NEW Chapter 13 Generator Protection

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CHAPTER 13

CHAPTER 13 GENERATOR PROTECTION

GENERATOR PROTECTION

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GENERATOR PROTECTION

Introduction

• • _General_General •

• _{Types Of Faults}_{Types Of Faults} •

• _{Other Abnormal Operating And/Or System Conditions}_{Other Abnormal Operating And/Or System Conditions} •

• _{Effects Of Generator Bus Faults}_{Effects Of Generator Bus Faults}

Internal Faults

•

• _{Differential Protection (Phase Faults)}_{Differential Protection (Phase Faults)} •

• _{Differential Protection (Ground Faults)}_{Differential Protection (Ground Faults)} •

• _{Field Grounds}_{Field Grounds}

Phase Fault Backup Protection

•

• _Introduction_Introduction •

• _{Generator Decrement Curve}_{Generator Decrement Curve} •

• _{Voltage Restraint Overcurrent Relays}_{Voltage Restraint Overcurrent Relays} •

• _{Voltage Controlled Overcurrent Relays}_{Voltage Controlled Overcurrent Relays}

Other Abnormal Conditions

•

• _Overloads_Overloads •

• _{Overexcitation and Overvoltage/Undervoltage Protection}_{Overexcitation and Overvoltage/Undervoltage Protection} •

• _{Unbalanced (Negative Sequence) Currents}_{Unbalanced (Negative Sequence) Currents} •

• _{Loss Of Prime Mover (Motoring)}_{Loss Of Prime Mover (Motoring)}

•

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Integrated Application Examples

Example of a Numerical Relay for Providing Comprehensive Generator

Protection – GE G60 Relay

•

• _Features_Features •

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INTRODUCTION

GENERAL

Synchronous generators for industrial and commercial applications are typically of the Synchronous generators for industrial and commercial applications are typically of the non-unit type (directly connected to the bus vice through a step-up transformer) with ratings unit type (directly connected to the bus vice through a step-up transformer) with ratings varying from .48-13.8 kV and .5 - 30 MVA.

varying from .48-13.8 kV and .5 - 30 MVA.

In medium-sized and large power stations the generators are operated exclusively in unit In medium-sized and large power stations the generators are operated exclusively in unit connection.

connection. In the In the unit connection the unit connection the generator is linked generator is linked to the to the busbar of busbar of the higherthe higher voltage level via a transformer. In the case of several parallel units, the generators are voltage level via a transformer. In the case of several parallel units, the generators are electrically isolated by the transformers. A circuit-breaker can be connected between the electrically isolated by the transformers. A circuit-breaker can be connected between the generator and the transformer.

generator and the transformer.

The task of electrical protection in these systems is to detect deviations from the normal The task of electrical protection in these systems is to detect deviations from the normal condition and to

condition and to react according to react according to the protection concept and the protection concept and the setting. the setting. The scope The scope ofof protection must be in reasonable relation to the total system costs and the importance of protection must be in reasonable relation to the total system costs and the importance of the system

the system..

Although generators are subject to numerous types of hazards, this chapter will limit Although generators are subject to numerous types of hazards, this chapter will limit discussion to four types of internal faults and several types of abnormal operating and/or discussion to four types of internal faults and several types of abnormal operating and/or system conditions. Additional protective schemes, such as overvoltage, out-of-step, system conditions. Additional protective schemes, such as overvoltage, out-of-step, synchronization, etc. should also be considered depending on the cost and relative synchronization, etc. should also be considered depending on the cost and relative importance of the generator.

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TYPES OF FAULTS TYPES OF FAULTS

•

• _{Phase and/or ground faults in the stator and associated protection zone}_{Phase and/or ground faults in the stator and associated protection zone} •

• _{Ground faults in the rotor (field winding)}_{Ground faults in the rotor (field winding)} •

• _{Field grounds}_{Field grounds} •

• _{External faults (phase fault backup protection)}_{External faults (phase fault backup protection)}

OTHER ABNORMAL OPERATING AND/OR SYSTEM CONDITIONS OTHER ABNORMAL OPERATING AND/OR SYSTEM CONDITIONS

• • _Overloads_Overloads • • _Overheating_Overheating • • _Overspeed_Overspeed •

• _{Loss of Prime Mover (Motoring)}_{Loss of Prime Mover (Motoring)} •

• _{Unbalanced Currents}_{Unbalanced Currents} •

• _{Out-of-Step (Loss of Synchronism)}_{Out-of-Step (Loss of Synchronism)} •

• _{Loss of Excitation}_{Loss of Excitation}

•

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EFFECTS OF GENERATOR BUS FAULTS

For a three-phase fault near the generator, the following characteristics apply: For a three-phase fault near the generator, the following characteristics apply: Machine kW and kVAR Output:

Machine kW and kVAR Output: • kVAR

• kVARoutout → 5→ 5-15 -15 times times kVARkVAR normal normal

• kW

• kWoutout → 0; generator cannot transmit kW→ 0; generator cannot transmit kW_3φ_3φ through through the the fault.fault.

• kVA

• kVAoutout = (kVAR= (kVAR22outout + kW+ kW 2 2 out out)) 1/2 1/2 ≈ kVAR ≈ kVAR out out

Voltage, Frequency, Power Factor, Current: Voltage, Frequency, Power Factor, Current:

• Volts • Volts → 0→ 0

• Frequency

• Frequency → rise to 61→ rise to 61-63 Hz-63 Hz •

• Power Power FactorFactor → 0→ 0

• Current

• Current → 10→ 10-15 -15 times times II

FLA

FLA (function of X(function of X ””

d d))

Machine Speed:

Machine Speed: Because the fault impedance (Z) is normally very small, and the kWBecause the fault impedance (Z) is normally very small, and the kW outout approaches zero, the generator “sees” the fault as an instantaneous drop in load and approaches zero, the generator “sees” the fault as an instantaneous drop in load and overspeeds in a

overspeeds in a very short time. very short time. All of the prime All of the prime mover kW input goes mover kW input goes to accelerating theto accelerating the rotor; if left unchecked the turbine blades can be seriously damaged (tearout). Speed rotor; if left unchecked the turbine blades can be seriously damaged (tearout). Speed control by the governor cannot react fast enough and therefore relays are used to protect control by the governor cannot react fast enough and therefore relays are used to protect the generator.

the generator.

Generator Stability

Generator Stability: Faults must be cleared within approximately 0.3 seconds (18 cycles): Faults must be cleared within approximately 0.3 seconds (18 cycles) to preserve stability. The fault is removed by dropping the generator; for large systems to preserve stability. The fault is removed by dropping the generator; for large systems load shedding is initiated to prevent frequency and voltage drops.

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INTERNAL FAULTS

DIFFERENTIAL PROTECTION (PHASE FAULTS) DIFFERENTIAL PROTECTION (PHASE FAULTS)

The suggested protection for instantaneous and sensitive protection for generator internal The suggested protection for instantaneous and sensitive protection for generator internal faults is differential protection (ANSI Device No. 87G), which is very similar to motor faults is differential protection (ANSI Device No. 87G), which is very similar to motor differential protection. A constant percentage, high sensitivity (e.g.,10%) differential differential protection. A constant percentage, high sensitivity (e.g.,10%) differential element is

element is recommended. recommended. If CT If CT saturation error exceeds saturation error exceeds 1%, a 1%, a lower sensitivity lower sensitivity (e.g.,(e.g., 25%) type element should be used. No settings are required for these elements.

25%) type element should be used. No settings are required for these elements.

Generator differential elements (Figure 13-1) are usually arranged to simultaneously trip Generator differential elements (Figure 13-1) are usually arranged to simultaneously trip the generator, field circuit, and neutral breakers (if used) through a manually reset lockout the generator, field circuit, and neutral breakers (if used) through a manually reset lockout auxiliary relay (ANSI Device No. 86). In some applications, the differential element also auxiliary relay (ANSI Device No. 86). In some applications, the differential element also trips the throttle and admits CO

trips the throttle and admits CO22 to the generator for fire protection.to the generator for fire protection.

Figure 13-1. Fixed Slope Relay Figure 13-1. Fixed Slope Relay

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DIFFERENTIAL PROTECTION (PHASE FAULTS)

Figures 13-2 and 13-3 show the different connection schemes depending on whether the Figures 13-2 and 13-3 show the different connection schemes depending on whether the generator is delta or wye-connected.

generator is delta or wye-connected.

Figure 13-2. Differential Relay Protection for Y-Connected Generator Figure 13-2. Differential Relay Protection for Y-Connected Generator

Figure 13-3. Differential Relay Protection for Delta-Connected Generator Figure 13-3. Differential Relay Protection for Delta-Connected Generator

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DIFFERENTIAL PROTECTION (PHASE FAULTS)

As an alternative to the sngle phase devices, a three-phase, numerical relay (e.g., As an alternative to the sngle phase devices, a three-phase, numerical relay (e.g., SEL-300G or GE 489 relay) that is more sensitive (high-speed) and that offers variable 300G or GE 489 relay) that is more sensitive (high-speed) and that offers variable percentage operating characteristics can be used to protect the generator (Figure 13-4). percentage operating characteristics can be used to protect the generator (Figure 13-4). These relays have very high sensitivity (.25/5 x 100 = 5%) during light internal faults, and These relays have very high sensitivity (.25/5 x 100 = 5%) during light internal faults, and relatively low sensitivity (30/60 x 100 = 50%) during heavy external faults, and can relatively low sensitivity (30/60 x 100 = 50%) during heavy external faults, and can therefore accommodate increased CT error during heavy external faults.

therefore accommodate increased CT error during heavy external faults.

Figure 13-4. Typical Variable Percentage Differential Relay Figure 13-4. Typical Variable Percentage Differential Relay

Another alternative differential scheme is to use three zero sequence current transformers Another alternative differential scheme is to use three zero sequence current transformers and three type instantaneous trip elements, as shown in Figure 13-5. Although this partial and three type instantaneous trip elements, as shown in Figure 13-5. Although this partial differential feature protection scheme is more sensitive and less costly (e.g.,6 CTs versus differential feature protection scheme is more sensitive and less costly (e.g.,6 CTs versus 3 CTs), it does not protect the cables between the generator terminals and the breaker. 3 CTs), it does not protect the cables between the generator terminals and the breaker. The instantaneous element, used in differential manner (ANSI Device No. 87) is typically The instantaneous element, used in differential manner (ANSI Device No. 87) is typically set at 0.15A. The zero sequence CTs are usually sized at a 50/5 ratio (most common) with set at 0.15A. The zero sequence CTs are usually sized at a 50/5 ratio (most common) with a 4-inch diameter, or 100/5 ratios are also available with 7 and 14-inch diameters.

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DIFFERENTIAL PROTECTION (PHASE FAULTS)

Figure 13-5 shows this protection scheme for a wye-connected generator and Figure 13-6 Figure 13-5 shows this protection scheme for a wye-connected generator and Figure 13-6 shows this protection scheme for a delta-connected generator.

shows this protection scheme for a delta-connected generator.

Figure 13-5. Y-Connected Generator Figure 13-5. Y-Connected Generator

Figure 13-6. Delta Generaor Figure 13-6. Delta Generaor

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DIFFERENTIAL PROTECTION (GROUND FAULTS)

For large generators, a separate feature (ANSI Device No. 87G) is considered essential for For large generators, a separate feature (ANSI Device No. 87G) is considered essential for generator protection for internal ground faults. ANSI Device No. 87G supplements generator protection for internal ground faults. ANSI Device No. 87G supplements (backups) the phase differential element that was previously discussed. The element can (backups) the phase differential element that was previously discussed. The element can be set for minimum time to clear internal faults faster (Figure 13-7). This element operates be set for minimum time to clear internal faults faster (Figure 13-7). This element operates the lockout relay (ANSI Device No. 86) to trip and lockout the line and field breakers, and the lockout relay (ANSI Device No. 86) to trip and lockout the line and field breakers, and the prime mover.

the prime mover.

Figure 13-7. Typical Ground Differential Scheme Figure 13-7. Typical Ground Differential Scheme

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A solidly grounded generator has zero or minimal impedance applied at the Wye neutral A solidly grounded generator has zero or minimal impedance applied at the Wye neutral point so that, during a ground fault at the generator HV terminals, ground current from the point so that, during a ground fault at the generator HV terminals, ground current from the generator is approximately equal to the 3 phase fault current.

generator is approximately equal to the 3 phase fault current.

A low resistance grounded generator refers to a generator that has substantial impedance A low resistance grounded generator refers to a generator that has substantial impedance applied at the wye neutral point so that, during a ground fault, a reduced but readily applied at the wye neutral point so that, during a ground fault, a reduced but readily detectable level of ground current, typically on the order of 100-500A, flows.

detectable level of ground current, typically on the order of 100-500A, flows.

A high impedance grounded generator refers to a generator with a large grounding A high impedance grounded generator refers to a generator with a large grounding impedance so that, during a ground fault, a nearly undetectable level of fault current flows, impedance so that, during a ground fault, a nearly undetectable level of fault current flows, necessitating ground fault monitoring with voltage based (e.g., 3rd harmonic voltage necessitating ground fault monitoring with voltage based (e.g., 3rd harmonic voltage monitoring and fundamental frequency neutral voltage shift monitoring) relays. The monitoring and fundamental frequency neutral voltage shift monitoring) relays. The location of the grounding, generator neutral(s) or transformer, also influences the location of the grounding, generator neutral(s) or transformer, also influences the protection approach.

protection approach.

The location of the ground fault within the generator winding, as well as the grounding The location of the ground fault within the generator winding, as well as the grounding impedance, determines the level of fault current. Assuming that the generated voltage impedance, determines the level of fault current. Assuming that the generated voltage along each segment of the winding is uniform, the prefault line-ground voltage level is along each segment of the winding is uniform, the prefault line-ground voltage level is proportional to the percent of winding between the fault location and the generator neutral, proportional to the percent of winding between the fault location and the generator neutral, V

VFGFG in Fig. 13-8. Assuming an impedance grounded generator where (Zin Fig. 13-8. Assuming an impedance grounded generator where (Z00, SOURCE and, SOURCE and

Z

ZNN)>>ZWINDING, the current level is directly proportional to the distance of the point from)>>ZWINDING, the current level is directly proportional to the distance of the point from

the generator neutral [Fig. 13-8(a)], so a fault 10% from neutral produces 10% of the the generator neutral [Fig. 13-8(a)], so a fault 10% from neutral produces 10% of the current that flows for a fault on the generator terminals. While the current level drops current that flows for a fault on the generator terminals. While the current level drops towards zero as the neutral is approached, the insulation stress also drops, tending to towards zero as the neutral is approached, the insulation stress also drops, tending to reduce the probability of a fault near the neutral. If a generator grounding impedance is low reduce the probability of a fault near the neutral. If a generator grounding impedance is low relative to the generator winding impedance or the system ground impedance is low, the relative to the generator winding impedance or the system ground impedance is low, the fault current decay will be non-linear. For I

fault current decay will be non-linear. For I11 in Fig. 13-8, lower fault voltage is offset byin Fig. 13-8, lower fault voltage is offset by

lower generator winding resistance. An example is shown in Fig. 13-8(b). lower generator winding resistance. An example is shown in Fig. 13-8(b).

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Figure 13-8.

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The generator differential element (87G) may be sensitive enough to detect winding The generator differential element (87G) may be sensitive enough to detect winding ground faults with low-impedance grounding per Fig. 13-9. This would be the case if a ground faults with low-impedance grounding per Fig. 13-9. This would be the case if a solid generator-terminal fault produces approximately 100% of rated current. The minimum solid generator-terminal fault produces approximately 100% of rated current. The minimum pickup setting of the differential relays should be adjusted to sense faults on as much of pickup setting of the differential relays should be adjusted to sense faults on as much of the winding as possible. However, settings below 10% of full load current (e.g., 0.4A for 4A the winding as possible. However, settings below 10% of full load current (e.g., 0.4A for 4A full load current) carry increased risk of misoperation due to transient CT saturation during full load current) carry increased risk of misoperation due to transient CT saturation during external faults or during step-up transformer energization. Lower pickup settings are external faults or during step-up transformer energization. Lower pickup settings are recommended only with high-quality CTs (e.g., C400) and a good CT match (e.g., identical recommended only with high-quality CTs (e.g., C400) and a good CT match (e.g., identical accuracy class and equal burden).

accuracy class and equal burden).

If 87G feature is provided per Fig. 13-9, relay 51N backs up the 87G, as well as external If 87G feature is provided per Fig. 13-9, relay 51N backs up the 87G, as well as external relays. If an 87G is not provided or is not sufficiently sensitive for ground faults, then the relays. If an 87G is not provided or is not sufficiently sensitive for ground faults, then the 51N provides the primary protection for the generator. The advantage of the 87G is that it 51N provides the primary protection for the generator. The advantage of the 87G is that it does not need to be delayed to coordinate with external protection; however, delay is does not need to be delayed to coordinate with external protection; however, delay is required for the 51N. One must be aware of the effects of transient DC offset induced required for the 51N. One must be aware of the effects of transient DC offset induced saturation on CTs during transformer or load energization with respect to the high speed saturation on CTs during transformer or load energization with respect to the high speed operation of 87G relays. Transient DC offset may induce CT saturation for many cycles operation of 87G relays. Transient DC offset may induce CT saturation for many cycles (likely not more than 10), which may cause false operation of an 87G relay. This may be (likely not more than 10), which may cause false operation of an 87G relay. This may be addressed by not block loading the generator, avoiding sudden energization of large addressed by not block loading the generator, avoiding sudden energization of large transformers, providing substantially overrated CTs, adding a very small time delay to the transformers, providing substantially overrated CTs, adding a very small time delay to the 87G trip circuit, or setting the feature fairly insensitively.

87G trip circuit, or setting the feature fairly insensitively.

Figure 13-9. Ground Fault Relaying Generator Low-Impedance Grounding Figure 13-9. Ground Fault Relaying Generator Low-Impedance Grounding

The neutral CT should be selected to produce a secondary current of at least 5A for a solid The neutral CT should be selected to produce a secondary current of at least 5A for a solid generator terminal fault, providing sufficient current for a fault near the generator neutral. generator terminal fault, providing sufficient current for a fault near the generator neutral. For example, if a terminal fault produces 1000A in the generator neutral, the neutral CT For example, if a terminal fault produces 1000A in the generator neutral, the neutral CT ratio should not exceed 1000/5. For a fault 10% from the neutral and assuming I ratio should not exceed 1000/5. For a fault 10% from the neutral and assuming I 11 isis

proportional to percent winding from the neutral, the 51N current will be 0.5A, with a proportional to percent winding from the neutral, the 51N current will be 0.5A, with a 1000/5 CT.

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FIELD GROUNDS

A field ground relay element (ANSI Device No. 64) detects grounds in the generator field A field ground relay element (ANSI Device No. 64) detects grounds in the generator field circuit (Figure 13-10).

circuit (Figure 13-10). This relay uses This relay uses a very a very sensitive d’Arsonval movement to sensitive d’Arsonval movement to measuremeasure DC ground currents. The element is used to alarm on the occurrence of a first ground to DC ground currents. The element is used to alarm on the occurrence of a first ground to permit an orderly shutdown of

permit an orderly shutdown of the generator. the generator. If a second If a second ground occurs before ground occurs before the first isthe first is cleared, the field winding is short circuited resulting in unbalance and vibrations which may cleared, the field winding is short circuited resulting in unbalance and vibrations which may severely damage the generator.

severely damage the generator.

Figure 13-10. Typical operation of a Field Ground Relay Figure 13-10. Typical operation of a Field Ground Relay

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PHASE FAULT BACKUP PROTECTION

INTRODUCTION

The function of phase fault backup protection is to disconnect the generator if the fault has The function of phase fault backup protection is to disconnect the generator if the fault has not been cleared by other downstream protective devices (e.g., feeder overcurrent relays, not been cleared by other downstream protective devices (e.g., feeder overcurrent relays, ANSI

ANSI Device Nos. Device Nos. 51/50). 51/50). This protection This protection prevents the prevents the generator and generator and other auxiliaryother auxiliary components from exceeding their thermal limits as well as protecting distribution components from exceeding their thermal limits as well as protecting distribution components against excessive

components against excessive damage. damage. Two types Two types of relays of relays are used are used to provide to provide thisthis protection.

protection. Impedance relays (ANSI Impedance relays (ANSI Device No. Device No. 21) are 21) are used to used to protect unit generatorsprotect unit generators (generator/transformer combinations), and time overcurrent relays (ANSI Device No. 51) (generator/transformer combinations), and time overcurrent relays (ANSI Device No. 51) are used for non-unit installations typically found in industrial/commercial applications. This are used for non-unit installations typically found in industrial/commercial applications. This Tab will restrict discussion to use of time overcurrent relays for backup phase fault Tab will restrict discussion to use of time overcurrent relays for backup phase fault protection.

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GENERATOR DECREMENT CURVE

Figure 13-11 is a generator decrement curve that is plotted at no-load and constant Figure 13-11 is a generator decrement curve that is plotted at no-load and constant excitation (curve 1) , field current at

excitation (curve 1) , field current at 3.0 p.u. of no-load 3.0 p.u. of no-load value (curve value (curve 2), and total current2), and total current including the dc component (curve 3). The machine characteristics for the curves that are including the dc component (curve 3). The machine characteristics for the curves that are shown in Figure 13-11 are as follows:

shown in Figure 13-11 are as follows: Machine Characteristics

Machine Characteristics::

•

• _19.5_{19.5 MVA,}_{MVA, p.f. =}_{p.f. = 80%,}_{80%, 12.47}_{12.47 kV,}_{kV, FLA}_{FLA =}_{= 903}_{903 A,}_{A, X”}_X”

d

d = = 10.7%, 10.7%, X’X’dd = 15.4%= 15.4%

• • _X_X

d

d = = 154%, 154%, IIFgFg = 1.0 = 1.0 p.u., p.u., IIFF = 3.0 = 3.0 p.u., p.u., T” = T” = 0.015 seconds0.015 seconds

• • _T’_T’

d

d = 0.417 seconds, T= 0.417 seconds, TAA = 0.189 seconds= 0.189 seconds

Figure 13-11. Decrement Curve Figure 13-11. Decrement Curve

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GENERATOR DECREMENT CURVE

If the information is not available, a generator’s decrement curve can be estimated and If the information is not available, a generator’s decrement curve can be estimated and drawn (log-log) paper by using the following approximate values.

drawn (log-log) paper by using the following approximate values. • X”

• X”_d_d = = 10%, 10%, II_sym_sym = 1.0/.10 = 10 p.u. @ 0.1 seconds= 1.0/.10 = 10 p.u. @ 0.1 seconds • X’

• X’_d_d = 15%, = 15%, I = 1.0/.15 = I = 1.0/.15 = 6.67 p.u. @ 6.67 p.u. @ 3.0 seconds3.0 seconds • X

• X_d_d = 150%, I = 1.0/1.5 = 0.67 p.u.= 150%, I = 1.0/1.5 = 0.67 p.u. • I

• Iasyasy≈ 1.6 I ≈ 1.6 I = 1.6 x = 1.6 x 10 = 16.0 10 = 16.0 p.u.p.u.

Figure 13-12.

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Phase-Fault Protection Phase-Fault Protection

Fig. 13-13 shows a simple means of detecting phase faults, but clearing is delayed, since Fig. 13-13 shows a simple means of detecting phase faults, but clearing is delayed, since the 51 relay must be delayed to coordinate with external devices. Since the 51 relay the 51 relay must be delayed to coordinate with external devices. Since the 51 relay operates for external faults, it is not generator zone selective.

operates for external faults, it is not generator zone selective.

It will operate for abnormal external operating conditions such as remote faults that are not It will operate for abnormal external operating conditions such as remote faults that are not properly cleared by remote breakers. The 51 pickup should be set at about 175% of rated properly cleared by remote breakers. The 51 pickup should be set at about 175% of rated current to override swings due to a slow-clearing external fault, the starting of a large current to override swings due to a slow-clearing external fault, the starting of a large motor, or the re-acceleration current of a group of motors.

motor, or the re-acceleration current of a group of motors.

Energization of a transformer may also subject the generator to higher than rated current Energization of a transformer may also subject the generator to higher than rated current flow.

flow.

Figure 13-13. Phase-Overcurrent Protection (51) must be delayed to coordinate with Figure 13-13. Phase-Overcurrent Protection (51) must be delayed to coordinate with

External Relays External Relays

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Fig. 13-14 shows an example of generator current decay for a 3 phase fault and a Fig. 13-14 shows an example of generator current decay for a 3 phase fault and a phase-phase fault. For a 3 phase-phase fault, the fault current decays below the pickup level of the 51 phase fault. For a 3 phase fault, the fault current decays below the pickup level of the 51 relay in approximately one second. If the time delay of the 51 can be selectively set to relay in approximately one second. If the time delay of the 51 can be selectively set to operate before the current drops to pickup, the relay will provide 3 phase fault protection. operate before the current drops to pickup, the relay will provide 3 phase fault protection. The current does not decay as fast for a phase-phase or a phaseground fault and, thereby, The current does not decay as fast for a phase-phase or a phaseground fault and, thereby, allows the 51 relay more time to trip before current drops below pickup. Fig. 13-14 allows the 51 relay more time to trip before current drops below pickup. Fig. 13-14 assumes no voltage regulator boosting, although the excitation system response time is assumes no voltage regulator boosting, although the excitation system response time is unlikely to provide significant fault current boosting in the first second of the fault. It also unlikely to provide significant fault current boosting in the first second of the fault. It also assumes no voltage regulator dropout due to loss of excitation power during the fault. If the assumes no voltage regulator dropout due to loss of excitation power during the fault. If the generator is loaded prior to the fault, prefault load current and the associated higher generator is loaded prior to the fault, prefault load current and the associated higher excitation levels will provide the fault with a higher level of current than indicated by the excitation levels will provide the fault with a higher level of current than indicated by the Fig. 13-14 curves. An estimate of the net fault current of a pre-loaded generator is a Fig. 13-14 curves. An estimate of the net fault current of a pre-loaded generator is a superposition of load current and fault current without pre-loading. For example, assuming superposition of load current and fault current without pre-loading. For example, assuming a pre-fault 1pu rated load at 30 degree lag, at one second the 3 phase fault value would be a pre-fault 1pu rated load at 30 degree lag, at one second the 3 phase fault value would be 2.4 ti

2.4 times ratmes rated, red, rather tather than 1.75 han 1.75 times rtimes rated (ated (1@30°1@30°+1.75@90°+1.75@90°=2.4@69°=2.4@69°). Under ). Under thesethese circumstances, the 51 relay has more time to operate before current decays below pickup. circumstances, the 51 relay has more time to operate before current decays below pickup.

Figure 13-14. Generator Fault Current Decay Example for 3 Phase and Phase-Phase Figure 13-14. Generator Fault Current Decay Example for 3 Phase and Phase-Phase Faults at Generator Terminals – with no Regulator Boosting or Dropout during Fault Faults at Generator Terminals – with no Regulator Boosting or Dropout during Fault

and no Pre-fault load and no Pre-fault load

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Figure 13-13 shows the CTs on the neutral side of the generator. This location allows the Figure 13-13 shows the CTs on the neutral side of the generator. This location allows the relay to sense internal generator faults but does not sense fault current coming into the relay to sense internal generator faults but does not sense fault current coming into the generator from the external system. Placing the CT on the system side of the generator generator from the external system. Placing the CT on the system side of the generator introduces a problem of the relay not seeing a generator internal fault when the main introduces a problem of the relay not seeing a generator internal fault when the main breaker is open and when running the generator isolated from other generation or the breaker is open and when running the generator isolated from other generation or the utility. If an external source contributes more current than does the generator, using CTs utility. If an external source contributes more current than does the generator, using CTs on the generator terminals, rather than neutral-side CTs, will increase 51 relay sensitivity on the generator terminals, rather than neutral-side CTs, will increase 51 relay sensitivity to internal faults due to higher current contribution from the external source; however, the to internal faults due to higher current contribution from the external source; however, the generator is unprotected should a fault occur with the breaker open or prior to generator is unprotected should a fault occur with the breaker open or prior to synchronizing.

synchronizing.

Voltage-restrained or voltage-controlled timeovercurrent relays (51VR, 51VC) may be used Voltage-restrained or voltage-controlled timeovercurrent relays (51VR, 51VC) may be used as shown in Fig. 13-15 to remove any concerns about ability to operate before the as shown in Fig. 13-15 to remove any concerns about ability to operate before the generator current drops too low. The voltage feature allows the relays to be set below generator current drops too low. The voltage feature allows the relays to be set below rated current. The voltage restrained approach causes the pickup to decrease with rated current. The voltage restrained approach causes the pickup to decrease with decreasing voltage.

decreasing voltage.

For example, the relay might be set for about 175% of generator rated current with rated For example, the relay might be set for about 175% of generator rated current with rated voltage applied; at 25% voltage the relay picks up at 25% of the relay setting voltage applied; at 25% voltage the relay picks up at 25% of the relay setting (1.75*0.25=0.44 times rated). The voltage controlled approach inhibits operation until the (1.75*0.25=0.44 times rated). The voltage controlled approach inhibits operation until the voltage drops below a preset voltage. It should be set to function below about 80% of rated voltage drops below a preset voltage. It should be set to function below about 80% of rated voltage with a current pickup of about 50% of generator rated. Since the voltage-controlled voltage with a current pickup of about 50% of generator rated. Since the voltage-controlled type has a fixed pickup, it can be more readily coordinated with external relays than can type has a fixed pickup, it can be more readily coordinated with external relays than can the voltage-restrained type. The voltage-controlled type is recommended since it is easier the voltage-restrained type. The voltage-controlled type is recommended since it is easier to coordinate. However, the voltage restrained type will be less susceptible to operation on to coordinate. However, the voltage restrained type will be less susceptible to operation on swings or motor starting conditions that depress the voltage below the voltage controlled swings or motor starting conditions that depress the voltage below the voltage controlled undervoltage unit dropout point.

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Figure 13-15. Voltage-restrained or Voltage Controlled Time-overcurrent Figure 13-15. Voltage-restrained or Voltage Controlled Time-overcurrent

Phase Fault Protection Phase Fault Protection

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OTHER ABNORMAL CONDITIONS

OVERLOADS

Most large generators are equipped with resistance temperature detectors (RTDs) that are Most large generators are equipped with resistance temperature detectors (RTDs) that are often used in a

often used in a bridge circuit to provide sensing bridge circuit to provide sensing intelligence to an indicator or intelligence to an indicator or a relay. a relay. TheThe relay has contact-opening torque when the resistance is low, which indicates low machine relay has contact-opening torque when the resistance is low, which indicates low machine temperature.

temperature. When the When the temperature of temperature of the machine the machine exceeds 120exceeds 120oo

C for class B-insulated C for class B-insulated machines, the bridge becomes unbalanced and the contact closes.

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OVEREXCITATION AND OVERVOLTAGE/UNDERVOLTAGE PROTECTION OVEREXCITATION AND OVERVOLTAGE/UNDERVOLTAGE PROTECTION

Overexcitation can occur due to higher than rated voltage, or rated or lower voltage at less Overexcitation can occur due to higher than rated voltage, or rated or lower voltage at less than rated frequency. For a given flux level, the voltage output of a machine will be than rated frequency. For a given flux level, the voltage output of a machine will be proportional to frequency. Since maximum flux level is designed for normal frequency and proportional to frequency. Since maximum flux level is designed for normal frequency and voltage, when a machine is at reduced speed, maximum voltage is proportionately voltage, when a machine is at reduced speed, maximum voltage is proportionately reduced. A volts/hertz relay (24) responds to excitation level as it affects thermal stress to reduced. A volts/hertz relay (24) responds to excitation level as it affects thermal stress to the generator (and to any transformer tied to that generator). IEEE C50.13 specifies that a the generator (and to any transformer tied to that generator). IEEE C50.13 specifies that a generator should continuously withstand 105% of rated excitation at full load.

generator should continuously withstand 105% of rated excitation at full load.

With the unit off line, and with voltage-regulator control at reduced frequency, the With the unit off line, and with voltage-regulator control at reduced frequency, the generator can be overexcited if the regulator does not include an overexcitation limiter. generator can be overexcited if the regulator does not include an overexcitation limiter. Overexcitation can also occur, particularly with the unit off line, if the regulator is out of Overexcitation can also occur, particularly with the unit off line, if the regulator is out of service or defective. If voltagebalance supervision (60) is not provided and a fuse blows on service or defective. If voltagebalance supervision (60) is not provided and a fuse blows on the regulator ac potential input, the regulator would cause overexcitation. Loss of ac the regulator ac potential input, the regulator would cause overexcitation. Loss of ac potential may also fool the operator into developing excessive excitation. The 24 relay can potential may also fool the operator into developing excessive excitation. The 24 relay can only protect for overexcitation resulting from an erroneous voltage indication if the 24 relay only protect for overexcitation resulting from an erroneous voltage indication if the 24 relay is connected to an ac potential source different than that used for the regulator.

is connected to an ac potential source different than that used for the regulator. Fig. 13-16 shows the relation among

Fig. 13-16 shows the relation among the 24 relay inverse squared

the 24 relay inverse squared

characteristics and an example of a characteristics and an example of a generator and transformer withstand generator and transformer withstand capability. The generator and

capability. The generator and transformer manufacturers should transformer manufacturers should supply the specific capabilities of these supply the specific capabilities of these units.

units.

Phase over (59) and under (27) Phase over (59) and under (27)

voltage relaying also acts as a backup voltage relaying also acts as a backup for excitation systemproblems.

for excitation systemproblems. Undervoltage relaying also acts as Undervoltage relaying also acts as fault detection relaying, because faults fault detection relaying, because faults tend to depress voltage.

tend to depress voltage.

Figure 13-16. Combined Generator/Transformer Figure 13-16. Combined Generator/Transformer

Overexcitation Protection using both the Overexcitation Protection using both the Inverse squared tripping. Equipment withstand Inverse squared tripping. Equipment withstand

curves are examples only curves are examples only

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UNBALANCED (NEGATIVE SEQUENCE) CURRENTS

Unbalanced loads, unbalanced system faults, open conductors, or other unsymmetrical Unbalanced loads, unbalanced system faults, open conductors, or other unsymmetrical operating conditions result in an unbalance of the generator phase voltages. The resulting operating conditions result in an unbalance of the generator phase voltages. The resulting unbalanced (negative sequence) currents induce double system frequency currents in the unbalanced (negative sequence) currents induce double system frequency currents in the rotor that quickly cause rotor overheating. Serious damage to the generator will occur if the rotor that quickly cause rotor overheating. Serious damage to the generator will occur if the unbalanced condition

unbalanced condition is allowed is allowed to persist to persist indefinitely. indefinitely. The ability The ability of a of a generator togenerator to withstand these negative sequence currents is defined by ANSI C 50.13 - 1977 as I

withstand these negative sequence currents is defined by ANSI C 50.13 - 1977 as I ₂₂22t = k,t = k, where the negative sequence current is expressed in per unit of the full load current and where the negative sequence current is expressed in per unit of the full load current and the time is given in seconds.

the time is given in seconds.

Negative sequence stator currents, caused by fault or load unbalance, induce Negative sequence stator currents, caused by fault or load unbalance, induce doublefrequency currents into the rotor that may eventually overheat elements not doublefrequency currents into the rotor that may eventually overheat elements not designed to be subjected to such currents. Series unbalances, such as untransposed designed to be subjected to such currents. Series unbalances, such as untransposed transmission lines, produce some negative-sequence current (I2) flow. The most serious transmission lines, produce some negative-sequence current (I2) flow. The most serious series unbalance is an open phase, such as an open breaker pole. ANSI C50.13-1977 series unbalance is an open phase, such as an open breaker pole. ANSI C50.13-1977 specifies a continuous I2 withstand of 5 to 10% of rated current, depending upon the size specifies a continuous I2 withstand of 5 to 10% of rated current, depending upon the size and design of the generator. These values can be exceeded with an open phase on a and design of the generator. These values can be exceeded with an open phase on a heavily-loaded generator.

heavily-loaded generator.

Fig. 13-17 shows the 46 relay connection. CTs on either side of the generator can be Fig. 13-17 shows the 46 relay connection. CTs on either side of the generator can be used, since the relay protects for events external to the generator. The alarm unit in the used, since the relay protects for events external to the generator. The alarm unit in the relay will alert the operator to the existence of a dangerous condition.

relay will alert the operator to the existence of a dangerous condition.

Figure 13-17 Negative Sequence Current Relay (46) protects against rotor Figure 13-17 Negative Sequence Current Relay (46) protects against rotor overheating due to a series unbalance or protracted external fault. Negative overheating due to a series unbalance or protracted external fault. Negative

sequence voltage relays (47) (less commonly applied) also responds sequence voltage relays (47) (less commonly applied) also responds

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Negative sequence voltage (47) protection, while not as commonly used, is an available Negative sequence voltage (47) protection, while not as commonly used, is an available means to sense system imbalance as well as, in some situations, a misconnection of the means to sense system imbalance as well as, in some situations, a misconnection of the generator to a system to which it is being paralleled.

generator to a system to which it is being paralleled.

UNBALANCED (NEGATIVE SEQUENCE) CURRENTS UNBALANCED (NEGATIVE SEQUENCE) CURRENTS Table 13-1 lists the typical k-values

Table 13-1 lists the typical k-values

Table 13-1. Generator k-Values Table 13-1. Generator k-Values

A negative sequence overcurrent relay (ANSI Device No. 46) is the recommended A negative sequence overcurrent relay (ANSI Device No. 46) is the recommended protection for this unbalanced condition.

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Figure 13-18. Current Unbalance Relay Time Current Characteristics Figure 13-18. Current Unbalance Relay Time Current Characteristics

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LOSS OF PRIME MOVER (MOTORING) LOSS OF PRIME MOVER (MOTORING)

Generator anti-motoring protection is designed for protection of the prime mover, or the Generator anti-motoring protection is designed for protection of the prime mover, or the system, rather than for

system, rather than for protection of the generator protection of the generator itself. itself. Motoring results from low Motoring results from low primeprime mover input to the generator, such as would occur if the steam supply to the turbine or the mover input to the generator, such as would occur if the steam supply to the turbine or the oil supply to the

oil supply to the diesel were lost. diesel were lost. When the prime mover input When the prime mover input to the generator cannotto the generator cannot meet all the losses, the deficiency is supplied by the system -- the generator absorbs real meet all the losses, the deficiency is supplied by the system -- the generator absorbs real power and reactive power flow (not relevant at this point) may be in or out depending on power and reactive power flow (not relevant at this point) may be in or out depending on the voltage

the voltage (system excitation). (system excitation). Under Under motoring conditions, motoring conditions, steam turbine steam turbine blades canblades can overheat, water wheel turbine blades can cavitate, and fire or possible explosion can result overheat, water wheel turbine blades can cavitate, and fire or possible explosion can result in a diesel unit.

in a diesel unit.

When the prime mover spins at synchronous speed with no power input, the approximate When the prime mover spins at synchronous speed with no power input, the approximate reverse power that is required to motor a generator, as a percentage of the nameplate kW reverse power that is required to motor a generator, as a percentage of the nameplate kW rating, is listed in Table 13-2.

rating, is listed in Table 13-2.

Table

Table 13-2. 13-2. Maximum Motoring Maximum Motoring PowerPower

Although there are a number of non-electrical (mechanical) protection schemes for the Although there are a number of non-electrical (mechanical) protection schemes for the generator prime mover, a reverse power relay (ANSI Device No. 32) is used to provide generator prime mover, a reverse power relay (ANSI Device No. 32) is used to provide supplemental protection.

supplemental protection.

The reverse power relay should have sufficient sensitivity such that motoring power The reverse power relay should have sufficient sensitivity such that motoring power provides 5-10 times the minimum pickup power of the relay. An induction disc directional provides 5-10 times the minimum pickup power of the relay. An induction disc directional power relay is frequently used to introduce sufficient time delay necessary to override power relay is frequently used to introduce sufficient time delay necessary to override momentary power surges

momentary power surges that might occur that might occur during synchronizing. during synchronizing. A time A time delay of delay of 10-1510-15 seconds is typical.

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The reverse-power feature (32) in Fig. 13-19 senses real power flow into the generator, The reverse-power feature (32) in Fig. 13-19 senses real power flow into the generator, which will occur if the generator loses its prime-mover input. Since the generator is not which will occur if the generator loses its prime-mover input. Since the generator is not faulted, CTs on either side of the generator would provide the same measured current. faulted, CTs on either side of the generator would provide the same measured current.

Figure 13-19. Anti-motoring (32) Loss-of-Field (40), Protection Figure 13-19. Anti-motoring (32) Loss-of-Field (40), Protection

In a steam-turbine, the low pressure blades will overheat with the lack of steam flow. In a steam-turbine, the low pressure blades will overheat with the lack of steam flow. Diesel and gas-turbine units draw large amounts of motoring power, with possible Diesel and gas-turbine units draw large amounts of motoring power, with possible mechanical problems. In the case of diesels, the hazard of a fire and/or explosion may mechanical problems. In the case of diesels, the hazard of a fire and/or explosion may occur due to unburnt fuel. Therefore, anti-motoring protection is recommended whenever occur due to unburnt fuel. Therefore, anti-motoring protection is recommended whenever the unit may be connected to a source of motoring power.

the unit may be connected to a source of motoring power.

Where a non-electrical type of protection is in use, as may be the case with a steam Where a non-electrical type of protection is in use, as may be the case with a steam turbine unit, the 32 relay provides a means of supervising this condition to prevent opening turbine unit, the 32 relay provides a means of supervising this condition to prevent opening the generator breaker before the prime mover has shut down. Time delay should be set for the generator breaker before the prime mover has shut down. Time delay should be set for about 5-30 seconds, providing enough time for the controls to pick up load upon about 5-30 seconds, providing enough time for the controls to pick up load upon synchronizing when the generator is initially slower than the system.

synchronizing when the generator is initially slower than the system.

Since motoring can occur during a large reactive-power flow, the real power component Since motoring can occur during a large reactive-power flow, the real power component needs to be measured at low power factors.

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Fig. 13-20 shows the use of two reverse-power relays: 32-1 and 32-2. The 32-1 relay Fig. 13-20 shows the use of two reverse-power relays: 32-1 and 32-2. The 32-1 relay supervises the generator tripping of devices that can wait until the unit begins to motor. supervises the generator tripping of devices that can wait until the unit begins to motor. Overspeeding on large steam-turbine units can be prevented by delaying main and field Overspeeding on large steam-turbine units can be prevented by delaying main and field breaker tripping until motoring occurs for non-electrical and selected electrical conditions breaker tripping until motoring occurs for non-electrical and selected electrical conditions (e.g., loss-of-field and overtemperature). Relay 32-1 should be delayed maybe 3 seconds, (e.g., loss-of-field and overtemperature). Relay 32-1 should be delayed maybe 3 seconds, while relay 32-2 should be delayed by maybe 20 seconds. Time delay would be based on while relay 32-2 should be delayed by maybe 20 seconds. Time delay would be based on generator response during generator power swings. Relay 32-2 trips directly for cases of generator response during generator power swings. Relay 32-2 trips directly for cases of motoring that were not initiated by lockout relay 86NE — e.g., governor control motoring that were not initiated by lockout relay 86NE — e.g., governor control malfunction.

malfunction.

Figure 13-20. Reverse-power relay 32-1 prevents load rejection before prime mover Figure 13-20. Reverse-power relay 32-1 prevents load rejection before prime mover shutdown for selected trips; relay 32-2 operates if motoring is not accompanied by shutdown for selected trips; relay 32-2 operates if motoring is not accompanied by

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LOSS OF EXCITATION (FIELD) LOSS OF EXCITATION (FIELD)

Protection to avoid unstable operation, potential loss of synchronism, and possible Protection to avoid unstable operation, potential loss of synchronism, and possible damage is important and is typically applied for all synchronous machines. Such protection damage is important and is typically applied for all synchronous machines. Such protection is included in the excitation system supplied with the machine, but additional protection is is included in the excitation system supplied with the machine, but additional protection is recommended to operate independently both as supplemental and backup protection. recommended to operate independently both as supplemental and backup protection. Generators have characteristics known as capability curves. Typical curves are shown in Generators have characteristics known as capability curves. Typical curves are shown in Figure 13-21. Temperature limits are basically zones, so these curves are designer’s Figure 13-21. Temperature limits are basically zones, so these curves are designer’s thermal limits.

thermal limits. As overheating varies wAs overheating varies with operation, three arcs ith operation, three arcs of circles define the of circles define the limits.limits. In one area of operation the limit is the overheating of the rotor windings, in another, in the In one area of operation the limit is the overheating of the rotor windings, in another, in the stator windings; and in the third, in the stator end iron.

stator windings; and in the third, in the stator end iron.

Loss of excitation can, to some extent, be sensed within the excitation system itself by Loss of excitation can, to some extent, be sensed within the excitation system itself by monitoring for loss of field voltage or current. For generators that are paralleled to a power monitoring for loss of field voltage or current. For generators that are paralleled to a power system, the preferred method is to monitor for loss of field at the generator terminals. system, the preferred method is to monitor for loss of field at the generator terminals. When a generator loses excitation power, it appears to the system as an inductive load, When a generator loses excitation power, it appears to the system as an inductive load, and the machine begins to absorb a large amount of VARs. Loss of field may be detected and the machine begins to absorb a large amount of VARs. Loss of field may be detected by monitoring for VAR flow or apparent impedance at the generator terminals.

by monitoring for VAR flow or apparent impedance at the generator terminals.

The power diagram (P-Q plane) of Fig. 13-22 shows 40Q characteristic of a typical loss of The power diagram (P-Q plane) of Fig. 13-22 shows 40Q characteristic of a typical loss of field relay with a representative setting, a representative generator thermal capability field relay with a representative setting, a representative generator thermal capability curve, and an example of the trajectory following a loss of excitation. The first quadrant of curve, and an example of the trajectory following a loss of excitation. The first quadrant of the diagram applies for lagging power factor operation (generator supplies VARs). The the diagram applies for lagging power factor operation (generator supplies VARs). The trajectory starts at point A and moves into the leading power factor zone (4th quadrant) trajectory starts at point A and moves into the leading power factor zone (4th quadrant) and can readily exceed the thermal capability of the unit. A trip delay of about 0.2-0.3 and can readily exceed the thermal capability of the unit. A trip delay of about 0.2-0.3 seconds is recommended to prevent unwanted operation due to other transient conditions. seconds is recommended to prevent unwanted operation due to other transient conditions. A second high speed trip zone might be included for severe underexcitation conditions. A second high speed trip zone might be included for severe underexcitation conditions.

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Figure 13-21. Typical generator Capability Curve (10 MVA) Figure 13-21. Typical generator Capability Curve (10 MVA)

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Figure 13-22. For loss of Field, the Power Trajectory moves from Point A into the Figure 13-22. For loss of Field, the Power Trajectory moves from Point A into the

Fourth Quadrant Fourth Quadrant

When impedance relaying is used to sense loss of excitation, the trip zone typically is When impedance relaying is used to sense loss of excitation, the trip zone typically is marked by a mho circle centered about the X axis, offset from the R axis by X'd/2. Two marked by a mho circle centered about the X axis, offset from the R axis by X'd/2. Two zones sometimes are used: a high speed zone and a time delayed zone (Figure 13-23) zones sometimes are used: a high speed zone and a time delayed zone (Figure 13-23)

Figure 13-23.

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With complete loss of excitation, the unit will eventually operate as an induction generator With complete loss of excitation, the unit will eventually operate as an induction generator with a positive slip. Because the unit is running above synchronous speed, excessive with a positive slip. Because the unit is running above synchronous speed, excessive currents can flow in the rotor, resulting in overheating of elements not designed for such currents can flow in the rotor, resulting in overheating of elements not designed for such conditions. This heating cannot be detected by thermal relay 49, which is used to detect conditions. This heating cannot be detected by thermal relay 49, which is used to detect stator overloads.

stator overloads.

Rotor thermal capability can also be exceeded for a partial reduction in excitation due to an Rotor thermal capability can also be exceeded for a partial reduction in excitation due to an operator error or regulator malfunction. If a unit is initially generating reactive power and operator error or regulator malfunction. If a unit is initially generating reactive power and then draws reactive power upon loss of excitation, the reactive swings can significantly then draws reactive power upon loss of excitation, the reactive swings can significantly depress the voltage. In addition, the voltage will oscillate and adversely impact sensitive depress the voltage. In addition, the voltage will oscillate and adversely impact sensitive loads. If the unit is large compared to the external reactive sources, system instability can loads. If the unit is large compared to the external reactive sources, system instability can result.

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INTEGRATED APPLICATION EXAMPLES INTEGRATED APPLICATION EXAMPLES

Figs. 13-24 through 13-28 show examples of protection packages. Figs. 13-24 through 13-28 show examples of protection packages.

Fig. 13-24 represents bare-minimum protection, with only overcurrent protection. Fig. 13-24 represents bare-minimum protection, with only overcurrent protection. Generators with such minimum protection are uncommon in an era of Generators with such minimum protection are uncommon in an era of microprocessor-based multifunction relays. Such protection likely would be seen only on very small based multifunction relays. Such protection likely would be seen only on very small (<50kVA) generators used for standby power that is never paralleled with the utility grid or (<50kVA) generators used for standby power that is never paralleled with the utility grid or other generators. It may appear to be a disadvantage to use CTs on the neutral side as other generators. It may appear to be a disadvantage to use CTs on the neutral side as shown, since the relays may operate faster with CTs on the terminal side. The increase in shown, since the relays may operate faster with CTs on the terminal side. The increase in speed would be the result of a larger current contribution from external sources. However, speed would be the result of a larger current contribution from external sources. However, if the CTs are located on the terminal side of the generator, there will be no protection prior if the CTs are located on the terminal side of the generator, there will be no protection prior to putting the machine on line. This is not recommended, because a generator with an to putting the machine on line. This is not recommended, because a generator with an internal fault could be destroyed when the field is applied.

internal fault could be destroyed when the field is applied.

Figure 13-24. Exaple of Bare-minimum Protection (Low–impedance Grounding Figure 13-24. Exaple of Bare-minimum Protection (Low–impedance Grounding ))

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Fig. 13-25 shows the suggested minimum protection with low-resistance grounding. It Fig. 13-25 shows the suggested minimum protection with low-resistance grounding. It includes differential protection, which provides fast, selective response, but differential includes differential protection, which provides fast, selective response, but differential protection becomes less common as generator size decreases below 2MVA, on 480V protection becomes less common as generator size decreases below 2MVA, on 480V units and below, and on generators that are never paralleled with other generation.

units and below, and on generators that are never paralleled with other generation.

The differential relay responds to fault contributions from both the generator and the The differential relay responds to fault contributions from both the generator and the external system. While the differential relay is fast, the slow decay of the generator field external system. While the differential relay is fast, the slow decay of the generator field will cause the generator to continue feeding current into a fault. However, fast relay will cause the generator to continue feeding current into a fault. However, fast relay operation will interrupt the externalsource contribution, which may be greater than the operation will interrupt the externalsource contribution, which may be greater than the generator contribution. Fast disconnection from the external source allows prompt generator contribution. Fast disconnection from the external source allows prompt restoration of normal voltage to loads and may reduce damage and cost of repairs.

restoration of normal voltage to loads and may reduce damage and cost of repairs.

Figure 13-25. Suggested minimum protection example (Low-impedance Grounding) Figure 13-25. Suggested minimum protection example (Low-impedance Grounding)

The differential relay (87G) may protect for ground faults, depending upon the grounding The differential relay (87G) may protect for ground faults, depending upon the grounding impedance. The 51N relay in Fig. 13-25 provides back-up protection for the 87G or will be impedance. The 51N relay in Fig. 13-25 provides back-up protection for the 87G or will be the primary protection if the differential relay (87G) is not sufficiently sensitive to the the primary protection if the differential relay (87G) is not sufficiently sensitive to the ground current level.

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The 51V voltage-controlled or voltage-restrained time overcurrent relay in Fig. 13-25 is The 51V voltage-controlled or voltage-restrained time overcurrent relay in Fig. 13-25 is shown on the CT on the high voltage/system side of the generator. This allows the relay to shown on the CT on the high voltage/system side of the generator. This allows the relay to see system contributions to a generator fault. It provides back-up for the differential relay see system contributions to a generator fault. It provides back-up for the differential relay (87G) and for external relays and breakers. Since it is monitoring CTs on the system side (87G) and for external relays and breakers. Since it is monitoring CTs on the system side of the generator, it will not provide any back-up coverage prior to having the unit on line. If of the generator, it will not provide any back-up coverage prior to having the unit on line. If there is no external source, no 87G, or if it is desired that the 51V provide generator there is no external source, no 87G, or if it is desired that the 51V provide generator protection while the breaker is open, connect the 51V to the neutral-side CTs.

protection while the breaker is open, connect the 51V to the neutral-side CTs.

Fig. 13-25 shows three relays sharing the same CTs with a differential relay. This is Fig. 13-25 shows three relays sharing the same CTs with a differential relay. This is practical with solid state and numeric relays, because their low burden will not significantly practical with solid state and numeric relays, because their low burden will not significantly degrade the quality of differential relay protection. The common CT is not a likely point of degrade the quality of differential relay protection. The common CT is not a likely point of failure of all connected relaying. A CT wiring error or CT short is unlikely to disable both failure of all connected relaying. A CT wiring error or CT short is unlikely to disable both the 87G and 51V relays. Rather, a shorted CT or defective connection will unbalance the the 87G and 51V relays. Rather, a shorted CT or defective connection will unbalance the differential circuit and cause the 87G to trip. Independent CTs could be used to provide differential circuit and cause the 87G to trip. Independent CTs could be used to provide improved back-up protection, although this seems to be a minimal advantage here. improved back-up protection, although this seems to be a minimal advantage here. However, a separate CT is used for the 51N relay that provides protection for the most However, a separate CT is used for the 51N relay that provides protection for the most likely type of fault. The reverse power relay (32) in Fig. 13-25 protects the prime mover likely type of fault. The reverse power relay (32) in Fig. 13-25 protects the prime mover against forces from a motored generator and could provide important protection for the against forces from a motored generator and could provide important protection for the external system if the motoring power significantly reduces voltage or overloads external system if the motoring power significantly reduces voltage or overloads equipment.

equipment.

Likewise, the loss-of-field relay (40) has dual protection benefits—against rotor Likewise, the loss-of-field relay (40) has dual protection benefits—against rotor overheating and against depressed system voltage due to excessive generator reactive overheating and against depressed system voltage due to excessive generator reactive absorption. Thermal relay (49) protects against stator overheating due to protracted heavy absorption. Thermal relay (49) protects against stator overheating due to protracted heavy reactive power demands and loss of generator cooling. Even if the excitation system is reactive power demands and loss of generator cooling. Even if the excitation system is equipped with a maximum excitation limiter, a failure of the voltage regulator or a faulty equipped with a maximum excitation limiter, a failure of the voltage regulator or a faulty manual control could cause excessive reactive power output. Frequency relaying (81O/U) manual control could cause excessive reactive power output. Frequency relaying (81O/U) protects the generator from off nominal frequency operation and senses generator protects the generator from off nominal frequency operation and senses generator islanding. The under and overvoltage function (27/59) detects excitation system problems islanding. The under and overvoltage function (27/59) detects excitation system problems and some protracted fault conditions.