gen protection

GE Power SystemsGenerator

Revised, December 2001GEK 75512H

These instructions do not purport to cover all details or variations in equipment nor to provide for every possiblecontingency to be met in connection with installation, operation or maintenance. Should further information be desired orshould particular problems arise which are not covered sufficiently for the purchaser’s purposes the matter should bereferred to the GE Company. 2001 GENERAL ELECTRIC COMPANY

Generator Protection

GEK 75512H Generator Protection

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TABLE OF CONTENTS

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

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

III. ALARMS 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Table I – Alarms 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

IV. PROTECTION WHEN GENERATOR IS OFF LINE 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

VI. PROTECTION RECOMMENDATIONS 10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A. Discussion and Recommendations for Generator Faults 11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1. Stator Overcurrent 11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2. Stator ground fault 11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3. Stator phase–to–phase fault 12. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4. Overvoltage 13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5. Volts per Hz 13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6. Field Overexcitation 14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7. Field Ground 14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8. Loss of Excitation 16. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9. Unbalanced armature currents 17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

10. Loss of synchronism 17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11. Abnormal frequency operation 18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12. Breaker failure 18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13. System backup 19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14. Voltage Surge 19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15. Transmission line switching 20. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16. High speed reclosing 21. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17. Subsynchronous resonance 21. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18. Inadvertent energization 22. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19. Bearing vibration 23. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Synchronizing errors 24. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21. Motoring 25. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22. Stator Overtemperature 26. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23. Loss of coolant to gas coolers 26. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24. Reduced seal oil pressure 27. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25. Local overheating 28. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26. Loss of stator coolant 29. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27. High water conductivity 30. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLE II – SUMMARY OF PROTECTION RECOMMENDATIONS 32. . . . . . . . . . . . . . . . . . . .

REFERENCES 33. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Generator Protection GEK 75512H

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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 not appli-cable to air cooled machines. The alarm and protection sections are sequenced so that recommendationswhich are generally applicable appear first, ones related to hydrogen systems next, and finally stator watercooling system alarms and protection. Recommendations for excitation system protection are not included,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 C50.10 General Requirements for Synchronous Machines

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

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

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

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

6. CEI/IEC 34-3 Rotating 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 of rea-sons. 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 considerationbe given to providing back-up protection for those faults where a device failure could subject the genera-tor to serious damage.

Generator protection is a large and complex subject. These instructions were written to provide informa-tion 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 recommendations.Such modifications will usually be communicated to all owners of affected turbine-generators throughGeneral Electric, Industrial and Power Systems, Technical Information Letter (TIL) series. These modi-fications will be incorporated in periodic revisions to these instructions.

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 connectall protective 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 generator op-eration that are mainly under control of an operator and/or electronic turbine-generator controller. Bothof these publications should be consulted during plant design and should be used in conjunction withother 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 relays thereare other relays or devices that initiate only an alarm or data logging. In these cases it becomes an opera-tor’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 Temperature De-tectors (RTDs) and Thermocouples (TCs). Some measure other variables such as hydrogen pressure and pu-rity, and stator cooling water pressure, flow and conductivity (if applicable). A typical list of alarm devicesfurnished with the generator is given in Table I, including recommended alarm points and signal ranges. Ifadditional special instrumentation is supplied, alarm settings will be specified in the appropriate section ofthe instruction book.

Table I 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 not rep-resent the actual capabilities of the generator or its auxiliary equipment and should not be used in any wayas 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 and cor-rected 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 while offline.

For this reason, it is recommended that, as a general rule, all alarms and protections be kept operative at alltimes. Exceptions to this rule are those protections which would mis-operate or give false signals when theunit is below rated speed, not excited, or not synchronized. Relaying and interlocking circuitry that operateswhen the unit is off line should be reviewed to make certain it does not inadvertently incapacitate any essen-tial protection.


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TABLE I – ALARMS

SIGNAL DEVICE RANGE SETTING NOTES

MACHINE TEMPERATURES

COLL./EXCITER AIR INCOLL./EXCITER AIR OUTGENERATOR FIELD

STATOR COIL (SLOT)

RTD OR TC

TRANSDUCER

RTD

–30 to 70oC–20 to 80oC0 to 150oC

0–100°C for H2O0–150oC for H2 and Air

45°CIN + 20°C*

*

*

In: Check FiltersOut: Check Ventilation

Reduce field currentby adj. MVAR load.

See Ref. 2

OTHER ALARMS

BEARING VIBRATION

BEARING OIL TEMP HIGH

NEGATIVE SEQUENCE CURRENT

GENERATOR OVERVOLTAGE

VIBRATIONDETECTOR-

RELAY

RELAY

---

---

---

---

---

---

---

Over 1.05 pu voltage

See Recommendationin this publication.See Turbine Section ofInstruction BookBalance or reduceload. SeeRecommendation for“UnbalancedArmature Currents.”Reduce machinevoltage.

AIR COOLING (if applicable)COLD AIR HOT AIR

RTDRTD

–30 to 70oC–10 to 90oC

**

LOCAL OVERHEATING(if applicable)

CORE MONITOR LEVEL(if applicable)MACHINE HEATING(if applicable)

CORE MONITOR

SIGNAL VALIDA-TION DEVICE

---

---

---

---

See Recommend. for“Local Overheating.”See Recommend. for“Local Overheating.”

*See applicable data sheet in generator section of Instruction Book.�Two switches@From operating pressure


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TABLE I – ALARMS (Cont’d)


SEAL OIL SYSTEM (if applic.)

DIFF SEAL OIL PRESSURELOW

DRAIN ENLARGEMENTLIQUID DETECTOR FULL

EMERGENCY PUMP RUNNING

FILTER DIFF. PRESSUREHIGH (if applicable)

VACUUM TANK OIL LEVELHIGH/LOW (if applicable)

MAIN PUMP MOTOROVERLOAD (if applicable)

EMERGENCY PUMP MOTOROVERLOAD (if applicable)

DIFF. PRESSURESWITCH

LIQUID LEVELDETECTOR

RELAY

DIFF. PRESSURESWITCH

FLOAT SWITCH

THERMOSTAT

THERMOSTAT

---

---

---*

---

---

---

3 psid[20.7 kPa][211 g/cm2]

10 psid[69 kPa (differential)][703 g/cm2 (diff.)]

+4/–6 in[+102/–152 mm]

See Ref. 3

See Ref. 3

See Ref. 3

See Ref. 3

See Ref. 3

See Ref. 2

See Ref 2

HYDROGEN GAS SYSTEM

COOLER HOT GAS TEMPHIGHCOOLER COLD GAS TEMPHIGH/LOWCOMMON COLD GAS TEMPHIGH (if applicable)MACHINE GAS TEMP HIGHMACHINE GAS PRESSUREHIGH/LOW

MACHINE GAS PURITY LOW

GENERATOR CASING LIQUIDDETECTOR FULL

RTD or TC

RTD or TC

RTD

METER RELAYPRESSURESWITCH

METER RELAY orTRANSMITTERLIQUIDDETECTOR

0–100°C

0–70°C

0–70°C

0–100°C---

50–100%0–100%---

*

*

*

*+4/–2 psi @[+27.6/–13.8 kPa][+281/–14.1 g/cm2]90%

See Ref. 4See Ref. 4

See Ref. 4

See Ref. 4



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TABLE I – ALARMS (Cont’d)


STATOR COOLING WATERSYSTEM (if applicable)

INLET TEMP HIGHINLET FLOW LOWINLET PRESSURE LOW

LIQUID HEADER OUTLETTEMP HIGHBULK WATER OUTLET TEMPHIGHCONN RING TEMP HIGH (if separately cooled)CONN RING FLOW LOW(if separately cooled)HV BUSHING OUTLET TEMPHIGHHV BUSHING FLOW LOW

MAIN FILTER DIFF PRESSUREHIGH

CONDUCTIVITY HIGH

TANK LEVEL HIGH/LOW

RESERVE PUMP RUNNING

RUNBACK INITIATED

RTD or TCFLOW SWITCHPRESSURESWITCHTC

RTD

TC

FLOWMETER

TC

FLOWMETER

DIFF PRESSURESWITCH

TRANSDUCER

FLOAT SWITCH

PRESSURESWITCH

RELAY

0–70°C**

0–100°C

0–100°C

0–100°C

*

0–100°C

*

0–15 psid[0–103 kPa (differential)][0–1.05 kg/cm2 (diff.)]

0–10 µmho/cm[0–10 µS/cm]

---

0–150 psi[0–1.03 MPa][0–10.5 kg/cm2]

NONE

2°C OVER MAX.**

*

*

*

*

*

3 gpm LOW[189 ml/s]8 psid[55 kPa (differential)][562 g/cm2(diff.)]

0.5 & 9.9 µmho/cm[0.5 & 9.9 µS/cm]

+4/–4 inches[+102/–102 mm]10 & 20� psi belownormal [69 & 138kPa][0.7 & 1.41kg/cm2]PRESET

See Ref. 2See Ref. 3See Ref. 3

See Ref. 3

See Ref. 2

See Ref. 2

See Ref. 3

See Ref. 2

See Ref. 3

Change filter before 7psid [48 kPa (diff.)][492 g/cm2 (diff.)]

Change resin on firstalarm. Trip manuallyon second alarmCheck main pump

Check cause andcorrect



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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., disconnected fromthe system or shut down. Some of the factors that should be considered in determining what type of trip touse 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 actionis allowable (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. Theowner 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 removes ex-citation simultaneously, as with a lock-out relay. A simultaneous trip is acceptable for all generatorfaults, and generally provides the highest degree of protection for the turbine-generator althoughit 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, but leavesthe turbine running near rated speed. Where maintaining speed is not harmful, this provides as higha degree of protection for the generator as a simultaneous trip (Type 1). If the plant can operate fol-lowing a full load rejection, and if the cause of the trip can be identified and rectified quickly, it maymake resynchronization possible in a shorter time than Type 1. Since it does result in a higher over-speed than Type 1, it should only be used when there is an advantage in not tripping the turbine.

3. Breaker trip – trips all generator line breakers but not the excitation or the turbine. This trip has ad-vantages similar to the generator trip when the fault permits excitation to remain applied. Its advan-tage over Type 2 is that it provides auxiliary power in cases where this cannot be switched to anotherbus. 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 the valvesare closed, and the recommended reverse power relay (or function) operates, normally after a three-second delay, the generator line breakers are tripped. Opening of the breakers then trips excitation.This trip should prevent any overspeed and thus is preferred whenever the risk from a three-seconddelay in tripping the generator is slight. It is also preferred for most faults in the turbine or steamgenerator. Its disadvantage is that certain multiple limit-switch failures, or a reverse power relayfailure, would prevent completing the trip. Although this probability is small, a second reverse pow-er relay, with a 10 to 30 second time delay, connected to produce a Type 1 simultaneous trip, is rec-ommended as a back-up. This back-up relay also serves as the primary protection for motoringwhich does not occur as part of a sequential trip.

5. Manual trip – turbine is tripped manually. When generator power reverses, reverse power relay tripsgenerator line breakers. Breaker opening trips excitation. This trip is recommended whenever anoperator sees the need for a fault trip and is not certain that a runback and trip (Type 6) will be fastenough. 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 tripped un-til after the turbine has been tripped and power has reversed. Then the generatorbreakers should be automatically tripped by the reverse power relay. A protectedbypass switch may be used to permit manually tripping the generator alone in caseof limit-switch or reverse power relay failure. A manual generator breaker tripshould 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, followed bythe 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 5 manual tripis not essential.

7. Automatic runback – reduces load (via turbine control) at a preset rate to a preset load. It is recom-mended here only for loss of stator coolant (if required). It is an alternative to tripping the unit, andpermits continuing on line at a very low load. When it can be used, it has the advantage of enablingearlier 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 is use-ful for some faults which may be load sensitive, such as local overheating, and where there is noneed to trip immediately. It also allows the generator to continue to supply reactive power to thesystem.

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

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.


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A. Discussion and Recommendations for Generator Faults

1. Stator Overcurrent

a. Description

Generators are designed to operate continuously at rated kVA, frequency and power factor overa range of 95 to 105% of rated voltage. Operation beyond rated kVA may result in harmful statorovercurrent. Note that at rated kVA, 95% voltage, stator current will be 105%. This is permissi-ble.

Normally, generator load is under the control of an operator. Situations can arise during systemdisturbances, such as accompanying generator or line tripouts, which can result in an overcur-rent condition.

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

Time (seconds) 10 30 60 120Armature current (percent) 226 154 130 116

b. 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 by wind-ing temperature detectors, usually TCs measuring stator cooling water temperature, and/orRTD’s in slots with the stator winding (if applicable). All functioning TCs and RTDs shouldbe continuously monitored and alarmed (see Ref. 1, and 2&3 for H20 cooled machines). How-ever, even though it may not result in excessive stator winding temperatures, operating abovespecified currents is not an acceptable practice since unmonitored phenomena, such as tempera-tures in other parts of the stator circuit, winding forces, abnormal magnetic fields, etc., may be-come excessive.

c. Recommendation

Automatic tripping is not provided for protection against stator overcurrent. However, all oper-ators should be made aware of the importance of operating the generator within its rated capa-bility. In cases when a generator will operate in an unattended station, some form of overcurrent(overload) protection should be provided. An alternative is stator overtemperature which pro-vides similar protection. For additional information, see Ref. 1.

2. Stator Ground Fault

a. Description

The generator stator neutral normally operates at a potential close to ground, generally througha high impedance grounding transformer/resistor. In some cases a reactor is used in a resonantgrounding arrangement. Should a phase winding or any equipment connected to it fault toground, the normally low neutral voltage could rise as high as line-to-neutral voltage, depend-ing on fault location.


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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 is prob-ably the result of damage which is not confined to one spot. In fact, the existence of a groundfault through tough, high-voltage insulation is usually a result of another, potentially cata-strophic, trouble. A second fault, even if detected by differential relays, may cause serious dam-age. A second fault in the same phase will not be detected by differential relays, and could causeserious damage as a result.

b. Detection

The usual method of detection is by a voltage relay across the grounding resistor. A current relayis sometimes used in place of a voltage relay or as a back-up. The relay should be insensitiveto third harmonic voltage, but should have as low a pick-up level at line frequency as is practicalto reduce the unprotected zone at the neutral end of the windings. Methods are available whichare designed to protect the entire winding. These schemes make use of the relationship of thirdharmonic voltages at the line and neutral terminals of the generator. These schemes supplementthe fundamental frequency protection.

c. 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 a si-multaneous trip, Type 1.

For further information, see Ref. 5.

3. Stator Phase-to-Phase Fault

a. Description

A stator phase-to-phase fault is any electrical fault between two phases of the armature winding.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 construc-tion of the armature it is very likely that this type of fault will grow to include ground, therebycausing significant damage to the stator core.

b. Detection

It is possible to detect a phase-to-phase fault in the winding by means of a differential relay. Thismethod provides protection for the entire winding, and its sensitivity is limited mainly by thedegree 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. How-ever, such faults are rare and will usually include ground, in which case they will be detectedby the stator ground fault relay.

c. 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.


13

4. Over-Voltage

a. Description

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

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

b. Recommended Action

Therefore, specific over-voltage protection is generally not required for the generator. Depend-ing on the circumstances, it may be desirable to protect other equipment connected to the gener-ator. For unmanned generating stations, consideration should by given to implementing auto-matic overvoltage protection. For additional information, see Ref. 1.

5. Volts Per Hertz

a. Description

Per unit voltage divided by per unit frequency, commonly called volts/Hertz, is a readily mea-surable 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 stator insula-tion systems. More severe overfluxing (above 110%) further increases core loss, and saturatesportions of the core to the point that flux flows out into adjacent structures. The resulting in-duced voltages can be coupled to stator punchings due to the manner in which cores are as-sembled and clamped. Severe overfluxing can breakdown interlaminar insulation, followed byrapid local core melting.

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 to main-tain rated stator voltage.

b. Detection

Volts per Hertz is calculated in a static circuit incorporated in a volts/Hertz relay or sensor. Tim-ing circuits are also incorporated. The volts/Hertz sensor is normally included as part of the ex-citation system.

c. 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.


14

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 as pos-sible consistent with security from false tripping. Selection of a modest maximum trip level ofabove 118%, coupled with a 2 second time delay satisfies these objectives. A load rejectionfrom full rated KVA, rated power factor and 105% of rated voltage will not result in trippingif an automatic voltage regulator is in service. Operation at 118% should be limited not to ex-ceed 45 seconds. The curve shape from 118 to 110% V/Hz approximates the overexcitation ca-pability of many transformers (for stepup and station service power applications). However ifthe transformers require lower values, the protective relays should be set accordingly. Continu-ous operation above 105% V/Hz is not sanctioned and an alarm function should be providedto alert the operator that corrective action is needed. The excitation control limiter (if applica-ble) 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

a. Description

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

Time (seconds) 10 30 60 120Field voltage (percent) 208 146 125 112

b. 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.

c. 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 sequential tripwould 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

a. Description


15

CONTROL RANGE

CONTROL SET POINT

2 3 6 20 45 1 2 4 6 10

SECONDS MINUTES

TYPICALPWR TRANSCAPABILITY

PROTECTIVERELAYACTION

1.3

1.2

1.1

1.0

PE

R U

NIT

OF

RA

TE

D G

EN

ER

AT

OR

V/H

z

CONTINUOUS GENERATOR CAPABILITY

ALARM

Figure 1. V/Hz Capability.


16

The generator field winding is electrically isolated from ground. Therefore the existence of oneground fault in the winding will usually not damage the rotor. However, the presence of two ormore grounds in the winding will cause magnetic and thermal imbalances plus localized heatingand damage to the rotor forging or other metallic parts. Unfortunately, the presence of the firstground fault makes detection of a second fault difficult, if not impossible. In addition, modernrotor winding insulation systems have achieved a level of quality that reduces the likelihoodof a field ground except under unusual circumstances where the probability of occurrence ofa second ground or other serious problem is high.

b. Detection

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

c. Recommendation

It is recommended that the field ground detector be connected to produce a sequential trip, Type4. Alternatively, a runback, Type 6, or simultaneous trip, Type 1, may be used.

8. Loss of Excitation

a. Description

Loss of excitation (or loss of field) results in loss of synchronism and operation of the generatoras an induction machine. This will result in the flow of slip frequency currents in the rotor body,wedges, and amortisseur windings (if so equipped), as well as severe torque oscillations in therotor shaft. The rotor is not designed to sustain such currents, nor is the turbine-generator shaftdesigned to long withstand the alternating torques. The result can be rotor overheating, couplingslippage and even rotor failure. The length of time before serious damage occurs depends onthe generator load at the time of the incident, slip frequency, and whether the field winding isopen circuited or shorted, and may be a matter of seconds.

A loss of excitation normally indicates a problem with the excitation system which, 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 the con-tinued operation of a generator without excitation. Consequently, if the generator is not discon-nected immediately when it loses excitation, widespread instability may very quickly develop,and major system shut-down may occur.

b. 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).

c. Recommendation

The generator should be tripped from the power system, using a simultaneous trip (Type 1), ora generator trip (Type 2). It is important that all excitation power be removed. It should not beassumed that, since there is loss of excitation, the exciter is not supplying power to an internalfault.


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9. Unbalanced Armature Currents

a. Description

When the generator is supplying an unbalanced load, the phase currents and terminal voltagesdeviate from the ideal balanced relationship, and a negative phase sequence armature current(I2) is imposed on the generator. The negative sequence current in the armature winding createsa magnetic flux wave in the air gap which rotates in opposition to the rotor at synchronous speed.This flux induces currents in the rotor body iron, wedges, retaining rings and amortisseur wind-ings, if so equipped, at twice the line frequency. Heating occurs in these areas and the resultingtemperatures depend upon the level and duration of the unbalanced currents. Under some condi-tions, it is possible to reach temperatures at which the rotor materials no longer contain the cen-trifugal forces imposed on them, resulting in serious damage to the turbine-generator set(Ref. 11).

There is always some low level unbalance in any power system and therefore limits on the con-tinuous unbalance have been established. For currents above the permissible continuous levels,a limit on the time-integral of I2

2 has been established for times up to 120 seconds. Such levelswill often result from faults, open lines or breaker failures.

Unless otherwise specified by the manufacturer as part of the generator design data information,the negative sequence current limits are given in the applicable standards (Ref 31 or Ref 32),where I2 is the per unit negative sequence current on the generator base and t is the time in se-conds. See Ref 1 for further comments on unbalanced loading capability.

b. 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 I2

2t limit (Ref 13).

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

c. Recommendations

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

10. Loss of Synchronism

a. Description

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

b. Detection

The majority of users do not apply specific loss-of-synchronization relaying. However, a skilledrelay engineer can adjust impedance relaying to reliably detect loss of synchronism. Loss of


18

excitation relays may provide detection, but cannot be relied upon under all conditions. If theelectrical center during loss of synchronism is in the transmission system, line relays may detectit. If they do not, specific relaying should be provided.

c. 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 core endheating can also result if the out-of-step operation is caused by reduced or lost excitation. There-fore, it is recommended that the generator be separated from the system without delay, prefer-ably during the first slip cycle (Ref. 14, 26, 27.). A breaker trip, Type 3, is recommended, andpermits the fastest resynchronization after conditions have stabilized.

11. Abnormal Frequency Operation

a. Description

For a generator connected to a power system, abnormal frequency operation is a result of a se-vere system disturbance. An isolated or unconnected unit could operate at low or high frequencydue to improper speed control adjustment or misoperation of the speed control.

There are two effects to be considered. The generator can tolerate underfrequency operation forlong periods, provided load and voltage are sufficiently reduced, as explained in Generator Op-eration instructions (Ref. 1).

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

b. Recommendation

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

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

12. Breaker Failure

a. Description

Since most faults involving the generator require tripping of the generator/line breakers, failureof any of them to open properly results in loss of protection and/or other problems, such as mo-toring. If one or two poles of a generator line breaker fail to open, the result can be a single-phaseload on the generator and negative sequence currents on the rotor.

b. 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. However,a more direct method is the use of Breaker Failure Protection (BFP) which is energized when


19

the breaker trip is initiated. After a suitable time interval, if confirmation of breaker trippingin all three lines is not received, a signal is generated.

c. Recommendation

Industry past practice has not always recognized the need for breaker failure protection becauseof the reliability of line breakers. However, it is recommended that BFP be used with all trippingrelays that can trip a generator line breaker. The BFP signal should trip all line breakers that canfeed current to the generator through the failed breaker (Ref. 15).

13. System Back-Up

a. Description

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

b. 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 consideredfor system back-up protection. However, these will not provide protection against balancedfaults.

c. Recommendation

System back-up protection is recommended. A breaker trip Type 3 is recommended, which per-mits the fastest resynchronization after the system fault has been cleared. In Steam turbines, ifimmediate resynchronization is not a priority, a type 1 trip may be considered to trip the turbine,exciter and generator breaker simultaneously.

14. Voltage Surges

a. 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.


20

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.

b. 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. They areprovided on some packaged generators where optional installation of surge capacitors close tothe surge arrestors would not be convenient. Application of LCI (load commutated inverters)for turbine-generator starting may also obviate the use of surge capacitors on multi-turn coilmachines.

Optimal protection requires surge protection be located in close proximity to the generator ter-minals.

15. Transmission Line Switching

a. Description

The switching of transmission lines at or near generating stations for maintenance purposes, orsimply restoring a line to service after a relayed tripout, are recognized as normal functions inthe course of operating a power system. In some cases these line switching operations can sub-ject nearby generating units to excessive duty. The effect on the generator in severe cases is thesame as for poor synchronizing in causing possible stator winding and shaft fatigue damage(Ref. 7).

b. Detection

A measure of the severity of a switching event is the sudden step change in power (∆P) seen bythe generator at the instant of switching. As a general guide, studies have shown that where ∆Pdoes 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 the generator, forspecific units and system switching events, but these cases should be carefully studied and identi-fied.

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

c. 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 breaker loca-tions can prevent line closings under circumstances predetermined to be excessive. Note, how-ever, that such check relays should not be applied without reliable means of overriding whichwould permit necessary line closing operations under emergency circumstances.


21

16. High Speed Reclosing

a. 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, par-ticularly 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 this cause de-pends on many factors, including both the unit’s and the system’s characteristics, the frequencyof fault occurrence, etc. Studies substantiate that significant shaft damage could occur with un-successful reclosing for close-in three-phase faults.

b. Recommendation

In order to eliminate or reduce the potential effects of unrestricted high speed reclosing of linesnear generating stations, an alternative reclosing practice such as one of the following is recom-mended:

• 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.

• 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 selectivityon 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 is recom-mended that either:

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

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

17. Subsynchronous Resonance (SSR)

a. Description

When a turbine-generator is connected to a transmission network that has series capacitor com-pensation or a high voltage dc (HVDC) transmission system, it is possible to develop subsyn-chronous (under line frequency) current oscillations in the lines and in the generator armature.In the case of series compensated ac systems, these currents interact with the synchronouslyrotating flux to produce torque pulsation on the generator rotor. If these pulsations are at a fre-quency close to one of the torsional natural frequencies of the turbine-generator, high levels oftorsional vibration can be induced in the shafts. Torsional instability of the turbine-generatorshaft system has the potential for being extremely damaging to the turbine-generator shafts, andresulted in two shaft failures in the early 1970s. A more recently observed phenomenon in-volves interaction between torsional modes and HVDC controls (Ref. 28). This could lead to


22

an unstable situation, resulting in spontaneous growth of torsional vibrations and potential dam-age to the shaft.

b. 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 methods ofidentifying subsynchronous resonance steady-state instability problems involve monitoringgenerator electrical terminal quantities. The armature current relay described in Ref. 20 utilizesthis approach.

c. 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, therefore,the owner’s responsibility to implement devices to detect, and protect the machine from, theinfluences of subsynchronous torsional interaction. In the case of HVDC transmission lines, thepotential for interaction between the HVDC controls and the turbine-generator rotor systemneeds to be accounted for in HVDC control design. General Electric has worked closely withmany utilities on system studies to define the requirements for protective devices on particularsystems. The company has also manufactured and has in service protective devices. This equip-ment includes (Ref. 20):

1) A static subsynchronous resonance filter (static blocking filter)

2) A supplementary excitation damping control (excitation system damper)

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

4) A torsional vibration monitor (Ref. 22)

In addition, generators that are applied for use in series capacitor compensated systems or sys-tems containing HVDC transmission are sometimes furnished with pole-face amortisseurwindings. The addition of pole-face amortisseur windings does not necessarily enhance nega-tive sequence capability. The function of amortisseur windings is to reduce the machine electri-cal resistance in the subsynchronous frequency range, which reduces the potential for torsionalinteraction at subsynchronous frequencies.

d. Recommendation

It is vital that the electric utility work closely with the manufacturer at the planning stage to de-fine the need for auxiliary equipment to protect the machine. This equipment, if required, needsto be operational when the machine is first connected to the network containing series capacitorcompensated and/or HVDC transmission lines. It needs to be highly reliable, as misoperationcould result in major machine failure.

18. Inadvertent Energization

a. Description


23

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 high slipinterval can be represented by negative sequence reactance (X2) in series with negative se-quence resistance (R2). The machine terminal voltage and current during this interval will bea function of generator, transformer and system impedances. If the generator-transformer isconnected to an infinite system, the machine currents will be high (several per unit), and con-versely, if the unit is connected to a weak system, the machine current could be low (1–2 perunit). During the period the machine is accelerating, high currents will be induced in the rotorand 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 energized while at standstill or very low speed.While many have survived the experience with minor damage, others have not.

b. 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 means specif-ically designed for this purpose.

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

c. Recommendation

It is recommended that the detection scheme described above be used to protect every generator.To prevent damage to the rotor, stator bearings, etc., it is desirable that high speed protectionbe provided for this contingency. The relaying should be connected to trip the main generatorbreaker, trip any breakers which could feed current to the generator if breaker failure is detected,and be so implemented that it is never taken out of service when the unit is shut down for anypurpose, even with the rotor removed.

19. Bearing Vibration

a. 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


24

• Rubbing

• Bent overhangs

• Out-of-round journals or collectors

• Stiffness dissymmetry.

b. 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 vibration,and alarming and/or tripping at predetermined levels of vibration. The vibration recorders donot provide the frequency spectrum information which could be useful in determining the causeof the vibration. This information must be obtained with a portable vibration analyzer.

c. Recommendation

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

For Vibration Level Exceeding Recommendations2 Poles 4 Poles

(mils) (µm) (mils) (µm)

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.

d. Reference

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

20. Synchronizing Errors

a. Description

Improper synchronizing of units to the line may occur for a number of reasons. The most severeof these results from incorrect connection of potential transformer or synchronizing aids suchthat gross out-of-phase synchronizing, such as a 120° error, may occur. A failure of automaticsynchronizing equipment may also result in large synchronizing errors. While turbine-genera-tors are designed to withstand these rare occurrences without catastrophic results, provided sta-tor current does not exceed the three-phase short circuit value, they can result in damage, such


25

as slipped couplings, with resulting high vibration, loosened stator windings, and fatigue dam-age 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.

b. Detection

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

c. 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 minimiz-ing 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

a. Description

Motoring of a generator will occur when turbine output is reduced such that it develops less thanno-load losses while the generator is still on line. Assuming excitation is sufficient, the genera-tor will operate as a synchronous motor driving the turbine. The generator will not be harmedby synchronous motoring, but, if it occurs as a result of failure to complete a sequential trip,protection for the fault originating that trip is lost. In addition, a steam turbine can be harmedthrough overheating during synchronous motoring.

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


26

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

b. Detection

Motoring following loss of turbine output can be detected with a reverse power relay. To avoidfalse trips due to power swings, a time-delay pick-up of 10 to 30 seconds is suggested. This isthe backup relay suggested in the description of Trip 4 – sequential trip. Measurement of verylow power levels at very low power factors will require relatively high precision. Reduction inreactive power flow in the generator will reduce the requirement for high precision. This maybe accomplished through control action of the excitation system or by operator action.

c. Recommendation

It is recommended that the reverse power relay referred to above be used and connected to pro-duce a Type 1, simultaneous trip. Alternatively, a Type 2 generator trip or Type 3 breaker tripcould be used. Breaker Failure Protection (see page 23) should be initiated, since line breakerfailure may be the cause of the motoring. In addition, the turbine section of the instruction book(Ref. 9) should be consulted and followed.

22. Stator Overtemperature

a. 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.

b. Detection

Armature bar temperatures are monitored by either TCs measuring stator cooling water temper-ature and/or RTD’s in the stator slots (if applicable). All functioning RTDs and TCs should beconstantly monitored and alarmed (see Ref 1, and 2&3 for H20 cooled machines). As pointedout in the stator overcurrent section, these temperature detectors do not provide completeprotection against damage due to overcurrent operation, because temperatures in other parts ofthe winding, winding forces, abnormal magnetic fields, etc. may become excessive.

c. Recommendation

Automatic shutdown is not always provided for protection against stator overheating on genera-tors with conventionally cooled stator windings. Section 26 describes automatic protection rec-ommended for liquid cooled armature windings. All operators should be made aware of the im-portance of operating the generator within its rated capability. In cases where a generator willoperate in an unattended station, some form of overtemperature protection should be provided.Implementation of an automatic stator overtemperature protection scheme also provides someovercurrent protection, and is generally easier to implement than overcurrent relaying.

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

a. Description


27

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 to anydamaging overtemperatures. However, without human monitoring and intervention, the condi-tion will persist.

b. Detection

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

c. 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)

a. 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 main pumpis driven by an ac motor. An emergency back-up pump is driven by a dc motor. This pump willstart automatically if the oil discharge pressure of the main pump decreases or if ac power islost. In addition to the main and emergency pumps, bearing header pressure is available to main-tain hydrogen pressure in the generator at a maximum of approximately 8 psig or 5 psid lessthan the available bearing header pressure, whichever is lower.

For most conventionally cooled hydrogen generators, seal oil is supplied from the lube oil tankby the same pump supplying bearing oil. The main pump is driven by an ac motor. An emergen-cy lube oil back-up pump is driven by a dc motor. This pump will start automatically if the sealoil differential pressure decreases or if ac power is lost. Some machines are provided with a spe-cific DC seal oil emergency backup pump in addition to the lube oil backup pump. Higher pres-sure (greater than 30 psig) conventionally cooled machines are provided with separate seal oilpumps. See Ref. 10 for details on the seal oil system provided.

b. Detection

Alarms indicate low differential seal oil pressure, main pump motor overload, and emergencypump running (see Table I).

c. Recommendation

If the main pump is lost an operator should take immediate action to determine the cause. If theproblem requires more than a few hours to correct, gas pressure should be reduced to the lowestvalue required for the generator load, as determined from the reactive capability curves. Thisprocedure is recommended because the emergency pump has only the bearing header pressureas back-up on liquid cooled machines, and no additional backup is provided on conventionallycooled generators. Careful consideration of the DC supply capacity and the purge cycle timeis required to decide how long it is safe operate on the backup DC pump. If this gas pressure


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cannot be maintained, additional reductions in both gas pressure and load will be required. Op-eration for long periods with the emergency pump or the bearing header supply only will resultin a reduction of hydrogen purity. For most generators under these conditions, gas must be scav-enged from the generator to maintain hydrogen purity as described in Ref. 4. Some convention-ally cooled machines will automatically increase the scavenge gas rate in an attempt to maintainpurity. Again, see Ref. 4 for details.

25. Local Overheating (if applicable)

a. 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 at theinner diameter of the stator core. This might cause electrical contact between laminations lead-ing to a flow of current and therefore heating. This type of damage may be caused by a foreignobject striking the core under the influence of electromagnetic forces in the machine. Overheat-ing may also be caused by improper cooling or by faulty or damaged insulation, allowing exces-sive leakage current to flow. It can also be caused by operating outside the capability limits, es-pecially in underexcited regions.

b. 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 Monitor,a Signal Validation Control and a Pyrolysate Collector. The generator Core Monitor is an ion-ization-type particulate detector that is connected to the generator so that a constant flow ofcooling gas passes through it. The cooling gas is monitored for the presence of submicron par-ticles (particulates). Under normal conditions, the gas coolant contains no particulates that canbe detected by the monitor. When overheating occurs, the thermal decomposition of organicmaterial, epoxy paint, core lamination enamel or other insulating materials produces a largenumber of particulates which can be detected by the monitor to produce an alarm. The particu-lates can be collected by the Pyrolysate Collector which is designed to operate when a generatorCore Monitor alarm occurs. Confirmation of overheating may be accomplished by laboratoryanalysis 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 alarm isverified, the Validation Control actuates a machine heating alarm.

c. Recommendation


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When a machine heating alarm occurs, load should be reduced by manual runback (Type 8) untilthe alarm signal clears. If the alarm signal does not clear within five minutes the generatorshould 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.

Additional information may be found in specific Generator Gas Monitoring System publica-tions in the Generator Instruction Book (Tab 28).

26. Loss of Stator Coolant (if applicable)

a. Description

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

Cooling flow may be reduced or lost because of:

1) System restrictions such as plugged filters or strainer, or a buildup of material such as cop-per oxide in the stator winding strands

2) Localized restriction in a single bar or group of bars in the winding

3) Pipe break

4) Loss of pumps

5) Misadjustment of the control valve

6) Control valve failure

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

b. Detection

1) 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 pressurealarm. System restrictions can also be signalled by the bulk water outlet temperature sen-sor which provides an alarm function, and by the individual liquid header outlet TCs andslot RTDs.

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


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3) 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.

4) Loss of both pumps will be detected by low pressure and low flow alarms and by a temper-ature rise signalled by all of the slot RTDs.

5) 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.

6) 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 than nor-mal flows and pressures are observed.

7) 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 belowfreezing unless provisions are made to protect vital parts of the system from the low tem-perature.

c. Recommendation

Most serious faults will initiate an alarm. These are listed in Table I. Appropriate operator actionshould be taken at the time of the alarm (Ref. 2, 3). The nature of the problem dictates the actionrequired, as discussed below.

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

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

If runback, rather than trip, was selected, but the runback fails to occur, a trip signal will be pro-duced.

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 or cali-brating sensors. These tasks should be performed periodically as recommended in the applica-ble instruction (Tab 33 of Generator Instruction Book).

27. High Water Conductivity (if applicable)

a. Description


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

b. Detection

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

c. 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, the unitshould be removed from service, using manual runback and trip (Type 6).


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TABLE II. SUMMARY OF GENERATOR PROTECTION RECOMMENDATIONS

Fault Type Recommendation Page

Electrical Faults

Stator overcurrent Runback 8 or 7 11Stator ground fault Trip 1 11Stator phase-to-phase fault Trip 1 12Over-voltage Restore normal voltage 13Over-volts/Hertz Trip 1 (or 2) 13Field overexcitation Trip 4 14Field ground Trip 4 (or 6) 14Loss of excitation Trip 1 (or 2) 16

System Faults

Unbalanced armature currents Trip 3 17Loss of synchronism Trip 3 17Abnormal frequency operation See Turbine Instructions 18Breaker failure Use Breaker Failure Protection 18System back-up Trip 3 19Voltage surges Use surge arrestors 19

System Operations

Transmission line switching Limit magnitude of power step 20High speed reclosing See detailed recommendations 21Subsynchronous resonance See detailed recommendations 21Inadvertent energization See detailed recommendations 22

Mechanical or Thermal Faults

Bearing vibration Trip 4 23Synchronizing errors Use check relays 24Motoring Trip 1 (or 2 or 3) 25Stator Overtemperature Alarm (Trip 6 or 4) 26Loss coolant to gas coolers Trip 6 (or 4) 26Reduced seal oil pressure Reduce H2 pressure & load 27Local Overheating Runback 8(or 7) or Trip 5 28Loss of stator coolant Runback 7 or Trip 4 29High water conductivity Trip 6 30

Protective Actions Key

1 Simultaneous trip 5 Manual trip2 Generator trip 6 Manual Runback and trip3 Breaker trip 7 Automatic runback4 Sequential trip 8 Manual runback

This table does not purport to summarize all the descriptive material containedin the referenced pages. These must be read and understood when using thissummary.


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REFERENCES

1) “Generator Operation,” Tab 19, Generator Instruction Book.

2) “Operator Action on High Temperature Alarms,” Tab 33, Generator Instruction Book.

3) “Operator Action on Low Flow and Low Pressure Alarms,” Tab 33, Generator Instruction Book.

4) “Gas Control System,” Tab 29, Generator Instruction Book.

5) Brown, P.G., Johnson, I.B. and 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 Synchronous Generators,” IEEE Trans., Vol. PAS-94,1975, pp. 1457–1463; available as GE Publication GER 3183.

7) Brown, P.G. and Quay, R., “Transmission Line Reclosing – Turbine-Generator Duties and Stability Consid-erations,” Texas A&M Relay Conference, April 1976.

8) Winick, Kenneth, “Relay Supervision of Manual Synchronizing,” available as GE Publication GER 2624.

9) “Sequential Tripping and Prevention of Motoring,” Turbine section of Instruction Book.

10) “Shaft Sealing System,” Tab 29, Generator Instruction Book.

11) Linkinhoker, C.L., Schmitt, N. and Winchester, R.L., “Influence of Unbalanced Currents on the Design andOperation of Large Turbine-Generators,” IEEE Trans., Vol. PAS-92, 1973, pp. 1597–1604; available as GEPublication GER 2874.

12) ANSI Std. C50.13-1977, Sections 6.3 and 6.5.

13) Graham, P.J., Brown, P.G. and Winchester, R.L., “Generator Protection with New Static Negative SequenceRelays,” IEEE Trans., Vol. PAS-94, 1974, pp. 1208–1223.

14) Working Group Report, “Out of Step Relaying for Generators,” IEEE Trans., Vol. PAS-96, No. 5, 1977,pp. 1556–1564.

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

16) Hoffman, D.C., “Back-up Protection for System Faults at the Generator,” General Electric Review, Febru-ary 1950.

17) Walker, D.N., Adams, S.L. and Placaek, R.J., “Torsional Vibration and Fatigue of Turbine-GeneratorShafts,” IEEE Power Engineering Society 1978 IEEE/ASME/ASCE Joint Power Generation Conference;Digest State of the Art Symposium, Turbine-Generator Shaft Torsionals.

18) IEEE Working Group of the Subsynchronous Machine Committee, “Steady State Switching Guide.”

19) Joyce, J.S. and Lambrecht, D., “Status of Evaluating the Fatigue of Large Steam Turbine-GeneratorsCaused by Electrical Disturbances,” IEEE Power Engineering Society 1978 IEEE/ASME/ASCE JointPower Generator Conference; Digest State of the Art Symposium, Turbine-Generator Shaft Torsionals.


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20) “Counter-measures to Subsynchronous Resonance Problems,” IEEE Subsynchronous Resonance WorkingGroup of the System Dynamic Performance Subcommittee; IEEE Trans., Vol. PAS-99, No. 5, 1980, pp.1810–1818.

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

22) Farmer, R.G., et. al., “Navajo Project Report on SSR Analysis and Solution,” IEEE Trans., Vol. PAS-96,No. 1, 1977, pp. 1226–1232.

23) “Recommendations for Reading and Recording Generator Resistance Temperature Detectors and Thermo-couples,” Tab 23, Generator Instruction Book.

24) “Starting and Loading,” Turbine section of Instruction Book.

25) Smaha, D.W., Rowland, C.R. and Pope, J.W., “Coordination of Load Conservation with Turbine-GeneratorUnderfrequency Protection,” IEEE Trans., Vol. PAS-99, No. 3, 1980, pp. 1137–1150.

26) Berdy, J., “Out-of-Step Protection for Generators,” available as GE Publication GER 3179.

27) Berdy, J., “Application of Out-of-Step Blocking and Tripping Relays,” available as GE Publication GER3180.

28) *Piwko, R.J. and Larsen, E.V., “HVDC System Control for Damping of Subsynchronous Oscillations,”IEEE Paper No. 81-TD660-0 (presented September 1981 at IEEE Transmission and Distribution Confer-ence).

29) ANSI/IEEE C37-101 IEEE Guide for Generator Ground Protection.

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

31) CEI/IEC standard 34-3 Rotating Electrical Machines – Specific requirements for turbine-type synchronousmachines.

32) ANSI C50.13 Requirements for Cylindrical Rotor Synchronous Generator.

GERs are General Electric Company publications which may be obtainedthrough the nearest GE Sales Office.

* Indicates change since last revision.

General Electric CompanyOne River Road, Schenectady, NY 12345518 • 385 •2211 TX: 145354

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