator sizes driven generator results in heating of the tubes. This and types. then produces strain in the tubes, and a rise in temperature of the low-pressure end of the turbine. 17.20.1 Direct-Connected Generator Vacuum pressure devices initiate progressive unloading of the set and, if eventually necessary, tripping of the A typical protection scheme for a direct-connected turbine valves followed by the high voltage circuit generator is shown in Figure 17.27. It comprises the breaker. The set must not be allowed to motor in the following protection functions: Electrical trip of governor Governor trip Emergency push button Stator differential (biased/high impedance) Stator E/F (or neutral voltage displacement) Back-up overcurrent (or voltage • 17 • dependent O/C) Lubricating oil failure Mechanical faults (urgent) Reverse/low forward power Underfrequency Pole slipping Overfluxing Inadvertent energisation Loss of excitation Stator winding temperature Excitation Unbalanced loading circuit breaker Under/overvoltage Low power interlock Generator Mechanical faults (non-urgent) circuit breaker N.B. Alarms and time delays omitted for simplicity Figure 17.27: Typical protection arrangement for a direct-connected generator • 304 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:50 Page 305 1. stator differential protection instantaneous electrical trip and which can be time 2. overcurrent protection – conventional or voltage delayed until electrical power has been reduced to a low dependent value. The faults that require tripping of the prime mover as well as the generator circuit breaker are also shown. 3. stator earth fault protection 4. overvoltage protection 17.20.2 Generator-Transformer Units 5. undervoltage protection 6. overload/low forward power/ reverse power These units are generally of higher output than direct- protection (according to prime mover type) connected generators, and hence more comprehensive protection is warranted. In addition, the generator 7. unbalanced loading transformer also requires protection, for which the 8. overheating protection detailed in Chapter 16 is appropriate 9. pole slipping Overall biased generator/generator transformer 10. loss of excitation differential protection is commonly applied in addition, Generator and Generator-Transfor mer P rotection or instead of, differential protection for the transformer 11. underfrequency alone. A single protection relay may incorporate all of 12. inadvertent energisation the required functions, or the protection of the 13. overfluxing transformer (including overall generator/generator transformer differential protection) may utilise a 14. mechanical faults separate relay. Figure 17.27 illustrates which trips require an Figure 17.28 shows a typical overall scheme. Electrical trip of governor Governor trip Emergency push button Stator differential (biased/high impedance) Stator E/F (or neutral voltage displacement) Back-up overcurrent (or voltage dependent O/C) Lubricating oil failure Mechanical faults (urgent) Reverse/low forward power Underfrequency Pole slipping Overfluxing • 17 • Inadvertent energisation Overall differential (transformer differential) Excitation Buchholz circuit HV overcurrent breaker HV restricted E/F Generator Transformer winding temperature circuit breaker Loss of excitation Low power Stator winding temperature interlock Unbalanced loading Under/overvoltage Mechanical faults (non-urgent) N.B. Alarms and time delays omitted for simplicity Figure 17.28: Typical tripping arrangements for generator-transformer unit Network Protection & Automation Guide • 305 • Chap17-280-315 17/06/02 10:50 Page 306 17.21 EMBEDDED GENERATION frequency and voltage, or for other reasons. In recent years, through de-regulation of the electricity From a Utility standpoint, the connection of embedded supply industry and the ensuing commercial generation may cause problems with voltage control and competition, many electricity users connected to MV increased fault levels. The settings for protection relays power distribution systems have installed generating sets in the vicinity of the plant may require adjustment with to operate in parallel with the public supply. The the emergence of embedded generation. It must also be intention is either to utilise surplus energy from other ensured that the safety, security and quality of supply of sources, or to use waste heat or steam from the prime the Utility distribution system is not compromised. The mover for other purposes. Parallel connection of embedded generation must not be permitted to supply generators to distribution systems did occur before de- any Utility customers in isolation, since the Utility supply regulation, but only where there was a net power import is normally the means of regulating the system voltage from the Utility. Power export to Utility distribution and frequency within the permitted limits. It also systems was a relatively new aspect. Since generation of normally provides the only system earth connection(s), to this type can now be located within a Utility distribution ensure the correct performance of system protection in Generator and Generator-Transfor mer P rotection system, as opposed to being centrally dispatched response to earth faults. If the Utility power infeed fails, generation connected to a transmission system, the term it is also important to disconnect the embedded 'Embedded Generation' is often applied. Figure 17.2 generation before there is any risk of the Utility power illustrates such an arrangement. Depending on size, the supply returning on to unsynchronised machines. In embedded generator(s) may be synchronous or practice this generally requires the following protection asynchronous types, and they may be connected at any functions to be applied at the 'Point of Common voltage appropriate to the size of plant being considered. Coupling' (PCC) to trip the coupling circuit breaker: The impact of connecting generation to a Utility a. overvoltage distribution system that was originally engineered only b. undervoltage for downward power distribution must be considered, particularly in the area of protection requirements. In c. overfrequency this respect, it is not important whether the embedded d. underfrequency generator is normally capable of export to the Utility distribution system or not, since there may exist fault e. loss of Utility supply conditions when this occurs irrespective of the design In addition, particular circumstances may require intent. additional protection functions: If plant operation when disconnected from the Utility f. neutral voltage displacement supply is required, underfrequency protection (Section 17.4.2) will become an important feature of the in-plant g. reverse power power system. During isolated operation, it may be h. directional overcurrent relatively easy to overload the available generation, such that some form of load management system may be In practice, it can be difficult to meet the protection required. Similarly, when running in parallel with the settings or performance demanded by the Utility without Utility, consideration needs to be given to the mode of a high risk of nuisance tripping caused by lack of co- • 17 • ordination with normal power system faults and generator operation if reactive power import is to be controlled. The impact on the control scheme of a disturbances that do not necessitate tripping of the sudden break in the Utility connection to the plant main embedded generation. This is especially true when busbar also requires analysis. Where the in-plant applying protection specifically to detect loss of the generation is run using constant power factor or Utility supply (also called 'loss of mains') to cater for constant reactive power control, automatic reversion to operating conditions where there would be no voltage control when the Utility connection is lost is immediate excursion in voltage or frequency to cause essential to prevent plant loads being subjected to a operation of conventional protection functions. voltage outside acceptable limits. Limits may be placed by the Utility on the amount of 17.21.1 Protection Against Loss of Utility Supply power/reactive power import/export. These may demand If the normal power infeed to a distribution system, or to the use of an in-plant Power Management System to the part of it containing embedded generation is lost, the control the embedded generation and plant loads effects may be as follows: accordingly. Some Utilities may insist on automatic tripping of the interconnecting circuit breakers if there is a. embedded generation may be overloaded, leading a significant departure outside permissible levels of to generator undervoltage/underfrequency • 306 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:50 Page 307 b. embedded generation may be underloaded, leading 17.21.2 ROCOF Relay Description to overvoltage/overfrequency A ROCOF relay detects the rate of change of frequency in c. little change to the absolute levels of voltage or excess of a defined setpoint. The signal is obtained from frequency if there is little resulting change to the a voltage transformer connected close to the Point of load flow through the PCC Common Coupling (PCC). The principal method used is to measure the time period between successive zero- The first two effects are covered by conventional voltage crossings to determine the average frequency for each and frequency protection. However, if condition (c) half-cycle and hence the rate of change of frequency. occurs, conventional protection may not detect the loss The result is usually averaged over a number of cycles. of Utility supply condition or it may be too slow to do so within the shortest possible auto-reclose dead-times 17.21.3 Voltage Vector Shift Relay Description that may be applied in association with Utility overhead line protection. Detection of condition (c) must be A voltage vector shift relay detects the drift in voltage phase angle beyond a defined setpoint as long as it takes Generator and Generator-Transfor mer P rotection achieved if the requirements of the Utility are to be met. Many possible methods have been suggested, but the place within a set period. Again, the voltage signal is one most often used is the Rate of Change of Frequency obtained from a voltage transformer connected close to the Point of Common Coupling (PCC). The principal (ROCOF) relay. Its application is based on the fact that method used is to measure the time period between the rate of change of small changes in absolute successive zero-crossings to determine the duration of frequency, in response to inevitable small load changes, each half-cycle, and then to compare the durations with will be faster with the generation isolated than when the the memorised average duration of earlier half-cycles in generation is in parallel with the public, interconnected order to determine the phase angle drift. power system. However, problems with nuisance tripping in response to national power system events, where the system is subject to significant frequency 17.21.4 Setting Guidelines excursions following the loss of a large generator or a Should loss of the Utility supply occur, it is extremely major power interconnector, have occurred. unlikely that there will be an exact match between the This is particularly true for geographically islanded power output of the embedded generator(s) and the connected systems, such as those of the British Isles. An alternative load. A small frequency change or voltage phase angle to ROCOF protection is a technique sometimes referred change will therefore occur, to which can be added any to as 'voltage vector shift' protection. In this technique changes due to the small natural variations in loading of the rate of phase change between the directly measured an isolated generator with time. Once the rate of change generator bus voltage is compared with a memorised a.c. of frequency exceeds the setting of the ROCOF relay for a set time, or once the voltage phase angle drift exceeds bus voltage reference. the set angle, tripping occurs to open the connection Sources of embedded generation are not normally between the in-plant and Utility networks. earthed, which presents a potential safety hazard. In the While it is possible to estimate the rate of change of event of an Utility system earth fault, the Utility frequency from knowledge of the generator set inertia • 17 • protection should operate to remove the Utility power and MVA rating, this is not an accurate method for infeed. In theory, this should also result in removal of the setting a ROCOF relay because the rotational inertia of embedded generation, through the action of the the complete network being fed by the embedded stipulated voltage/frequency protection and dependable generation is required. For example, there may be other 'loss of mains' protection. However, in view of safety embedded generators to consider. As a result, it is considerations (e.g. fallen overhead line conductors in invariably the case that the relay settings are determined public areas), an additional form of earth fault protection at site during commissioning. This is to ensure that the Utility requirements are met while reducing the may also be demanded to prevent the backfeed of an possibility of a spurious trip under the various operating earth fault by embedded generation. The only way of scenarios envisaged. However, it is very difficult to detecting an earth fault under these conditions is to use determine whether a given rate of change of frequency neutral voltage displacement protection. The additional will be due to a 'loss of mains' incident or a requirement is only likely to arise for embedded load/frequency change on the public power network, and generation rated above 150kVA, since the risk of the hence spurious trips are impossible to eliminate. Thus small embedded generators not being cleared by other the provision of Loss of Utility Supply protection to meet means is negligible. power distribution Utility interface protection Network Protection & Automation Guide • 307 • Chap17-280-315 17/06/02 10:50 Page 308 requirements, may actually conflict with the interests of Salient details of the generator, network and protection the national power system operator. With the growing required are given in Table 17.2. The example contribution of non-dispatched embedded generation to calculations are based on a MiCOM P343 relay in respect the aggregate national power demand, the loss of the of setting ranges, etc. embedded generation following a transmission system 22.214.171.124 Differential protection incident that may already challenge the security of the system can only aggravate the problem. There have been Biased differential protection involves the determination claims that voltage vector shift protection might offer of values for four setting values: Is1, Is2, K1 and K2 in better security, but it will have operation times that vary Figure 17.5. Is1 can be set at 5% of the generator rating, with the rate of change of frequency. As a result, in accordance with the recommendations for the relay, depending on the settings used, operation times might and similarly the values of Is2 (120%) and K2 (150%) of not comply with Utility requirements under all generator rating. It remains for the value of K1 to be circumstances. Reference 17.1 provides further details determined. The recommended value is generally 0%, of the operation of ROCOF relays and the problems that but this only applies where CT's that conform to IEC may be encountered. 60044-1 class PX (or the superseded BS 3938 Class X) Generator and Generator-Transfor mer P rotection are used – i.e. CT's specifically designed for use in Nevertheless, because such protection is a common differential protection schemes. In this application, the requirement of some Utilities, the 'loss of mains' CT's are conventional class 5P CT's that meet the relay protection may have to be provided and the possibility of requirements in respect of knee-point voltage, etc. spurious trips will have to be accepted in those cases. Where neutral tail and terminal CT's can saturate at Site measurements over a period of time of the typical different times due to transiently offset magnetising rates of frequency change occurring may assist in inrush or motor starting current waveforms with an r.m.s. negotiations of the settings with the Utility, and with the level close to rated current and where there is a high L/R fine-tuning of the protection that may already be time constant for the offset, the use of a 0% bias slope commissioned. may give rise to maloperation. Such waveforms can be encountered when plant of similar rating to the generator is being energised or started. Differences 17.22 EXAMPLES OF GENERATOR PROTECTION between CT designs or differing remanent flux levels can SETTINGS lead to asymmetric saturation and the production of a This section gives examples of the calculations required differential spill current. Therefore, it is appropriate to for generator protection. The first is for a typical small select a non-zero setting for K1, and a value of 5% is generator installed on an industrial system that runs in usual in these circumstances. parallel with the Utility supply. The second is for a larger 184.108.40.206 Voltage controlled overcurrent protection generator-transformer unit connected to a grid system. This protection is applied as remote backup to the downstream overcurrent protection in the event of 17.22.1 Protection Settings of a protection or breaker failure conditions. This ensures Small Industrial Generator that the generator will not continue to supply the fault under these conditions. Generator Data • 17 • kVA kW PF Rated Rated Rated Rated Prime Mover At normal voltage, the current setting must be greater voltage current frequency speed type than the maximum generator load current of 328A. A 6250 5000 0.8 11000 328 50 1500 Steam Turbine margin must be allowed for resetting of the relay at this Generator Parameters current (reset ratio = 95%) and for the measurement Generator type Xd p.u. X'd p.u. CT Ratio VT Ratio tolerances of the relay (5% of Is under reference Salient Pole 2.349 0.297 500/1 11000/110 conditions), therefore the current setting is calculated as: Network Data 328 I vcset > ×1.05 Earthing Maximum earth Minimum phase Maximum downstream 0.95 resistor fault current fault current phase fault current 31.7Ω 200A 145A 850A > 362.5 A Existing Protection The nearest settable value is 365A, or 0.73In. CT Ratio Overcurrent Settings Earth Fault Settings Characteristic Setting TMS Characteristic Setting TMS The minimum phase-phase voltage for a close-up single- 200/1 SI 144A 0.176 SI 48A 0.15 phase to earth fault is 57%, so the voltage setting Vs Table 17.2: Data for small generator protection example must be less than this. A value of 30% is typically used, giving Vs = 33V. The current setting multiplying factor • 308 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:50 Page 309 K must be chosen such that KIS is less than 50% of the an operation time of not less than 1.13s. At a TMS of 1.0, generator steady-state current contribution to an the generator protection relay operating time will be: uncleared remote fault. This information is not available (missing data being common in protection studies). However, the maximum sustained close-up phase fault 0.14 s current (neglecting AVR action) is 145A, so that a setting ( ) 0.02 200 −1 chosen to be significantly below this value will suffice. A 20 value of 87.5A (60% of the close-up sustained phase fault current) is therefore chosen, and hence K = 0.6. 1.13 This is considered to be appropriate based on knowledge =2.97s, so the required TMS is = 0.38 . of the system circuit impedances. The TMS setting is 2.97 Use a setting of 0.4, nearest available setting. chosen to co-ordinate with the downstream feeder protection such that: 184.108.40.206 Neutral voltage displacement protection 1. for a close-up feeder three-phase fault, that results This protection is provided as back-up earth-fault Generator and Generator-Transfor mer P rotection in almost total voltage collapse as seen by the relay protection for the generator and downstream system (direct-connected generator). It must therefore have a 2. for a fault at the next downstream relay location, if setting that grades with the downstream protection. The the relay voltage is less than the switching voltage protection is driven from the generator star-connected It should also be chosen so that the generator cannot be VT, while the downstream protection is current operated. subjected to fault or overload current in excess of the It is therefore necessary to translate the current setting stator short-time current limits. A curve should be of the downstream setting of the current-operated provided by the manufacturer, but IEC 60034-1 demands earth-fault protection into the equivalent voltage for the that an AC generator should be able to pass 1.5 times NVD protection. The equivalent voltage is found from rated current for at least 30 seconds. The operating time the formula: of the downstream protection for a three-phase fault current of 850A is 0.682s, so the voltage controlled relay element should have a minimum operating time of 1.09s V eff = ( I pe × Z e ) × 3 (0.4s grading margin used as the relay technology used VT ratio for the downstream relay is not stated – see Table 9.2). 48 × 31.7 × 3 With a current setting of 87.5A, the operating time of = 100 the voltage controlled relay element at a TMS of 1.0 is: = 45.6 V 0.14 where: 0.02 = 3.01s 850 Veff = effective voltage setting −1 87.5 Ipe = downstream earth-fault current setting Therefore a TMS of: Ze = earthing resistance Hence a setting of 48V is acceptable. Time grading is 1.09 = 0.362 required, with a minimum operating time of the NVD • 17 • 3.01 protection of 1.13s at an earth fault current of 200A. Using the expression for the operation time of the NVD is required. Use 0.375, nearest available setting. element: 18.104.22.168 Stator earth fault protection t = K/(M-1) sec The maximum earth fault current, from Table 17.2, is where: 200A. Protection for 95% of the winding can be provided if the relay is set to detect a primary earth fault V current of 16.4A, and this equates to a CT secondary M = V snvd current of 0.033A. The nearest relay setting is 0.04A, providing protection for 90% of the winding. and The protection must grade with the downstream earth V = voltage seen by relay fault protection, the settings of which are also given in Vsnvd = relay setting voltage Table 17.2. At an earth fault current of 200A, the downstream protection has an operation time of 0.73s. the value of K can be calculated as 3.34. The nearest The generator earth fault protection must therefore have settable value is 3.5, giving an operation time of 1.18s. Network Protection & Automation Guide • 309 • Chap17-280-315 17/06/02 10:50 Page 310 188.8.131.52 Loss of excitation protection quantities (corresponding to 107% of rated stator voltage) is typically used, with a definite time delay of Loss of excitation is detected by a mho impedance relay 10s to allow for transients due to load switch- element, as detailed in Section 17.16.2. The standard off/rejection, overvoltages on recovery from faults or settings for the P340 series relay are: motor starting, etc. Xa = 0.5X'd x (CT ratio/VT ratio) The second element provides protection in the event of a (in secondary quantities) large overvoltage, by tripping excitation and the = -0.5 x 0.297 x 19.36 x 500/100 generator circuit breaker (if closed). This must be set = -14.5Ω below the maximum stator voltage possible, taking into Xb = Xd x (CT ratio/VT ratio) account saturation. As the open circuit characteristic of the generator is not available, typical values must be = 2.349Ω x 19.36 x (500/100) used. Saturation will normally limit the maximum = 227Ω overvoltage on this type of generator to 130%, so a The nearest settings provided by the relay are Xa = - setting of 120% (132V secondary) is typically used. Generator and Generator-Transfor mer P rotection 14.5Ω Xb = 227Ω. The time delay td1 should be set to Instantaneous operation is required. Generator avoid relay element operation on power swings and a manufacturers are normally able to provide typical setting of 3s is used. This value may need to be recommendations for the relay settings. For embedded modified in the light of operating experience. To prevent generators, the requirements of the local Utility may also cyclical pick-up of the relay element without tripping, have to be taken into account. For both elements, a such as might occur during pole-slipping conditions, a variety of voltage measurement modes are available to take account of possible VT connections (single or three- drop-off time delay tdo1 is provided and set to 0.5s. phase, etc.), and conditions to be protected against. In 188.8.131.52 Negative phase sequence current protection this example, a three-phase VT connection is used, and This protection is required to guard against excessive overvoltages on any phase are to be detected, so a heating from negative phase sequence currents, whatever selection of 'Any' is used for this setting. the cause. The generator is of salient pole design, so from 126.96.36.199 Underfrequency protection IEC 60034-1, the continuous withstand is 8% of rating 2 This is required to protect the generator from sustained and the I 2t value is 20s. Using Equation 17.1, the overload conditions during periods of operation isolated required relay settings can found as I2>> = 0.05 and K = from the Utility supply. The generating set manufacturer 8.6s. The nearest available values are I2>> = 0.05 and will normally provide the details of machine short-time K = 8.6s. The relay also has a cooling time constant capabilities. The example relay provides four stages of Kreset that is normally set equal to the value of K. To co- underfrequency protection. In this case, the first stage is ordinate with clearance of heavy asymmetric system used for alarm purposes and a second stage would be faults, that might otherwise cause unnecessary operation applied to trip the set. of this protection, a minimum operation time tmin should be applied. It is recommended to set this to a value of 1. The alarm stage might typically be set to 49Hz, with a Similarly, a maximum time can be applied to ensure that time delay of 20s, to avoid an alarm being raised under the thermal rating of the generator is not exceeded (as transient conditions, e.g. during plant motor starting. • 17 • this is uncertain, data not available) and to take account The trip stage might be set to 48Hz, with a time delay of of the fact that the P343 characteristic is not identical 0.5s, to avoid tripping for transient, but recoverable, dips with that specified in IEC 60034. The recommended in frequency below this value. setting for tmax is 600s. 188.8.131.52 Reverse power protection 184.108.40.206 Overvoltage protection The relay setting is 5% of rated power. This is required to guard against various failure modes, e.g. AVR failure, resulting in excessive stator voltage. A 0.05 ×5 ×10 6 setting = two-stage protection is available, the first being a low- CT ratio ×VT ratio set time-delayed stage that should be set to grade with 0.05 ×5 ×10 6 transient overvoltages that can be tolerated following = load rejection. The second is a high-set stage used for 500 ×100 instantaneous tripping in the event of an intolerable =5 W overvoltage condition arising. This value can be set in the relay. A time delay is Generators can normally withstand 105% of rated required to guard against power swings while generating voltage continuously, so the low-set stage should be set at low power levels, so use a time delay of 5s. No reset higher than this value. A setting of 117.7V in secondary time delay is required. • 310 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:50 Page 311 Protection Quantity Value Parameter Value Unit Is1 5% Generator MVA rating 187.65 MVA Is2 120% Generator MW rating 160 MW Differential protection K1 5% Generator voltage 18 kV K2 150% Synchronous reactance 1.93 pu Ise 0.04 Direct-axis transient reactance 0.189 pu Stator earth fault TMS 0.4 Minimum operating voltage 0.8 pu Vsnvd 48V Generator negative sequence capability 0.08 pu Neutral voltage displacement K 3.5 Generator negative sequence factor, Kg 10 Xa -14.5Ω Generator third harmonic voltage under load 0.02 pu Xb 227Ω Generator motoring power 0.02 pu Loss of excitation td1 3s alarm 1.1 pu tDO1 0.5s Generator overvoltage time delay 5 s Ivcset 0.73 trip 1.3 pu Vs 33 Generator undervoltage not required Voltage controlled overcurrent Generator and Generator-Transfor mer P rotection K 0.6 Max pole slipping frequency 10 Hz TMS 0.375 Generator transformer rating 360 MVA I2>> 0.05 Generator transformer leakage reactance 0.244 pu K 8.6s Generator transformer overflux alarm 1.1 pu Negative phase sequence Kreset 8.6s Generator transformer overflux alarm 1.2 pu tmin 1.5s Network resistance (referred to 18kV) 0.56 mΩ tmax 600s Network reactance (referred to 18kV) 0.0199 Ω V> meas mode three-phase System impedance angle (estimated) 80 deg V> operate mode any Minimum load resistance 0.8 Ω V>1 setting 107% Generator CT ratio 8000/1 V>1 function DT Generator VT ratio 18000/120 Overvoltage V>1 time delay 10s Number of generators in parallel 2 V>2 setting 120% V>2 function DT Table 17.4: System data for large generator protection example V>2 time delay 0sec F<1 setting 49Hz F<1 time delay 20s Underfrequency 22.214.171.124 Voltage restrained overcurrent protection F<2 setting 48Hz F<2 time delay 0.5s The setting current Iset has to be greater than the full- P1 function reverse power load current of the generator (6019A). A suitable margin P1 setting 5W must be allowed for operation at reduced voltage, so use Reverse Power P1 time delay 5s a multiplying factor of 1.2. The nearest settable value is P1 DO time 0s 7200A. The factor K is calculated so that the operating Table 17.3: Small generator protection example – relay settings current is less than the current for a remote end three phase fault. The steady-state current and voltage at the generator for a remote-end three-phase fault are given by the expressions: 17.22.2 Large Generator Transformer Unit Protection • 17 • VN The data for this unit are given in Table 17.4. It is fitted I flt = with two main protection systems to ensure security of ( nR f ) + ( X d + X t + nX f ) 2 2 tripping in the event of a fault. To economise on space, the setting calculations for only one system, that using a where: MiCOM P343 relay are given. Settings are given in If = minimum generator primary current for a primary quantities throughout. multi-phase feeder-end fault 188.8.131.52 Biased differential protection VN = no-load phase-neutral generator voltage The settings follow the guidelines previously stated. As Xd = generator d-axis synchronous reactance 100% stator winding earth-fault protection is provided, high sensitivity is not required and hence Is1 can be set Xt = generator transformer reactance to 10% of generator rated current. This equates to 602A, rf = feeder resistance and the nearest settable value on the relay is 640A (= 0.08 of rated CT current). The settings for K1, Is2 and K2 Xf = feeder reactance follow the guidelines in the relay manual. n = number of parallel generators Network Protection & Automation Guide • 311 • Chap17-280-315 17/06/02 10:50 Page 312 hence, A TMS value of 10 is selected, to match the withstand curve supplied by the manufacturer. Iflt = 2893A 18.104.22.168 100% Stator earth fault protection = 0.361N and This is provided by a combination of neutral voltage displacement and third harmonic undervoltage V N 3(( nR f ) 2 + ( X t + nX f ) 2 ) protection. For the neutral voltage displacement V flt = protection to cover 90% of the stator winding, the ( nR f ) 2 + ( X d + X t + nX f ) 2 minimum voltage allowing for generator operation at a =1304 V minimum of 92% of rated voltage is: = 0.07U N 0.92 ×18 kV ×0.1 A suitable value of K is therefore 0.3611.2 = 0.3 . 3 = 956.1V A suitable value of V2set is 120% of Vflt, giving a value Generator and Generator-Transfor mer P rotection of 1565V. The nearest settable value is 3000V, minimum Use a value of 935.3V, nearest settable value that allowable relay setting. The value of V1set is required to ensures 90% of the winding is covered. A 0.5s definite be above the minimum voltage seen by the generator for time delay is used to prevent spurious trips. The third a close-up phase-earth fault. A value of 80% of rated harmonic voltage under normal conditions is 2% of rated voltage is used for V1set, 14400V. voltage, giving a value of: 18.104.22.168 Inadvertent energisation protection 18 kV ×0.02 This protection is a combination of overcurrent with undervoltage, the voltage signal being obtained from a 3 VT on the generator side of the system. The current = 207.8 V setting used is that of rated generator current of 6019A, in accordance with IEEE C37.102 as the generator is for The setting of the third harmonic undervoltage installation in the USA. Use 6000A nearest settable protection must be below this value, a factor of 80% value. The voltage setting cannot be more than 85% of being acceptable. Use a value of 166.3V. A time delay the generator rated voltage to ensure operation does not of 0.5s is used. Inhibition of the element at low occur under normal operation. For this application, a generator output requires determination during value of 50% of rated voltage is chosen. commissioning. 18.104.22.168 Negative phase sequence protection 18.104.22.168 Loss of excitation protection The generator has a maximum steady-state capability of The client requires a two-stage loss of excitation 8% of rating, and a value of Kg of 10. Settings of I2cmr protection function. The first is alarm only, while the = 0.06 (=480A) and Kg = 10 are therefore used. second provides tripping under high load conditions. To Minimum and maximum time delays of 1s and 1300s are achieve this, the first impedance element of the P343 used to co-ordinate with external protection and ensure loss of excitation protection can be set in accordance • 17 • tripping at low levels of negative sequence current are with the guidelines of Section 17.16.3 for a generator used. operating at rotor angles up to 120o, as follows: 220.127.116.11 Overfluxing protection Xb1 = 0.5Xd = 1.666Ω The generator-transformer manufacturer supplied the Xa1 = 0.75X'd = 0.245Ω following characteristics: Use nearest settable values of 1.669Ω and 0.253Ω. A Alarm: V f >1.1 time delay of 5s is used to prevent alarms under transient conditions. For the trip stage, settings for high Trip: V >1.2 , inverse time characteristic load as given in Section 17.16.3 are used: f kV 2 18 2 Hence the alarm setting is 18000 ×1.05 60 = 315 V Hz . X b2 = = =1.727 Ω MVA 187.65 A time delay of 5s is used to avoid alarms due to X a 2 = −0.75 X d = −0.1406 Ω ′ transient conditions. The nearest settable value for Xb2 is 1.725Ω. A time The trip setting is 18000 ×1.2 60 = 360 V Hz . delay of 0.5s is used. • 312 • Network Protection & Automation Guide Chap17-280-315 17/06/02 10:50 Page 313 184.108.40.206 Reverse power protection Protection Quantity Value The manufacturer-supplied value for motoring power is Is1 8% Is2 100% 2% of rated power. The recommended setting is Differential protection K1 0% therefore 1.6MW. An instrumentation class CT is used in K2 150% conjunction with the relay for this protection, to ensure Vn3H< 166.3V accuracy of measurement. A time delay of 0.5s is used. 100% Stator earth fault Vn3H delay 0.5s The settings should be checked at the commissioning Vsnvd 935.3V Neutral voltage displacement stage. Time Delay 0.5s Xa1 -0.245Ω 184.108.40.206 Over/under-frequency protection Xb1 1.666Ω Loss of excitation For under-frequency protection, the client has specified td1 5s the following characteristics: Xa2 -0.1406Ω Xb2 1.725Ω Alarm: 59.3Hz, 0.5s time delay Voltage controlled overcurrent td2 0.5s Generator and Generator-Transfor mer P rotection 1st stage trip: 58.7Hz, 100s time delay tDO1 0s Iset 7200A 2nd stage trip: 58.2Hz, 1s time delay K 3 Negative phase sequence V1set 14400V Similarly, the overfrequency is required to be set as follows: V2set 3000V Alarm: 62Hz, 30s time delay I2>> 0.06 Kg 10 Trip: 63.5Hz, 10s time delay Overvoltage Kreset 10 These characteristics can be set in the relay directly. tmin 1s tmax 1300s 184.108.40.206 Overvoltage protection V> meas mode three-phase The generator manufacturers' recommendation is: V> operate mode any V>1 setting 19800V Alarm: 110% voltage for 5s V>1 function DT Underfrequency V>1 time delay 5s Trip: 130% voltage, instantaneous V>2 setting 23400V This translates into the following relay settings: V>2 function DT V>2 time delay 0.1s Alarm: 19800V, 5s time delay P1 function reverse power Trip: 23400V, 0.1s time delay Reverse Power P1 setting 1.6MW P1 time delay 0.5s 220.127.116.11 Pole slipping protection P1 DO time 0s This is provided by the method described in Section Inadvertent energisation Dead Mach I> 6000A Dead Mach V< 9000V 184.108.40.206. Detection at a maximum slip frequency of 10Hz Za 0.243Ω is required. The setting data, according to the relay Zb 0.656Ω manual, is as follows. Zc 0.206Ω Forward reach, ZA = Zn + Zt α 90° Pole Slipping Protection θ 80° • 17 • = 0.02 + 0.22 T1 15ms = 0.24Ω T2 15ms F>1 setting 62Hz Reverse reach, ZB = ZGen F>1 time delay 30s Reverse Power F>2 setting 63.5Hz = 2 x X'd F>2 time delay 10s = 0.652Ω P1 function reverse power P1 setting 1.6MW Reactance line, ZC = 0.9 x Z Overfrequency P1 time delay 0.5s = 0.9 x 0.22 P1 DO time 0s F<1 setting 59.3Hz = 0.198Ω F<1 time delay 0.5s where: Underfrequency F<2 setting 58.7Hz F<2 time delay 100s Z1 = generator transformer leakage impedance F<3 setting 58.2Hz F<3 time delay 1s Zn = network impedance Table 17.5: Relay settings for large generator protection example Network Protection & Automation Guide • 313 • Chap17-280-315 17/06/02 10:50 Page 314 The nearest settable values are 0.243Ω, 0.656Ω, and 0.206Ω respectively. The lens angle setting, α, is found from the equation: 1.54 − R l min α min =180 o − 2 tan −1 (Z A + Z B ) and, substituting values, αmin = 62.5° Use the minimum settable value of 90°. The blinder angle, θ, is estimated to be 80°, and requires checking during commissioning. Timers T1 and T2 are set to 15ms as experience has shown that these settings are satisfactory Generator and Generator-Transfor mer P rotection to detect pole slipping frequencies up to 10Hz. This completes the settings required for the generator, and the relay settings are given in Table 17.5. Of course, additional protection is required for the generator transformer, according to the principles described in Chapter 16. 17.23 REFERENCES 17.1 Survey of Rate Of Change of Frequency Relays and Voltage Phase Shift Relays for Loss of Mains Protection. ERA Report 95-0712R, 1995. ERA Technology Ltd. • 17 • • 314 • Network Protection & Automation Guide