new chapter 13 generator protection

Chapter 13 Generator Protection

CHAPTER 13

GENERATOR PROTECTION

Chapter 13 Page 2 Generator Protection


Introduction

bull General

bull Types Of Faults

bull Other Abnormal Operating AndOr System Conditions

bull Effects Of Generator Bus Faults

Internal Faults

bull Differential Protection (Phase Faults)

bull Differential Protection (Ground Faults)

bull Field Grounds

Phase Fault Backup Protection

bull Introduction

bull Generator Decrement Curve

bull Voltage Restraint Overcurrent Relays

bull Voltage Controlled Overcurrent Relays

Other Abnormal Conditions

bull Overloads

bull Overexcitation and OvervoltageUndervoltage Protection

bull Unbalanced (Negative Sequence) Currents

bull Loss Of Prime Mover (Motoring)

bull Loss Of Excitation (Field)


Integrated Application Examples

Example of a Numerical Relay for Providing Comprehensive Generator Protection ndash GE G60 Relay

bull Features

bull Setting Example


INTRODUCTION GENERAL

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 varying from 48-138 kV and 5 - 30 MVA

In medium-sized and large power stations the generators are operated exclusively in unit connection In the unit connection the generator is linked to the busbar of the higher 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 generator and the transformer

The task of electrical protection in these systems is to detect deviations from the normal condition and to react according to the protection concept and the setting The scope of protection must be in reasonable relation to the total system costs and the importance of the system

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 andor system conditions Additional protective schemes such as overvoltage out-of-step synchronization etc should also be considered depending on the cost and relative importance of the generator


TYPES OF FAULTS

bull Phase andor ground faults in the stator and associated protection zone

bull Ground faults in the rotor (field winding)

bull Field grounds

bull External faults (phase fault backup protection)

OTHER ABNORMAL OPERATING ANDOR SYSTEM CONDITIONS

bull Overloads

bull Overheating

bull Overspeed

bull Loss of Prime Mover (Motoring)

bull Unbalanced Currents

bull Out-of-Step (Loss of Synchronism)

bull Loss of Excitation

bull Overvoltage


EFFECTS OF GENERATOR BUS FAULTS

For a three-phase fault near the generator the following characteristics apply

Machine kW and kVAR Output

bull kVAR out rarr 5-15 times kVARnormal

bull kW out rarr 0 generator cannot transmit kW3φ through the fault

bull kVA out = (kVAR2 out + kW

2 out)

12 asymp kVARout

Voltage Frequency Power Factor Current

bull Volts rarr 0

bull Frequency rarr rise to 61-63 Hz

bull Power Factor rarr 0

bull Current rarr 10-15 times IFLA

(function of Xrdquo

d)

Machine Speed Because the fault impedance (Z) is normally very small and the kW out approaches zero the generator ldquoseesrdquo the fault as an instantaneous drop in load and overspeeds in a very short time All of the prime mover kW input goes to accelerating the 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 the generator

Generator Stability Faults must be cleared within approximately 03 seconds (18 cycles) to preserve stability The fault is removed by dropping the generator for large systems load shedding is initiated to prevent frequency and voltage drops


INTERNAL FAULTS DIFFERENTIAL PROTECTION (PHASE FAULTS)

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 differential protection A constant percentage high sensitivity (eg10) differential element is recommended If CT saturation error exceeds 1 a lower sensitivity (eg 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 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 trips the throttle and admits CO2 to the generator for fire protection

Figure 13-1 Fixed Slope Relay


DIFFERENTIAL PROTECTION (PHASE FAULTS)

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

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

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


DIFFERENTIAL PROTECTION (PHASE FAULTS) As an alternative to the sngle phase devices a three-phase numerical relay (eg SEL-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) These relays have very high sensitivity (255 x 100 = 5) during light internal faults and relatively low sensitivity (3060 x 100 = 50) during heavy external faults and can therefore accommodate increased CT error during heavy external faults

Figure 13-4 Typical Variable Percentage Differential Relay

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 differential feature protection scheme is more sensitive and less costly (eg6 CTs versus 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 set at 015A The zero sequence CTs are usually sized at a 505 ratio (most common) with a 4-inch diameter or 1005 ratios are also available with 7 and 14-inch diameters



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

Figure 13-5 Y-Connected Generator

Figure 13-6 Delta Generaor


DIFFERENTIAL PROTECTION (GROUND FAULTS) 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 (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 the lockout relay (ANSI Device No 86) to trip and lockout the line and field breakers and the prime mover

Figure 13-7 Typical Ground Differential Scheme


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 generator is approximately equal to the 3 phase fault current

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 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 impedance so that during a ground fault a nearly undetectable level of fault current flows necessitating ground fault monitoring with voltage based (eg 3rd harmonic voltage monitoring and fundamental frequency neutral voltage shift monitoring) relays The location of the grounding generator neutral(s) or transformer also influences the protection approach

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 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 VFG in Fig 13-8 Assuming an impedance grounded generator where (Z0 SOURCE and ZN)gtgtZWINDING 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 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 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 fault current decay will be non-linear For I1 in Fig 13-8 lower fault voltage is offset by lower generator winding resistance An example is shown in Fig 13-8(b)


Figure 13-8 Effects of Fault Location within Generator on Current Level


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 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 the winding as possible However settings below 10 of full load current (eg 04A for 4A 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 recommended only with high-quality CTs (eg C400) and a good CT match (eg identical accuracy class and equal burden)

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 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 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 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 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 87G trip circuit or setting the feature fairly insensitively

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 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 ratio should not exceed 10005 For a fault 10 from the neutral and assuming I1 is proportional to percent winding from the neutral the 51N current will be 05A with a 10005 CT


FIELD GROUNDS

A field ground relay element (ANSI Device No 64) detects grounds in the generator field circuit (Figure 13-10) This relay uses a very sensitive drsquoArsonval movement to measure DC ground currents The element is used to alarm on the occurrence of a first ground to permit an orderly shutdown of the generator If a second ground occurs before the first is cleared the field winding is short circuited resulting in unbalance and vibrations which may severely damage the generator

Figure 13-10 Typical operation of a Field Ground Relay


PHASE FAULT BACKUP PROTECTION

INTRODUCTION

The function of phase fault backup protection is to disconnect the generator if the fault has not been cleared by other downstream protective devices (eg feeder overcurrent relays ANSI Device Nos 5150) This protection prevents the generator and other auxiliary components from exceeding their thermal limits as well as protecting distribution components against excessive damage Two types of relays are used to provide this protection Impedance relays (ANSI Device No 21) are used to protect unit generators (generatortransformer combinations) and time overcurrent relays (ANSI Device No 51) are used for non-unit installations typically found in industrialcommercial applications This Tab will restrict discussion to use of time overcurrent relays for backup phase fault protection


GENERATOR DECREMENT CURVE

Figure 13-11 is a generator decrement curve that is plotted at no-load and constant excitation (curve 1) field current at 30 pu of no-load value (curve 2) and total current including the dc component (curve 3) The machine characteristics for the curves that are shown in Figure 13-11 are as follows

Machine Characteristics

bull 195 MVA pf = 80 1247 kV FLA = 903 A Xrdquod = 107 Xrsquod = 154

bull Xd = 154 IFg = 10 pu IF = 30 pu Trdquo = 0015 seconds

bull Trsquod = 0417 seconds TA = 0189 seconds

Figure 13-11 Decrement Curve



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

bull Xrdquod = 10 Isym = 1010 = 10 pu 01 seconds

bull Xrsquod = 15 I = 1015 = 667 pu 30 seconds

bull Xd = 150 I = 1015 = 067 pu

bull Iasy asymp 16 I = 16 x 10 = 160 pu

Figure 13-12 Typical Generator Decrement Curve


Phase-Fault Protection

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 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 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 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 flow

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


Fig 13-14 shows an example of generator current decay for a 3 phase fault and a phase-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 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 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 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 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

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 a pre-fault 1pu rated load at 30 degree lag at one second the 3 phase fault value would be 24 times rated rather than 175 times rated (130deg+17590deg=2469deg) Under these 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 Faults at Generator Terminals ndash with no Regulator Boosting or Dropout during Fault

and no Pre-fault load


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 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 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 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 generator is unprotected should a fault occur with the breaker open or prior to synchronizing

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 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 decreasing voltage

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 (175025=044 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 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 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 swings or motor starting conditions that depress the voltage below the voltage controlled undervoltage unit dropout point


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

Phase Fault Protection


OTHER ABNORMAL CONDITIONS OVERLOADS

Most large generators are equipped with resistance temperature detectors (RTDs) that are often used in a bridge circuit to provide sensing intelligence to an indicator or a relay The relay has contact-opening torque when the resistance is low which indicates low machine temperature When the temperature of the machine exceeds 120oC for class B-insulated machines the bridge becomes unbalanced and the contact closes


OVEREXCITATION AND OVERVOLTAGEUNDERVOLTAGE PROTECTION

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 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 reduced A voltshertz relay (24) responds to excitation level as it affects thermal stress to the generator (and to any transformer tied to that generator) IEEE C5013 specifies that a 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 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 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 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 is connected to an ac potential source different than that used for the regulator

Fig 13-16 shows the relation among the 24 relay inverse squared characteristics and an example of a generator and transformer withstand capability The generator and transformer manufacturers should supply the specific capabilities of these units

Phase over (59) and under (27) voltage relaying also acts as a backup for excitation systemproblems Undervoltage relaying also acts as fault detection relaying because faults tend to depress voltage

Figure 13-16 Combined GeneratorTransformer Overexcitation Protection using both the

Inverse squared tripping Equipment withstand curves are examples only


UNBALANCED (NEGATIVE SEQUENCE) CURRENTS Unbalanced loads unbalanced system faults open conductors or other unsymmetrical operating conditions result in an unbalance of the generator phase voltages The resulting 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 unbalanced condition is allowed to persist indefinitely The ability of a generator to withstand these negative sequence currents is defined by ANSI C 5013 - 1977 as I2

2t = k

where the negative sequence current is expressed in per unit of the full load current and the time is given in seconds

Negative sequence stator currents caused by fault or load unbalance induce doublefrequency currents into the rotor that may eventually overheat elements not designed to be subjected to such currents Series unbalances such as untransposed 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 C5013-1977 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 heavily-loaded generator

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

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

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


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 generator to a system to which it is being paralleled

UNBALANCED (NEGATIVE SEQUENCE) CURRENTS

Table 13-1 lists the typical k-values

Table 13-1 Generator k-Values

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


Figure 13-18 Current Unbalance Relay Time Current Characteristics


LOSS OF PRIME MOVER (MOTORING)

Generator anti-motoring protection is designed for protection of the prime mover or the system rather than for protection of the generator itself Motoring results from low prime mover input to the generator such as would occur if the steam supply to the turbine or the oil supply to the diesel were lost When the prime mover input to the generator cannot 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 the voltage (system excitation) Under motoring conditions steam turbine blades can overheat water wheel turbine blades can cavitate and fire or possible explosion can result in a diesel unit

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 rating is listed in Table 13-2

Table 13-2 Maximum Motoring Power

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 supplemental protection

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 power relay is frequently used to introduce sufficient time delay necessary to override momentary power surges that might occur during synchronizing A time delay of 10-15 seconds is typical


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 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

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 mechanical problems In the case of diesels the hazard of a fire andor explosion may occur due to unburnt fuel Therefore anti-motoring protection is recommended whenever 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 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 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

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


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 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 (eg 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 generator response during generator power swings Relay 32-2 trips directly for cases of motoring that were not initiated by lockout relay 86NE mdash eg governor control malfunction

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

an 86NE operation


LOSS OF EXCITATION (FIELD)

Protection to avoid unstable operation potential loss of synchronism and possible 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 recommended to operate independently both as supplemental and backup protection Generators have characteristics known as capability curves Typical curves are shown in Figure 13-21 Temperature limits are basically zones so these curves are designerrsquos thermal limits As overheating varies with operation three arcs of circles define the limits 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

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 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 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

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 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 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 02-03 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


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


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

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 Xd2 Two zones sometimes are used a high speed zone and a time delayed zone (Figure 13-23)

Figure 13-23 Loss of Excitation using Impedance Relay


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 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 stator overloads

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 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 loads If the unit is large compared to the external reactive sources system instability can result


INTEGRATED APPLICATION EXAMPLES

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

Fig 13-24 represents bare-minimum protection with only overcurrent protection 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 (lt50kVA) 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 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 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 internal fault could be destroyed when the field is applied

Figure 13-24 Exaple of Bare-minimum Protection (Lowndashimpedance Grounding)


Fig 13-25 shows the suggested minimum protection with low-resistance grounding It includes differential protection which provides fast selective response but differential 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

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 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 generator contribution Fast disconnection from the external source allows prompt restoration of normal voltage to loads and may reduce damage and cost of repairs

Figure 13-25 Suggested minimum protection example (Low-impedance 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 the primary protection if the differential relay (87G) is not sufficiently sensitive to the ground current level


The 51V voltage-controlled or voltage-restrained time overcurrent relay in Fig 13-25 is shown on the CT on the high voltagesystem side of the generator This allows the relay to 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 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 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 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 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 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 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 against forces from a motored generator and could provide important protection for the external system if the motoring power significantly reduces voltage or overloads equipment

Likewise the loss-of-field relay (40) has dual protection benefitsmdashagainst rotor overheating and against depressed system voltage due to excessive generator reactive 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 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 (81OU) protects the generator from off nominal frequency operation and senses generator islanding The under and overvoltage function (2759) detects excitation system problems and some protracted fault conditions


Fig 13-26 shows minimum basic protection for a medium impedance grounded generator It differs from Fig 13-26 only in the use of a ground differential relay) This protection provides faster clearing of ground faults where the grounding impedance is too high to sense ground faults with the phase differential relay (87G) The relay compares ground current seen at the generator high voltage terminals to ground current at the generator neutral The 51N relay provides backup for the ground differential (87N) and for external faults using the current polarizing mode The polarizing winding measures the neutral current

Figure 13-26 Suggested minimum protection example (low-resistance ground)


Fig 13-27 shows minimum basic protection for a high impedance grounded generator It differs from Fig 13-26 only in the ground relay protection and the method of grounding The voltage units 59N27-3N provide the only ground protection since the ground fault current is too small for phase differential relay (87G) operation The 59N relay will not be selective if other generators are in parallel since all the 59N relays will see a ground fault and nominally operate at the same time If three Phase-Ground Y-Y VTs were applied in Fig 13-26 the 27 and 59 could provide additional ground fault protection and an additional generator terminal 59N ground shift relay could be applied

Figure 13-27 Suggested minimum protection example (high-resistance grounding)

Typical relays include a third harmonic undervoltage function (27-3N) that provides supervision of the grounding system protects for faults near the generator neutral and detects a shorted or open connection in the generator ground connection or in the distribution transformer secondary circuit


Fig 13-28 shows the application of additional relays for extended protection overexcitation relay (24) negative sequence overcurrent and overvoltage relay (46 and 47) ground-overcurrent relay (51GN) voltage-balance relay (60) field-ground relay (64F) frequency relay (81) and the 2750 62 relay combination for inadvertent energization protection Relay 51GN provides a second means of detecting stator ground faults or faults in the generator connections or faults in the delta transformer windings Differential relay 87T and sudden-pressure relay 63 protect the unit step-up transformer Relay 51N provides backup for external ground faults and for faults in the highvoltage transformer windings and leads This relay may also respond to an open phase condition or a breaker-interrupter flashover that energizes the generator The 51N relay will be very slow for the flashover case since it must be set to coordinate with external relays and is a lastresort backup for external faults

Figure 13-28 shows wye-connected VTs appropriate with an isolated-phase bus

Figure 13-28 Extended Protection Example (High-resistance grounding)


Table 13-3 Typical Relay Settings

IEEE No Function Typical Settings and Remarks

24 Overexcitation PU 11VNOM60 TD 03 reset TD 5 alarm PU 118VNOM60 alarm delay 25s

25 Synchronism Check Max Slip 6RPM Max phase angle error 10deg Max VMAGerror 25 VNOM

32 Reverse Power (one stage) PU turbine 1 of rated 15 s PU Reciprocating engine 10 of rated 5 s

32-1 Reverse Power Nonelectrical Trip Supervision

PU same as 32 3 s

40 Loss-of-field (VAR Flow Approach)

Level 1 PU 60 VA rating Delay 02s Level 2 PU 100 VA rating 01s

46 Negative Sequence Overcurrent

I2 PU 10 Irated K=10

49 Stator Temperature (RTD) Lower 95degC upper 105degC

5087 Differential via flux summation CTs

PU10 INOM or less if 1A relay may be used

5027 IE Inadvertent Energization Overcurrent with 27 81 Supervision

50 05A (10 INOM) 27 85 VNOM(81 Similar)

51N Stator Ground Over-current (Low Med Z Gnd Phase CT Residual)

PU 10 INOM curve EI TD 4 Inst none Higher PU required to coordinate with load No higher than 25 INOM

5051N Stator Ground Over-current (Low Med Z Gnd Neutral CT or Flux Summation CT)

PU 10 INOM Curve EI TD4 Inst 100 INOM Higher PU if required to coordinate with load No higher than 25 INOM

51GN 51N Stator Ground Over-current (High Z Gnd)

PU 10 IFAULTat HV Term Curve VI TD4

51VC Voltage Controlled Overcurrent

PU 50 INOM Curve VI TD 4 Control voltage 80VNOM


IEEE No Function Typical Settings and Remarks 51VR Voltage Restrained

Overcurrent PU 175 INOM Curve VI TD 4 Zero Restraint Voltage 100 VNOM L-L

59N 27-3N 59P

Ground Overvoltage 59N 5 VNEU during HV terminal fault 27-3N 25 V3rd during normal operation TD 10s 59P 80 VNOM

67IE Directional OC for Inadvertent Energization

PU 75-100 INOM GEN Definite Time (01-025 sec) Inst 200 INOM GEN

81 Overunder frequency Generator protection 57 62Hz 05s Island detection 59 61Hz 01s

87G Generator Phase Differential

BE1-87G 04A BE1-CDS220 Min PU 01 Tap BE1-CDS220 Min PU 01 Tap

87N Generator Ground Differential

BE1-CDS220 Min PU 01 times tap Slope 15 Time delay 01s choose low tap BE1-67N current polarization time 025A Curve VI TD 2 Instantaneous disconnect

87UD Unit Differential BE1-87T or CDS220 Min PU035Tap Tap INOM Slope 30


EXAMPLE OF A NUMERICAL RELAY FOR PROVIDING COMPREHENSIVE GENERATOR PROTECTION GE G60 RELAY

Features Protection and Control bull Generator stator differential

bull 100 stator ground protection

bull Loss of excitation

bull Power swing blocking and out-of-step tripping

bull Backup distance

bull Reverse low forward power

bull Restricted ground fault

bull Overexcitation

bull Generator unbalance

bull Split phase protection

bull Phase sequence reversal for pumped storage

bull Abnormal frequency protection

bull Enhanced RTD protection


Communications

bull Networking interfaces ndash 100Mbit Fiber Optic Ethernet RS485 RS232 RS422 G703 C3794

bull Multiple Protocols - IEC61850 DNP 30 Level 2 Modbus RTU Modbus TCPIP IEC60870-5-104 Ethernet Global Data (EGD)

bull Direct IO ndash secure high-speed exchange of data between URs for Direct Transfer Trip and IO Extension applications

bull Embedded Managed Ethernet Switch with 4 - 100 Mbit Fiber optic ports and 2 copper ports

Monitoring and Metering

bull Metering - current voltage power energy frequency

bull Oscillography ndash analog and digital parameters at 64 samplescycle

bull Event Recorder - 1024 time tagged events with 05ms scan of digital inputs

bull Data Logger - 16 channels with sampling rate up to 1 sample cycle

bull Advanced relay health diagnostics

bull Synchronised measurement of voltage amp current and sequence component phasors

- 1 to 60 phasorssec


The G60 Generator Protection System is a microprocessor based relay that provides protection monitoring control and recording functions for AC generators driven by steam gas or hydraulic turbineS Current voltage and frequency protection are provided along with fault diagnostics

Voltage current and power metering is built into the relay as a standard feature Current parameters are available as total waveform RMS magnitude or as fundamental frequency only RMS magnitude and angle (phasor)

Diagnostic features include an event recorder capable of storing 1024 time-tagged events oscillography capable of storing up to 64 records with programmable trigger content and sampling rate and data logger acquisition of up to 16 channels with programmable content and sampling rate The internal clock used for time-tagging can be synchronized with an IRIGB signal or via the SNTP protocol over the Ethernet port This precise time stamping allows the sequence of events to be determined throughout the system Events can also be programmed (via FlexLogictrade equations) to trigger oscillography data capture which may be set to record the measured parameters before and after the event for viewing on a personal computer (PC) These tools significantly reduce troubleshooting time and simplify report generation in the event of a system fault

A faceplate RS232 port may be used to connect to a PC for the programming of settings and the monitoring of actual values

Table 13-4 ANSI Device Numbers and Functions


Figure 13-30 Single Line Diagram

Table 13-5 Other Device Functions


SETTING EXAMPLE This secion provides an example of the seting required for an example system configuration Consider the protection system shown below

Figure 13-31 Setting Example

Ideally the CTs should be selected so the generator nominal current is 80 to 85 of CT primary The following settings are entered for the example system The M5 bank and the ground CT input on each of the groups are unused in this example

The nominal current is given by


STATOR DIFFERENTIAL ELEMENT THEORY OF OPERATION

The stator differential protection element is intended for use on the stator windings of rotating machinery

Figure 13-32 Stator Differential Characteristic


This element has a dual slope characteristic The main purpose of the percent-slope characteristic is to prevent a maloperation caused by unbalances between CTs during external faults CT unbalances arise as a result of the following factors

1 CT accuracy errors

2 CT saturation

The characteristic allows for very sensitive settings when fault current is low and less sensitive settings when fault current is high and CT performance may produce incorrect operate signals

bull Stator Diff Line End Source This setting selects the source connected to CTs in the end of the machine stator winding closest to the load and furthest from the winding neutral point Both line and neutral-side CTs should be wired to measure their currents in the same direction with respect to the neutral point of the winding

bull Stator Diff Neutral End Source This setting selects the source connected to CTs in the end of the machine stator winding furthest from the load and closest to the winding neutral point Both line and neutral-side CTs should be wired to measure their currents in the same direction with respect to the neutral point of the winding

bull Stator Diff Pickup This setting defines the minimum differential current required for operation This setting is based on the amount of differential current that might be seen under normal operating conditions A setting of 01 to 03 pu is generally recommended

bull Stator Diff Slope 1 This setting is applicable for restraint currents from zero to STATOR DIFF BREAK 1 and defines the ratio of differential to restraint current above which the element will operate This slope is set to ensure sensitivity to internal faults at normal operating current levels The criteria for setting this slope is to allow for maximum expected CT mismatch error when operating at the maximum permitted current This maximum error is generally in the range of 5 to 10 of CT rating

bull Stator Diff Break 1 This setting defines the end of the Slope 1 region and the start of the transition region It should be set just above the maximum normal operating current level of the machine

bull Stator Diff Slope 2 This setting is applicable for restraint currents above the STATOR DIFF BREAK 2 setting when the element is applied to generator stator windings This slope is set to ensure stability under heavy external fault conditions that could lead to high differential currents as a result of CT saturation A setting of 80 to 100 is recommended

The transition region (as shown on the characteristic plot) is a cubic spline automatically calculated by the relay to result in a smooth transition between STATOR DIFF SLOPE 1 and STATOR DIFF SLOPE 2 with no discontinuities


bull Stator Diff Break 2 This setting defines the end of the transition region and the start of the Slope 2 region It should be set to the level at which any of the protection CTs are expected to begin to saturate

SATURATION DETECTION

External faults near generators typically result in very large time constants of DC components in the fault currents Also when energizing a step-up transformer the inrush current being limited only by the machine impedance may be significant and may last for a very long time In order to provide additional security against maloperations during these events the G60 incorporates saturation detection logic When saturation is detected the element will make an additional check on the angle between the neutral and output current If this angle indicates an internal fault then tripping is permitted

SETTING THE STATOR DIFFERENTIAL ELEMENT

The ldquoLINErdquo and ldquoNEUTRLrdquo sources are both required for the stator differential element The minimum pickup can usually be set as low as 005 pu (corresponding to 025 A secondary or 400 A primary in this example) Set the STATOR DIFF SLOPE 1 setting to accommodate for CT errors a setting of 10 is adequate in most instances Set the STATOR DIFF SLOPE 2 setting to accommodate for errors due to CT saturation a setting of 80 is recommended for most applications The STATOR DIFF BREAK 1 setting must be greater than the maximum load expected for the machine The STATOR DIFF BREAK 2 setting should be set at the level where CT saturation is expected to occur

GENERATOR UNBALANCE

THEORY OF OPERATION

The generator unbalance element protects the machine from rotor damage due to excessive negative-sequence current

The element has an inverse time stage which is typically used for tripping and a definite time stage typically used for alarm purposes The inverse time stage operating characteristic is defined by the following equation

bull Gen Unbal Inom This setting is the rated full load current of the machine bull GEN UNBAL STG1 PICKUP This setting defines the pickup of the stage 1 element expressed as a percentage of the nominal current as specified by GEN UNBAL INOM setting It is typically set at the maximum continuous negative sequence current rating of the machine


bull Gen Unbal Stg1 K-Value This setting is the negative sequence capability constant This value is normally provided by the generator manufacturer (refer to ANSI C5013 for details)

bull Gen Unbal Stg1 Tmin This is the minimum operate time of the stage 1 element The stage will not operate before this time expires This is set to prevent false trips for faults that would be cleared normally by system protections

bull Gen Unbal Stg1 Tmax This is the maximum operate time of the stage 1 element This setting can be applied to limit the maximum tripping time for low level unbalances

bull Gen Unbal Stg1 K-Reset This setting defines the linear reset rate of the stage 1 element It is the maximum reset time from the threshold of tripping This feature provides a thermal memory of previous unbalance conditions

bull Gen Unbal Stg2 Pickup This setting defines the pickup of the stage 2 element expressed as a percentage of the nominal current as specified by GEN UNBAL INOM setting The definite time element would normally be used to generate an alarm to prompt an operator to take some corrective action The stage 2 element would typically be set at a safe margin below the stage 1 pickup setting

bull Gen Unbal Stg2 Pkp Delay This is the minimum operate time of the stage 2 element This is set to prevent nuisance alarms during system faults

Figure 13-33 Generator Unbalance Inverse Time Curves


SETTING THE GENERATOR UNBALANCE ELEMENT

Stage 1 of the generator unbalance element is typically used to trip the generator In this example the I2 capability of the machine is 8 and the I22T capability is 10 The generator nominal current is

The minimum operate time of stage 1 will be set to 025 seconds the maximum operating time will be 10 minutes and the reset time will be set to 4 minutes Stage 2 is typically set lower than stage 1 with a time delay to prevent nuisance alarms for external faults that are normally cleared by system protection For the application example the pickup setting is Pickup=70 times I2 capability=070 times 8 = 56

LOSS OF EXCITATION

THEORY OF OPERATION

The operating characteristic is shaped out of two offset mho circles shifted down along the imaginary axis as shown below

Figure 13-34 Loss of Excitation Operationg Characteristics


Stage 1 Settings

The stage 1 characteristic is typically set to detect a loss of excitation for load conditions of 30 of the nominal or higher

This is achieved with a mho element with a diameter equal to the base impedance of the machine and an offset equal to half the machine transient reactance (Xprimed)

The stage 1 element should be time delayed to allow for blocking by the VT fuse failure element (50 ms)

Stage 2 Settings

The stage 2 characteristic is typically set to detect a loss of excitation for all load conditions This is achieved with a mho element with a diameter equal to the synchronous reactance of the machine and an offset equal to half the machine transient reactance (Xprimed)

During stable power swing conditions the positive-sequence impedance may momentarily enter the stage 2 characteristic For security of the function under such conditions it is recommended to delay stage 2 by a minimum of 05 seconds


SETTING THE LOSS OF EXCITATION ELEMENT

The voltage supervision setting will be determined by a system study and may be disabled on either element if required VT fuse failure should supervise this element


REVERSE POWER

THEORY OF OPERATION

The reverse power element should be set at frac12 the rated motoring power The pickup is calculated as follows

SETTING THE REVERSE POWER ELEMENT

To prevent maloperation for power swings the element is typically time delayed by 20 to 30 seconds For sequential tripping applications the time delay will be 2 to 3 seconds The element may be blocked when the generator is offline The line source will be used for this application

SYSTEM BACKUP OVERCURRENT

INVERSE TIME OVERCURRENT CHARACTERISTICS

The inverse time overcurrent curves used by the time overcurrent elements are the IEEE IEC GE Type IAC and I2t standard curve shapes This allows for simplified coordination with downstream devices

If none of these curve shapes is adequate FlexCurvestrade may be used to customize the inverse time curve characteristics

The Definite Time curve is also an option that may be appropriate if only simple protection is required

Table 13-6 Overcurrent Curve Types


A time dial multiplier setting allows selection of a multiple of the base curve shape (where the time dial multiplier = 1) with the curve shape (CURVE) setting Unlike the electromechanical time dial equivalent operate times are directly proportional

to the time multiplier (TD MULTIPLIER) setting value For example all times for a multiplier of 10 are 10 times the multiplier 1 or base curve values Setting the multiplier to zero results in an instantaneous response to all current levels above pickup

Time overcurrent time calculations are made with an internal lsquoenergy capacityrsquo memory variable When this variable indicates that the energy capacity has reached 100 a time overcurrent element will operate If less than 100 energy capacity is accumulated in this variable and the current falls below the dropout threshold of 97 to 98 of the pickup value the variable must be reduced Two methods of this resetting operation are available ldquoInstantaneousrdquo and ldquoTimedrdquo The ldquoInstantaneousrdquo selection is intended for applications with other relays such as most static relays which set the energy capacity directly to zero when the current falls below the reset threshold The ldquoTimedrdquo selection can be used where the relay must coordinate with electromechanical relays


IEEE CURVES

The IEEE time overcurrent curve shapes conform to industry standards and the IEEE C37112-1996 curve classifications for extremely very and moderately inverse The IEEE curves are derived from the formulae

Table 13-7 IEEE Inverse Time Curve Constants

Table 13-8 IEEE Curve Trip Times (In Seconds)


Table 13-9 IEC (BS) Inverse Time Curve Constants

Table 13-10 IEC Curve Trip Times (In Seconds)


The phase time overcurrent element can provide a desired time-delay operating characteristic versus the applied current or be used as a simple definite time element The phase current input quantities may be programmed as fundamental phasor magnitude or total waveform RMS magnitude as required by the application

Two methods of resetting operation are available ldquoTimedrdquo and ldquoInstantaneousrdquo (refer to the Inverse Time overcurrent curves characteristic sub-section earlier for details on curve setup trip times and reset operation) When the element is blocked the time accumulator will reset according to the reset characteristic For example if the element reset characteristic is set to ldquoInstantaneousrdquo and the element is blocked the time accumulator will be cleared immediately

The PHASE TOC1 PICKUP setting can be dynamically reduced by a voltage restraint feature (when enabled) This is accomplished via the multipliers (Mvr) corresponding to the phase-phase voltages of the voltage restraint characteristic curve (see the figure below) the pickup level is calculated as lsquoMvrrsquo times the PHASE TOC1 PICKUP setting If the voltage restraint feature is disabled the pickup level always remains at the setting value

Figure 13-35 Phase Time Overcurrent Voltage Restraint Characteristics


SETTING THE SYSTEM BACKUP PROTECTION ELEMENTS

System backup protection is implemented using a phase time overcurrent element with voltage restraint enabled The NEUTRL source will be chosen for this element The pickup of this element should be set at a safe margin above the maximum load expected on the machine

The selection of all standard curves (and FlexCurvestrade) is allowed for easy coordination with system relaying For the example system an IEEE extremely inverse curve will be used and a setting will be chosen such that the operate time for a three phase fault on the high side of the transformer is 075 seconds For simplicity the power system contribution is not considered

Since this element will coordinate with system protections a timed reset is chosen The element must be blocked for a VT fuse failure The neutral source will be chosen


BACKUP DISTANCE

THEORY OF OPERATION

This function provides time-delayed protection for system faults that have not been cleared by system protections and to provide backup protection for stator faults

The ldquoLinerdquo source will be used in this example to permit the application of a forward and reverse zone The memory duration will be left at the default setting (10 cycles)

Zone 1 will look forward and cover the GSU and the transmission line leaving the station Zone 3 will look in the reverse direction and cover the stator winding Zone 2 will not be used in this example Both the VTs and the CTs are located on the low voltage side of the GSU The transformer vector diagram (see Figure 13-31) shows this transformer to be Yd1 Consequently due to the location of instrument transformers Dy11 is chosen for both the XFMR VOL CONNECTION and XFMR CUR CONNECTION settings There are no transformers in the reverse direction Therefore ldquoNonerdquo is chosen for both of the zone 3 transformer connection settings The reach of the zone 1 element will be set at 120 of impedance of the GSU and the transmission line In the instance that there are multiple lines andor multiple generators the zone 1 reach must be increased to compensate for the infeed effect

The zone 3 reach will be set at 120 of the generator transient reactance The time delay of this element should be compared to the generator decrement curve to verify the adequacy of this setting

An mho shape has been chosen for this example Therefore the quadrilateral settings are left at their default values


STATOR GROUND FAULT

THEORY OF OPERATION

The G60 relay provides a two-zone function designed to detect stator winding ground faults on resistance and high-impedance grounded generators The Zone 1 element 64G1 uses a fundamental-frequency neutral overvoltage element that is sensitive to faults in the middle and upper portions of the winding The Zone 2 element 64G2 uses a third-harmonic voltage differential function to detect faults in the upper and lower portions of the winding By using the two zones together the relay provides 100 percent stator ground fault coverage

Note Most generators produce enough third-harmonic voltage for proper application of the 64G2 element however some generators (eg those with 23 pitch winding) may not In those cases the element based on the third-harmonic voltage such as the 64G2 cannot be used for 100 percent Stator Ground Protection

When a ground fault occurs high in the winding of a resistance or high-impedance grounded generator a voltage appears at the generator neutral The neutral voltage magnitude during the fault is proportional to the fault location within the winding For instance if a fault occurs 85 percent up the winding from the neutral point the neutral voltage is 85 percent of the generator rated line-neutral voltage

This function detects stator ground faults in all but the bottom 5ndash10 percent of the generator winding In this area close to the generator neutral the neutral voltage does not increase significantly during a generator ground fault The G60 relay uses the third-harmonic voltage differential element to detect faults in this area

The following formula is used to create an adaptive operating quantity based on the amount of third harmonic that appears at the generator terminals

where VN(3rd) is a magnitude of the 3rd harmonic in the voltage measured at the machine neutral point measured via an auxiliary channel of the VT bank and V0(3rd) is a magnitude of the 3rd harmonic in the zero-sequence voltage measured at the machine terminals

This element requires wye-connected VTs for measurement of the third harmonic in the zero-sequence voltage at the generator output terminals


Example 1 Operating quantities under normal conditions

Consider the figure shown below In the case of a high impedance grounded machine the neutral resistor is typically chosen such that power dissipated in the resistor during a single line to ground fault is approximately equal to the reactive power produced by the zero sequence capacitance of the stator winding and the GSU LV winding (X0c ) At power system frequencies the neutral resistance is therefore equal to Xoc 3 and at 3 x Fn the neutral resistance is Xoc

For analysis assume that E3 = 10 V R = 5 Ω and Xc = 5 Ω


In actual practice the |VN| |VN + V0| ratio may vary from 04 to 085 under normal conditions The pickup and supervision setpoints are determined by evaluating the operating quantities during a fault condition


OVEREXCITATIONELEMENT THEORY OF OPERATION

VOLTS PER HERTZ (ANSI 24)

The per-unit VHz value is calculated using the maximum of the three-phase voltage inputs or the auxiliary voltage channel Vx input if the Source is not configured with phase voltages To use the VHz element with auxiliary voltage set SYSTEM SETUP 992256992256 SIGNAL SOURCES 992256 SOURCE 1(6) 992256992256 SOURCE 1(6) PHASE VT to ldquoNonerdquo and SOURCE 1(6) AUX VT to the corresponding voltage input bank If there is no voltage on the relay terminals in either case the per-unit VHz value is automatically set to ldquo0rdquo The per unit value is established as per voltage and nominal frequency power system settings as follows

1 If the phase voltage inputs defined in the source menu are used for VHz operation then ldquo1 purdquo is the selected SYSTEM SETUP rarr AC INPUTS rarrdarr VOLTAGE BANK N rarrdarr PHASE VT N SECONDARY setting divided by the divided by the SYSTEM SETUP rarrdarr POWER SYSTEM rarr NOMINAL FREQUENCY setting

2 When the auxiliary voltage Vx is used (regarding the condition for ldquoNonerdquo phase voltage setting mentioned above) then the 1 pu value is the SYSTEM SETUP rarrAC INPUTS rarrdarr VOLTAGE BANK N 992256992256 AUXILIARY VT N SECONDARY setting divided by the SYSTEM SETUP rarrdarr POWER SYSTEM rarr NOMINAL FREQUENCY setting

3 If VHz source is configured with both phase and auxiliary voltages the maximum phase among the three voltage channels at any given point in time is the input voltage signal for element operation and therefore the per-unit value will be calculated as described in Step 1 above If the measured voltage of all three phase voltages is 0 than the perunit value becomes automatically 0 regardless of the presence of auxiliary voltage

The element has a linear reset characteristic The reset time can be programmed to match the cooling characteristics of the protected equipment The element will fully reset from the trip threshold in VOLTSHZ T-RESET seconds The VHz element may be used as an instantaneous element with no intentional time delay or as a Definite or Inverse timed element

The characteristics of the inverse curves are shown below

bull DEFINITE TIME T(sec) = TD Multiplier For example setting the TD Multiplier set to 20 means a time delay of 20 seconds to operate when above the VoltsHz pickup setting Instantaneous operation can be obtained the same way by setting the TD Multiplier to ldquo0rdquo


This protection should be set to coordinate with the manufacturers excitation capability curves For example system the combined generatorGSU limit curve is shown below


Program the volts per hertz 1 element with an inverse characteristic (curve A) a pickup of 105 and a TDM of 40 Program the volts per hertz 2 element with a definite time characteristic a pickup of 123 and a time delay of 2 seconds Both elements will issue a trip The volts per hertz 1 pickup will be used to generate an alarm Either source may be assigned in this example


FREQUENCY ELEMENT The pickup and delay settings are dependent on operating practices and system characteristics In this example two overfrequency and two underfrequency elements will be used The elements will be blocked when offline Underfrequency will initiate a trip Overfrequency will alarm only Either source may be assigned


ACCIDENTAL ENERGIZATION ELEMENT

THEORY OF OPERATION

This element provides protection against energization while the generator is at standstill or reduced speed The feature is armed using either the AND or OR combination of the undervoltage and machine off-line conditions selected with the

ACCDNT ENRG ARMING MODE setting (see below) The undervoltage condition is determined from the measured voltages The machine off-line status is indicated by a dedicated FlexLogictrade operand Once armed the accidental energization feature operates upon detecting an overcurrent condition in any of the stator phases

This feature can also provide protection against poor synchronization

bull ACCDNT ENRG ARMING MODE This setting specifies whether the feature gets armed by either of the undervoltage or machine off-line conditions (ldquoUV or Off-linerdquo value) or by both the conditions (ldquoUV and Off-linerdquo value) In both cases the element is armed after 5 seconds of the appropriate condition and de-armed 250 ms after the arming condition (UV andor Off-line) ceases

The ldquoUV or Off-linerdquo selection shall be made when the VTs are on the power system side of the disconnecting device

If this is the case the measured voltages may be normal regardless of the status of the protected machine thus the need for an OR condition The ldquoUV or Off-linerdquo value provides protection against poor synchronization During normal synchronization there should be relatively low current measured If however synchronization is attempted when conditions are not appropriate a large current would be measured shortly after closing the breaker Since this feature does not de-arm immediately but after a 250 ms time delay this will result in operation under imprecise synchronization

The ACCDNT ENRG OC PICKUP setting can control the required precision of synchronization

The ldquoUV and Off-linerdquo value shall be made when the VTs are on the generator side of the disconnecting device If this is the case both the undervoltage and machine off-line conditions are required to indicate that the protected generator is not energized

bull ACCDNT ENRG OC PICKUP This setting specifies the current level required to operate the armed Accidental Energization element If any of the phase current is above the ACCDNT ENRG OC PICKUP level the feature operates

bull ACCDNT ENRG UV PICKUP This setting specifies the voltage level required to arm the Accidental Energization element

All of the line-to-line voltages must drop below the ACCDNT ENRG UV PICKUP level in order to detect the undervoltage condition The setting is entered in voltage pu values As


the element always responds to the line-to-line voltages care must be applied in picking up the value depending on the VT connection

bull ACCDNT ENRG OFFLINE This setting specifies the FlexLogictrade operand indicating that the protected generator is off-line

Chapter 13

Generator protection Generator protection

INTRODUCTION

INTERNAL FAULTS






DIFFERENTIAL PROTECTION (GROUND FAULTS)

FIELD GROUNDS


Generator decrement curve



OTHER ABNORMAL CONDITIONS








Introduction

bull General

bull Types Of Faults

bull Other Abnormal Operating AndOr System Conditions

bull Effects Of Generator Bus Faults

Internal Faults

bull Differential Protection (Phase Faults)

bull Differential Protection (Ground Faults)

bull Field Grounds

Phase Fault Backup Protection

bull Introduction

bull Generator Decrement Curve

bull Voltage Restraint Overcurrent Relays

bull Voltage Controlled Overcurrent Relays

Other Abnormal Conditions

bull Overloads

bull Overexcitation and OvervoltageUndervoltage Protection

bull Unbalanced (Negative Sequence) Currents

bull Loss Of Prime Mover (Motoring)

bull Loss Of Excitation (Field)




bull Features









TYPES OF FAULTS



bull Field grounds



bull Overloads

bull Overheating

bull Overspeed





bull Overvoltage








2 out)

12 asymp kVARout


bull Volts rarr 0




(function of Xrdquo

d)







































FIELD GROUNDS





INTRODUCTION















bull Xd = 150 I = 1015 = 067 pu



































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS














bull Features









TYPES OF FAULTS



bull Field grounds



bull Overloads

bull Overheating

bull Overspeed





bull Overvoltage








2 out)

12 asymp kVARout


bull Volts rarr 0




(function of Xrdquo

d)







































FIELD GROUNDS





INTRODUCTION















bull Xd = 150 I = 1015 = 067 pu



































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS


















TYPES OF FAULTS



bull Field grounds



bull Overloads

bull Overheating

bull Overspeed





bull Overvoltage








2 out)

12 asymp kVARout


bull Volts rarr 0




(function of Xrdquo

d)







































FIELD GROUNDS





INTRODUCTION















bull Xd = 150 I = 1015 = 067 pu



































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS


















2 out)

12 asymp kVARout


bull Volts rarr 0




(function of Xrdquo

d)







































FIELD GROUNDS





INTRODUCTION















bull Xd = 150 I = 1015 = 067 pu



































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS















































FIELD GROUNDS





INTRODUCTION















bull Xd = 150 I = 1015 = 067 pu



































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS













INTRODUCTION















bull Xd = 150 I = 1015 = 067 pu



































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS
























bull Xd = 150 I = 1015 = 067 pu



































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS











































2t = k






























an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS



































an 86NE operation















































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS

























































PU same as 32 3 s





















59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS














59N 27-3N 59P



















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS




















bull Overexcitation







Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS












Communications


































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS
































2 CT saturation















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS

















GENERATOR UNBALANCE

THEORY OF OPERATION
















LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS























LOSS OF EXCITATION

THEORY OF OPERATION




Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS












Stage 1 Settings




Stage 2 Settings







REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS















REVERSE POWER

THEORY OF OPERATION















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS
















IEEE CURVES


















BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS

























BACKUP DISTANCE

THEORY OF OPERATION







STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS












STATOR GROUND FAULT

THEORY OF OPERATION
































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS



































THEORY OF OPERATION















Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS














Chapter 13


INTRODUCTION

INTERNAL FAULTS







FIELD GROUNDS











new chapter 13 generator protection

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