Abnormal Frequency Protection for Generating Power PLant-IEE C37.106-1987

ANSI/IEEE C37.106-1987

An American National Standard

IEEE Guide for Abnormal Frequency Protection for Power Generating Plants

Sponsor

Power System Relaying Committeeof theIEEE Power Engineering Society

Cosecretariats

Institute of Electrical and Electronics EngineersNational Electrical Manufacturers Association

Approved March 22, 1984Reaffirmed June 18, 1992

IEEE Standards Board

Approved September 12, 1986Reaffirmed November 2, 1993

American National Standards Institute

© Copyright 1987

The Institute of Electrical and Electronics Engineers, Inc

345 East 47th Street, New York, NY 10017, USA

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Comments on standards and requests for interpretations should be addressed to:

Secretary, IEEE Standards Board345 East 47th StreetNew York, NY 10017USA

iii

Foreword

(This Foreword is not a part of ANSI/IEEE C37.106-1987, IEEE Guide for Abnormal Frequency Protection for Power GeneratingPlants.)

This standard is the result of the valuable input of not only the listed working group members who had this status at thetime of its approval, but those also who are listed as past members of the working group. One who deserves specialrecognition is C. M. Shuster, who served as the first working group chairman and thus gave early guidance on theformat and substance of the proposed guide.

Preparation of the guide began in 1978 shortly after the publication of a report by the National Electric ReliabilityCouncil (NERC) in July 1978. The title of the report was “Underfrequency and Undervoltage Relay Applications toLarge Turbine-Generators.” The guide thus responds to concerns and issues raised by the NERC report.

Some of the more important subjects that came under working group discussion and were accorded a place in the guidewere:

1) Generator over-/underfrequency capabilities2) Turbine over-/underfrequency capabilities with a need to establish operating limits of turbine blades during

abnormal frequency operation3) Components of the power plant that may be frequency sensitive4) Generator/turbine underfrequency protection relay schemes5) Coordination of generator/turbine protection schemes with existing system load shedding schemes6) Generator/transformer volts/hertz protection7) Special underfrequency considerations in nuclear power plants

The Accredited Standards Committee C37 on Power Switchgear had the following membership when it reviewed andapproved this document:

W. E. Laubach, Chair C. H. White, Secretary

W. N. Rothenbuhler, Executive Vice-Chairman of High-Voltage Switchgear StandardsS. H. Telander, Executive Vice-Chairman of Low-Voltage Switchgear Standards

D. L. Swindler, Executive Vice-Chairman of IEC Activities

Organization Represented Name of Representative

Association of Iron and Steel Engineers J. M. Tillman

Electric Light and Power Group D. O. Craghead

R. L. Capra

D. A. Ditzler

K. D. Hendrix

J. H. Provanzana (Alt)

D. E. Soffrin (Alt)

D. T. Weston

Institute of Electrical and Electronics Engineers H. W. Mikulecky

M. J. Beachy (Alt)

G. R. Hanks

R. P. Jackson (Alt)

C. A. Mathews

E. W. Schmunk

iv

At the time this guide was completed, the Working Group on Generating Plant Abnormal Frequency Protection had thefollowing membership:

C. J. Pencinger, Chair

J. BerdyJ. J. BonkD. C. DawsonR. J. FernandezS. E. GrierR. W. Haas

T. L. KaschalkL. E. LandollJ. R. LathamG. R. NailG. C. ParrJ. W. Pope

E. T. SageH. S. SmithR. C. SteinR. D. StumpF. Von Roeschlaub

Past members who have contributed review and comments are:

D. C. AdamsonW. A. ElmoreC. H. Griffin

J. A. ImhofC. M. ShusterW. M. Strang

J. E. WaldronF. WolfR. C. Zaklukiewicz

The following persons were on the balloting committee that approved this document for submission to the IEEEStandards Board:

R. F. ArehartC. W. BarnettE. A. BaumgartnerJ. L. BlackburnJ. J. BonkJ. R. BoyleB. BozokiH. J. CalhounD. M. ClarkG. A. ColgroveD. H. ColwellD. Dalasta

R. W. DempseyR. E. DietrichJ. B. DinglerW. A. ElmoreE. J. EmmerlingR. J. FeltonR. J. FernandezA. T. GiulianteS. E. GrierC. H. GriffinR. W. HaasR. E. Hart

R. W. HirtlerS. H. HorowitzF. B. HuntT. L. KaschalkD. K. KaushalJ. L. KoepfingerB. L. LairdL. E. LandollJ. R. LathamH. LeeJ. R. LindersW. R. Lund

C. A. Schwalbe

C. E. Zanzie

National Electrical Manufacturers Association C. A. Wilson

T. L. Fromm

R. A. McMaster

R. O. D. Whitt

Tennessee Valley Authority R. C. St. Clair

Testing Laboratory Group L. Frier

W. T. O'Grady

R. W. Seelbach (Alt)

US Department of the Army Corps of Engineers H. K. Snyder

US Department of the Interior, Bureau of Reclamation R. H. Auerbach

US Department of the Navy, Naval Construction Battalion Center R. L. Clark

Western Area Power Authority G. D. Birney

Organization Represented Name of Representative

v

G. J. MarieniA. J. McconnellF. N. MeissnerR. J. MoranJ. J. MurphyG. C. ParrR. W. PashleyA. G. PhadkeA. C. Pierce

J. W. PopeG. D. RockefellerB. D. RussellE. T. SageJ. E. StephensA. SweetanaE. F. TroyJ. R. TurleyE. A. Udren

W. H. Van ZeeD. R. VolzkaC. L. WagnerJ. E. WaldronJ. W. WaltonE. J. WeissJ. A. Zulaski

When the IEEE Standards Board approved this standard on March 22, 1984, it had the following membership:

James H. Beall, Chair John E. May, Vice Chair Sava I. Sherr, Secretary

J. J. ArchambaultJohn T. BoettgerJ. V. BonucchiRene CastenschioldEdward ChelottiEdward J. CohenLen S. CoreyDonald C. FleckensteinJay Forster

Daniel L. GoldbergDonald N. HeirmanIrvin N. HowellJack KinnJoseph L. Koepfinger *Irving KolodnyGeorge KonomosR. F. LawrenceDonald T. Michael *

John P. RiganatiFrank L. RoseRobert W. SeelbachJay A. StewartClifford O. SwansonW. B. WilkensCharles J. Wylie

* Member emeritus

vi

CLAUSE PAGE

1. Introduction and Scope .......................................................................................................................................1

2. References...........................................................................................................................................................1

3. Steam Generating Plant—Abnormal Frequency Operation................................................................................2

3.1 General Background .................................................................................................................................. 23.2 Generator Over-/Underfrequency Capability............................................................................................. 23.3 Turbine Over-/Underfrequency Capability ................................................................................................ 43.4 Power Plant Auxiliaries—UnderfrequencyConsiderations ....................................................................... 73.5 Underfrequency Protection Methods for Steam Turbines ......................................................................... 83.6 Coordination with System Load Shedding Scheme................................................................................. 133.7 Generator-Transformer Overexcitation.................................................................................................... 173.8 Generator-Transformer Volts/Hertz Protection ....................................................................................... 19

4. Nuclear Generating Plant—Special Consideration...........................................................................................22

4.1 General Background ................................................................................................................................ 224.2 Boiling Water Reactor (BWR)/Underfrequency Considerations............................................................. 224.3 Pressurized Water Reactor (PWR)/Underfrequency Considerations....................................................... 22

5. Combustion-Turbine Underfrequency Operation .............................................................................................23

5.1 General Background ................................................................................................................................ 235.2 Combustion-Turbine Underfrequency Capability ................................................................................... 245.3 Underfrequency Protection Philosophy, Relay Settings, and Guidelines ................................................ 245.4 Underfrequency Protection Considerations for Combined Cycle Generating Units ............................... 24

6. Bibliography......................................................................................................................................................25

Annex ............................................................................................................................................................................26

1

An American National Standard

IEEE Guide for Abnormal Frequency Protection for Power Generating Plants

1. Introduction and Scope

This guide has been prepared to assist the protection engineer in applying relays for the protection of generating plantequipment from damage caused by operation at abnormal frequencies including overexcitation. Emphasis is placed onthe protection of the major generating station components at steam generating stations, nuclear stations, and oncombustion-turbine installations. Consideration is also given to the effect of abnormal frequency operation on thoseassociated station auxiliaries whose response can affect plant output.

The guide also presents background information regarding the hazards caused by operating generation equipment atabnormal frequencies. It documents typical equipment capabilities and describes acceptable protective schemes.Recommended methods for coordinating the underfrequency protective scheme with system load shedding schemesare also included. Sufficient information is provided to apply suitable coordinated protection for given specificsituations.

2. References

[1] ANSI C50.13-1977, American National Standard Requirements for Cylindrical-Rotor Synchronous Generators.1

[2] ANSI/IEEE C57.12.00-1980, IEEE Standard General Requirements for Liquid-Immersed Distribution, Power, andRegulating Transformers.2

[3] BAUMAN, H. A., HAHN, G. R., and METCALF, C. N. The Effect of Frequency Reduction on Plant Capacity andon System Operation. AIEE Transactions on Power Apparatus and Systems, vol PAS-74, Feb 1955, pp 1632–1637.

[4] BUTLER, O. D. and SWENSON, C. J. Effect of Low Frequency and Low Voltage on Thermal Plant Capability andLoad Relief During Power System Emergencies—Effect of Reduced Voltage and/or Frequency Upon Steam PlantAuxiliaries. AIEE Transactions on Power Apparatus and Systems, vol PAS-72, Feb 1955, pp 1628–1632.

[5] Electric Power Research Institute. RP 764—Research in Long-Term Power System Dynamics. Final Report No EL367, prepared by General Electric Company, Feb 1977 and Final Report No EL 983, vols I and II, prepared by GeneralElectric Company, July 1982.

1ANSI publications can be obtained from the Sales Department, American National Standards Institute, 1430 Broadway, New York, NY 10018.2ANSI/IEEE publications can be obtained from the Sales Department, American National Standards Institute, 1430 Broadway, New York, NY10018, or from the Institute of Electrical and Electronics Engineers, Service Center, Piscataway, NJ 08854.

2 Copyright © 1987 IEEE All Rights Reserved

ANSI/IEEE C37.106-1987 IEEE GUIDE FOR ABNORMAL FREQUENCY

[6] Electric Power Research Institute. RP 745—Development of Short-Term and Mid-Firm Simulation Techniques forLarge Interconnected Power Systems. Final Report No EL 596, prepared by Arizona Public Service and Arizona StateUniversity, June 1979.

[7] Electric Power Research Institute. RP 849—Determining Load Characteristics for Transient Performances. FinalReport No EL 849, vols I–III, prepared by University of Texas at Arlington, May 1979; Final Report No EL 850, volsI–IV, prepared by General Electric Company, Mar 1981; Final Report No EL 851, vol 1, prepared by Institut deRecherche de l' Hydro Quebec, Nov 1980; and Final Report No EL 851, vol II, prepared by Institut de Recherche del' Hydro Quebec, Mar 1981.

[8] HOLGATE, R. The Effect of Frequency and Voltage. AIEE Transactions on Power Apparatus and Systems, volPAS-74, Feb 1955, pp 1637-1646.

[9] KEARNS, K. D., ROSSI, C. E., and GEETS, J. M. The Effects of Electrical System Underfrequency Transients onPressurized Water Reactors. Transactions of the American Nuclear Society, vol 15, no 2, Nov 12, 1972, p 828.

[10] SCHROEDER, T. W. Steam Plant Operation at Reduced Voltage and Frequency. Electric Light and Power, vol 29,Aug 1951, pp 70–74.

[11] SMAHA, D. W., ROWLAND, C. R., and POPE, J. W. Coordination of Load Conservation with TurbineGenerator Underfrequency Protection.IEEE Transactions on Power Apparatus and Systems, vol PAS-99, May/June1980, pp 1137–1145.

[12] UDREN, E. A. Load-Shedding and Frequency Relaying.Applied Protective Relaying, Westinghouse ElectricCorporation, 1979, chap 21, p 2.

3. Steam Generating Plant—Abnormal Frequency Operation

3.1 General Background

There are two major considerations associated with operating a steam generating station at abnormal frequency. Theyare

1) Protection of equipment from damage that could result from operation at abnormal frequency2) Prevention of a cascading effect that leads to a complete plant shutdown as long as limiting conditions are not

reached during abnormal frequency operation

The major components of a steam plant that are affected by abnormal frequency operation are the generator and unitstep-up transformer, the turbine, and the station auxiliaries. In this section, the effect of abnormal frequency operationon the various station components is discussed and various protective schemes are presented.

3.2 Generator Over-/Underfrequency Capability

While no standards have been established for abnormal frequency operation of synchronous generators, it isrecognized that reduced frequency results in reduced ventilation; therefore, operation at reduced frequency should beat reduced kilovoltamperes (kVA). Figure 1 shows typical recommended maximum continuous loading at variousfrequencies for 2-pole or 4-pole cylindrical rotor generators as published by two manufacturers.

Copyright © 1987 IEEE All Rights Reserved 3

PROTECTION FOR POWER GENERATING PLANTS ANSI/IEEE C37.106-1987

Figure 1—Generator Capability Versus Frequency

In view of reduced generator capability and expected increased loading during underfrequency conditions, the short-time thermal capability of a generator could be exceeded. Operating precautions should be taken to stay within theshort-time thermal rating of the generator rotor and stator. The permissible short-time operating levels for both thestator and rotor for cylindrical rotor synchronous generators are specified in ANSI C50.13-1977 [1]3 and are shown inFig 2.

The underfrequency limitations on the generator, however, are usually less restrictive than the limitations on theturbine, which are discussed in the next section.

Overfrequency is usually the result of a sudden reduction in load and, therefore, corresponds to light-load or no-loadoperation of a generator. During overfrequency operation, machine ventilation is improved and the flux densityrequired for a given terminal voltage is reduced. Therefore, operation within the allowable overfrequency limits of theturbine will not produce generator overheating as long as operation is within rated kilovoltamperes and 105% of ratedvoltage.

3The numbers in brackets correspond to those of the references listed in Section 2; when preceded by B, they correspond to the bibliography inSection 6



Figure 2—Generator Short-Time Thermal Capability

3.3 Turbine Over-/Underfrequency Capability

A turbine blade is designed to have its natural frequencies sufficiently displaced from rated speed and multiples ofrated speed (that is, the rated fundamental frequency and its harmonics) to avoid a mechanical resonant condition thatcould result in excessive mechanical stresses in the blade. Excess stress can occur if the system damping is insufficientto overcome the excitation stimulus produced by turbine steam flow. For a resonant condition, the vibratory stress canbe 300 times greater than the stress during nonresonant operating conditions.

Figure 3 is a Campbell diagram for a particular blade design that illustrates how a change in turbine speed can produceexcitation frequencies that coincide with the natural frequency of that blade. With sufficient stimulus, the mechanicalstresses produced in the blade can be potentially damaging and can lead to destructive failure after a period of time.The number of natural frequency bands plotted is generally limited to those for which the turbine would likely producea sufficient level of stimulus to cause excessive stresses. The curves labeled 1 through 6 indicate the points where thefrequency is an integral multiple (that is, a harmonic) for a given turbine speed. The rated speed line illustrates that thisblade design does not have natural frequencies that coincide with 60 Hz or any harmonics up through the sixth.However, speed deviations from rated speed would eventually cause an intersection with one or more of the naturalfrequency bands at some multiple of the changed operating speed. Point A illustrates such a condition, and themagnitude of stress in the vicinity about point A for a given stimulus will follow that of a typical resonance curve, asshown in Fig 4.



Figure 3—Typical Tuned Blade Campbell Diagram

Figure 4—Typical Resonance Curve

The peak stress at resonance is limited only by system damping, which may be extremely low. Manufacturers havedetermined that it is economically impractical to design long low-pressure turbine blades with sufficient strength towithstand stresses due to mechanical resonance for all steam flow stimuli. Therefore, operation at frequencies otherthan rated or near rated speed is time-restricted to the limits shown for the various frequency bands published by eachturbine manufacturer for various blade designs.



Figure 5—Steam Turbine Partial or Full-Load Operating Limitations During Abnormal Frequency

The abnormal frequency limits are generally based on worst-case conditions because

1) The natural frequencies of blades within a stage differ due to manufacturing tolerances2) The fatigue strength may decline with normal operation for reasons such as pitting corrosion and erosion of

the blade edges3) The limit should also recognize the effect of additional loss of blade life incurred during abnormal operating

conditions not associated with underspeed or overspeed operation

Figure 5 illustrates the most restrictive time limitations at various frequencies for operation of all the large steam-driven turbines of five of the world's turbine manufacturers. Figure 6 is a composite representation developed from thecapability curves in Fig 5, using the most restrictive limits of the five manufacturers. The blank areas between 59.5and 60.5 Hz are areas of unrestricted time operating frequency limits, while the dotted areas above 60.5 Hz and below59.5 Hz are areas of restricted time operating frequency limits. Operation outside these areas is not recommended.This curve was developed as a composite in order to evaluate the performance of different relay schemes. It is notmeant to be used as a standard of performance for steam turbines. It is recommended that the manufacturer beconsulted in order to obtain the applicable curve of the turbine to be studied.

Time spent in a given frequency band is cumulative but independent of the time accumulated in any other band. Foreach incident, the first ten cycles in a given frequency band are not accumulated since some time is required formechanical resonance to be established in the turbine blading. For example, the composite curve indicates thatoperation between 58.5 and 57.9 Hz is permitted for ten minutes before turbine blade damage is probable. If a unitoperates within this frequency band for one minute, then nine more minutes of operation within this band are permittedover the life of the blade.

The abnormal frequency capability curves are applicable whenever the unit is connected to the system. These curvesalso apply when the turbine generator unit is not connected to the system, if it is operated at abnormal frequency whilesupplying its auxilliary load. During periods when the unit is being brought up to speed, being tested at no-load foroperation of the overspeed trip device, or being shut down, blade life will not be significantly affected if themanufacturer's procedures are followed.



Figure 6—Steam Turbine Partial or Full-Load Operating Limitations During Abnormal Frequency (Composite Worst-Case Limitations of Five Manufacturers in Fig 5)

3.4 Power Plant Auxiliaries—UnderfrequencyConsiderations

The ability of the steam supply system to continue operating during an extended period of underfrequency operationis a function of the margin in capacity of the auxiliary motor drives and shaft-driven loads.

The most limiting auxiliary equipments are generally the boiler feed pumps, circulating water pumps, and condensatepumps, since each percent of speed reduction causes a larger percent loss of capacity [3], [4]. The critical frequency atwhich the performance of the pumps will affect the plant output will vary from plant to plant. However, tests andexperience have shown that the plant capability will begin to decrease by 57 Hz [4], and that frequencies in the regionof 53 to 55 Hz [3], [4], [8] are critical for continued plant operation due to the reduction in the output of the pumps.

In general, other plant auxiliaries have less influence on plant capability. For example, induced draft fans usually havea design margin to accommodate an underfrequency condition of approximately 54 Hz before plant output is affected[10]. Tests [4], [10] indicate little influence from other auxiliaries for modest underfrequency conditions (3 Hz), but atmore severe underfrequency conditions (6 Hz) the loss of capability becomes significant. Consequently, the minimumsafe frequency level for maintaining plant output is dependent on each plant and the equipment design and capacityassociated with each generating unit. However, as stated earlier, the turbine limitations, as shown in Figs 5 and 6,indicate it is generally prohibitive to operate the turbine below 57 Hz. The effects of operating at below rated voltageon the performance of station auxiliary equipment are not covered in this guide.



3.5 Underfrequency Protection Methods for Steam Turbines

Section 3.3 of this guide describes the capability of steam turbines during abnormal frequency operation. This sectionwill describe possible protection methods for preventing turbine operation outside the prescribed limits. Thediscussion will be limited to underfrequency protection. Overfrequency relay protection is generally not appliedbecause governor runback controls or operator action are counted upon to correct the turbine speed. However, duringan underfrequency operation, it may not be possible to restore system frequency due to control limitations andoverload conditions.

3.5.1 System Load Shedding

If system load shedding is provided, then it is considered as the primary turbine underfrequency protection.Appropriate load shedding can cause the system frequency to return to normal before the turbine abnormal limit isexceeded.

It is now common practice to drop load by automatic underfrequency relays in order to maintain a load-to-generationbalance during a system overload [11]. The amount of load shed varies with coordinating regions and individual utilitypractices from 25-50% or more. The frequency trip points and number of steps also vary. Two examples of typicalschemes are given in the Appendix, Tables (A.1) and (A.2).

3.5.2 Need for Turbine Protection

In designing underfrequency load shedding systems, it is necessary to make assumptions about the degree to which anormally interconnected system may break up into islands during a major disturbance. On strongly interconnectedsystems, these assumed islands may be as large as an entire region or system. Load shedding is then provided to permitfrequency recovery in each island for the maximum expected generation deficiency.

If unforeseen circumstances occur, it is possible that a system may break into islands different from those assumed inthe load shedding design. These islands may not contain sufficient load shedding within their boundaries to permitfrequency recovery. If the system design is such that this type of islanding is possible, underfrequency protection ofturbine generators should be considered as a means to reduce the risk of steam turbine damage in the islanded area. Inaddition, if it is credible that the load shedding system may fail (as could occur on a system sensing frequency at acentral location and using communication channels for tripping), turbine generator frequency protection could providebackup protection against such a failure.

Generator underfrequency tripping should be considered as the last line of defense, as it is very likely to cause an areablackout. This risk should be weighed against the risk of possible turbine damage, conceivably to the point of failure,if backup protection is not provided.

3.5.3 Protective System Philosophy

As examples, two schemes are described in 3.5.5 for abnormal frequency protection of steam turbine generators.Philosophy common to both schemes is presented in this section.

A turbine underfrequency protection scheme should be adaptable in order to be able to protect turbines with differentoperating frequency limits. It should also be flexible enough to be adjusted in case underfrequency operating limits arerevised by turbine designers due to new technological discoveries and improved materials applications. The protectivesystem should have a level of security consistent with other relays applied for generator protection. In most powersystems in North America, the probability of an underfrequency event is low; therefore, most of the time, the relaysystem will be called upon to restrain from tripping during normal frequency operation. Station operation informationin the form of alarms for an underfrequency condition is also important. Depending on training and experience, anoperator might not react properly to an alarm, and an automatic protective scheme should be considered.



3.5.4 Criteria for Underfrequency Protection

The following design criteria are suggested as guidelines in the development of an underfrequency protection scheme:

1) Establish trip points and time delays based on the manufacturer's turbine abnormal frequency limits2) Coordinate the turbine generator underfrequency tripping relays with the system automatic load shedding

program3) Failure of a single underfrequency relay should not cause an unnecessary trip of the machine4) Failure of a single underfrequency relay to operate during an underfrequency condition should not jeopardize

the overall protective scheme5) Static relays should be considered as their accuracy, speed of operation, and reset capability are superior to

the electromechanical relays6) The turbine underfrequency protection system should be in service whenever the unit is synchronized to the

system, or while separated from the system but supplying auxiliary load7) Provide separate alarms to alert the operator for each of the following:

a) A situation of less than the nominal system frequency band on the electrical systemb) An underfrequency level detector output indicating a possible impending trip of the unitc) An individual relay failure

3.5.5 Turbine Underfrequency Protection Relay Schemes

Ideally, based on the turbine capabilities, a number of underfrequency relays and timers would be required to fullyprotect the turbine. To avoid unnecessary generator trips during a disturbance from which the system could recover,and to minimize stresses on the turbine, a protection scheme providing five or six frequency bands is desirable. Theideal protection system would accumulate time spent in each underfrequency band and preserve it in a nonvolatilememory.

Two protective schemes are presented here that provide different levels of protection and utilize the turbine abnormalfrequency capability to different degrees.

Scheme 1 provides more complete protection and allows full utilization of the abnormal frequency capability of theturbine, but is more complicated than Scheme 2.

3.5.5.1 Scheme 1

A multisetpoint scheme with frequency band logic and accumulating counters (see Fig 7, block diagram).

Protective Scheme 1 is designed to closely follow the turbine manufacturer's limit curves for underfrequencyoperation. This scheme can be applied where it is desired to fully protect the turbine and allow as muchunderfrequency operation as possible before tripping.

Protection Scheme 1 takes into account the following factors in its application:

1) It utilizes six underfrequency setpoints in addition to supervision steps and takes into account the cumulativetime spent in each underfrequency band (multistage underfrequency relays can be used to reduce the numberof relays required if desired).

2) Scheme 1 accumulates the time spent in each underfrequency band independently and stores it in anonvolatile memory.

3) A time delay of ten cycles (in addition to relay operating time) should occur before accumulation begins toallow the underfrequency blade resonance to be established to avoid unnecessary accumulation of time.

4) When the time for a particular band is used up, an output is given that can be used for alarms or tripping.5) All frequency steps are supervised so that two static relay steps in series are required for an output.6) All outputs are event recorder monitored.



7) Where possible, units are tripped to station service load if the turbine and boiler limits allow. Each machineshould be reviewed for its capability to operate during a full-load rejection. In general, units with drum typeboilers are more capable of continued operation after full-load rejection than are units with once-throughboilers. Units with once-through boilers may be tripped sequentially to prevent turbine overspeeding. In anycase, the unit manufacturer should be consulted before any tripping scheme is implemented.

3.5.5.2 Application Example—Scheme 1 (See Fig 8)

The following is an application example showing Scheme 1 applied to protect a turbine that has the generalized turbineabnormal frequency operating limits shown in Fig 6.

The settings are selected based upon the following criteria:

1) The frequency set points are set equal to or slightly higher than the steps of the turbine abnormal frequencyoperating limits

2) The time delay setpoints are set equal to or slightly lower than the steps of the turbine blade time restrictedoperating limits

3) The settings are modified in some cases to provide coordination with the load shedding scheme

The dotted line in Fig 8 represents the characteristic of the relay setting, whereas the solid line represents the turbineabnormal frequency operating limit for time-restricted operation.

The sample setting shown provides some margin under the turbine damage limit for the trouble-free operation curveand maintains coordination with the system load shedding curve. Counter accumulation times for each band during asystem frequency excursion are also shown.

Table 1 summarizes the frequency and timer settings used in this example for Scheme 1.



Figure 7—Protection Scheme 1—Block Diagram



Figure 8—Application Example—Scheme 1

3.5.5.3 Scheme 2

A four-setpoint scheme—two alarms, a slow trip, and a fast trip (for a block diagram, see Fig 9).

Scheme 2 is a simple protection system using two frequency steps. It may be considered for applications where it isdeemed acceptable to have less than full time versus frequency relay protection for the turbine. Extremely lowprobability of underfrequency occurrence and high reliance on the system load shedding program are factors thatwould be evaluated in considering use of Scheme 2.

Protection Scheme 2 takes into account the following factors in its application:

1) For severe frequency decays (below 58.5 Hz), automatic relay action is taken. For less severe frequencydecays (59.5-58.5 Hz), the system operator will be relied on to take corrective action.

2) The protection engineer should consider an acceptable percentage of available abnormal frequency operatingtime (Fig 6) for the turbine.

3) Scheme 2 does not accumulate time for multiple underfrequency events. Therefore, this scheme does notprotect for multiple underfrequency events whose sam is greater than the turbine abnormal frequencycapability.



4) If the frequency relay timer is set for 50% of the abnormal frequency capability, one event using 50% of thecapability will cause a relay operation.

5) Two static relays must operate for a trip output.

Table 1—Frequency and Timer Settings for Scheme 1

3.5.5.4 Application Example—Scheme 2 (see Fig 10)

3.5.5.4.1 Turbine Protection

The generalized abnormal frequency turbine limits given in 3.3 (Fig 6) apply to this example. In the followingexample, the frequency relay timer setting is adjusted for 50% of the allowable time in the given frequency band.

The dotted line in Fig 10 represents the characteristic of the relay setting, whereas the solid line represents the turbinedamage limit for trouble-free operation.

Table 2 summarizes the frequency and timer settings used in this example for Scheme 2.

3.6 Coordination with System Load Shedding Scheme

3.6.1 Introduction

An underfrequency relaying scheme that protects a steam turbine from the effects of underfrequency should coordinatewith other underfrequency protection schemes used on the connected system. Most large systems now have a loadshedding scheme operated by underfrequency relays. Such a scheme will increase the likelihood of recovering fromsuch a disturbance if properly applied.

The modern steam turbine usually is a sufficiently large part of the system generation such that tripping during arecoverable underfrequency condition could prevent system recovery. Therefore, the turbine underfrequencyprotection scheme should not operate until the automatic load shedding scheme has operated to maintain the systemfrequency at an operable level.

3.6.2 Requirements

In order to coordinate a steam turbine underfrequency protection scheme with a system automatic load sheddingscheme, the following information is required:

Frequency Band (Hz) Time Delay Comments

60.0–59.5 — Continuous operation allowed.

59.5 and below 1.5 sContinuous underfrequency alarm. Time delay to avoid spurious alarms.

59.5–58.858.8–58.058.0–57.557.5–57.057.0–56.556.5 and below

50.0 min*

9.0 min*

1.7 min*

14.0 s*

2.4 s*

1.0 s*

*Indicates total accumulated time set on accumulating timer.

Alarm “underfrequency limitexceeded.” These bands maytrip or alarm depending on individual utilities’ practices.For “alarm,” the operator hasthese respective times to shed load or isolate the unit (based on the limits of Fig 6).



1) A frequency response characteristic of the system for the conditions to be considered, including the effects ofthe automatic load shedding scheme used

2) A time-frequency characteristic of the proposed turbine underfrequency scheme

3.6.3 System Frequency Response

While the approximate frequency response characteristic of a small islanded system is relatively easy to determinefrom information on generator inertia constants and load generation imbalance, a precise determination requirescorrect modeling of the loads, turbine and boiler control, etc. For a large interconnected system, modeling of loads,turbine and boiler control, area load-frequency controls, and spinning reserves are difficult to include in a simplerepresentation of the system. The system load may vary with frequency, as well as voltage, which is also affected byimbalance of load and generation. The generation inertia constants may vary throughout the mix of steam-turbine,hydro, and combustion-turbine generators in the island under consideration. If the system has islanded, each islandwill probably have a different mixture of the above types of generation.

Figure 9—Protection Scheme 2—Block Diagram



The islanded system frequency response is determined primarily by the system inertia constant and the magnitude ofthe internal overload, which is affected by the automatic load shedding scheme of each of the systems included in theisland. The smaller the inertia constant, the faster the frequency decline for a given overload. Newer generating unitsmay have inertia constants of 2 or 3, since the trend in turbine generator design is toward larger outputs with smallerrotor masses. Older generators with massive rotors had inertia constants as large as 10.

Large generating units with smaller inertia constants will tend to dictate the composite system inertia constants, as maybe seen from the following equation [12]:

where subscripts 1,2,…n refer to individual generating units within the system.

MVA 1, … etc

machine base

A system's frequency response characteristic can be determined by using a transient stability type of computerprogram capable of determining system voltage and frequency during a disturbance caused by a sudden imbalance ofload and generation. Such a program should be used very carefully with full awareness of the effects of the modelingused with the program.

Figure 10—Application Example—Scheme 2

Hsystem

H1MVA 1 H2MVA 2 …HnMVA n+ +

MVA 1 MVA 2 …MVA n+ +------------------------------------------------------------------------------------------=

H in MW s–MVA

------------------- on machine base



Table 2—Frequency and Timer Settings for Scheme 2

A utility should identify the condition or conditions of overload or loss of generation from which it can reasonablyexpect to recover. A load shedding scheme can then be applied to optimize the system frequency response.

The Electric Power Research Institute (EPRI) has sponsored several research programs to determine the methods andtools for simulating a system time versus frequency characteristic. Programs were developed that provide time versusfrequency characteristics for various types of systems with various mixes of generation and load imbalance. Theseprograms are lisited in [5], [6], and [7].

3.6.4 Turbine Protection Time-Frequency Characteristic

When a scheme for turbine underfrequency protection is determined and relay setting tentatively determined, a timeversus frequency curve can be drawn for the scheme (see Figs 8 and 10).

3.6.5 Coordination

The system frequency response should be compared with the turbine protection characteristic to determine ifcoordination between the two exists. For example, in Fig 8 the relay characteristic is a series of frequency bands. Inorder to trip, the system frequency must remain inside a particular band (that is, below the pick-up point) in excess ofthe time setting for that particular band. In Fig 8, the 57.5–58.0 Hz band is set at 1.7 minutes. The frequency remainsbelow 57.5 and 58.0 Hz for 0.012 minutes; therefore, the relay would not trip on this incident alone. However, the timein a band may be cumulative depending on the scheme used and the previous history may have stored sufficient timesuch that this incident could cause the relay to trip. Precaution should be taken to assure that the turbine protectionfrequency relay has sufficient associated time delay to prevent tripping on a recoverable swing. The protectionengineer should decide how much margin is necessary. This may be influenced by whether the relay scheme trips theturbine or alarms. There has not been sufficient experience with these turbine protection schemes to determine therequired margin by experience, so one should rely on judgment at this time.

If there is insufficient margin between a recoverable swing and tripping a turbine for a projected system frequencyresponse, there are several options available:

1) Modify the load shedding scheme by increasing the number of steps or the amount of load to be shed. Thisshould change the frequency response sufficiently to allow the desired margin to be obtained.

2) Modify the turbine protection scheme to take additional risk of loss of blade life for the turbine.3) Accept that, for worst-case conditions, coordination is not possible for the degree of turbine protection

desired.

Frequency Band (Hz) Time Delay Comments

60.0–59.5 —No relay action—turbine can operate continuously.

59.5 None Frequency recorder alarms.

59.5–58.5 —System operator must shed load or isolate the unit within 30 min (based on limits of Fig 6).

58.5–57.057.0 and below

5.0 min1 s

These bands may trip or alarmdepending on individual utilities’ practices. For “alarm,” the operator has these respective times to shed load or isolate the unit (based on the limits of Fig 6).



Options 1 or 2 could be employed to add margin to the scheme. The user should decide what is the most important forhis application and make a decision accordingly. In general, option 2 would be the least desirable compromise to make.The best choice would be to go as far as possible or practical with option 1 before having to resort to options 2 or 3.

3.7 Generator-Transformer Overexcitation

Overexcitation of generators and transformers may result in thermal damage to cores due to excessively high flux inthe magnetic circuits. Excess flux saturates the core steel and flows into the adjacent structure causing high eddycurrent losses in the core and adjacent conducting materials. Severe overexcitation can cause rapid damage andequipment failure.

Since flux is directly proportional to voltage and inversely proportional to frequency, the unit of measure for excitationis defined as per unit voltage divided by per unit frequency, volts/hertz (V/Hz). Overexcitation exists whenever the perunit volts/hertz exceeds the design limits of the equipment; for example, a large steam-turbine generator designed fora voltage limit of 1.05 per unit at rated frequency will experience overexcitation whenever the per unit volts/hertzexceeds 1.05. Should the voltage exceed 105% at rated frequency, or the frequency go below 95% at rated voltage,overexcitation will exist.

3.7.1 Generator-Transformer Overexcitation Limitations

The manufacturer's volts/hertz limit should be obtained individually for the transformer and the generator. Thetransformer and generator volts/hertz limits are generally in the form of curves (Fig 11). Some generatormanufacturers recommend protective relay settings instead cf a capability curve.

It should be noted that the limiting condition for the generator step-up transformer (GSU) is the voltage at the high-voltage terminals in accordance with paragraph 4.1.6 of ANSI/IEEE C57.12.00-1980 [2]. This paragraph states thattransformers shall be capable of operating continuously at full load, with a secondary (highside GSU) voltage andvolts/hertz no greater than 105%, a power factor of 80% or higher and frequency at least 95% of rated values. At noload it shall be capable of operating continuously with a voltage and volts/hertz no greater than 110% of rated values.

The full-load operating requirement can be demonstrated by the following example. The low-voltage terminals of theGSU must have the ability to operate at any voltage that results from subtracting the voltage drop across the leakagereactance vectorially.

Transformer rating: 806.4 MVA @ 0.8 p.f.lagging VH = 500 kV

VL = 22.8 kV

Generator rating: 24 kV

NOTE — In this example, the transformer low-winding voltage rating is 95% of the generator voltage rating.



Figure 11—Overexcitation Limitations (No-Load Conditions—Various Manufacturers)

1 per unit load at 0.8 p.f. lagging with VH = 105% yields the following percent current at rated MVA load:

The low-side voltage VL = 113.18% of the 22.8 kV rating.

This is (22.8)(113.18%)/24 = 107.52% on the generator rating.



The calculated voltage of 107.52% exceeds the generator-rated voltage limitation of 105%. Therefore, the high-sidevoltage, VH, must be limited to approximately 102%.

This calculation demonstrates that the no-load transformer operating requirement of 110% is more stringent than the113.18% full-load requirement calculated above. Volts/hertz protection should be based on the 110% over-voltage limit.Note that the transformer over-excitation limitation curves in Fig 11 asymptotically approach the 110% volts/hertz limit.

The limit curves should be modified to reflect differences, if any exist, in equipment voltage ratings resulting in asingle volts/hertz limit for the generator-transformer unit connected scheme. To determine the generator-transformervolts/hertz limit, the curve for the generator step-up transformer (GSU) should be plotted on the generator voltagebase, together with the generator limits.

Assume that the generator volts/hertz limit curve for manufacturer 2 and the transformer volts/hertz limit curve formanufacturer 5 describe the volts / hertz capability of the unit connected scheme in the previous example. Since, in thisexample, the transformer low-voltage rating is 95% of the generator voltage rating, the transformer curve must belowered by a factor of 0.95 and replotted on the generator volts/ hertz limit curve as shown in Fig 12.

Figure 12—Dual-Level Volts/Hertz Setting Example

3.8 Generator-Transformer Volts/Hertz Protection

Volts/hertz protection needs generally arise from different situations than those for which turbine underfrequencyprotection is provided. Turbine-generator shutdown with the automatic voltage regulator left in service, sudden loadrejection with the automatic voltage regulator out of service, and manual excitation adjustment during startup withfaulty metering are events that support the need for volts/hertz protection. The following recommendations showvolts/hertz protection schemes that provide protection for both the generator and transformer on unit connectedschemes. The more commonly employed methods are discussed.



3.8.1 Volts/Hertz Limiter or Regulator

One approach to providing overexcitation protection is to use a volts/hertz limiter that is available with the automaticvoltage regulators used on some generators. The volts/hertz signal is combined with the voltage regulator signal tolimit generator field current to hold the generator output voltage to safe volts/hertz values. For example, a limiter setfor a maximum volts/hertz of 105% will maintain this value for all frequencies below 1/1.05 of normal frequency.

For frequencies above 1/1.05 per unit of normal frequency, the voltage regulator will maintain the set value of voltage.The limiter is usually supplemented with volts/hertz relaying that can initiate protective action after a time delay bytripping the machine. This provides protection should the voltage regulator malfunction or be out of service.

3.8.2 Volts/Hertz Protection

Some manufacturers recommend that the volts/hertz protection should be in service at all times. Some users disablethe volts/hertz protection when the unit breakers are closed since system load should limit the volts/hertz to anacceptable level. When the unit breakers are closed, the decision to trip or not should be based on system design andoperating considerations. Any system conditions such as opening of remote breakers that can cause an excessive volts/hertz condition on the transformer or generator would require that the relay be connected to trip to avoid damage.

3.8.2.1 Dual-Level Volts/Hertz Protection

The dual-level volts/hertz protection scheme employs two separate volts/hertz relays and two timers. These areconnected such that relay A initiates timer A, and relay B initiates timer B.

Please refer to Fig 12 for a dual-level volts/ hertz setting example. The settings for the two relay steps should bederived using the following recommendations.

Relay A. The level detector pickup for relay A should be set in the range of 1.07–1.10 per unit volts/hertz on thegenerator voltage base. The time delay for relay A should be selected in conjunction with the relay B level detectorpickup to provide coordination with the minimum limit curve.

Relay B. The level detector pickup for relay B should be set in the range from 1.18–1.20 per unit volts/hertz. The timedelay for relay B should be in the range of 2–6 seconds to prevent transient voltage and frequency excursions fromcausing unnecessary unit tripping. It should be recognized that the actual level of volts/hertz would be in excess of thetrip setting, hence the time setting should be kept low, as indicated, to provide adequate protection.

If manufacturers’ recommended relay settings are available for a given installation, these settings should be verifiedagainst the limit curves and applied to the dual-level protection scheme. This example shows the appropriate setting forthe combination volts/hertz limit curve for the generator and step-up transformer.

Relays A and B should trip the generator breaker and the generator field through separate lockout relays forredundancy. The need to trip the turbine will depend on whether the unit is on-line or off-line when the overexcitedcondition occurs, the type of unit, and the boiler design. If the unit is off-line at the time over-excitation occurs, it isonly necessary to trip the generator field. However, manufacturers’ tripping recommendations should be followed,when available.

For units that can operate under the control of a dc regulator (manual control), the relaying should be so designed thatit initiates tripping with no intentional time delay when a condition occurs that causes the volts/hertz ratio to exceed1.10 per unit. This action will assist in preventing machine damage for very high volts/ hertz conditions that result fromhaving rated field current on the generator at no load.

3.8.2.2 Volts/Hertz Connection Details

Typical volts/hertz relays are single-phase devices. Complete and redundant protection should include the followingconsiderations:



1) Connect one set of relays to voltage transformers that supply the voltage regulator. A second set should beconnected to a different set of voltage transformers, such as those used for metering. Battery supplies shouldbe separated.

2) Operators should recognize conditions of a voltage transformer fuse failure. Sensing of all three phasevoltages may be necessary.

3) Avoid having a voltage balance relay (device 60) block all protection.4) Provide alarm and inhibit circuits that prevent exceeding a safe level of excitation when a unit is off-line.

3.8.3 Inverse Characteristic Volts/Hertz Protection

A volts/hertz relay with an inverse characteristic can be applied to protect a generator or transformer, or both, fromexcessive volts/hertz. A minimum operate level of volts/hertz and time delay can usually be set to provide adequateprotection for the generator-transformer combined volts/hertz characteristics, as discussed in 3.7.1. Themanufacturer's volts/hertz limitations should be obtained if possible, and used to determine the combinedcharacteristic.

One version of the inverse characteristic volts/hertz relay has a separately set volts/ hertz unit with an adjustabledefinite time delay. This unit can be connected to trip or alarm and extend the ability of the relay characteristic tomatch the volts/hertz characteristic of a generator-transformer combination.

The generator manufacturer's tripping recommendations should be followed if available. Most manufacturers are nowrecommending that the unit be tripped with no additional time delay by the volts/hertz relay.

Figure 13 shows an example of a volts/hertz relay with an inverse characteristic set to protect a typical generator-transformer combination.

Figure 13—Volts/Hertz Setting Example



4. Nuclear Generating Plant—Special Consideration


This section presents guidelines associated with protection of nuclear generating plants during abnormal frequencyconditions. The material presented deals mainly with the underfrequency considerations that affect operation of thenuclear steam system. The turbine generator considerations for a nuclear plant are, in general, the same as describedin Section 3 and no further discussion is included here. In general, the main effect of frequency changes on a nuclearsteam system is that output of electrical pumps in the system will vary with frequency. This will cause various coolantflows in the system to change. In some cases, reduced flows in parts of the system may be detrimental to equipment,and safeguards should be considered. The boiling water reactor (BWR) and the pressurized water reactor (PWR) areanalyzed separately because their responses to abnormal frequency operation differ.

4.2 Boiling Water Reactor (BWR)/Underfrequency Considerations

Some boiling water reactor (BWR) units employ nonseismically qualified motor-generator sets to supply power to thereactor protection systems. To ensure that these systems have the capability to perform their intended safety functionsduring a seismic event for which an underfrequency condition of the motor-generator sets or alternate supply coulddamage components of these systems, redundant underfrequency relays are provided. This protection is installedbetween each motor-generator set and its respective reactor protection system bus, and between the alternate powersource and the reactor protection system buses. Operation of either or both of the underfrequency detectors associatedwith a reactor protection system bus will cause a half-scram of the unit. If one or both of the underfrequency detectorsoperate on each of the reactor protection system buses, a full scram of the unit occurs.

There are several factors that should be considered in the setting of the underfrequency relays for BWR units:

1) The tolerance characteristic of the underfrequency relay2) The slip characteristic of the motor-generator (MG) sets3) The characteristics of the power system load shedding schemes

A combination of a plus tolerance on the underfrequency relay and a relatively high slip of the motor-generator setsmay make coordination with the load shedding schemes difficult to attain. As an example, an underfrequency relaywith a 2% tolerance and a motor-generator set with a 1% slip characteristic would require an underfrequency settingof less than 57 Hz to obtain coordination with a load shedding program that limits the decline in frequency to 58 Hzfor typical islanding conditions.

4.3 Pressurized Water Reactor (PWR)/Underfrequency Considerations

The fundamental effect of abnormal system frequency on a nuclear generating plant employing a pressurized waterreactor (PWR) is to the reactor coolant flow rate. The flow rate of the reactor coolant is proportional to the reactorcoolant pump speed, which varies with the power system frequency.

PWR design requires that the coolant flow rate through the reactor core be proportioned to the rate of heat productionin the reactor. This prevents the actual heat flux in the reactor from reaching the critical heat flux level, at which pointfuel rod cladding damage would occur due to localized steam bubble or void formation at the cladding surface. Themeasure of this critical heat flux to the actual heat flux (measured or calculated) is called the departure from nucleateboiling ratio, or DNBR. Historically, PWR design called for minimum DNBRs of approximately 1.3, but newer designratios on some reactors are smaller.

If the power system frequency at a nuclear generating plant collapses, the reactor will be tripped automatically whenlimiting reduced coolant flow conditions exist. Sufficient coolant can then be delivered to the reactor core by the



reactor coolant pumps driven by motors with huge flywheels that are sized to coast down at a rate consistent with thereactor core design.

When the reactor trips, normally the generator synchronizing breakers are tripped and the reactor core is shut down—but the reactor coolant pump motors remain connected to the power system. If the power system frequency decays ata rate greater than the designed “freewheel” coast down rate of the flywheel, the reactor coolant flow rate will beforced down by the decaying system to the point where the plant's DNBR may not be maintained. This is one of themore serious impacts that underfrequency can impose on a PWR plant.

One solution that was proposed for this condition was to automatically separate the reactor coolant pumps from thepower system if the system frequency rate of decay exceeds the flywheel's coast down rate.

To accomplish this, however, it is required that the switchgear supplying the reactor coolant pumps meet all therequirements of Class 1E equipment in a nuclear power plant; this is difficult and costly to achieve. The preferredapproach is to apply an underfrequency relay to trip the reactor at a frequency such that the DNBR does not go belowa minimum specified level during the time the control rods are lowered and the coolant pumps are coasting down.Since the coast down is related to the system frequency decay rate, a determination of the maximum system decay ratemust be made.

It is recognized by the electric utility industry that the frequency rate of decay in most power systems will probably notexceed 5 Hz/s. Regardless, it should be noted that the frequency decay rates calculated by methods excluding practicallimits of generator loading or system damping are conservatively high.

In most power systems that are left isolated and overloaded, system voltage will decline along with system frequency.This effect will result in the rate of decay of system frequency being less than the freewheel coast down rate of thereactor coolant pumps. Where this condition can be shown to exist, it has been determined that the requirement toinclude underfrequency tripping of the reactor is not necessary.

In summary, the following parameters should be considered when applying underfrequency protection to a PWR plant:

1) The designed DNBR of the plant2) The size of the coolant system with respect to the reactor core3) The rating of the core with respect to loading4) The maximum rate of power system frequency decay that may be encountered5) Coordination with power system load shedding schemes6) System voltage conditions that exist at the time of a system frequency decline

As may be expected from examination of the listed parameters, a joint effort of the manufacturer and the utilityengineer is required to arrive at an underfrequency setting that assures adequate reactor core protection. But it isgenerally considered the customer's responsibility to ascertain that the manufacturer's plant design specifications areadequate to cover worst-case underfrequency conditions on the utility system.

5. Combustion-Turbine Underfrequency Operation


The underfrequency limitations for combustion-turbine generators (CTGs) are similar in many respects to thelimitations for steam-turbine generators. There are, however, certain differences in the design and application of CTGsthat may result in different protective requirements. These differences are emphasized in the following subsections.



5.2 Combustion-Turbine Underfrequency Capability

While manufacturers should be consulted for their specific recommendations, CTG underfrequency capability forcontinuous operation generally ranges from 57–60 Hz as limited by the turbine blades.

CTGs have a unique operating control requirement that, to some extent, protects the turbine generator duringunderfrequency conditions. A combustion turbine may lose air flow if an attempt is made to maintain full outputduring underfrequency conditions. Loss of air flow would result in eventual unit trip on blade over-temperature. Ingeneral, CTGs are equipped with a control that automatically unloads the unit by reducing fuel flow as speeddecreases. This control has the overall effect of protecting the blading from damage and the generator fromoverheating during underfrequency operation of the unit.

5.3 Underfrequency Protection Philosophy, Relay Settings, and Guidelines

5.3.1 Protection Philosophy and Relay Settings

One reason that combustion-turbine generators are installed is for peak shaving purposes because of their fast startupcapability. Another important application of fast startup is its potential for aiding in the prevention of system collapseand in system restoration following such a collapse. Underfrequency protection philosophy should reflect theseapplications and, therefore, may be substantially different from the philosophy for larger, steam-driven units.

Underfrequency conditions will occur when part of a system has become islanded with insufficient local generation.This generation may contain a mixture of CTGs and steam units. If the proportion of CTGs is negligible, no generalrecommendations for underfrequency protection can be made, and the user should tailor the protection to the specificapplication of each unit. If the proportion of CTGs is significant, the premature loss of these units may result in the lossof the island. In this case, every effort should be made to keep the CTGs in operation for as long as frequencyconditions permit the steam units to operate.

This should not present a problem since CTGs, in general, have a greater capability than steam units forunderfrequency operation, particularly if the control system includes a load-runback feature. These factors suggest anunderfrequency protection scheme with a single trip setpoint at or below the lowest underfrequency trip setpoint forthe steam units in the vicinity.

Temporary frequency variations may well occur during system restoration following a blackout. The importance ofquick restoration would seem to outweigh the risk of some turbine blade damage during this period, and considerationshould be given to a facility for manual defeat of the protection under this condition.

5.3.2 Protection Guidelines

The following guidelines should be considered when applying underfrequency protection to combustion turbines:

1) Use one underfrequency relay per unit supplied by the unit voltage transformer.2) If added security is desired, supervise tripping with a second underfrequency relay. This relay may be

common to several units.3) Be aware of existing underfrequency protection provided by the manufacturer in the unit's control system.

Coordination of settings and trip logic may be required to avoid interference with external protection.

5.4 Underfrequency Protection Considerations for Combined Cycle Generating Units

In a combined cycle generating installation, which is a combination of a combustion-turbine unit and a steam-turbineunit, each unit would be subjected to the same underfrequency limitations as discussed in the respective sections forthese types of units. A recommended approach for protecting a combined cycle installation is to provide separateunderfrequency protective schemes for each unit of the combined cycle installation. The method used for protection ofeach unit could follow the method described in the specific section of this guide. That is, the steam-turbine unit wouldfollow the recommendations in Section 3 and the combustion-turbine unit would follow recommendations in Section 5.



6. Bibliography

[B1] BALDWIN, M. S., ELMORE, W. A., and BONK, J. J. Improve Turbine-Generator Protection for IncreasedPlant Reliability. IEEE Transactions on Power Apparatus and Systems, vol PAS-99, May/June 1980, pp 982-989.

[B2] BALDWIN, M. S. and SCHENKEL, H. S. Determination of Frequency Decay Rates During Periods ofGenerator Deficiency. IEEE Transactions on Power Apparatus and Systems, vol PAS-95, Jan/Feb 1976, pp 26-36.

[B3] BERDY, J., BROWN, P. G., and GOFF, L. Protection of Steam Turbine Generators During Abnormal FrequencyConditions. General Electric Company, 1974, Protective Relaying Conference, Georgia Institute of Technology.

[B4] DALZIEL, C. F. and STEINBACH, E. W. Underfrequency Protection of Power Systems for System Relief, LoadShedding-System Splitting, AIEE Transactions on Power Apparatus and Systems, vol PAS-78, Dec 1959, pp 1227-1238.

[B5] HAHN, R. S., DISGUPTA, S., BAYTCH, E., and WILLOUGHBY, R. D. Maximum Frequency Decay Rate forReactor Coolant Pump Motors.IEEE Transactions on Nuclear Science, vol NS-26, Feb 1977, pp 863-870.

[B6] HOHN, A. and NOVACEK, P. Last-Stage Blades of Large Steam Turbines. Brown Boveri Review, vol 59, Jan1972, pp 42-53.

[B7] HOROWITZ, S. H, POLITIS, A., and GABRIELLE, A. F. Frequency Actuated Load Shedding and Restoration,Part 2—Implementation. IEEE Transactions on Power Apparatus and Systems, vol PAS-90, 1971, p 1460.

[B8] IEEE Committee Report. The Effect of Frequency and Voltage on Power System Load. Presented at the IEEEWinter Power Meeting, New York, NY, Jan 30-Feb 4, 1966.

[B9] IEEE Committee Report. Survey of Underfrequency Relay Tripping of Load Under Emergency Conditions.IEEE Transaction on Power Apparatus and Systems, vol PAS-87, Mar 1968, pp 1362-1366.

[B10] LOKAY, H. E. and BURTNYK, V. Application of Underfrequency Relays for Automatic Load Shedding. IEEETransactions on Power Apparatus and Systems, vol PAS-78, Mar 1968, p 776.

[B11] LOKAY, H, E., and THOITS, P. O. Effects of Future Turbine Generator Characteristics on Transient Stability.IEEE Transactions on Power Apparatus and Systems, vol PAS-90, Nov/ Dec 1971, pp 2427—2431.

[B12] MALISZEWSKI, R. M., DUNLOP, R. D., and WILSON, G. L. Frequency Actuated Load Shedding andRestoration, Part 1—Philosophy. IEEE Transactions on Power Apparatus and Systems, vol PAS-90, 1971, p 1452.

[B13] MERRIAN, M. M. and VANDEWALLE, D. J. The Effect of Grid Frequency Decay Transients on PressurizedWater Reactors. IEEE Transactions on Power Apparatus and Systems, vol PAS-95, Jan/Feb 1976, pp 269-274.

[B14] NARAYAN, V. Monitoring Turbogenerators in the Underfrequency Range. Brown Boveri Review, vol 67, Sept1980, pp 530-534.

[B15] NARAYAN, V., SCHINDLER, H., PENCINGER, C., and CARREAU, D. Frequency Excursion Monitoring ofLarge Turbo-Generators. IEE (London) Conference on Developments in Power-System Protection, Publication No185, 10-12, June 1980, pp 45-48.

[B16] SOMM, E. and STYS, Z. S. The Development of Last-Stage Blades for Large Steam Turbines. Proceedings ofthe American Power Conference, vol 38, 1976, pp 581-589.

[B17] WARNER, R. E., DILLMAN, T. L., and BALDWIN, M. S., Off-Frequency Turbine Generator Unit Operation.American Power Conference, Apr 1976.


ANSI/IEEE C37.106-1987

Annex

(This Appendix is not a part of ANSI/IEEE C37.106-1987, IEEE Guide for Abnormal Frequency Protection for Power GeneratingPlants, but is included for information only.)

Table A-1 —Typical Load Shedding Scheme with 3 Steps

Table A-2 —Typical Load Shedding Scheme with 6 Steps

StepFrequency Trip Point

(Hz) Percent of Load ShedFixed Time Delay

(Cycles) on Relay*

*Auxiliary relay and breaker time should be added to obtain tripping time.

123

59.358.958.5

1015

As required to arrest decline before 58.2 Hz

66

StepFrequency Trip Point

(Hz) Percent of Load ShedFixed Time Delay

(Cycles) on Relay*

*Auxiliary relay and breaker time should be added to obtain tripping time.

1 59.5 10 6

2 59.2 10 6

3 58.8 5 6

4 58.8 5 14

5 58.4 5 14

6 58.4 5 21

Documents

Abnormal Frequency Protection for Generating Power PLant-IEE C37.106-1987