COORDINATION OF GENERATOR PROTECTION WITH GENERATOR EXCITATION CONTROL AND GENERATOR CAPABILITY

1 COODINATION OF ENEATO POTECTION WITH ENEATO ECITATION CONTOL AND ENEATO CAPABILITY Working roup J-5 of the otating Machinery Subcommittee, Power System elay Committee Chairperson: Charles J. Mozina Vice Chairperson: Michael eichar Members:. Bukhala S. Conra, T. Crawley, J. arell,. Hamilton, I. Hasenwinkle, D. Herbst, L. Henriksen,. Johnson, P. Kerrigan, S. Khan,. Kobet, P. Kumar, S. Patel, B. Nelson, D. Sevcik, M. Thompson, J. Uchiyama, S. Usman, P. Wauby, M. Yalla Abstract-- This paper was written by a Working roup of the IEEE Power System elay Committee to provie guiance to the inustry to better coorinate generator protection with generator control. The paper iscusses specific calculation methos that can be use to insure generator protection an excitation system control are fully coorinate. It also specifically aresses the coorination of relays with generator full loa capability an machine steay state stability limits. Because of recent blackouts, NEC (North American Electric eliability Council) is eveloping stanars [1-3] for the coorination of generator protection an control. This paper provies practical guiance on proviing this coorination. Inex Terms-- Automatic Voltage egulator (AV), NEC (North American Electric eliability Council), Over Excitation Limiter (OEL), Uner Excitation Limiter (UEL), Steay State Stability Limit (SSSL), MW-Mvar (P-Q) Diagram, esistance- eactance (-) Diagram I. INTODUCTION The nee to coorinate generator protection with generator control an loa capability has been well known to generator protection engineers. The techniques, metho an practices to provie this coorination are well establishe but scattere in various textbooks, papers an in relay manufacturer s literature. In many cases these techniques, methos an practices are not well known to the practicing generator protection engineers. The purpose of this paper is to provie a single ocument that can be use to aress coorination of generator protection with generator control. The paper uses example calculations as its means of communicating these methos. This paper also iscusses steay state stability an its impact on setting generator protection. The nee to improve coorination between generator protection an control has come to light after recent misoperation of generator protection uring major system isturbances. Two significant isturbances are the 1996 western area isturbances an 003 east coast blackout. Because of these isturbances, NEC (North American Electric eliability Council) is asking users to verify coorination of generator protection an control [1-3]. This paper provies practical guiance for proviing this coorination in the following specific protection areas: enerator Capability Curve Coorination Unerexcite setting coorination with generator loss-offiel (40) protection Overexcite setting coorination with generator impeance (1) backup protection AV Coorination - Unerexcite Operation Coorination of the Uner Excitation Limiter (UEL) with loss-of-fiel protection an Steay State Stability Limits AV Coorination Overexcitation Operation Coorination of AV V/Hz limiter with overexcitation (V/Hz) protection II. ENEAL DISCUSSION OF ENEATO CAPABILITY AND ECITATION CONTOL A. Excitation Control Basics The excitation system of a generator provies the energy for the magnetic fiel (satisfying magnetizing reactance) that keeps the generator in synchronism with the power system. In aition to maintaining the synchronism of the generator, the excitation system also affects the amount of reactive power that the generator may absorb or prouce. Increasing the 1

excitation current will increase the reactive power output. Decreasing the excitation will have the opposite effect, an in extreme cases, may result in loss of synchronism of the generator with the power system. If the generator is operating isolate from the power system, an there are no other reactive power sources controlling terminal voltage, increasing the level of excitation current will increase the generator terminal voltage an vice versa. The most commonly use voltage control moe for generators of significant size that are connecte to a power system is the AV (Automatic Voltage egulator) moe. In this moe the excitation system helps to maintain power system voltage within acceptable limits by supplying or absorbing reactive power as require. In isturbances where short circuits epress the system voltage, electrical power cannot fully be elivere to the transmission system. Fast response of the excitation system help to increase the synchronizing torque to allow the generator to remain in synchronism with the system. After the short circuit has been cleare, the resulting oscillations of the generator rotor spee with respect to the system frequency will cause the terminal voltage to fluctuate above an below the AV set point. Excitation controls are calle upon to prevent the AV from imposing unacceptable conitions upon the generator. These controls are the maximum an minimum excitation limiters. The overexcitation limiter (OEL) prevents the AV from trying to supply more excitation current than the excitation system can supply or the generator fiel can withstan. The OEL must limit excitation current before the generator fiel overloa protection operates. The uner excitation limiter (UEL) prevents the AV from reucing excitation to such a low level that the generator is in anger of losing synchronism, exceeing machine uner-excite capability, or tripping ue to exceeing the loss of excitation protection setting. The UEL must prevent reuction of fiel current to a level where the generator loss-of-fiel protection may operate. B. enerator Steay State Stability Basics Steay state instability occurs when there are too few transmission lines to transport power from the generating source to the loa center. Loss of transmission lines into the loa center can result in steay state instability. Fig.1 illustrates how steay state instability occurs for a simplifie system with no losses. The ability to transfer real (MW) power is escribe by the power transfer equation below an is plotte graphically in Fig. 1. Pe = Eg Es Sin ( θg- θs ) Where: Eg = Voltage at eneration Es = Voltage at System Pe = Electrical eal Power Transfer = Steay State eactance Between enerator an System θg = Voltage Angle at eneration Max. Power Transfer P e θs = Voltage Angle at System Pe Pmax = Eg Es 0 Max. Power Transfer All Lines in Service All linesin service Line 11 trippe Trippe Line Trippe Line trippe 0 90g o - s 180 0 0g - 0s 0 0 40 60 80 100 10 140 160 180 00 Fig. 1 Power Angle Analysis - Steay State Instability From the power transfer equation above it can be seen that the maximum power (Pmax) that can be transmitte is when θg-θs = 90 0 i.e. sin 90 0 = 1. When the voltage phase angle between local an remote generation increases beyon 90 0 the power that can be transmitte is reuce an the system becomes unstable an usually splits apart into islans. If enough lines are trippe between the loa center an remote generation supplying the loa center the reactance () between these two sources increases to a point where the maximum power (Pmax), which can be transferre, is insufficient to maintain synchronism. The power angle curve in Fig. 1 illustrates this reuction as line 1 trips the height of the power angle curve an maximum power transfer is reuce because the reactance () has increase. When line trips the height of the power angle curve is reuce further to the point where the power being transferre cannot be maintaine an the unit goes unstable. During unstable conitions generators may slip poles an lose synchronism. Voltage collapse an steay state instability can occur together as transmission lines tripping increase the reactance between the loa center an remote generation. A graphical metho can be use to estimate the steay state stability limit for a specific generator. This metho is iscusse in Section IV of this paper. C. enerator Watt/var Capability A typical cylinrical rotor generator capability curve is shown in Fig.. The capability curve establishes the steay state (continuous) generator operating limits. The generator capability curve is normally publishe at generator rate voltage. Salient pole generators have a slightly ifferent characteristic in the unerexcite region. The curve also shows how the AV control limits steay state operation to within generator capabilities. The generator capability (Fig.) is a composite of three ifferent curves: the stator wining limit, the rotor heating limit an the stator en iron limit. The stator

3 wining limit is a long-term conition relative to the generator wining current carrying capability. eactive Power into System + Mvar Overexcite 0 Unerexcite - Mvar eactive Power into enerator Overexcitation Limiter (OEL ) Uner Excitation Limiter (UEL) otor Wining Limite Steay State Stator En Stability Limit Iron Limite + MW MW Mvar Stator Wining Limite eal Power into System MW Mvar System Normal Overexcite Operation Unerexcite Operation System Fig. Typical enerator Capability Curve an Operating Limits for a cylinrical rotor generator The rotor wining limit is relative to the rotor s current carrying capability. It is also associate with longer time conitions. The stator en iron limit is a relatively short time conition, cause by a reuction in the fiel current to the point where a significant portion of the excitation is being supplie from the system to the generator. Significant unerexcitation of the generator causes the rotor retaining ring to become saturate. The ey currents prouce by the flux cause localize heating. Hyrogen coole generators have multiple capability curves to reflect the effect of operating at ifferent H pressures. voltage bus minimum an maximum voltage uring peak an light loa conitions. The high an low voltage limits for the auxiliary bus, generator terminal an system buses are interrelate by the tap position selecte for the generator step up transformer an the unit auxiliary transformer. Consequently, as power system operating change, it is necessary to check tap setting to ascertain that aequate reactive power is available to meet power system nee uner emergency conitions. D. P-Q to - Conversion Both Figures an 3 illustrate the capability of a generator on a MW-Mvar (P-Q) iagram. This information is commonly available from all generator manufactures. Protection functions for the generator, such as loss-of-fiel (40) an system backup istance (1) relaying measure impeance, thus these relay characteristics are typically isplaye on a esistance- eactance (-) iagram. To coorinate the generator capability with these impeance relays, it is necessary to either convert the capability curve an excitation limiters (UEL an OEL) to an - plot or to convert impeance relay settings to a MW-Mvar plot. Figure 3 illustrates this conversion [4]. The CT an VT ratios (c/v) convert primary ohms to seconary quantities that are set within the relay an kv is the rate voltage of the generator. The generator excitation control limiters are intene to limit operation of the generator to within its continuous capabilities. Fig illustrates how these limiter setpoints can be plotte on a typical generator capability curve. enerally, the setting of the UEL control will also coorinate with the steay-state stability limit of the generator which is a function of the generator impeance, system impeance an generator terminal voltage. This section of the paper iscusses steay state stator stability in general terms. The next sections of this paper will outline a conservative graphical metho for estimating the steay state stability limit for a generator as well as a specific example. The overexcitation control (OEL) limits generator operating in the overexcite region to within the generator capabilities curve. Some users set the OEL just over the machine capability curve to allow full machine capability an to account for equipment tolerances, while others set it just uner the capability curve as shown in Fig. MVA = kv ( c ) v Engineers shoul be aware that more restrictive limits of generator capability coul be impose by the power plant auxiliary bus voltage limits (typically +/- 5%), the generator terminal voltage limits (+/-5%), an the system generator high Fig. 3 Transformation from MW- Mvar to - an - to MW-Mvar Plot 3

4 P o w e r S y s te m Im peance of the longest transm ission line L L 1 = 0.0 1 0 9 5 + j0.1 1 5 4 6 p u o n 1 0 0 M V A b a s e Im peance of shortest transm ission line S L 1 = 0.0 0 5 4 6 + j0.0 5 7 7 3 p u o n 1 0 0 M V A b a s e S ystem Im peances: M in.= s tro n g e s t lin e o u t o f s e rv ic e M a x.= a ll lin e s in s e rv ic e M in S 1 = 0.0 0 1 0 5 + j0.0 1 6 4 6 3 p u o n 1 0 0 M V A b a s e 1 4 5 k V 1 9 k V m a x s 1 = 0.000511+ j0.010033pu on 100M V A base U n it T ra n s fo rm e r T = 0.1 1 1 1 p u o n 4 5 M V A b a s e V T 0,0 0 0 V 1 0 V C T 1 8 0 0 0 /5 A A u x. T ra n s fo rm e r 4 9 M V A B a se = 1.1 8 8 8 p u ' = 0. 0 5 7 7 p u " = 0.1 7 8 4 7 p u = 0.1 7 6 7 6 p u C T 1 8 0 0 0 /5 A 1 4 4 0 0 4 0 /1 0 V 1. 5 O h m s Fig.4 One line iagram with generator an power system ata for example generator III. BASIC MACHINE AND SYSTEM DATA FO EAMPLE CALCULATION 400 Mvar 60 PSI 45 PSI A 49 Mva, 0kV irect coole cylinrical rotor steam turbine rate at 140A, 0.77PF has been selecte as the sample generator to emonstrate the calculation methos to provie coorination of generator AV control, machine capability an steay state stability limit with relay protection. Fig. 4 shows the basic one line iagram as well as machine an system impeance ata that are require for the example calculations. The unit transformer in this example is 45MVA, Y-groune/elta whose tap are set at 145/19kV. Fig 5 shows the generator capability curve for the example machine. Key symbols use in calculation are efine in Appenix I. 300 00 100 0 49 MVA 0 kv 3600 PM 0.77 PF Hyrogen - Water Coole 100 00 300 400 MW 0.77 LA 0.90 LA O.98 LA 500 IV. AV COODINATION- UNDEECITED OPEATION 100 0.95 LEAD Excitation systems selom operate at the extremes of their capabilities until the system voltage attempts to rise or fall outsie its normal operating range. During voltage transients, excitation controls allow short-term operation of the excitation system an generator beyon the rate steay state limits. The excitation system controls an protective relays must coorinate with regar to both pickup magnitues as well as time elays. The setting of the uner excitation limiter takes into consieration the generator capability curve an the setting of the loss-of-fiel 00 300 Fig 5 enerator Capability Curve for Example enerator relay (see Section V) plus the characteristics of the uner excitation limiter itself. These characteristics vary with each generator an system configuration. The automatic voltage regulator uses the generator terminal voltage an phase current to calculate the existing operating conitions. By comparing the actual point of operation to the esire limit, 4

5 the regulator etermines when it is appropriate to ajust the generator fiel current in orer to remain within the esire operating conitions. Alternatively, iscrete relays have also been applie to motor operate rheostat excitation systems. These relays operate similarly to the above automatic regulator function, measuring generator voltage an current to etermine the actual operating conition, an then initiating a control signal when the limit setting is exceee. It shoul be note that the limit settings can change with voltage. Some limiters change as the square of the voltage (90% voltage results in 81% of the setting), while others are proportional with the voltage (90% voltage results in 90% of the setting). Still other limiters may not change with voltage at all. To assure proper operation for all conitions, the specific voltage variation characteristic shoul be ientifie when setting the limiter. Manual regulators o not have uner excitation limiters as an active component. The process for establishing the unerexcitation limit an checking the coorination is as follows: 1. Obtain the generator capability curve.. Obtain the step-up transformer impeance ( T ), generator synchronous () an transient reactance ( ). A. Steay State Stability Limit (SSSL) - raphical Metho The steay state stability limit (See Section II) reflects the ability of the generator to ajust for graual loa changes. The steay state stability limit is a function of the generator voltage an the impeances of the generator, step-up transformer an system. This metho assumes fiel excitation remains constant (no AV) an is conservative. NEC explicitly requires that generators operate uner AV control, which improves the stability limit. When making the calculations, all impeances shoul be converte to the same MVA base, usually the generator base. The steay state stability limit is a circle efine by the equations shown in Fig. 6 below [4]: enerator V SU T Per Unit Mvar System eactance S Where e= T + S 3. Determine the equivalent system impeance typically with the strongest source out-of-service. 4. Calculate the steay state stability limit an plot on the generator capability curve. V 1 1 e V 1_ + 1 e 5. Calculate the loss-of-fiel relay setting an plot on the generator capability curve. This setting shoul be ajuste, epening upon the steay state stability curve an the generator capability curve (see Section V). MW - Mvar PE UNIT PLOT Per Unit MW 6. Determine the most limiting conition(s), consiering the generator capability curve, the steay state stability curve an the loss-of-fiel relay characteristic. 7. Determine the uner excitation limiter setting. e 8. Verify that the impeance loci o not swing into the relay impeance characteristic, causing a false trip for a stable system transient. This generally requires transient stability stuies. - e + e 9. Determine the time elay, base upon the excitation system time constants an the characteristics of the system swings. Verify the coorination between the uner excitation limiter setting an the loss-of-fiel relay settings. - DIAAM PLOT Fig. 6 raphical Metho for Steay State Stability 5

6 Where = generator synchronous reactance s = equivalent system reactance e = the sum system an step-up transformer reactance (s + T ) V = generator terminal voltage The graphical metho shown in Fig. 6 is wiely use in the inustry to isplay the steay state stability limit on P- Q an - iagrams. The generator cannot be operate beyon the steay state stability limit. It shoul be note that the weaker the transmission system, the smaller the circle raius. Often times, the system reactance moel will consist of the normal system without the single strongest line from the external system. This provies a setting still vali for any line out of- service. In most cases, the steay state stability limit is outsie the generator capability curve, an oes not restrict generator operation. B. Steay State Stability Limit (SSSL) Calculation Example an UEL Setting. 1. enerator an system ata are shown in Fig. 4 an the generator capability curve in Fig. 5.. The step-up transformer reactance is given as 0.1111 pu on a 45 MVA base. The generator synchronous reactance is 1.18878 pu on a 49 MVA base. The generator transient reactance is 0.0577 pu. The transformer impeance on the generator base is 0.11607 pu as calculate below: 19 min S * 0.07338 0. 0661pu 0 4. To calculate the steay state stability limit on a P-Q iagram use the equations in Fig 6. e= T + min S1 = 0.11607pu+0.0661pu =0.1838 pu. The generator synchronous impeance,, is 1.18878 pu (see Fig.4). Center = V 1-1 = 1 1-1 e 0.184 1.18878 =.31pu of 49 MVA or 114 MVA aius = V 1 + 1 = 1 1 + 1 e 0.184 1.18878 = 3.16pu of 49 MVA or 1556 MVA Using the equations for the center an the raius in Fig. 6. the center is at 114 on the positive Mvar axis, an the raius is 1556MVA. The intercept point on the negative Mvar axis is at 414Mvar (1556-114). The P-Q plot is shown below in Fig. 7. Fig. 7 also shows the UEL an generator capability (CC) on the P-Q plot. MVA kv T * MVA T 49 19 * 45 0 Tlow * T kvs T *0.111 0.11607 3. The system impeance (with the strongest source out of service) is min S1 = j0.016463 pu on a 100 MVA base. The system voltage base is 138kV, which is ifferent than the transformer s 145kV high sie tap. Therefore to account for the ifference in the voltages, the impeance has to be ajuste as the square of the voltages (138 /145 ) as shown below: min ST MVA kv 1 * * min MVA kv S S Thigh 49 138 min ST1 * * 0.016463 0. 07338pu 100 145 S1 The impeance then must be converte from the transformer voltage base to the generator voltage base. min S kv kv Tlow * min ST1 6 Fig.7 enerator Capability (CC), Unerexcitation Limiter (UEL) an Steay State Stability Limit (SSSL) for Example enerator P-Q Plot 5. From Fig., generally the stator en iron limit on the generator capability curve is the most limiting conition, compare to the steay state stability limit or the loss-offiel relay characteristic.

7 6. The uner excitation limiter (UEL) shoul be set to operate prior to reaching the stator en iron limit. Assuming that the plant operates between H pressures of 45psig an 60psig, use a margin of 10% of the leaing Mvar limit (machine en turn limit or steay state stability limit, whichever is most limiting) at various MW points. The example limiter has three set points, one on the negative var axis, one on the positive Watt axis, an one efine with both a Watt an var point. All points are expresse as per unit on the generator MVA base. They shoul be selecte to allow the greatest range of generator operation as possible. The points (vars pu, Watts pu) will be (0.45, 0), (0.7, 0.81) an (0, 1.1). They are plotte on Fig. 7 in Mvar an Mw values using the 49 MVA base. 7. The uner excitation limiter time elay shoul be minimal. Some limiters o not have an intentional elay, but utilize a amping setting or circuit to stabilize the limiter output. In aition, there may be a setting to proportionally increase the limiter output, epenant upon the severity of the unerexcitation conition (increase output for a more severe conition). The limiter manufacturer shoul be consulte for these parameters. V. ENEATO LOSS OF FIELD COODINATION To limit system voltage the generators may have to operate unerexcite an absorb Vars from the power system. It is important that the generator be able to o so within its capabilities as efine by the generator capability curve. The generator uner excitation limiter (UEL) must be set to maintain operation within the capability curve as show in Fig.. The loss of fiel relay must be set to allow the generator to operate within its unerexcite capability. relay approach is wiely use within the inustry to provie high-spee etection. There are two basic esigns of this type of protection. The first metho (Scheme 1 Fig.8) consists of two offset Mho units. An impeance circle iameter equal to the generator synchronous reactance an offset ownwar by ½ of the generator transient reactance is use for the one istance element. The operation of this element is elaye approximately 30-45 cycles to prevent misoperation uring a stable transient swing. A secon relay zone, set at an impeance iameter of 1.0 per unit (on the generator base), with the same offset of ½ of the generator transient reactance is use also. This one 1 element has a few cycles of elay an more quickly etects severe unerexcitation conitions. When synchronous reactance is less than or equal to 1.0 per unit (e.g. hyro generators) only the one is use an is set with the iameter equal to 1.0 per unit. The secon relaying metho (Scheme Fig.10) consists of an unervoltage unit, an impeance unit an a irectional unit. In this case the generator synchronous an transient reactances are use to etermine the settings. As with the first scheme, two elements are use, one without significant elay (typically 0.5 secon for the most severe conition) an the other elaye to prevent misoperation. For both schemes the relay settings are base on ct an vt seconary quantities, thus the impeances nee to be calculate on the ct an vt seconary basis. A. Loss of Fiel Calculation Example Scheme1: In this example, two mho characteristics are use. Stanar settings for this two zone loss-of-fiel scheme are shown below in Fig.8. Partial or total loss of fiel on a synchronous generator is etrimental to both the generator an the power system to which it is connecte. The conition must be quickly etecte an the generator isolate from the system to avoi generator amage. A loss of fiel conition, which is not etecte, can have a evastating impact on the power system by causing both a loss of reactive power support as well as creating a substantial reactive power rain. This reactive rain, when the fiel is lost on a large generator, can cause a substantial system voltage ip. When the generator loses its fiel, it operates as an inuction generator, causing the rotor temperature to rapily increase ue to the slip inuce ey currents in the rotor iron. The high reactive current rawn by the generator from the power system can overloa the stator winings. These hazars are in aition to the previously mentione stator en-iron amage limit. The most wiely applie metho for etecting a generator loss of fiel conition on major generators is the use of istance relays to sense the variation of impeance as viewe from the generator terminals. A two-zone istance 7 - - 1.0 pu one one 1 - Heavy Loa Light Loa Fig. 8 Loss-of-Fiel - Diagram -- Scheme 1 + Impeance Locus During Loss of Fiel

8 The zone element is set at a iameter of or 1.18878 pu an the one1 iameter woul be set at 1.0 pu on the generator base. Both units are offset by /.The generator ata is shown in Fig.4.The formula to convert the generator impeances (which are in pu) to relay seconary ohm is shown below: kv * MVA PU sec * Where: sec = elay Seconary Ohms kv = enerator ate Voltage pu = pu eactance MVA = enerator ate MVA c = CT ratio v = VT ratio one 1 Diameter of the circle is set at 1.0 pu or 17.56 Ω Offset of the circle / is 0.0577/ pu or -1.8067 Ω ' Time elay: A short time elay of approximately 3 to 5 cycles is suggeste to prevent misoperation uring switching transients. one- Diameter of the mho circle is set at C V = 1.1888 pu or 0.88 Ω.Offset of the mho circle is set the same as for one 1 or -1.8067 Ω Time elay: A minimum time elay of 30 to 45 cycles is typically use to prevent relay misoperation uring stable power swing conitions. In cases where only one mho element is use, the methoology for one above is typically employe. Fig. 9 shows the loss of fiel relay characteristics along with generator capability curve (CC), the uner excitation limiter (UEL), an the steay state stability limit (SSSL) plotte on the - plane. The CC, UEL curves are converte from P-Q plane to - plane using the calculation metho escribe in Fig.3. 10.0 5.0 0.0-5.0-10.0-15.0-0.0-5.0-30.0-35.0-40.0 j -0.0-15.0-10.0-5.0 0.0 5.0 10.0 15.0 0.0 5.0 30.0 ONE1 ONE SSSL Fig 9 Loss-of- Fiel, Scheme 1, - Plot Scheme: This scheme also uses both one 1 an one elements. Stanar settings for this two zone loss-of-fiel scheme are shown below in Fig.10: - T + mins1 1.1 one + one 1 CC UEL UEL Heavy Loa Light Loa - Directional Element CC ONE ONE1 SSSL + Impeance Locus During Loss of Fiel - Fig. 10 Loss -of-fiel - Diagram -- Scheme Scheme uses a combination of two impeance elements, a irectional unit an an unervoltage unit applie at the generator terminals. The one element is set to coorinate with the Steay State Stability Limit. The top of the one circle (positive offset) is set at the system impeance in front of the generator. Typically, this will be the generator 8

9 transformer reactance T + mins1. mins1 is the weak source (with the strongest line out of service) system impeance on the generator base. The transformer an system impeance must be put on the same base as the generator. The negative reach is set to at least 110% of to encompass the SSSL with margin. The negative reach of one 1 element is then set to match. The negative offset of one 1 element is set to / to establish the top of the circle. Since the one element has a positive offset it is supervise by a irectional element (DE) to prevent pickup for system or unit transformer faults. The irectional element is typically set at an angle of between 10 an 0 egrees. This unit is usually set at 13 o. The one time elay is typically set at 10 sec. to 1 minute. A loss of fiel conition is generally accompanie by low generator terminal voltage. For this conition an unervoltage relay is use to reuce the one time elay. The rop out of the unervoltage unit is typically set at 0.80-0.87 pu which will cause accelerate one tripping with a time to 0.3-0. sec. Transient stability stuies can be use to refine the voltage supervision an time elay settings. one- Diameter is typically set to 1.1 times plus the weak system source an step-up transformer impeances.the 110% multiplier on provies a margin to pickup before reaching the steay state stability limit. In this application, there is a large separation between the SSSL an the CC. In orer to provie better protection for uner-excite operation of the unit, the margin can be set to 15%, which moves the characteristic to approximately half way between the SSSL an the CC curves. Diameter of the circle in pu: 1.5 * min Diameter 1.5*1.1888 0.11610.066 Diameter 1.6683 Diameter T or 9.3 Ω S one Delay: Set the one elay long enough that corrective action may take place to restore excitation before the unit goes unstable. Settings of 1 secon to 1 minute are appropriate. Since two zones are use, the elay will be set to 10 sec. Phase Unervoltage Element: An uner-excitation conition accompanie by low system voltage cause by the system's inability to supply sufficient Vars will cause the unit to go unstable more quickly. For this conition, an unervoltage unit is use to bypass the one time elay for low system voltage. The rop out of the unervoltage unit is typically set at 0.8 pu which will cause accelerate one tripping with a time elay of 0.5 sec. one-1 one 1 Diameter: Set to same negative reach as one of /. Diameter of the circle in pu: ' 1Diameter 1.5* 0.0577 1Diameter 1.5*1.1888 1Diameter 1.3831 or 4.3 Ω one 1 offset: Set to one half of the generator transient reactance. ' 1Offset 0.0577 1Offset 0.10885 or 1.806 Ω Offset Fig. 11 shows the loss of fiel relay characteristic for Scheme with the generator capability curve (CC), the uner excitation limiter (UEL) an steay state stability limit (SSSL). one Offset: Set the one offset to the system source impeance (eactance) as seen from the terminals of the unit. min Offset T S 0.11610.066 Offset Offset 0.183 or 3. Ω one Directional Supervision: Since the one element has a positive offset; it is supervise by a irectional element (DE) to prevent pickup of the element for system or unit transformer faults. Set the irectional element to 13 egrees. 9

10 10.0 j DI ELEMENT 5.0 0.0-0.0-15.0-10.0-5.0 0.0 5.0 10.0 15.0 0.0 5.0 30.0 ONE -5.0 when the generator is subjecte to low system voltage. Note that the impeance is reuce by the square of the voltage. System voltage uner emergency conitions can reuce to planne levels of 90 to 95 percent of nominal ratings [5]. Utility transmission planners shoul be consulte for worst case emergency voltage levels at power plants. ONE1-10.0-15.0-0.0-5.0 SSSL C UEL UEL CC Distance relays with a mho characteristic an one or two zones are commonly use for phase fault backup. If only one zone is use its setting is base on the one criteria outline below. Setting generator backup protection with aequate margin over loa an stable power swings is an art as well as a science. The suggeste criteria below provie reasonable settings that can be verifie for security using transient stability computer stuies. -30.0-35.0 ONE DI ONE1 SSSL The one 1 relay element is set to the smaller of two conitions: -40.0 Fig 11 Loss-of- Fiel, Scheme, - Plot VI. ENEATO PHASE BACKUP (1) COODINATION The primary purpose of the phase istance (1) relay is to protect the generator from supplying prolonge fault current to fault on the power system to which the generator is connecte. A mho characteristic is commonly use to etect system phase faults an to separate the generator after a set time elay. The relay s impeance reach an time elay settings must be coorinate with transmission system primary an backup protection to allow selectivity. Typically, the phase istance relay s reach begins at the voltage input to the relay an extens the length of the longest line out of the transmission substation. Some factors involving the settings are as follows: 1. In-fees: Apparent impeance ue to in-fees will require larger reaches; however, settings to cover long lines may overreach ajacent short lines.. Transmission System Protection: If the transmission lines exiting the power plant have proper primary an backup protection as well as local breaker failure the nee to set the 1 relay to respon to faults at the en of the longest lines is mitigate. 3. Loa Impeance: Settings shoul be checke to ensure the maximum loa impeance ( max/loa =kv / MVA at rate power factor angle (PFA) oes not encroach into the reach. A typical margin of 150-00 % at rate power factor is recommene to avoi tripping uring power swing conitions. Due to recent blackouts cause by voltage collapse the 1 istance setting shoul be checke for proper operating margins 1. 10% of the unit transformer impeance.. Set to respon to faults 80% of the one 1 setting of the shortest transmission line exiting the power plant (neglecting in-fees) plus step-up transformer impeance. Some users apply one 1 as a backup to generator bus work an SU protection with typical settings of 50-80% of the SU impeance. A time elay of approximately 0.5 secons gives the primary protection (generator ifferential, transformer ifferential an overall ifferential) enough time to operate before the generator backup function. Stability stuies may be require to insure that one 1 unit oes not trip for stable power swings. The one relay element is typically set at the smaller of the three following criteria: 1. 10% of the longest line with in-fees.. 50 to 67% of the generator loa impeance ( loa ) at the rate power factor angle (PFA) of the generator. This provies a 150 to 00% margin over generator full loa. This is typically the limiting criteria. 3. 80 to 90 % of generator loa impeance at the maximum torque angle of the one impeance relay setting (typically 85 0 ). 4. Time elay to coorinate with transmission system backup protection an local breaker failure. A. one 1 Setting Example Set zone 1 using the smaller of the two criteria: Criteria 1 10% of the unit transformer ( T ) Converting T to seconary ohms 10

11 kv * T T sec * MVA 0 T sec T sec. 038 C V * 0.11607 18,000 5 * 49 0,000 10 1 P.U. ~ I S maxs1 I '+ T LL1 1 reach Criteria 1.0 *.038. 45 Set at 80% of the one 1 setting of the shortest line plus step-up transformer impeance. The impeance of the shortest line exiting the power plant is SL1 = j 0.05773 pu on a 100MVA base. The zone 1 line setting is 80% of the line length. First put the impeance on the generator base. SL SL SL MVA MVA 49 138 * 100 145 0.319 kv kv S Tlow * * * SL1 S kvthigh kv pu 19 * 0 *0.05773 Converting the line impeance to seconary relay ohms. kv * SL1 L1sec * MVA 0 *0.319 18,000 5 L1 sec * 49 0,000 10 4. 077 L1sec Assuming the zone 1 line setting is 80% of the lines then: 1reach T sec 0.8* (0.8* L1sec ).0410.8* (0.8* 4.077) 4. 6095 1 reach Set the zone 1 at the smaller setting of.45 at a MTA of 85 0. B. one Setting Example Criteria 1 C V _ LINE The apparent impeance reach ( ) to the en of the longest line exiting the plant will require an in-fee calculation because both the generator an the utility transmission system will contribute fault current. The saturate value of transient reactance is use in this calculation since this is for a time elaye backup element. 11 Fees Fig. 1 Equivalent Circuit for Apparent Impeance with In- Total = LL1 I Total = 1 max S1 1 ' 1 0.04566 + j0.5004 pu 1 Total Current Divier ule: I S = I Total 1.76895 pu I = I Total 0.07 pu T = 0.18097 j1.9853 pu x x ' ' ' T T MaxS1 T = MaxS1 MaxS1 = = Base on the criteria 1 for the one element setting: _ LINE = ( T I I 1. I S + LL1 ) x B _ relay = 90. Ω 85, maximum torque angle one (MTA) = 85 Criteria To satisfy criteria, the reach of the 1- element shoul not excee 50% to 66.7% (00% to 150% of the generator capability curve) loa impeance at rate power factor. Otherwise the istance element coul trip on loa or stable power swings. This calculate is shown below: max = loa kv MVA CT VT atio atio = 17.56 39.64(0.77pf) The reach setting at MTA base on max loaing base on max loa above is:

1 _ MTA = 0.67x max_ loa COS( MTA PFA ) where FPA is the rate power factor angle. Criteria 3 = 16.685; j 30.0 5.0 LONEST LINE (WITH IN FEED), 75.5 OHMS The reach of the 1- element shoul not excee 80% to 90% (15% to 111% of the generator capability curve) loa impeance at maximum torque angle. Otherwise the istance element coul limit the generator capability curve. This can be calculate as: 0.0 ONE CC CC ONE ONE1 SYSTEM _ = CC MTA kv MVA CC _ MTA CT VT atio atio = 3.14 85 15.0 50% to 67% OF CC @ PFA _ MTA = 0.9 x CC MTA _ = 0.885 Since criteria gives the smallest reach setting, the 1- setting shoul be set at 16.6at the MTA of 85 0 to provie a secure setting. This is much less than the 90. reach require to respon to faults at the en of the longest line. For this case, upgraing of the backup protection on the transmission system shoul be investigate to provie proper primary an backup protection as well as local breaker failure. For this case, upgraing of the backup protection on the transmission system shoul be investigate to provie proper primary an backup protection as well as local breaker failure. In this case the esire generator remote backup cannot be provie without compromising loaability. Fig. 13 shows the istance elements an generator capability curve plotte on an - iagram. SHOTEST LINE (NO INFEED) 10.0 5.0 0.0-10.0-5.0 0.0 5.0 10.0 15.0 0.0 TANSFOME HIH SIDE -5.0 ONE1 Fig.13 1 Distance Setting Examples Plotte on an - Diagram MTA PFA VII. AV COODINATION- OVEECITED OPEATION Excitation system protection/control as well as protection external to the excitation system nees to be coorinate so as not to limit the generator overexcitation capability. During major system isturbances, the excitation control/ protection must allow the generator to operate within its short time capabilities. 1

13 Percent of at ate Fiel Current 50 00 150 100 50 0 0 0 0 C50.13 I*t Trip I*t Control Limit 0 0 0 40 60 80 100 10 Time In Secons 0 Another important factor that must be incorporate into the esign of the excitation protection/control system is the nee to accommoate fiel forcing uring faults to ai in maintaining transient stability. This ictates that very high rotor fiel current (typically in the range of 140-80% of rating) must be permitte to flow for a short perio of time without causing the exciter control to reuce fiel voltage because of the high fiel current. enerator Fiel DCCB or Contactor OC en. AV CT Excitation Transformer Static Exciter VT enerator Step-up Transformer 51* * FUSES USEDON SMALLE ENEATOS Fig. 14 C50.13 Cylinrical-otor Fiel Short Time Capability [7] an Typical Limiter Control an Trip Coorination [13] System var support provie by the generator is extremely important to maintain power system voltage stability. IEEE C50.13 [7] efines the short-time fiel thermal capability for cylinrical-rotor generators. In this stanar the short time thermal capability is given in terms of permissible fiel current as a function of time. A plot (curve rawn from ata in C50.13) of this short time capability is shown in Fig.14. Present-ay exciters fall into two broa categories: those using AC generators (alternators) as a power source an those that use transformers. Because the protection requirements of the excitation system are closely relate to their esign, the fiel protection equipment is normally provie as part of the excitation system. Data for the specific generator fiel capability nee to be use in etermining excitation capability an coorination. It is important that the control as well as any tripping protection that maybe embee within the exciter allow the generator to provie full overexcitation system support uring system voltage transient as well as for steay state conitions. As iscusse in Section II of this paper, the selection of the step-up transformer tap setting play a key role in etermining whether the generator can provie it s full var support to the system without being limite by the generator terminal voltage. enerally, in the US generator step-up transformers are not equippe with LTC loa tap changing. Consequently, as power system operating conitions change over time, it is necessary to perioically check that optimum transformer tap settings have been selecte [1]. Such checks are typically one by system planning engineers who etermine optimum tap settings from loa flow stuies. OC= DC OVECUENT ELAY Fig. 15 Typical Transformer Supplie Excitation System Fiel forcing times are typically at least 1 secon but may be as long as 10 secons for compoun or brushless excitation systems. [13]. Fig. 15 illustrates a typical transformer supplie static excitation system with the excitation transformer connecte to the generator terminals. Excitation systems have controls an limiters that are esigne to protect the fiel from thermal amage ue to prolonge exposure to high current or overexcitation ue to higher than allowable flux (V/Hz) levels. Typically key protection/control elements within the excitation system that affect overexcitation generator operation inclue: Overexcitation Limiter (OEL) Protects the generator fiel circuitry from excessive current versus time heating. Its setting shoul be coorinate with the generator capability in the overexcitation region as escribe in Section II of this paper so that full var capability of the generator is available. The setting shoul also allow the exciter to respon to fault conitions where fiel current is booste (fiel forcing) to a high level for a short perio of time. In many cases this coorination is provie by not enabling OEL control until the fiel forcing time is exceee. The OEL setting shoul also allow utilization of the short time fiel current capability as efine by C50.13 (Fig. 14 for cylinrical rotor generators). Typically, the OEL takes over control to limit fiel current from the steay state AV control for close in faults where the inuce fiel current remains high or uring sustaine system low voltage conitions requiring fiel current above rate levels. In new excitation systems the OEL 13

14 limiter control has the ability to moify its setting base on either hyrogen pressure (if the generator is hyrogen coole) or inlet air temperature measurements. V/Hz Limiter Limits the generator V/Hz ratio by limiting the generator voltage to a programme setting. Steay state limit are +/- 5% of rate generator stator terminal voltage at rate frequency. The setting shoul permit short time excursions uring transient conitions. The V/Hz limiter is a limit function to the AV setpoint an is not a variable as is the above escribe OEL in Fig.14. Fiel Overcurrent Protection DC overcurrent protection is provie in exciters as show in Fig. 15. Some exciters have a protective inverse time moule that calculates the I*t to provie an inverse time curve. It nees to be coorinate with the OEL setting as well as the short time capability of the fiel (Fig. 14). It also shoul allow fiel forcing to take place uring fault conitions. In some cases this protection may trip the exciter if OEL initiate runback is unsuccessful. Excitation Transformer Protection This protection is typically provie by either overcurrent relays on larger generator or fuses on small machines connecte on the primary of the excitation transformer (Fig.15). Typically the kva size of the excitation transformer an its protection is provie as part of the excitation system package. The time overcurrent protection shoul be coorinate with the fiel short time overloa capability an fiel forcing. The short time fiel capability is specifie in terms of DC current as a multiple of fiel rate current (Fig. 14). The kw component at various fiel overloa levels can be etermine by I f where f is the fiel resistance an I is the fiel current at various multiples of fiel rate current. The AC time overcurrent require proviing that KW can then be etermine at the AC voltage rating of the excitation transformer. Doing so, however, neglects the loss in the brige circuitry, which can be significant for high ceiling static exciter. The power factor that results can be far from unity with most of the loa being vars ue to the fact that the brige circuit is firing with a more elaye angle. The resulting short time current on the AC excitation transformer is a combination of the fiel current requirements an losses in the brige circuitry. The excitation system manufacture shoul be able to provie the relationship of AC current to DC current at various excitation an over excitation levels. elay engineers nee to be aware of the control an tripping protection that resies within the exciter an its impact on limiting generator overexcitation operation. Traitionally, tripping for excitation system problems such at V/Hz (4), overvoltage (59) an loss of fiel (40) were one by relays external to the excitation system. This was one to separate protection an control. New igital excitation systems have begun to provie these protection functions within the excitation system control. A. Testing of Excitation Systems Operating the generator at its maximum excitation level to ensure that controllers operate to keep the generator within safe limits before protection operates can be perioically teste. Such test may be one not only by bring the generator slowly up to its steay state limit, but also by bringing it rapily up to the limit so that coorination for short time operation above the steay state limit can be checke. Conucting these tests on a large generator can result in system voltage problems. These tests must be carefully coorinate so that system voltage is maintaine within acceptable levels. eference 13 provies a etail escription of testing the exciter OEL, UEL an V/Hz limiter. B. V/Hz (4) Protection One of the major functions of V/Hz protection is to serve as a backup in case of the failure of the V/Hz limiter within the excitation control. V/Hz protection is set base on the short time capability of the generator an transformers connecte to the generator terminals. The flux in the stator core of a generator or core of a transformer is irectly proportional to voltage an inversely proportional to frequency. Overexcitation of a generator or any transformer connecte to the generator terminals will occur whenever the ratio of voltage to frequency (V/Hz) applie to the terminals excees 1.05 pu (generator base) for a generator; an 1.05 pu (transformer base) for a transformer at full loa. The transformer no loa level is 1.10 pu. For transformers the point of measurement is the output terminals. IEEE/ANSI C50.1 an C50.13 [7] provie voltage ranges for generators. Typically the allowable range for continuous operation is between 0.95 an 1.05 pu V/Hz. The manufacturer shoul be consulte for V/Hz short time capability of a specific generator. The primary concern from an excitation stanpoint is the possibility of excessive V/Hz overexciting the generator. When the V/Hz ratios are exceee, saturation of the iron core of generators an transformers will occur resulting in the breakown of core inter-lamination insulation ue to excessive voltage an ey current heating. During system isturbances, overexcitation is cause by the suen loss of loa ue to transmission line tripping which can islan the generator from the power gri with little loa an the shunt capacitance of the unloae transmission lines. Uner these conitions the V/Hz level may excee 1.5 pu where the voltage regulator is slow in responing. With the AV control in service, the overexcitation woul generally be reuce to safe limits (less than 1.05pu) in a few secons. The limiter will limit the V/Hz generator output to a set maximum within the generator capability curve. Even with a V/Hz limiter in the 14

15 excitation control, it is common an recommene practice [6] to provie separate V/Hz relaying to protect the generator an any transformers connecte to the generator terminals. The setting of these relays is base on the short time V/Hz capability of the generator as shown in Fig.14. In moern application where igital relays are use, the V/Hz protection of the transformer resies in the transformer protection relay an is set to protect the transformer. Both generator an transformer protection must be coorinate with the AV V/Hz limiter control. The exciter s V/Hz limiting shoul be set at the upper limit of the normal operating range an below the continuous operating limit for the generator an unit connecte transformer. Similarly, a V/Hz relay(s) shoul be set with enough elay to allow AV control action to take place before tripping the unit. This relay(s) however, must still protect the generator from amage. This typically is not a problem because the AV control can ajust generator terminal voltage within secons. C. Overexcitation elay Settings There are two basic types of V/Hz protection scheme use within the inustry. The first an most common is the ual efinite time setpoint metho. Typical conservative protection applications recommen a maximum trip level at 1.18 pu V/Hz with a -6 secon time elay for the first setpoint. The secon setpoint is set at 1.10 pu V/Hz with a time elay of 45-60 secons. The secon metho uses an inverse-time characteristic curve as well as efinite time setpoints to better match the inverse times V/Hz capability of the generator. This scheme can be precisely applie when a V/Hz vs. time curve for a specific generator is available. The minimum pickup is typically 1.10 pu V/Hz. The inverse-time function is set with a greater time elay than the exciter in orer to permit the exciter to operate to reuce voltage before protection action takes place. D. V/H Overexcitation Protection Setting Example The overexcitation capability limits for the example generator an the connecting transformer are shown in Table 1 an in Fig 14. The main transformer s V/Hz capability has alreay been ajuste in the table by 19/0 = 0.95 multiplying factor to put its V/Hz capability on the generator s voltage base so the generator s V/Hz capability an the transformer s V/Hz capability points may be plotte together. reactance of the transformer. This is typically one at the full loa rating of the transformer at an 80% power factor. A sample calculation is shown in ANSI/IEEE C37.106 [11]. The values in Table 1 an in Fig.16 have been so compensate. Many new igital transformer relays have V/Hz protective functions within the relay package. The newer practice is to provie the V/Hz step-up transformer protection within the transformer package, an measures V/Hz at the step up transformer high voltage terminals. The setting calculation example uses two relay elements to provie protection; one inverse time element an a efinite time element. The combine protection curve is also shown in Fig.16. The type of curve an time ial shoul be selecte such that the relay characteristic operates before the generator an transformer capability limits are reache. Table 1 Overexcitation Capability Main Transformer Capability Time (min) V/Hz (%) 40 106.4 30 106.9 0 107.4 10 108.4 6 109.3 11.1 1 114.3 0.5 118 0.3 13.5 enerator Capability Time (min) V/Hz (%) 33 110 5 111 0 111.5 15 11.5 10 113.5 5 115.5 118 1 10 0.5 1 0. 15 The overexcitation transformer limits are efine in ANSI/IEEE C57.1 [10] an are measure at the output of the transformer at a power factor of 80%. The output of the generator step-up transformer is at the high voltage terminals of the transformer. If the V/Hz protective relay that is use to protect the generator step up transformer is locate at the generator terminals the setting must be compensate for the voltage rop across the leakage 15

16 Percentage V/Hz 130 15 10 115 110 105 100 Definite Time Pickup 0.01 0.1 1 10 100 VIII Inverse Time Pickup Operating Time in Minutes Transformer enerator Inverse Time Curve Definite Time Series5 Fig. 16 V/Hz Characteristic Plot CONCLUSIONS ecent misoperations of generation protection uring major system isturbances have highlighte the nee for better coorination of generator protection with generator capability, generator excitation control (AV) an transmission system protection. The techniques, methos an practices to provie this coorination are well establishe but scattere in various textbooks, papers an relay manufactures literature. This paper provies a single ocument that can be use by relay engineers to aress these coorination issues. This paper provies practical guiance on proper coorination of generator protection an generator AV control to enhance security an system stability. The paper uses example calculations as a means of communicating these methos. The paper also aresses the coorination of generator protection with generator full loa capability an machine steay state stability. Setting of protective relays is an art as well as a science. The calculations shown in this paper are intene to illustrate typical settings an factors that must be consiere in eveloping generator settings. The Working roup recognizes that other methoologies that affect the same results coul also be use. Keeping generators on-line uring major system isturbances is a key goal that requires coorination of generator protection with generator control. It is the hope of the Power System elay Committee Working roup that authore this paper that it will assist the inustry in reaching this goal. EFEENCES [1] NEC PC-001-0 System Protection Coorination, Aopte by NEC Boar of Trustees, Feb 8, 005. [] NEC PC-04-1 enerator Performance During Frequency an Voltage Excursions, Pening NEC eview an Approval. [3] NEC PC-019-1 Coorination of enerator Voltage Controls with Unit Capabilities an Protection, Pening NEC eview an Approval. [4] Protective elaying Theory an Applications eite by Walter A. Elmore, ABB Power T&D Company Inc. Coral Springs, FL, 1994. [5] Final eport on the August 14, 003 Blackout in the Unite States an Canaa: Causes an ecommenations, U.S. Canaa Power System Outage Task Force, April 5, 004. [6] IEEE uie for AC enerator Protection, ANSI/IEEE C37.10-1995. [7] American National Stanar for Cylinrical otor Synchronous enerators, ANSI/IEEE C-50.13-005. [8] IEEE Committee eport A Survey of enerator Back- Up Protection Practices IEEE Transactions on Power Delivery, Vol.5 April 1990. [9] IEEE Committee eport Performance of enerator Protection During Major System Disturbances IEEE Transactions on Power Delivery. IEEE Transactions on Power Delivery, Vol19, Oct. 004. [10] IEEE Stanar, Test Coe for Distribution, Power an egulating Transformers, ANSI/IEEE C57.1 Latest evision. [11] IEEE uie for Abnormal Frequency Protection of Power enerating Plants, IEEE Stanar C37-106-003 [1] M.M. Abibi, L.H.Fink, estoration from Cascaing Failures IEEE PES Power & Energy Magazine, Vol.4 Number 5, Sept./Oct. 006. [13] A.Muroch,.W. Delmerico, S.Venkataraman,.A. Lawson, J.E, Curran, W.. Pearson, Excitation System Protective Limiters an Their Effect on Volt/var Control Design, Computer Moeling, an Fiel Testing IEEE Transactions on Power Delivery, IEEE Transactions on Energy Conversion, Volume: 15, Issue: 4, Dec. 000 Pages: 440 450 APPENDI I Definition of key symbols uses in calculations. Steay State Stability Calculations (Section IV): T= SU reactance on the generator base. 16

17 min ST1 = System reactance with the strongest line (line that contributes the most fault current) out of service. See Fig. 4. eactance is on the SU transformer base. = System reactance with the strongest line out of min S service on the generator base. Loss of Fiel elay Coorination (Section V): 1 Diameter setting of one 1. Diameter one. 1 Offset Offset = Loss of Fiel (LOF) impeance circle iameter = LOF impeance circle iameter setting of = Offset of one 1 LOF impeance setting. = Offset of one LOF impeance setting. max loa = ate loa generator impeance in seconary ohms at generator rate power factor. _ MTA = one 1 setting in seconary ohm at 85 0 to maintain a margin of 150% at rate power factor angle. = Impeance of enerator Capability curve at _ MTA Max. Torque Angle (MTA) of the one relay in seconary ohms with a margin of 90%. enerator Phase Backup (1) Coorination (Section VI): one1 Calculation: T sec= SU reactance in seconary ohms. 1 reach SL = Diameter of one 1 impeance setting. = Line reactance of the shortest line existing the power plant on generator base. L1sec = Line reactance of the shortest line existing the power plant in seconary ohms. = one 1 1relay setting. 1 reach one Calculations: Total = Total short circuit impeance of a fault at the en of the longest transmission line exiting the power plant. = Impeance of longest line exiting the power plant LL1 on the generator base. maxs1 = System impeance on generator base all lines in service. = Total fault current for a fault at the en of the I Total longest line exiting the power plant. I = System contribution for a fault at the en of the S longest line existing the power plant. I = enerator contribution for a fault at the en of the longest line existing the power plant. _ LINE = one relay setting to see the en of the longest line existing the power plant in seconary ohms with 10% margin. B _ relay = enerator base ohms = ate en. Sec. Voltage/ate en Sec. Current = 69.8V/ 3.95A = 17.56 Ώ. 17