gek75512k generator protection

GEK 75512kRevised October 2006

GE Energy

Generator Protection

These instructions do not purport to cover all details or variations in equipment nor to provide forevery possible contingency to be met in connection with installation, operation or maintenance. Shouldfurther information be desired or should particular problems arise which are not covered sufficiently forthe purchaser's purposes the matter should be referred to the GE Company.

© 2006 General Electric Company

GEK 75512k Generator Protection

TABLE OF CONTENTS

I. INTRODUCTION.......................................................................................................................... 3A. Standards .................................................................................................................................. 3B. Protection Responsibility ......................................................................................................... 3C. Protection Equipment............................................................................................................... 4

II. RELATIONSHIP BETWEEN OPERATION, PROTECTION AND ALARMS .................... 5A. Operation and Protection.......................................................................................................... 5B. Protection and Alarms.............................................................................................................. 5

III. ALARMS ........................................................................................................................................ 5

IV. PROTECTIONWHEN GENERATOR IS OFF LINE .............................................................. 6

V. TRIPPING METHODS................................................................................................................. 9A. Protective Actions for Generator Faults................................................................................... 9

VI. PROTECTION RECOMMENDATIONS ................................................................................... 11A. Discussion and Recommendations for Generator Faults ......................................................... 11

LIST OF FIGURES

Figure 1. ................................................................................................................................................ 16

LIST OF TABLES

Table 1. ALARMS ................................................................................................................................. 6Table 2 . SUMMARY OF GENERATO R PROTECTION RECOMMENDATIONS ........................... 32

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Generator Protection GEK 75512k

I. INTRODUCTION

This instruction book insert was prepared to provide a summary of General Electric's recommendations forprotection of its cylindrical rotor synchronous generators. Since a wide variety of technology is applied tomachines of various size and rating, not all of the alarm and protection recommendations are applicable fora given generator design. For example, references to hydrogen and stator water cooling systems are notapplicable to air cooled machines. The alarm and protection sections are sequenced so that recommenda-tions which are generally applicable appear first, ones related to hydrogen systems next, and finally statorwater cooling system alarms and protection. Recommendations for excitation system protection are notincluded, but are covered in separate instructions.

This instruction book discusses the kinds of protection that are desirable, and the action that is believed tobe best for the needed protection. Specific relays and relay circuits are not discussed.

A. Standards

General Electric turbine-generators are designed and built to meet or surpass applicable industry ac-cepted standards. For the cylindrical rotor synchronous generators covered by these instructions, thesestandards are:

1. ANSI C50.10General Requirements for Synchronous Machines

2. ANSI C50.13Requirements for Cylindrical Rotor Synchronous Generator

3. ANSI C50.14Requirements for Cylindrical Rotor Synchronous Generators

4. ANSI C50.15Requirements for Gas Turbine Driven Synchronous Machines

5. CEI/IEC 34-1Rotating Electrical Machines - Rating and Performance

6. CEI/IEC 34-3Rotating Electrical Machines - Specific requirements for turbine-type synchronous machines

B. Protection Responsibility

There are IEEE Standards covering generator protection which provide guidance material on generatorprotective relaying. These include:

1. ANSI/IEEE C37.101IEEE Guide for Generator Ground Protection

2. ANSI/IEEE C37.102IEEE Guide for AC Generator Protection

3. ANSI/IEEE C37.106IEEE Guide for Abnormal Frequency Protection for Power Generating Plants

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There are two IEEE Press Books which provide a useful anthology of the background material relatedto generator protection. These are:

1. IEEE Press Book - Protective Relaying for Power Systems: Volume 1, 1980

2. IEEE Press Book - Protective Relaying for Power Systems: Volume 2, 1992.

Another useful reference is the IEEE Buff Book from the color series - ANSI/IEEE Std 242 - Protectionand Coordination of Industrial and Commercial Power Systems.

The operating limits specified by the manufacturer may be inadvertently exceeded for a number ofreasons. These include, among others:

• internal generator failure

• auxiliary equipment failure

• operator error

• abnormal system conditions

The protection methods and equipment in place should be able to safely protect the generator no matterwhich of these circumstances, or combination of them, causes the abnormal operation.

Since protective relays and other devices are not immune to failure, it is recommended that considera-tion be given to providing back-up protection for those faults where a device failure could subject thegenerator to serious damage.

Generator protection is a large and complex subject. These instructions were written to provide infor-mation on protection, based on our experience as designers and manufacturers, that may not always bereadily available in other forms.

The recommendations contained in these instructions are based on the best available information at thetime of publication. Changes in the state of the art may result in modification of these recommenda-tions. Such modifications will usually be communicated to all owners of affected turbine-generatorsthr ough G enera l Electr ic , Te chnic al Informa tion Le tter (TIL) serie s. These modifications will be incorporated in pe riod ic re vis i on s t o t he se in stru ctio n s.

C. Protection Equipment

It should not be assumed that any required hardware is part of the turbine-generator supplied, althoughin certain cases some protection is due to special requirements or it is integrated into the excitation orcontrol system.

In either case, it is the owner's or his designate's responsibility to check, adjust, calibrate and connect allprotective equipment to suitable tripping relays or circuits in order to provide the intended protection.The manufacture should be consulted for specific protection application issues or concerns.

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II. RELATIONSHIP BETWEEN OPERATION, PROTECTION AND ALARMS

A. Operation and Protection

The line between generator operation and protection is not always clear and there is inevitably an areaof overlap. These instructions cover those functions that are mainly performed by protective relayingor similar devices or functions. A companion instruction (Ref. 1) covers those aspects of generatoroperation that are mainly under control of an operator and/or electronic turbine-generator controller.Both of these publications should be consulted during plant design and should be used in conjunctionwith other parts of the instruction book for proper operation of the turbine-generator.

B. Protection and Alarms

Those protective relays or devices that trip the generator should alert an operator as to the cause of anytrip, and be able to take direct action if this should prove necessary. In addition to the tripping relaysthere are other relays or devices that initiate only an alarm or data logging. In these cases it becomesan operator's responsibility to decide what corrective action is required and to take it.

III. ALARMS

Many of the “alarm only” devices are for temperature measurement. These are Resistance TemperatureDetectors (RTDs) and Thermocouples (TCs). Some measure other variables such as hydrogen pressureand purity, and stator cooling water pressure, flow and conductivity (if applicable). A typical list of alarmdevices furnished with the generator is given in Table 1, including recommended alarm points and signalranges. If additional special instrumentation is supplied, alarm settings will be specified in the appropriatesection of the instruction book.

Table 1 contains information which may be useful when specifying signal monitoring or recording equip-ment.

The table also includes typical ranges of the variable for each of the devices shown. These ranges do notrepresent the actual capabilities of the generator or its auxiliary equipment and should not be used in anyway as a guide for operation.

When a protective device or function signals a trip, or when the operator trips the unit because of an alarmor other indication of malfunction, it is most important that the cause of the problem be determined andcorrected before attempting to restart or resynchronize. Failure to do so may lead to more serious troubles.

IV. PROTECTION WHEN GENERATOR IS OFF LINE

The need for protecting a generator while on line is well known, but the need when off line may not be aswell understood. Nevertheless, there are circumstances under which a generator could be damaged whileoff line.

For this reason, it is recommended that, as a general rule, all alarms and protections be kept operative atall times. Exceptions to this rule are those protections which would mis-operate or give false signals whenthe unit is below rated speed, not excited, or not synchronized. Relaying and interlocking circuitry thatoperates when the unit is off line should be reviewed to make certain it does not inadvertently incapacitateany essential protection.

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Table 1. ALARMS

SIGNAL DEVICE RANGE SETTING NOTES

MACHINE TEMPERATURES

GENERATOR WITH

BRUSHLESS EXCITER

BRUSHLESS EXCITER RTD -20º to 80ºC Generator Cold

Gas +40ºC

Check Ventilation

GENERATOR WITH STATIC

EXCITATION

COLLECTOR AIR IN RTD or TC -30º to 70°C 45°C In: Check Filters

COLLECTOR AIR OUT RTD or TC -20º to 80°C AIR IN + 20°C Out: Check Ventilation

GENERATOR FIELD TRANSDUCER 0º to 150°C Reduce field current byadj. MVAR load.

STATOR COIL (SLOT) RTD 0 to 100°C for H2O See Ref. 2

0 to 150°C for H2 andAir

OTHER ALARMS

BEARING VIBRATION VIBRATION DETECTOR --- --- See Recommendation in

this publication.

BEARING OIL TEMP HIGH - --- --- See Turbine Section of

Instruction Book

NEGATIVE SEQUENCE

CURRENTRELAY --- --- Balance or reduce load.

See Recommendation for

“Unbalanced Armature

Currents.”

GENERATOR OVERVOLTAGE RELAY --- Over 1.05 pu

voltage

Reduce machine voltage.

AIR COOLING (if applicable)

COLD AIR RTD -30 to 70°C

HOT AIR RTD -10 to 90°C

LOCAL OVERHEATING (if

applicable)

CORE MONITOR LEVEL (if

applicable)CORE MONITOR --- --- See Recommend. for

“Local Overheating.”

MACHINE HEATING (if

applicable)SIGNAL VALIDATION

DEVICE

--- --- See Recommend. for

“Local Overheating.”

@From operating pressure

†Two switches

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Table 1. ALARMS (Cont'd)


SEAL OIL SYSTEM (if applic.)

DIFF SEAL OIL PRESSURE

LOW

DIFF. PRESSURE

SWITCH

--- 3 psid

[20.7 kPa]

[211 g/cm2]

See Ref. 3

DRAIN ENLARGEMENT

LIQUID DETECTOR FULL

LIQUID LEVEL

DETECTOR

--- See Ref. 3

EMERGENCY PUMP RUNNING RELAY --- See Ref. 3

FILTER DIFF. PRESSURE HIGH

(if applicable)

DIFF. PRESSURE

SWITCH

10 psid

[69 kPa

(differential)][703 g/cm2

(diff.)]

See Ref. 3

VACUUM TANK OIL LEVEL

HIGH/LOW (if applicable)

FLOAT SWITCH --- +4/-6 in

[+102/-152 mm]

See Ref. 3

MAIN PUMP MOTOR

OVERLOAD (if applicable)

THERMOSTAT --- See Ref. 2

EMERGENCY PUMP MOTOR

OVERLOAD (if applicable)

THERMOSTAT --- See Ref 2

HYDROGEN GAS SYSTEM

COOLER HOT GAS TEMP HIGH RTD or TC 0–100°C

COOLER COLD GAS TEMP

HIGH/LOW

RTD or TC 0–70°C

COMMON COLD GAS TEMP

HIGH (if applicable)

RTD 0–70°C

MACHINE GAS TEMP HIGH METER RELAY 0–100°C See Ref. 4

MACHINE GAS PRESSURE

HIGH/LOW

PRESSURE SWITCH --- +4/-2 psi @

[+27.6/-13.8

kPa][+281/-14.1

g/cm2]

See Ref. 4

MACHINE GAS PURITY LOW METER RELAY or

TRANSMITTER

50–100°C

0–100°C

90% See Ref. 4

GENERATOR CASING LIQUID

DETECTOR FULL

LIQUID DETECTOR --- See Ref. 4

†Two switches@From operating pressure

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Table 1. ALARMS (Cont'd)


STATOR COOLING WATER

SYSTEM (if applicable)

INLET TEMP HIGH RTD or TC 0–70°C 2ºC OVER

MAX.

See Ref. 2

INLET FLOW LOW FLOW SWITCH See Ref. 3

INLET PRESSURE LOW PRESSURE SWITCH See Ref. 3

LIQUID HEADER OUTLETTEMP HIGH

TC 0–100°C See Ref. 3

BULK WATER OUTLET TEMPHIGH

RTD 0–100°C See Ref. 2

CONN RING TEMP HIGH (ifseparately cooled)


CONN RING FLOW LOW (ifseparately cooled)

FLOWMETER See Ref. 3

HV BUSHING OUTLET TEMPHIGH


HV BUSHING FLOW LOW FLOWMETER 3 gpm LOW[189 ml/s]

See Ref. 3

MAIN FILTER DIFF PRESSUREHIGH

DIFF PRESSURESWITCH

0–15 psid[0–103 kPa

(differential)]

[0–1.05 kg/cm2 (diff.)]

8 psid[55 kPa

(differential)]

[562g/cm2(diff.)]

Change filter before 7 psid[48 kPa (diff.)]

[492 g/cm2 (diff.)]

CONDUCTIVITY HIGH TRANSDUCER 0–10 µmho/cm[0–10 µS/cm]

0.5 & 9.9µmho/cm

[0.5 & 9.9

µS/cm]

Change resin on firstalarm. Trip manually on

second alarm

TANK LEVEL HIGH/LOW FLOAT SWITCH --- +4/-4 inches

[+102/-102 mm]

Check main pump

RESERVE PUMP RUNNING PRESSURE SWITCH 0–150 psi

[0–1.03 MPa][0–10.5 kg/cm2]

10 & 20† psi

below normal[69 & 138

kPa][0.7 & 1.41

kg/cm2]

Check cause and correct

RUNBACK INITIATED RELAY NONE PRESET

†Two switches

@From operating pressure

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V. TRIPPING METHODS

There are a number of ways a turbine-generator, or a generator alone, may be tripped, i.e., disconnectedfrom the system or shut down. Some of the factors that should be considered in determining what type oftrip to use for each fault requiring one are:

• severity of fault to generator

• probability of fault spreading

• amount of overspeed resulting

• probability of high overspeed

• importance of removing excitation

• need for maintaining auxiliary power

• need for shutting down the unit

• time required to resynchronize

• effect on the power system

In recognition of the factors above, the manufacturer recommends an action that insures protection of thegenerator. Unless otherwise noted, a protective action with a lower number than the recommended action isallowable (see Table II). Although the lower number protective action may provide faster protection, addi-tional danger to the turbine is incurred. These dangers include higher overspeed and worse turbine thermalshock duty. The recommended protective actions are selected based on the manufactures judgement withregard to providing acceptable generator protection, while minimizing unnecessarily harsh turbine duty.The owner should select the action to be used based on the importance of the applicable factors in his case.

A. Protective Actions for Generator Faults

1. Simultaneous trip - trips the turbine valves closed, opens generator line breakers and removesexcitation simultaneously, as with a lock-out relay. A simultaneous trip is acceptable for all gen-erator faults, and generally provides the highest degree of protection for the turbine-generatoralthough it does permit a small overspeed and there is a slight probability of high overspeed.

2. Generator trip - opens the generator line breakers and removes excitation simultaneously, butleaves the turbine running near rated speed. Wheremaintaining speed is not harmful, this providesas high a degree of protection for the generator as a simultaneous trip (Type 1). If the plant canoperate following a full load rejection, and if the cause of the trip can be identified and rectifiedquickly, it may make resynchronization possible in a shorter time than Type 1. Since it doesresult in a higher overspeed than Type 1, it should only be used when there is an advantage in nottripping the turbine.

3. Breaker trip - trips all generator line breakers but not the excitation or the turbine. This trip hasadvantages similar to the generator trip when the fault permits excitation to remain applied. Itsadvantage over Type 2 is that it provides auxiliary power in cases where this cannot be switchedto another bus. If this is not an advantage, Types 2 or 1 should be used.

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4. Sequential trip - trips the turbine first. When the turbine inlet valve limit switches indicate thevalves are closed, and the recommended reverse power relay (or function) operates, normallyafter a three-second delay, the generator line breakers are tripped. Opening of the breakers thentrips excitation. This trip should prevent any overspeed and thus is preferred whenever the riskfrom a three-second delay in tripping the generator is slight. It is also preferred for most faultsin the turbine or steam generator. Its disadvantage is that certain multiple limit-switch failures,or a reverse power relay failure, would prevent completing the trip. Although this probability issmall, a second reverse power relay, with a 10 to 30 second time delay, connected to produce aType 1 simultaneous trip, is recommended as a back-up. This back-up relay also serves as theprimary protection for motoring which does not occur as part of a sequential trip.

5. Manual trip - turbine is tripped manually. When generator power reverses, reverse power relaytrips generator line breakers. Breaker opening trips excitation. This trip is recommended when-ever an operator sees the need for a fault trip and is not certain that a runback and trip (Type 6)will be fast enough. Note that Type 5 is actually a manually initiated sequential trip.

NOTE

There are no cases for which manually tripping the generator breakers is recom-mended. This is because the generator breakers should not normally be trippeduntil after the turbine has been tripped and power has reversed. Then the gener-ator breakers should be automatically tripped by the reverse power relay. A pro-tected bypass switch may be used to permit manually tripping the generator alonein case of limit-switch or reverse power relay failure. A manual generator breakertrip should only be used with full recognition of the risk involved.

6. Manual runback and trip - manually decreases turbine output to low level or to zero, followedby the turbine (sequential) trip. This is the “normal” trip, which is preferred for all normal shut-downs. It is also recommended for trips required by alarms when the operator judges a Type 5manual trip is not essential.

7. Automatic runback - reduces load (via turbine control) at a preset rate to a preset load. It isrecommended here only for loss of stator coolant (if required). It is an alternative to tripping theunit, and permits continuing on line at a very low load. When it can be used, it has the advantageof enabling earlier return to full load if the trouble can be quickly corrected.

8. Manual runback - manually reduces load at a rate and to a level determined by operator. This isuseful for some faults which may be load sensitive, such as local overheating, and where there isno need to trip immediately. It also allows the generator to continue to supply reactive power tothe system.

The recommendations in these instructions are intended to provide the best balanced protection forthe turbine-generator for generator faults. Unusual circumstances or other plant limitations must beconsidered by the owner, and may require different actions. Turbine problems should be handled inaccordance with applicable turbine instructions.

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VI. PROTECTION RECOMMENDATIONS

The remainder of this instruction book comprises discussions of, and detailed recommendations for, eachof the “faults” listed in the table of contents, and summarized in Table II.

References are listed at the end of the book.

A. Discussion and Recommendations for Generator Faults

1. Stator Overcurrent

1. Description

Generators are designed to operate continuously at rated kVA, frequency and power factorover a range of 95 to 105% of rated voltage. Operation beyond rated kVA may result inharmful stator overcurrent. Note that at rated kVA, 95% voltage, stator current will be 105%.This is permissible.

Normally, generator load is under the control of an operator. Situations can arise during sys-tem disturbances, such as accompanying generator or line tripouts, which can result in anovercurrent condition.

For short times, it is permissible to exceed the current corresponding to rated kVA. This ca-pability is specified in ANSI Standard C50.13 as follows:

Time (seconds) 10 30 60 120

Armature current (percent) 226 154 130 116

2. Detection

Stator current should be monitored by an operator, and kept within rated value by adjustmentof the turbine-generator controls.

A consequence of overcurrent is stator winding overheating, which should be detected bywinding temperature detectors, usually TCs measuring stator cooling water temperature,and/or RTD's in slots with the stator winding (if applicable). All functioning TCs andRTDs should be continuously monitored and alarmed (see Ref. 1, and 2&3 for H20 cooledmachines). However, even though it may not result in excessive stator winding temperatures,operating above specified currents is not an acceptable practice since unmonitored phe-nomena, such as temperatures in other parts of the stator circuit, winding forces, abnormalmagnetic fields, etc., may become excessive.

3. Recommendation

Automatic tripping is not provided for protection against stator overcurrent. However, alloperators should be made aware of the importance of operating the generator within its ratedcapability. In cases when a generator will operate in an unattended station, some form ofovercurrent (overload) protection should be provided. An alternative is stator overtempera-ture which provides similar protection. For additional information, see Ref. 1.

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2. Stator Ground Fault

1. Description

The generator stator neutral normally operates at a potential close to ground, generallythrough a high impedance grounding transformer/resistor. In some cases a reactor is usedin a resonant grounding arrangement. Should a phase winding or any equipment connectedto it fault to ground, the normally low neutral voltage could rise as high as line-to-neutralvoltage, depending on fault location.

Although a single ground fault will not necessarily cause immediate damage, the presence ofone increases the probability of a second. This is because the occurrence of such a fault isprobably the result of damage which is not confined to one spot. In fact, the existence of aground fault through tough, high-voltage insulation is usually a result of another, potentiallycatastrophic, trouble. A second fault, even if detected by differential relays, may cause seriousdamage. A second fault in the same phase will not be detected by differential relays, and couldcause serious damage as a result.

2. Detection

The usual method of detection is by a voltage relay across the grounding resistor. A currentrelay is sometimes used in place of a voltage relay or as a back-up. The relay should beinsensitive to third harmonic voltage, but should have as low a pick-up level at line frequencyas is practical to reduce the unprotected zone at the neutral end of the windings. Methodsare available which are designed to protect the entire winding. These schemes make use ofthe relationship of third harmonic voltages at the line and neutral terminals of the generator.These schemes supplement the fundamental frequency protection.

3. Recommendations

The grounding impedance should limit the ground fault current to less than 25 amperes. Theusual criterion based on circuit capacitance will normally result in less than 10 amperes. Thestator ground fault relay should be connected to trip the unit within several seconds, using asimultaneous trip, Type 1.

For further information, see Ref. 5.

3. Stator Phase-to-Phase Fault

1. Description

A stator phase-to-phase fault is any electrical fault between two phases of the armature wind-ing. This type of fault is very serious because very large currents can flow and produce largeamounts of damage to the winding if allowed to persist. Because of the nature of the con-struction of the armature it is very likely that this type of fault will grow to include ground,thereby causing significant damage to the stator core.

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2. Detection

It is possible to detect a phase-to-phase fault in the winding by means of a differential relay.This method provides protection for the entire winding, and its sensitivity is limited mainlyby the degree to which the various current transformers are matched.

The differential relay method cannot protect against a fault within one phase of the winding.Such a turn-to-turn fault can only be detected by the resulting armature current unbalance.However, such faults are rare and will usually include ground, in which case they will bedetected by the stator ground fault relay.

3. Recommendations

Upon detection of a phase-to-phase fault in the winding, it is imperative that the unit be trippedwithout delay, using a simultaneous (Type 1) trip.

4. Over-Voltage

1. Description

Permissible voltage limits under various operating conditions are given in the Generator Op-eration instructions (Ref. 1). It is normally an operator's responsibility to maintain voltage(and the corresponding kVA) within specified limits.

With turbine-generators it is unlikely that voltage will depart significantly from the presetvalue. If it does, due to a regulator failure or a system disturbance, a trip signal will usuallybe produced by one of the protective relays, such as volts/Hertz or maximum excitation limit.

2. Recommended Action

Therefore, specific over-voltage protection is generally not required for the generator. De-pending on the circumstances, it may be desirable to protect other equipment connected to thegenerator. For unmanned generating stations, consideration should by given to implementingautomatic overvoltage protection. For additional information, see Ref. 1.

5. Volts Per Hertz

1. Description

Per unit voltage divided by per unit frequency, commonly called volts/Hertz, is a readilymeasurable quantity that is proportional to flux in the generator and step-up transformer cores.

Moderate overfluxing (105%–110%) increases core loss, elevating core temperatures for allgenerator designs and armature temperatures for generators with conventionally cooled statorwindings. Long term operation at elevated temperatures can shorten the life of the statorinsulation systems. More severe overfluxing (above 110%) further increases core loss, andsaturates portions of the core to the point that flux flows out into adjacent structures. Theresulting induced voltages can be coupled to stator punchings due to the manner in whichcores are assembled and clamped. Severe overfluxing can breakdown interlaminar insulation,followed by rapid local core melting.

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Over-volts/Hertz can be caused by regulator failure, load rejection while under control of thedc regulator, or excessive excitation with the generator off line.

It can also result from decreasing speed while the ac regulator or the operator attempts tomaintain rated stator voltage.

2. Detection

Volts per Hertz is calculated in a static circuit incorporated in a volts/Hertz relay or sensor.Timing circuits are also incorporated. The volts/Hertz sensor is normally included as part ofthe excitation system.

3. Recommendation

Even though over-volts/Hertz is more likely to occur when off line, it can also occur when online. For this reason the volts/Hertz protection should be in operation whenever excitation isapplied.

Refer to Figure 1 for a graphical representation of the recommended V/Hz protection.

In view of the potential consequences it is prudent to provide as conservative protection aspossible consistent with security from false tripping. Selection of a modest maximum triplevel of above 118%, coupled with a 2 second time delay satisfies these objectives. A loadrejection from full rated KVA, rated power factor and 105% of rated voltage will not resultin tripping if an automatic voltage regulator is in service. Operation at 118% should be lim-ited not to exceed 45 seconds. The curve shape from 118 to 110% V/Hz approximates theoverexcitation capability of many transformers (for stepup and station service power applica-tions). However if the transformers require lower values, the protective relays should be setaccordingly. Continuous operation above 105% V/Hz is not sanctioned and an alarm func-tion should be provided to alert the operator that corrective action is needed. The excitationcontrol limiter (if applicable) should be set to prevent continuous operation above 109%.

The trip signal should produce a simultaneous trip, Type 1, or a generator trip, Type 2.

6. Field Overexcitation

1. Description

The generator field winding is designed to operate continuously at a current equal to thatrequired to produce rated kVA at rated conditions. In addition, higher currents are permittedfor short times, to permit field forcing during transient conditions. These limits are specifiedin terms of a curve of field voltage vs. time defined by the following points in ANSI StandardC50.13-1977:

Time (seconds) 10 30 60 120

Field voltage (percent) 208 146 125 112

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2. Detection

Most excitation systems now being furnished include a Maximum Excitation Limit function.Its purpose is to prevent prolonged field overcurrent by recalibrating the current regulator,transferring to another regulator, and, finally, producing a trip signal, as required.

3. Recommendation

The owner's responsibility with respect to this function is to see that the Maximum ExcitationLimit is properly adjusted and maintained, and properly connected to trip the unit when re-quired. Protection Type 4, sequential trip, or Type 1, simultaneous trip, is recommended. Forhigh response exciters, a Type 1 trip may be required to avoid rapid overheating of the fieldshould the exciter stay at ceiling for an extended period of time. In such cases a sequentialtrip would take too long.

Since loss of potential transformer signal to the voltage regulator is one cause of field overcur-rent, relaying to detect this situation and automatic transfer to another regulator is suggested.Sensing and transfer functions are part of most modern excitation systems.

7. Field Ground

1. Description

The generator field winding is electrically isolated from ground. Therefore the existence ofone ground fault in the winding will usually not damage the rotor. However, the presenceof two or more grounds in the winding will cause magnetic and thermal imbalances plus lo-calized heating and damage to the rotor forging or other metallic parts. Unfortunately, thepresence of the first ground fault makes detection of a second fault difficult, if not impossi-ble. In addition, modern rotor winding insulation systems have achieved a level of qualitythat reduces the likelihood of a field ground except under unusual circumstances where theprobability of occurrence of a second ground or other serious problem is high.

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Figure 1.

2. Detection

The relay necessary to detect a field ground is normally supplied with the excitation system.

3. Recommendation

It is recommended that the field ground detector be connected to produce a sequential trip,Type 4. Alternatively, a runback, Type 6, or simultaneous trip, Type 1, may be used.

8. Loss of Excitation

1. Description

Loss of excitation (or loss of field) results in loss of synchronism and operation of the gen-erator as an induction machine. This will result in the flow of slip frequency currents inthe rotor body, wedges, and amortisseur windings (if so equipped), as well as severe torqueoscillations in the rotor shaft. The rotor is not designed to sustain such currents, nor is theturbine-generator shaft designed to long withstand the alternating torques. The result can berotor overheating, coupling slippage and even rotor failure. The length of time before seriousdamage occurs depends on the generator load at the time of the incident, slip frequency, andwhether the field winding is open circuited or shorted, and may be a matter of seconds.

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A loss of excitation normally indicates a problemwith the excitation systemwhich, dependingon its nature, could be serious (e.g., collector ring flashover, if so equipped). Because of theVARs absorbed to make up for the low or lost excitation, some systems cannot tolerate thecontinued operation of a generator without excitation. Consequently, if the generator is notdisconnected immediately when it loses excitation, widespread instability may very quicklydevelop, and major system shut-down may occur.

2. Detection

Since loss of excitation results in a marked change in reactive kVA, a loss of excitation relayof the impedance or mho type is usually used (Ref. 6).

3. Recommendation

The generator should be tripped from the power system, using a simultaneous trip (Type 1),or a generator trip (Type 2). It is important that all excitation power be removed. It shouldnot be assumed that, since there is loss of excitation, the exciter is not supplying power to aninternal fault.

9. Unbalanced Armature Currents

1. Description

When the generator is supplying an unbalanced load, the phase currents and terminal volt-ages deviate from the ideal balanced relationship, and a negative phase sequence armaturecurrent (I2) is imposed on the generator. The negative sequence current in the armature wind-ing creates a magnetic flux wave in the air gap which rotates in opposition to the rotor atsynchronous speed. This flux induces currents in the rotor body iron, wedges, retaining ringsand amortisseur windings, if so equipped, at twice the line frequency. Heating occurs in theseareas and the resulting temperatures depend upon the level and duration of the unbalancedcurrents. Under some conditions, it is possible to reach temperatures at which the rotor ma-terials no longer contain the centrifugal forces imposed on them, resulting in serious damageto the turbine-generator set (Ref. 11).

There is always some low level unbalance in any power system and therefore limits on thecontinuous unbalance have been established. For currents above the permissible continuouslevels, a limit on the time-integral of I22 has been established for times up to 120 seconds.Such levels will often result from faults, open lines or breaker failures.

Unless otherwise specified by the manufacturer as part of the generator design data informa-tion, the negative sequence current limits are given in the applicable standards (Ref 31 or Ref32), where I2 is the per unit negative sequence current on the generator base and t is the timein seconds. See Ref 1 for further comments on unbalanced loading capability.

2. Detection

The protection scheme should be designed such that it will permit negative sequence currentsup to the continuous limit, but produce a trip signal if the level exceeds this value long enoughto reach the permissible I22t limit (Ref 13).

17


It is also desirable to alert an operator when I2 exceeds a normal level, which may be lowerthan the permissible continuous negative sequence current. This enables him to adjust loadin order to prevent a trip. Ref. 1 describes in more detail the actions an operator may take.

3. Recommendations

A negative sequence relay, similar to that described above, should be used on all units. Itshould be arranged to cause a breaker trip, Type 3, generator trip, Type 2, or a simultaneoustrip, Type 1.

10. Loss of Synchronism

1. Description

Loss of synchronism, also referred to as out-of-step operation or pole slipping, can occur asa result of steady-state transient or dynamic instability. It also may occur as a result of lossof excitation or synchronizing errors.

2. Detection

The majority of users do not apply specific loss-of-synchronization relaying. However, askilled relay engineer can adjust impedance relaying to reliably detect loss of synchronism.Loss of excitation relays may provide detection, but cannot be relied upon under all condi-tions. If the electrical center during loss of synchronism is in the transmission system, linerelays may detect it. If they do not, specific relaying should be provided.

3. Recommendation

Out-of-step operation can result in pulsating torques and winding stresses and high rotor ironcurrents that are potentially damaging to the generator. Excessive stator winding and coreend heating can also result if the out-of-step operation is caused by reduced or lost excitation.Therefore, it is recommended that the generator be separated from the system without delay,preferably during the first slip cycle (Ref. 14, 26, 27.). A breaker trip, Type 3, is recom-mended, and permits the fastest resynchronization after conditions have stabilized.

11. Abnormal Frequency Operation

1. Description

For a generator connected to a power system, abnormal frequency operation is a result ofa severe system disturbance. An isolated or unconnected unit could operate at low or highfrequency due to improper speed control adjustment or misoperation of the speed control.

There are two effects to be considered. The generator can tolerate underfrequency operationfor long periods, provided load and voltage are sufficiently reduced, as explained in GeneratorOperation instructions (Ref. 1).

The generator can also tolerate overfrequency operation provided voltage is within an accept-able range.

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2. Recommendation

For the generator, specific protection for abnormal frequency operation is not required. How-ever, the turbine is very sensitive to abnormal frequencies and recommendations given for itshould be carefully studied and followed (Ref. 24, 25). Detection of abnormal frequencyoperation may also be used to identify system problems.

Refer unusual frequency operation questions to the GE company for recommendations.

12. Breaker Failure

1. Description

Since most faults involving the generator require tripping of the generator/line breakers, fail-ure of any of them to open properly results in loss of protection and/or other problems, suchas motoring. If one or two poles of a generator line breaker fail to open, the result can be asingle-phase load on the generator and negative sequence currents on the rotor.

2. Detection

Both types of failure described above will cause conditions that may be detected by other pro-tective devices, e.g., reverse power, loss of synchronism or negative sequence relays. How-ever, a more direct method is the use of Breaker Failure Protection (BFP) which is energizedwhen the breaker trip is initiated. After a suitable time interval, if confirmation of breakertripping in all three lines is not received, a signal is generated.

3. Recommendation

Industry past practice has not always recognized the need for breaker failure protection be-cause of the reliability of line breakers. However, it is recommended that BFP be used withall tripping relays that can trip a generator line breaker. The BFP signal should trip all linebreakers that can feed current to the generator through the failed breaker (Ref. 15).

13. System Back-Up

1. Description

System back-up protection is also known as external fault back-up protection. As this nameimplies, it is used to protect the generator from supplying short circuit current to a fault in anadjacent system element because of a primary relaying failure (Ref. 15, 16).

2. Detection

Either voltage restrained or current restrained inverse-time overcurrent or distance relays maybe used, depending on the kind of relaying with which the back-up relays must be selective.Negative sequence relays, in addition to their primary protective role, are sometimes con-sidered for system back-up protection. However, these will not provide protection againstbalanced faults.

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3. Recommendation

System back-up protection is recommended. A breaker trip Type 3 is recommended, whichpermits the fastest resynchronization after the system fault has been cleared. In Steam tur-bines, if immediate resynchronization is not a priority, a type 1 trip may be considered to tripthe turbine, exciter and generator breaker simultaneously.

14. Voltage Surges

1. Description

Certain abnormal conditions could occur which might subject the generator to high voltagessurges. Among these are:

• Switching surges from circuit breakers at generator voltage

• Positive and negative surges arriving simultaneously on two phases

• Ineffective direct stroke shielding

• Failure of high side surge protective equipment

• Accidental connection between high and low side transformer windings, due to internalfailure, external flashover or other cause

The latter category is not a normal protective function of low voltage arrestors and would sub-ject them to excessive duty which could cause their failure. In view of the potential personnelhazard in the event of surge arrestor failure, the user should consider physically isolating thesurge arrestor cubicles and limiting access to them.

2. Recommendation

To provide protection for these and similar situations, surge arrestors are recommended for allunits. Surge capacitors are generally not required for machines with single-turn coils. Theyare provided on some packaged generators where optional installation of surge capacitorsclose to the surge arrestors would not be convenient. Application of LCI (load commutatedinverters) for turbine-generator starting may also obviate the use of surge capacitors on multi-turn coil machines.

Optimal protection requires surge protection be located in close proximity to the generatorterminals.

15. Transmission Line Switching

1. Description

The switching of transmission lines at or near generating stations for maintenance purposes,or simply restoring a line to service after a relayed tripout, are recognized as normal functionsin the course of operating a power system. In some cases these line switching operations cansubject nearby generating units to excessive duty. The effect on the generator in severe cases

20


is the same as for poor synchronizing in causing possible stator winding and shaft fatiguedamage (Ref. 7).

2. Detection

A measure of the severity of a switching event is the sudden step change in power (∆P) seenby the generator at the instant of switching. As a general guide, studies have shown that where∆P does not exceed 0.5 per unit on the generator kVA base the duty will be negligible (Ref.17, 18). Values of ∆P greater than 0.5 per unit may be determined to be non-harmful to thegenerator, for specific units and system switching events, but these cases should be carefullystudied and identified.

Predetermination of duties associated with line-switching operations and operating proce-dures which limit these duties to acceptable values can be found from simulating these op-erations, using a computer program such as that normally used for stability studies (Ref. 17,18).

3. Recommendation

The recommended procedure for avoiding excessive duty for the normal planned line-switch-ing operation is to establish, where necessary, operating procedures which limit the machine∆P to either the general 0.5 per unit level or an individually determined level for that unit.

As an adjunct to established operating procedures, phase angle check relays at key breakerlocations can prevent line closings under circumstances predetermined to be excessive. Note,however, that such check relays should not be applied without reliable means of overridingwhich would permit necessary line closing operations under emergency circumstances.

16. High Speed Reclosing

1. Description

High speed reclosing of transmission circuits directly out of generating stations or electricallyclose to the station may cause significant shaft fatigue damage to the turbine-generator unit,particularly where high speed reclosing following severe multi-phase faults is permitted (Ref.7, 19). The actual fatigue duty which a unit may experience during its lifetime from thiscause depends on many factors, including both the unit's and the system's characteristics, thefrequency of fault occurrence, etc. Studies substantiate that significant shaft damage couldoccur with unsuccessful reclosing for close-in three-phase faults.

2. Recommendation

In order to eliminate or reduce the potential effects of unrestricted high speed reclosing oflines near generating stations, an alternative reclosing practice such as one of the followingis recommended:

• Delayed reclosing, with a delay of 10 seconds or longer.

• Sequential reclosing, i.e., reclose initially only from the remote end of the line and blockclosing at the station if the fault persists. This is recommended only if the remote end ofthe line is not electrically near other turbine-generator units.

21


• Selective reclosing, i.e., high speed reclosing only for the less severe faults such as singleline-to-ground; delayed reclosing on others. Other relaying practices providing selectiv-ity on the basis of fault severity would also be effective in reducing shaft fatigue duty.

Where such alternative reclosing practices are not considered acceptable to the user, it isrecommended that either:

a. Detailed studies be performed to determine the probable lifetime fatigue damage whichmight be experienced for the reclosing practice contemplated, or

b. Torsional monitoring equipment be installed to determine the accumulated fatigue dam-age being incurred.

17. Subsynchronous Resonance (SSR)

1. Description

When a turbine-generator is connected to a transmission network that has series capacitorcompensation or a high voltage dc (HVDC) transmission system, it is possible to developsubsynchronous (under line frequency) current oscillations in the lines and in the genera-tor armature. In the case of series compensated ac systems, these currents interact with thesynchronously rotating flux to produce torque pulsation on the generator rotor. If these pul-sations are at a frequency close to one of the torsional natural frequencies of the turbine-gen-erator, high levels of torsional vibration can be induced in the shafts. Torsional instabilityof the turbine-generator shaft system has the potential for being extremely damaging to theturbine-generator shafts, and resulted in two shaft failures in the early 1970s. A more re-cently observed phenomenon involves interaction between torsional modes and HVDC con-trols (Ref. 28). This could lead to an unstable situation, resulting in spontaneous growth oftorsional vibrations and potential damage to the shaft.

2. Detection

Unstable or high levels of torsional vibration may be detected by observing the variations inangular velocity of the turbine-generator. A common measuring system involves a toothedwheel, a magnetic pickup and a frequency demodulator. Strain gauge telemetry systems havealso been utilized in short-term tests to detect shaft torsional oscillations. Indirect methodsof identifying subsynchronous resonance steady-state instability problems involve monitor-ing generator electrical terminal quantities. The armature current relay described in Ref. 20utilizes this approach.

3. Responsibility for Detection

It should be understood by those utilities that utilize series capacitor compensation, or haveHVDC transmission in their system, that the potential for damaging torsional vibrations is aconsequence of the special electrical characteristics of the transmission network. It is, there-fore, the owner's responsibility to implement devices to detect, and protect the machine from,the influences of subsynchronous torsional interaction. In the case of HVDC transmissionlines, the potential for interaction between the HVDC controls and the turbine-generator ro-tor system needs to be accounted for in HVDC control design. General Electric has workedclosely with many utilities on system studies to define the requirements for protective devices

22


on particular systems. The company has also manufactured and has in service protective de-vices. This equipment includes (Ref. 20):

a. A static subsynchronous resonance filter (static blocking filter)

b. A supplementary excitation damping control (excitation system damper)

c. A machine frequency relay (armature current frequency relay) (Ref. 21)

d. A torsional vibration monitor (Ref. 22)

In addition, generators that are applied for use in series capacitor compensated systems orsystems containing HVDC transmission are sometimes furnished with pole-face amortisseurwindings. The addition of pole-face amortisseur windings does not necessarily enhance neg-ative sequence capability. The function of amortisseur windings is to reduce the machineelectrical resistance in the subsynchronous frequency range, which reduces the potential fortorsional interaction at subsynchronous frequencies.

4. Recommendation

It is vital that the electric utility work closely with the manufacturer at the planning stage todefine the need for auxiliary equipment to protect the machine. This equipment, if required,needs to be operational when the machine is first connected to the network containing seriescapacitor compensated and/or HVDC transmission lines. It needs to be highly reliable, asmisoperation could result in major machine failure.

18. Inadvertent Energization

1. Description

When a generator is energized three-phase while at standstill or reduced speed, it will behaveand accelerate as an induction motor. The equivalent machine impedance during the highslip interval can be represented by negative sequence reactance (X2) in series with negativesequence resistance (R2). The machine terminal voltage and current during this interval willbe a function of generator, transformer and system impedances. If the generator-transformeris connected to an infinite system, the machine currents will be high (several per unit), andconversely, if the unit is connected to a weak system, the machine current could be low (1–2per unit). During the period the machine is accelerating, high currents will be induced in therotor and the time to damage may be on the order of a few seconds.

NOTE

Negative sequence reactance of a steam turbine-generator is approximately equalto the subtransient reactance X"dv.

A number of generators have been accidentally energizedwhile at standstill or very low speed.While many have survived the experience with minor damage, others have not.

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2. Detection

While there are several generator zone relays that may detect this contingency, their perfor-mance may be marginal. Therefore, the preferred approach is to provide detection meansspecifically designed for this purpose.

One such method is to use overcurrent relays that are armed by a speed relay when the gen-erator is off line.

3. Recommendation

It is recommended that the detection scheme described above be used to protect every gen-erator. To prevent damage to the rotor, stator bearings, etc., it is desirable that high speedprotection be provided for this contingency. The relaying should be connected to trip themain generator breaker, trip any breakers which could feed current to the generator if breakerfailure is detected, and be so implemented that it is never taken out of service when the unitis shut down for any purpose, even with the rotor removed.

19. Bearing Vibration

1. Description

High vibration (as defined below) on a generator is a symptom of a problem. There are manypossible causes of vibration, including:

• Unbalance

• Misalignment

• Thermal sensitivity

• Damaged bearings

• Oil whip

• Rubbing

• Bent overhangs

• Out-of-round journals or collectors

• Stiffness dissymmetry.

2. Detection

All bearings are normally provided with vibration detectors and recorders. Either velocityprobes, proximity probes, or both are used. These permit recording and monitoring of vi-bration, and alarming and/or tripping at predetermined levels of vibration. The vibrationrecorders do not provide the frequency spectrum information which could be useful in deter-mining the cause of the vibration. This information must be obtained with a portable vibrationanalyzer.

24


3. Recommendation

For both generator and alternator bearings provided with proximity probes, the table belowsummarizes recommendations for various levels of shaft vibration. The vibration levels aregiven in mils [µm], peak-to-peak, unfiltered.

For Vibration Level Exceeding

2 Poles 4 Poles

(mils) (µm) (mils) (µm)

Recommendations

10 254 12 305 Sequential trip (Type 4)

7 178 10 254 Runback and trip within 15 minutes(Type 6)

6 152 8 203 Correct at first opportunity

3 76 5 127 Correct when convenient

For generators provided with velocity probes which monitor endshield or pedestal deflectionin the vicinity of the bearing, the alarm level is 0.5 in/sec, and the trip level is 1 in/sec.

4. Reference

For more detailed information on vibration, refer to the turbine section of the instruction book(Ref. 24).

20. Synchronizing Errors

1. Description

Improper synchronizing of units to the line may occur for a number of reasons. The mostsevere of these results from incorrect connection of potential transformer or synchronizingaids such that gross out-of-phase synchronizing, such as a 120° error, may occur. A failure ofautomatic synchronizing equipment may also result in large synchronizing errors. While tur-bine-generators are designed to withstand these rare occurrences without catastrophic results,provided stator current does not exceed the three-phase short circuit value, they can result indamage, such as slipped couplings, with resulting high vibration, loosened stator windings,and fatigue damage to the shaft and other mechanical parts (Ref. 7).

Careless synchronizing, while generally a less severe incident, may, on an accumulated basis,have the same result.

The following synchronizing limits are recommended to avoid damaging effects:

• Breaker closing within ± 10° (electrical angle)

• Voltage matching within 0 to +5%

• Slip slower than 10 seconds per slip cycle for manual synchronization.

• Slip slower than 6 seconds per slip cycle for automatic synchronization.

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2. Detection

A severe out-of-phase synchronizing incident will be evident from the physical effects ofnoise and turbine-generator foundation vibration. In addition, a tripout may result from thevibration trips or from electrical protective relays. Poor synchronizing routine is less evi-dent but would be observable by the synchroscope and an oscillation of electrical quantities(power, VARs) subsequent to the synchronizing.

3. Recommendations

Careful checking of circuits during initial installation or equipment changeout and the estab-lishment of well-adhered-to procedures for manual synchronizing are key elements in mini-mizing out-of-phase synchronizing incidents.

A Synch Check function should monitor manual synchronizing to prevent large errors (Ref.8).

Automatic synchronizing relays can provide very high accuracy. Where such relays are used,however, it is important that a check function be applied to provide an independent back-up.Failure of the primary relays to perform should be alarmed, since this might otherwise not benoticed.

21. Motoring

1. Description

Motoring of a generator will occur when turbine output is reduced such that it develops lessthan no-load losses while the generator is still on line. Assuming excitation is sufficient,the generator will operate as a synchronous motor driving the turbine. The generator willnot be harmed by synchronous motoring, but, if it occurs as a result of failure to complete asequential trip, protection for the fault originating that trip is lost. In addition, a steam turbinecan be harmed through overheating during synchronous motoring.

If field excitation is lost, along with turbine output, the generator will run as an inductionmotor, driving the turbine. In addition to possible harm to the turbine, this will produce slip-frequency currents in the rotor and could cause it to overheat if continued long enough.

A third type of motoring occurs when the generator is accidentally energized when at lowspeed. This is discussed separately under “Accidental Energization”.

2. Detection

Motoring following loss of turbine output can be detected with a reverse power relay. Toavoid false trips due to power swings, a time-delay pick-up of 10 to 30 seconds is suggested.This is the backup relay suggested in the description of Trip 4 - sequential trip. Measurementof very low power levels at very low power factors will require relatively high precision. Re-duction in reactive power flow in the generator will reduce the requirement for high precision.This may be accomplished through control action of the excitation system or by operator ac-tion.

26


3. Recommendation

It is recommended that the reverse power relay referred to above be used and connected toproduce a Type 1, simultaneous trip. Alternatively, a Type 2 generator trip or Type 3 breakertrip could be used. Breaker Failure Protection (see page 23) should be initiated, since linebreaker failure may be the cause of the motoring. In addition, the turbine section of the in-struction book (Ref. 9) should be consulted and followed.

22. Stator Overtemperature

1. Description

Stator overheating may result from overcurrent operation, improper gas pressure or purity (ifapplicable), gas or water cooling system malfunction, internal cooling passage blockage, etc.

2. Detection

Armature bar temperatures are monitored by either TCs measuring stator cooling water tem-perature and/or RTD's in the stator slots (if applicable). All functioning RTDs and TCs shouldbe constantly monitored and alarmed (see Ref 1, and 2&3 for H20 cooled machines). Aspointed out in the stator overcurrent section, these temperature detectors do not provide com-plete protection against damage due to overcurrent operation, because temperatures in otherparts of the winding, winding forces, abnormal magnetic fields, etc. may become excessive.

3. Recommendation

Automatic shutdown is not always provided for protection against stator overheating on gen-erators with conventionally cooled stator windings. Section 26 describes automatic protectionrecommended for liquid cooled armature windings. All operators should be made aware ofthe importance of operating the generator within its rated capability. In cases where a gen-erator will operate in an unattended station, some form of overtemperature protection shouldbe provided. Implementation of an automatic stator overtemperature protection scheme alsoprovides some overcurrent protection, and is generally easier to implement than overcurrentrelaying.

23. Loss of Coolant to Gas Coolers (if applicable)

1. Description

Serious overheating of all generator components will occur if coolant flow to the gas coolersis lost. Various machine temperature alarms will detect the overheating condition prior toany damaging overtemperatures. However, without human monitoring and intervention, thecondition will persist.

2. Detection

The RTD's monitoring the hot and cold gas temperatures may be used as the basis for estab-lishing protection against the loss of gas coolant. Refer to Table 1 for Alarm information.

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3. Recommendation

For machines which run unattended, consideration should be given to implementing an auto-matic runback (trip 6) or trip 4 (sequential trip), based on the cold and hot gas RTD's.

24. Reduced Seal Oil Pressure (if applicable)

1. Description

A floating, radial ring-type seal is used to prevent hydrogen leakage from the generator alongthe shaft. Oil is supplied to the seals at a pressure slightly higher than that of the hydrogen inthe generator.

For large, liquid cooled generators, the oil is supplied by a seal oil pumping unit. The mainpump is driven by an ac motor. An emergency back-up pump is driven by a dc motor. Thispump will start automatically if the oil discharge pressure of the main pump decreases or ifac power is lost. In addition to the main and emergency pumps, bearing header pressure isavailable to maintain hydrogen pressure in the generator at a maximum of approximately 8psig or 5 psid less than the available bearing header pressure, whichever is lower.

For most conventionally cooled hydrogen generators, seal oil is supplied from the lube oiltank by the same pump supplying bearing oil. The main pump is driven by an ac motor. Anemergency lube oil back-up pump is driven by a dc motor. This pump will start automaticallyif the seal oil differential pressure decreases or if ac power is lost. Some machines are pro-vided with a specific DC seal oil emergency backup pump in addition to the lube oil backuppump. Higher pressure (greater than 30 psig) conventionally cooled machines are providedwith separate seal oil pumps. See Ref. 10 for details on the seal oil system provided.

2. Detection

Alarms indicate low differential seal oil pressure, main pumpmotor overload, and emergencypump running (see Table 1).

3. Recommendation

If the main pump is lost an operator should take immediate action to determine the cause.If the problem requires more than a few hours to correct, gas pressure should be reduced tothe lowest value required for the generator load, as determined from the reactive capabilitycurves. This procedure is recommended because the emergency pump has only the bearingheader pressure as back-up on liquid cooled machines, and no additional backup is providedon conventionally cooled generators. Careful consideration of the DC supply capacity andthe purge cycle time is required to decide how long it is safe operate on the backup DC pump.If this gas pressure cannot be maintained, additional reductions in both gas pressure and loadwill be required. Operation for long periods with the emergency pump or the bearing headersupply only will result in a reduction of hydrogen purity. For most generators under these con-ditions, gas must be scavenged from the generator to maintain hydrogen purity as describedin Ref. 4. Some conventionally cooled machines will automatically increase the scavengegas rate in an attempt to maintain purity. Again, see Ref. 4 for details.

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25. Local Overheating (if applicable)

1. Description

Before synchronization, there are at least two areas of possible overheating in the generatorwhich are a function of field excitation:

• Stator core heating, which is related to the stator flux (volts/Hertz).

• Generator field heating, which is related to field current.

After synchronization, in addition to these two, there is also the possibility of stator windingheating (including end windings, connection rings, leads, and high voltage bushings), whichis related to armature current.

Local overheating can be caused in a number of ways. One is damage to the laminations atthe inner diameter of the stator core. This might cause electrical contact between laminationsleading to a flow of current and therefore heating. This type of damage may be caused by aforeign object striking the core under the influence of electromagnetic forces in the machine.Overheating may also be caused by improper cooling or by faulty or damaged insulation,allowing excessive leakage current to flow. It can also be caused by operating outside thecapability limits, especially in underexcited regions.

2. Detection

On hydrogen-cooled steam turbine-generators, overheating can be detected by the use of theGenerator Gas Monitoring System (GGMS). The GGMS consists of a generator Core Moni-tor, a Signal Validation Control and a Pyrolysate Collector. The generator Core Monitor is anionization-type particulate detector that is connected to the generator so that a constant flowof cooling gas passes through it. The cooling gas is monitored for the presence of submicronparticles (particulates). Under normal conditions, the gas coolant contains no particulatesthat can be detected by the monitor. When overheating occurs, the thermal decomposition oforganic material, epoxy paint, core lamination enamel or other insulating materials producesa large number of particulates which can be detected by the monitor to produce an alarm. Theparticulates can be collected by the Pyrolysate Collector which is designed to operate whena generator Core Monitor alarm occurs. Confirmation of overheating may be accomplishedby laboratory analysis of the particulates.

The Validation Control is used to automatically discriminate between a Core Monitor alarmcaused by an instrument malfunction and one caused by local overheating. When the alarmis verified, the Validation Control actuates a machine heating alarm.

3. Recommendation

When a machine heating alarm occurs, load should be reduced by manual runback (Type8) until the alarm signal clears. If the alarm signal does not clear within five minutes thegenerator should be tripped manually (Type 5).

Contacts are provided in the Validation Control which can be used to actuate runback or tripcircuits if this feature is desired.

29


Additional information may be found in specific Generator Gas Monitoring System publica-tions in the Operation and Maintenance Manual (O&M Manual).

26. Loss of Stator Coolant (if applicable)

1. Description

Stator winding cooling water is supplied by one of two identical pumps. The pump not run-ning is in a standby mode and is connected to start automatically if the discharge pressure ofthe operating pump falls.

Cooling flow may be reduced or lost because of:

a. System restrictions such as plugged filters or strainer, or a buildup of material such ascopper oxide in the stator winding strands

b. Localized restriction in a single bar or group of bars in the winding

c. Pipe break

d. Loss of pumps

e. Misadjustment of the control valve

f. Control valve failure

g. Freeze-up of the system or instrument lines containing moisture

2. Detection

a. System restrictions downstream of the control valve sensing point will be signaled by thelow flow alarm. System restrictions upstream of the sensing point will be compensatedfor by the control valve. If the limits of control valve operation are reached, a restrictionwill be signalled by the low pressure and low flow alarms. A high differential pressurewill occur across the component containing the restriction, and the most likely place forthis is the main filter. On newer units, filter pressure is monitored by a differential pres-sure alarm. System restrictions can also be signalled by the bulk water outlet temperaturesensor which provides an alarm function, and by the individual liquid header outlet TCsand slot RTDs.

b. Localized restrictions in a single bar or group of bars might be detected by the individualliquid header outlet TCs and the slot RTDs.

c. A pipe break will be detected by a rise in the bulk outlet temperature and the individualliquid heater TCs, or by the low pressure alarm and a temperature rise indicated by theslot RTDs.

d. Loss of both pumps will be detected by low pressure and low flow alarms and by a tem-perature rise signalled by all of the slot RTDs.

30


e. Misadjustment of the control valve, which causes a flow restriction, will be detected bylow pressure, low flow, and high bulk outlet temperature alarms. The individual outletTCs and slot RTDs will also be affected.

f. Control valve failure is likely to cause higher flow than required. There are no alarms todetect this, but the situation will, in time, be apparent to an operator when higher thannormal flows and pressures are observed.

g. Freezing temperatures in the station are particularly dangerous because some of the pro-tective devices may freeze and either fail to operate or operate incorrectly. The generatorshould not be operated above its no-liquid capability when station temperatures are be-low freezing unless provisions are made to protect vital parts of the system from the lowtemperature.

3. Recommendation

Most serious faults will initiate an alarm. These are listed in Table 1. Appropriate operatoraction should be taken at the time of the alarm (Ref. 2, 3). The nature of the problem dictatesthe action required, as discussed below.

Abnormal temperatures in the stator require that a check be made of the cooling flow. If apumping unit abnormality is not apparent, a local restriction in the stator winding may bethe cause. Temperature limits are outlined in the generator instruction book (Tab 30). Loadreduction may be necessary to prevent exceeding limits.

Problems with the cooling system should be corrected at the time of the alarm. If they arenot, and the condition (flow, pressure, etc.) becomes more abnormal, a second contact willoperate. This should be used to initiate either a runback or a trip, as selected by the ownerduring the design stage. If tripping was selected, a sequential trip, Type 4, may be used.Operators should be advised, however, not to wait for automatic protection to operate but totake corrective action immediately. This is the reason for the alarm.

If runback, rather than trip, was selected, but the runback fails to occur, a trip signal will beproduced.

In many cases a load reduction to the no-liquid capability of the generator is required beforemaintenance can be performed, such as adjustment of the control valve, changing filters orcalibrating sensors. These tasks should be performed periodically as recommended in theapplicable instruction (Tab 33 of Generator Instruction Book).

27. High Water Conductivity (if applicable)

1. Description

High purity water is required to cool the stator winding conductors safely. The water purityis maintained by fine filtration and a deionizer. A reduction in deionizer resin capacity willresult in an increase in water conductivity.

31


2. Detection

Water conductivity is continuously monitored at both inlet and outlet of the stator. A conduc-tivity above 0.5 µmhos/cm [0.5 µS/cm] will initiate an alarm. A second alarm will registerwhen conductivity rises to 9.9 µmhos/cm [9.9 µS/cm].

3. Recommendation

The operator should replace the deionizer resin after the first alarm at 0.5 µmhos/cm [0.5µS/cm], and before the second alarm. The unit should not be operated with water conductivityabove the second alarm point, which is 9.9 µmhos/cm [9.9 µS/cm]. If this alarm sounds, theunit should be removed from service, using manual runback and trip (Type 6).

Ta ble 2 . SUMMA RY OF GEN ERATO R PR OT ECTI ON REC OMME NDAT IONS

Fault Type Recommendation Page

Electrical Faults

Stator overcurrentStator ground faultStator phase-to-phase faultOver-voltageOver-volts/HertzField overexcitationField groundLoss Of excitation

Runback 8 or 7Trip 1Trip 1Restore normal voltage 13Trip 1 (or 2)Trip 4Trip 4 (or 6)Trip 1 (or 2)

1111121313141416

System Faults

Unbalanced armature currentsLoss of synchronismAbnormal frequencyoperationBreaker failureSystem Back-upVoltage surges

Trip 3Trip 3See Turbine InstructionsUse Breaker FailureProtectionTrip 3Use surge arrestors

171718181919

System Operations

Transmission line switchingHigh speed reclosingSubsynchronous resonanceInadvertent energization

Limit magnitude of powerstepSee detailed recommendationsSee detailed recommendationsSee detailed recommendations

20212122

Mechanical or ThermalFaults

32


Fault Type Recommendation Page

Bearing vibrationSynchronizing errorsMotoringStator OvertemperatureLoss coolant to gas coolersReduced seal oil pressureLocal OverheatingLoss of stator coolantHigh water conductivity

Trip 4Use check relaysTrip 1 (or 2 or 3)Aarm (Trip 6 or 4)Trip 6 (or 4)Reduce H2 pressure & loadRunback 8(or 7) or Trip 5Runback 7 or Trip 4Trip 6

232425262627282930

Protective Actions Key

1 Simultaneous trip2 Generator trip3 Breaker trip4 Sequential trip5 Manual trip6 Manual Runback and trip7 Automatic runback8 Manual runback

This table does not purport to summarize all the descriptive material contained in thereferenced pages. These must be read and understood when using this summary.

REFERENC ES

1. Generator Tab in O&M Manual.

2. “Operator Action on High Temperature Alarms,” Generator Section o f O &M Manual.

3. “Operator Action on Low Flow and Low Pressure A larms,” G enera tor Se ction of O &M Ma nual.

4. “Gas Control Sys tem,” Generator Se ction of O&M Manual.

5. Brow n, P.G., J ohnson, I.B. a nd Stevenson, J.R., “Generator Neutral Grounding,” IEEE Trans.,Vol. PAS-97, No. 3, 1978, pp. 683–694.

6. Berdy, J., “Loss of Excitation Protection for Modern Sync hronous Generators,” IEEE Trans.,Vol. PAS-94, 1975, pp. 1457–1463; available as G E Publication GER 3183.

7. B row n, P.G. and Q ua y, R., “Transmiss ion Li ne Reclosing - Turbine-Generator D uties andStability Considerations,” Texas A&M Relay Conference, April 1976.

8. Winick, K enneth, “Relay Supervision of Manual Synchronizing,” available as GE PublicationGER 2624.

9. “Sequential Tripping and Prevention of Motoring,” Turbine section of O &M Manual.

10. “Shaft Sealing System,” Generator Se ction o f O &M Manual.

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11 . Linkinhoker, C .L., Schmitt, N. and Winchester, R.L., “ Influence of Unbalanced Currents o nthe Design and Operation of Large Tu rbine-Generators,” IEEE Trans., Vol. PAS-92, 1973,pp. 1597–1604; available as GE Publication GER 2874.

12. ANSI Std. C 50.13-1977, Sections 6.3 and 6.5.

13 . Gra ha m , P. J., Bro wn , P.G . an d Wi nc he ster, R.L., “ Gen era t or Prote ctio n with Ne w S ta tic N eg -ative Sequence Relays,” IEEE Trans., Vol. PAS-94, 1974, pp. 1208–1223.

14 . Work i n g G r ou p Re po r t, “O ut of Ste p Rela yin g for Gen er ato r s,” I EEE Tr a ns . , Vol. PA S -96 ,No. 5, 1977, pp. 1556–1564.

15. IEEE Committee Report, “Local Back-up R elaying Protection,” I EEE Trans., Vol. PAS-89,No. 6, 1970, pp. 1061–1608.

16 . Hoffman, D .C ., “Back-up Protection for System Faults at the Gene rator,” Ge neral E lectricReview, February 1950.

17. Walker, D.N., Adams, S.L. and Plac ae k, R.J. , “Torsional Vibration a nd Fatigue of Tu rbine-Generator Shafts,” IEEE Powe r Engineering Society 1978 IEEE/ASME/ASCE Joint PowerGe ne ratio n Co nfe ren ce ; D i ge st Sta t e o f th e Art S ym p os i um , Tu r bin e-G en era t or Sha f t Tor-siona l s.

18. IEEE Wo rking Group of the Subsynchronous Ma chine Committee, “Steady State Switchin gGuide . ”

19. Joyce, J.S. a nd La mbrec ht, D., “Sta tus of Evaluating the Fatigue of Larg e Steam Tur-bine -Genera tor s Ca us ed by E le ctrica l Disturbance s,” IEEE Powe r Enginee ring Society 1 978IEEE/ASME/ASC E J oint Power Generator Conference; Digest State of the Art Symposium,Turbine-Generator Shaft To rsionals.

20. “Counter-measures to Subsynchronous Resonanc e Problems,” IEEE Subsynchronous Res-onance Working G roup of the System D ynamic Performance Subcommittee; IEEE Trans.,Vol. PAS-99, N o. 5, 1980, pp. 1810–1818.

21. Bowler, C.E.J., et a l., “ The Navajo SMF Ty pe SSR Relay,” IEEE Trans., Vol. PAS-97, No.5, 1978, pp. 1489–1495.

22. Farmer, R.G., et. a l., “N avajo Proje ct Report o n SSR Analysis and Solution,” IEEE Trans.,Vol. PAS-96, N o. 1, 1977, pp. 1226–1232.

23. “R esis tance Te mpe rature Dete ctors” p ub lication, Generator Section of O&M Manual.

24. “Starting a nd Loading,” publication, Tu rbine section o f O&M Manual.

25 . S m ah a, D.W., R ow l an d, C . R. a nd P op e , J.W. , “Coordination of Load Conservation with Tur-bine-Generator Underfrequency Protection,” IEEE Trans., Vol. PAS-99, No. 3, 1 980, pp.1137–1150.

26 . Be rdy, J., “O ut-o f-Ste p P ro tec tio n for G en erators,” available as G E Publication GER 3179.

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27. Berdy, J., “Application o f O ut-of-Step Block ing and Tripping Relays,” available a s GE Pub-lication G ER 3180.

28. Piwko, R.J. and Larsen, E.V., “HVDC System Control for Damping of Subsynchronous Os-cillations,” IEEE Paper N o. 81-TD660-0 (presented September 1981 at IEEE Transmissionand Distribution Conference).

29. ANSI/IEEE C37-101 IEEE Guide for Gene rator G roun d Protection.

30. ANSI/IEEE C37-102 IEEE Guide for AC Generator Protection.

31. CEI/IEC standard 34-3 Rotating Electrical Machine s - Specific requirements for turbine-typesynchronous machines.

32. ANSI C 50 .13 Requirements for Cylindrical Rotor Synchronous Gene rator.

GERs are G eneral Electric Company publications which may be obtained through the near-est GE Sales Office.

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GE Energy

General Electric Companywww.gepower.com

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