application aspects of generator and excitation system for process plants

IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 35, NO. 3, MAY/JUNE 1999 703

Application Aspects of Generator andExcitation System for Process Plants

Shoaib Khan, Senior Member, IEEE

AbstractThis paper has been prepared to provide a betterunderstanding of the subject matter and to serve as a guidefor those involved in engineering, maintenance, and operationof turbogenerators in a process plant. The paper covers allaspects of a turbogenerator and the system considerations thatare required to achieve a reliable power system and minimizepower outage during system disturbances. These include thefollowing: 1) generator parameters; 2) excitation system; 3)neutral grounding; 4) protection; 5) synchronizing; 6) integrationinto the power system; 7) utility interface; and 8) islanding.Additional reference is provided for further investigation andclarification into the subject matter.Index Terms Excitation system, generator neutral ground-

ing, generator parameters, generator protection, synchronizing,system integration, utility interface, islanding.

I. INTRODUCTION

THE purpose of a turbogenerator in a process plant is toproduce power, save energy cost, and minimize poweroutages during system disturbances. The turbine is sized tomatch the available steam, and the generator is selected toproduce active (megawatt) and reactive (megavar) power.A properly selected generator and excitation system will

allow a ride-through during system disturbances and reducethe number of plant shutdowns. This paper provides someguidelines in the selection and application of generator andexciter that are important for the overall system operation.These include the following: generator rating and parameters; excitation system; neutral grounding considerations; protection considerations; synchronizing; integration into the power system; plant power system and utility interface; system disturbances and islanding.

II. GENERATOR RATING AND PARAMETERSGenerator rating (output) is given in megavoltamperes,

which is the vector sum of its megawatt and megavar output.The megawatt rating is determined by the turbine capability,and the megavar or power factor rating is selected to meet thePaper PID 9822, presented at the 1998 IEEE Pulp and Paper Industry

Conference, Portland, ME, June 1620, and approved for publication inthe IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS by the Pulp and PaperIndustry Committee of the IEEE Industry Applications Society. Manuscriptreleased for publication November 3, 1998.The author is with Sandwell Inc., Montreal, PQ H3B 4V8, Canada.Publisher Item Identifier S 0093-9994(99)03847-5.

Fig. 1. Generator capability curve.

load reactive power requirements and voltage support. Thereis a tendency to purchase the generator with a lower powerfactor, i.e., larger megavoltampere rating than is necessary.Larger generator frames contribute higher short-circuit currentsand introduce higher losses such as windage and core, as wellas losses associated with higher current. It is better topurchase the generator with adequate megavar capability anda high-performance excitation system.A typical generator reactive capability curve is shown in

Fig. 1. Reference [2] states:the generator shall operate successfully at rated kVA,

frequency and power factor at any voltage not more than5% above or below rated voltage, but not necessarily inaccordance with the standard performance establishedfor operation at rated voltage.

Capability curves for other generator voltages can be obtainedfrom the manufacturer. At lower than rated voltage, theunderexcited var capability is reduced, whereas the overexcitedvar capability is unaffected for 5% voltage variation fromthe rated voltage.Generator parameters that are of importance for the indus-

trial power system are short-circuit ratio (SCR), subtransientreactance ( ), and transient reactance ( ).

00939994/99$10.00 1999 IEEE

704 IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 35, NO. 3, MAY/JUNE 1999

Fig. 2. Typical brushless excitation system. Rotating components are mounted on the same shaft.

SCR is the ratio of the field current at no-load rated voltageto the field current required to produce rated armature currentwith short-circuited generator terminals. A higher value ofSCR is an indication of greater stability margin. With theapplication of high-speed regulator and exciter, SCR in theorder of 0.5 or higher is considered to be adequate.Subtransient reactance ( ) determines the initial generator

current during faults. A standard value in the order of 10%for 3600 r/min (two-pole) and 15% for 1800 r/min (four-pole) machines is used. Short-circuit contribution is alwaysa problem for integrating a generator into an existing powersystem. We do not recommend a value higher than 15%for two- or four-pole machines. Transient reactance ( ) isgenerally 150% of and a higher value compromiseson stability.Another important criteria to be applied to the generator

and excitation system is that they must deliver a sustainedshort-circuit current of 3.0 pu for 10 s. This feature allows theprotective relay settings to operate within a reasonable time.

III. EXCITATION SYSTEMThe excitation system consists of an exciter, voltage regula-

tor, and power supply. The system plays an important role inrecovery and voltage support during system disturbances. Thesalient features of the excitation system for a process plantgenerator shall be as follows:1) high ceiling voltage in the order of 4.0 pu or higher

from rated load field voltage;2) field forcing or ceiling current of 2.25 pu or higher;3) capable of changing the generator field voltage from

the voltage at the rated capacity and voltage to ceilingvoltage in less than 150 ms;

4) high response ratio.

The response ratio is defined as the average rate of increaseof field voltage during the first 0.5 s divided by the rated fieldvoltage [5]. In general, the higher the response ratio of theexciter, the better is the transient stability of the system.A high initial response (HIR) excitation system is capable

of attaining 95% of difference between ceiling voltage andfield-rated voltage in 100 ms or less. However, for small- andmedium-size brushless units used in process plants, an HIRexcitation system is costly and difficult to build.Two types of exciters, brushless and static, are available.

A. Brushless Excitation SystemMedium- and high-speed machines with ratings up to sev-

eral hundred megavoltamperes utilize brushless excitation sys-tems. A typical brushless excitation system is shown in Fig. 2.The brushless excitation system includes an alternatorrectifiermain exciter and a permanent magnet generator pilot exciter(PMG), both directly driven from the synchronous generatorshaft. Field power for the main exciter is supplied from thePMG, which has a set of rotating permanent magnets and astationary three-phase armature. The high-frequency (420 Hz)output from the PMG is rectified to provide excitation for themain exciter. The three-phase output of the rotating armatureof the main exciter is fed along the shaft to the rotating rectifiersystem, the dc output of which is conducted to the synchronousgenerator field. Fuses are connected in series with the diodes toprotect the main exciter windings. Redundant diodes must beprovided to prevent generator outage on the loss of a limitednumber of diodes per phase.Brushless excitation system without PMG offers a faster

response to transients. In this system, an ac source, either fromthe generator terminals or auxiliary power supply, is rectifiedto provide excitation for the main exciter. A dc source from a

KHAN: GENERATOR AND EXCITATION SYSTEM FOR PROCESS PLANTS 705

(a) (b) (c) (d) (e)Fig. 3. Neutral grounding methods.

station battery must be provided to achieve field forcing whenthe ac source voltage dips to 80% or lower. This dc sourceprovides power for field flashing when the ac source is takenfrom the generator terminals.The brushless excitation system completely eliminates com-

mutators, collector rings, and carbon brushes, and system faultsdo not affect the source of excitation.

B. Static Excitation SystemThe static excitation system is used for large turbogener-

ators, hydrogenerators, and where fast transient response isrequired. The system comprises a power transformer, thyristor-controlled rectifier, electronic regulator, and a de-excitationunit. The excitation power is taken from the generator ter-minals, rectified, and fed to the generator field winding viacollector rings. The system can provide a high ceiling voltage,extremely short voltage response time, and negative fieldforcing.Excitation systems for hydroelectric generators are gener-

ally provided with a three-phase full-wave thyristor bridge.This arrangement has the ability to provide both a positiveor negative voltage to the field and decreases the recoverytime during a full-load rejection accompanied by overspeedcondition.

C. Voltage RegulatorThe voltage regulator shall be an automatic/manual, high

speed, continuously active, negligible deadband, static type,complete with the following features: voltage- and current-sensing elements responsive to gen-erator voltage and current, respectively;

var/power factor and volts/hertz controls; limiters to control rotor angle and current; loss of potential protection, including transfer of controlsfrom automatic to manual;

manual voltage-adjusting device follows the regulatorvoltage-adjusting device;

transfer of voltage control from regulator to manual modeand vice versa from a remote point.

IV. NEUTRAL GROUNDING CONSIDERATIONSThe objectives of generator neutral grounding are as fol-

lows: minimize the damage for internal ground faults; limit mechanical stresses in the generator for externalground faults;

limit temporary and transient overvoltages on the gener-ator insulation system;

provide a means of system ground fault detection; coordinate with the requirements of other equipmentconnected to the system.

Generator neutral grounding methods are shown in Fig. 3.

A. Solidly Grounded Neutral [Fig. 3(a)]This method is not recommended for the following reasons: risk of mechanical damage from line-to-ground faults; abnormal third harmonic current flow; generator is normally designed to withstand stresses as-sociated with three-phase faults at the machine terminals.Because of low zero-sequence impedance in generators,a solid phase-to-ground fault at the machine terminalswill produce higher winding currents than those from athree-phase fault.

B. High-Resistance (HR) GroundingThe neutral current is limited to 515 A. The main advan-

tages are the following: minimum damage from internal ground faults; transient overvoltage is limited.The criteria for HR grounding are

or

where is the effective neutral resistance and is thecapacitive reactance of the three phases.1) Resistor Directly Connected to Neutral: This method is

not recommended as high resistance and low current make theresistor more fragile and prone to mechanical damage.2) Distribution Transformer/Resistor Combination [Fig.

3(c)]: In this arrangement, a single-phase distributiontransformer is used for the neutral grounding, and the resistoris connected to the secondary. This combination permitsthe application of a robust and higher current-rated resistor.References [8] and [18] have provided guidelines for sizingtransformer and resistor.

C. Low-Resistance Grounding [Fig. 3(b)]This method permits coordination with other equipment

connected to the system and is generally used where: generator is connected directly to the plant load bus withoutgoing feeders;

two or more generators bused at generator voltage areconnected to the system through one step-up transformer.

The resistor rating is usually from 100 A to 1.5 times generatorfull-load current with a short time rating of 10 s.


D. Grounded Through a Grounding Transformer [Fig. 3(d)]This method is used to provide low-resistance grounding for

the same purpose as above and offers some advantages. A zig-zag grounding transformer with a neutral resistor is connectedto the bus. The ground current is not affected by the numberof units connected to the bus or system interconnections.In addition to the zig-zag transformer, each generator shall

be provided with a high-resistance grounding. This arrange-ment will provide ground-fault protection during unit startupand synchronizing.

E. Low-Reactance Grounding [Fig. 3(e)]This method is generally used where the generator is con-

nected directly to a distribution system with solidly groundedneutral. The inductive reactance is selected to give. Low-reactance grounding produces phase-to-ground faultcurrents ranging from 25% to 100% of the three-phase faultcurrent. There is a possibility of iron core damage for internalfaults.

and are zero-sequence and positive-sequence reac-tance, respectively.This method is not recommended for process plants.

F. Resonant GroundingThis method is similar to high-resistance grounding using

transformer-resistance combination, except that the resistor isreplaced by a reactor. The reactor is selected so that the induc-tive reactance matches the three-phase capacitive reactance ofthe equipment. On line-to-ground fault, the system-chargingcurrent is neutralized by an equal component of the inductivecurrent.

V. PROTECTION CONSIDERATIONSThis subject is well covered in [9] and [10]. A typical

protection scheme for a low-resistance grounded generatorconnected to a plant load bus is shown in Fig. 4. The followingcriteria are recommended as a minimum for the selection ofprotection relays: proven experience of a minimum period of three yearsand tested to ANSI/IEEE Standards;

digital integrated protection scheme, microprocessorbased, with self-checking and self-diagnostics.

Most of the digital integrated generator protection packagesdo not have out-of-step and ground differential elements.These features shall be provided by separate protective ele-ments. Some of the integrated protection units include fourtrip relays which permit the grouping of protective elementsto provide trip output contacts.A review and further consideration are given to the features

and setting of the following elements.1) Accidental Energization (AE): This feature or an inter-

lock must be provided to prevent human error in the closingof the generator breaker when the turbine is not running.Integrated generator protection relays include a logic circuitto achieve this feature.2) Volts per Hertz [24 in Fig. 4(a)]: This feature protects

the generator and transformer if full voltage is applied whilethe frequency is reduced, which might occur during isolated

operation or malfunction of the voltage regulator. The setpoints or relay operating curve shall be below the generatorand transformer limit curves. The generator limit curve isavailable from the manufacturer, and the transformer limitcurve provided in [12] can be used.3) Reverse Power or Antimotoring [32 in Fig. 4(a)]:

Motoring of generator occurs when, for some reason, theenergy supply to the prime mover is cut off while the generatoris still on the line. Primary indication of motoring is the flowof real power into the generator. The estimated power requiredto motor the idling prime mover is as follows:1) diesel engineabout 25%;2) hydro unit0.2%2%;3) steam turbine0.5%3%.Reverse power relays are supplied with time delay (up to

30 s) to prevent operation during power swings caused bysystem disturbances or synchronizing.The relay or element is set at about 50%70% of the

motoring power, which can be obtained from the manufactureror measured during commissioning. Two relays [32-1 and 32-2in Fig. 4(a)], each with an integrating timer, must be provided.The timer for 32-1 is set at about 3 s to protect against lossof steam to the prime mover and can be used for sequentialtripping. The timer for 32-2 is set at 1030 s to override thepower swings.4) Loss of Field/Excitation [40 in Fig. 4(a)]: Excitation

can be lost due to field open circuit, field short circuit,regulation system failure, or loss of power supply to theexcitation system.For a steam turbine, the unit will overspeed and operate as

an induction generator. It will supply power to the system andreceive vars from the system. The stator current can be 2.0 puand a high level of current is induced in the rotor.Two zone impedance elements are used for detecting genera-

tor loss of field. The relay senses the variation of impedance asviewed from the generator terminal. Use relay manufacturersliterature for setting calculations.5) Negative-Sequence Current [46 in Fig. 4(a)]: This fea-

ture protects the generator against sustained unbalance ornegative-sequence currents. The standards call for the machineto withstand 5%10% of negative-sequence current ( ) con-tinuously and higher values for shorter periods according toformula . For salient-pole and indirectly cooledgenerators, the permissible 10%. Permissible is 40 forsalient-pole machines and 30 for indirectly cooled cylindricalrotor generators.6) Voltage-Restrained Overcurrent [51V in Fig. 4(a)]: This

is the final backup feature to trip the generator if faults are notcleared by other system protections. Block 51V in Fig. 4(a)for voltage transformer fuse-blown condition from device 60.Device 51V is replaced by device 21 if coordination is neededwith high-voltage distance relays.Time settings are set long enough to permit other protections

to clear with a current pickup set at approximately 2 pu and100% voltage.

7) Overvoltage [59 in Fig. 4(a)]: This device protectsagainst overvoltage, such as might occur if there was a


(a)

Fig. 4. (a) A typical protection scheme.

malfunction of the voltage regulator. The usual setting forturbogenerators will be 110% of nominal volts and a timedelay of 1520 s.8) Out of Step [78 in Fig. 4(a)]: When generator loses

synchronism, the resulting peak currents and off-frequencyoperations cause winding stresses, pulsating torques, andmechanical resonance. Loss of excitation relay 40 [Fig. 4(a)]may provide some degree of protection, but cannot be reliedupon to detect the loss of synchronism.

This protection is highly recommended, even if the systemstability study shows that the loss of synchronism can bedetected by the device 40. System parameters change, andstability study is costly and time consuming.9) FrequencyOver/Under [81 O/U in Fig. 4(a)]: In iso-

lated operations, overloading of generators will cause thesystem frequency to decay and the unit may be subjected toprolonged operation at reduced frequency. Underfrequency ofa turbine generator is more critical than overfrequency. Tur-


(b)Fig.

4.(Contin

ued.)

(b)Auto/manualsynchronizingscheme.


bine manufacturers provide limits in the form of permissibleoperating time in a specified frequency band. The setting shallnot be less than 57.5 Hz, even if the turbine limit is lower,as the motors cannot be operated at below 57 Hz and ratedvoltage.10) Differential, Phase [87G in Fig. 4(a)]: Generator in-

ternal faults must be cleared as quickly as possible tominimize the costly damage to the insulation, winding, andcore. Differential relaying will detect three-phase, phase-to-phase, double-phase-to-ground faults, and phase-to-groundfaults, depending upon the generator grounding method. Twoschemes, variable slope percentage differential and high-impedance differential, are used for differential protection.Variable slope percentage differential scheme is more widelyused and its characteristics result in a relay that is verysensitive to internal faults and insensitive to CT error currentduring severe external faults.11) Differential, Ground [87GN in Fig. 4(a)]: Since dif-

ferential relays (87G) are not sensitive to internal groundfaults, a separate ground differential element is required toprovide low current pickup and minimize iron core damage. Asimple directional overcurrent relay connected in a differentialform, as shown in Fig. 4(a), provides an excellent protectionagainst internal ground faults.12) Stator Ground [51GN in Fig. 4(a)]: This is a backup

ground overcurrent protection. For low-resistance groundedmachines, the setting is about 5% of the resistor continuouscurrent rating. The relay operating curve must be coordinatedwith the voltage transformer primary fuse.13) Generator Tripping Scheme: Generator tripping

scheme must be developed with care. Where possible, thegenerator trip relays shall provide redundancy in trip pathsand trip functions. A tripping logic adapted from [10] and[11] is shown in Table I.

VI. SYNCHRONIZINGNumerous accidents resulting in machine damage have been

reported [19] and were associated with human error. Thedamage is cumulative and can be minimized by safeguardingagainst human errors.In order to achieve a successful synchronizing operation,

the following parameters must be matched, with a certaintolerance, at the time of breaker closing: phase angle; frequency; voltage.

Excessive phase-angle difference across the synchronizingbreaker, just prior to closing, tends to sharply bump themachine. A slight frequency difference, coincidental with thephase-angle error, can result in a synchronizing accident andmachine damage. A voltage difference, prior to closing of thebreaker, will result in a steady flow of vars after the breakeris closed. If the generator frequency (speed) and voltage arehigher, then the active and reactive power will respectivelyflow from the generator to the system.Synchronizing facility shall include both auto and manual

features. Autosynchronizing minimizes the risk factors associ-

TABLE ISUGGESTED TRIP LOGIC

ated with human error and shall be used when the machineis brought to speed and paralleled to the system. Set thesynchronizer to close the breaker with machine frequency andvoltage being slightly higher than that of the system to preventreverse power flows.Manual synchronizing becomes a necessity when the gen-

erator is supplying the load in an isolated mode of operationand has to be paralleled to the system. It shall be supervisedby a synchronizer that will check phase angle, frequency, andvoltage and shall allow closing within a small window. Thesynchronism check relay shall include the following features: adjustable phase-angle settings; adjustable slip-frequency settings; adjustable voltage settings (undervoltage and differentialvoltage);

adjustable time settings.A typical synchronizing scheme with manual/auto features isshown in Fig. 4(b).

VII. INTEGRATION INTO THE POWER SYSTEMIntegration of a synchronous generator into an existing plant

power system is a challenge. The impact of the short-circuitcurrent contribution and var flow must be resolved to ensure anefficient and reliable operating system. The following schemescan be considered to minimize the impact of short-circuitcontribution.


Fig. 5. Integration with a duplex reactor.

A. Higher ReactanceHigher value of generator will reduce the short-circuit

contribution. However, a limit of 15% is recommended, asexplained earlier. This approach is not practical for existinginstallations with low margins in switchgear rating.

B. Current-Limiting ReactorIn applications where the short-circuit level exceeds the

switchgear rating by a small margin when the synchronousgenerator is operating in parallel with the network, a current-limiting reactor with a bypass breaker can be used. The reactorwill be bypassed when the generator is not tied to the network.

C. Duplex ReactorA duplex reactor is formed when two identical single-phase

reactors are physically arranged so that their magnetic fieldsare interlinked in an opposite sense.In a duplex reactor, the normal working currents in one

winding partially erase the voltage drop in the other. Withbalanced loading, the reactive kilovoltampere loss and reactivevoltage drop are lower than for two independent reactors.With current flow in one winding section only, the duplexreactor behaves the same as one of the two reactors. Furtherexplanation is provided in [13].The application of a duplex reactor is an excellent solution

to circumvent the problem associated with increased fault levelresulting from the integration. However, system engineeringmust be carried out for the equipment selection. A single-line diagram of an integrated system with a duplex reactor isshown in Fig. 5.

D. Unit-Connected System (Fig. 6)In this arrangement, the generator delivers the power to the

high-voltage bus through a step-up transformer, which is againstepped down for utilization. This system is simple, widely

Fig. 6. Unit-connected generator.

used in utility systems, and has some merit, such as the appli-cations of HR grounding, and is less affected by the systemdisturbances. The disadvantage in industrial systems is that thepower has to go through two transformations, thus incurringadditional losses. However, for systems with large units orwhere the short-circuit contribution is large, this arrangementoffers the best alternative. The step-up transformer windingconnection shall be Delta on the generator side and Wye withneutral grounded on the HV side. A guide for the selection ofa generator step-up transformer is provided in [14].

E. Fault-Current LimitersThe fault-current limiter is applied to resolve the problem

associated with the increased fault levels. Their application ison the rise in existing installations, and we have seen their useeven in generator circuits. There are two problems encounteredwith this approach, which must be resolved before the decisionis made. The unit must have been tested and certified as asystem to ensure that the downstream equipment is protected.The other problem is related to protection coordination, whichis almost impractical to achieve.A fault-current limiter shall not be used in a generator

circuit. The generator shall be tripped only for faults associatedwith the unit (turbine/generator).Faults within the generator zone are cleared fast by the

generator protective relays. High set voltage restraint phaseovercurrent relays provide backup protection for remote faultsnot cleared by upstream or feeder protective devices.

VIII. PLANT POWER SYSTEM AND UTILITY INTERFACEThe majority of process plants receive power at voltage

levels ranging from 34.5 to 230 kV. Reference [7] has pro-vided some guidelines for the protections and interface. Tra-ditionally, two-winding transformers with Delta primary andgrounded Wye secondary are used. There is a potential prob-lem with the Delta (ungrounded) system when synchronousgenerators or large synchronous motors are connected withinthe plant power system. On line-to-ground faults at the trans-mission line feeding the plant, the utility remote (sendingend) breaker will trip. However, the high-voltage bus and


(a) (b)Fig. 7. HV transformer connections.

the line will remain energized from the plant generator andsynchronous motors. Due to the uncleared ground fault on theHV side, the voltage across two healthy phases will experiencetransient overvoltage with a minimum line-to-ground voltageequal to or higher than times their rating, thus stressing theinsulation of the connected equipment (surge arresters, etc.)and leading to their failures.The utility tie transformer primary winding shall be Wye

with the neutral solidly grounded. This connection will preventovervoltages caused by line-to-ground faults. This connectionalso facilitates the detection of ground faults, which can beisolated by tripping the high-voltage circuit breaker.The main or tie transformer can be provided with two

different winding configurations:1) Wye primary with neutral solidly grounded, Wye sec-

ondary with neutral resistance grounded, and Delta ter-tiary with one corner grounded;

2) Wye primary with neutral solidly grounded and Deltasecondary. With Wye primary and Delta secondary ar-rangement, a zig-zag grounding transformer with a neu-tral resistor is required to achieve system grounding.Fig. 7 shows the above connections.

IX. SYSTEM DISTURBANCE AND ISLANDINGFaults on the system cause momentary voltage dips that

interrupt production or shut down the plant. Ability of thesystem to maintain stability and ride through the disturbancedepends on the following: type and duration of faults; system inertia and system characteristics; load torque.In order to improve the ride-through capability of the

system, the generator and excitation system, including thevoltage regulator, shall provide the following: sufficient var capability; HIR exciter;

field forcing and high ceiling voltage; short-circuit support.The utilization equipment must have sufficient threshold

voltage to survive through the voltage dips. These include thefollowing: high breakdown torque for induction motors; higher pull-out torque for synchronous motors and fieldforcing capability;

lower threshold voltages for control systems, variable-frequency drives, etc.

Most of the plant system disturbances result from lightningstrikes on the utility (power company) transmission lines.These lightning strikes cause overvoltage and flashover, thuscreating line-to-ground faults. The system voltage is depresseduntil the fault is cleared or plant power system is separated(islanded) from the utility. The voltage dip will depend on thelocation, severity, and duration of the fault.The following steps are suggested to determine and improve

the plant electrical system ride-through capability. Carry out a meaningful system stability study. The studymust include line-to-ground faults on the utility transmis-sion lines originating from the substation supplying powerto the plant. Experience has shown that lowering the towerfooting resistance by installing counterpoise reduces thefault frequency from lightning strikes substantially.

Determine the voltage profile at all critical buses, anglefor generators and synchronous motors, and slip forinduction motors. Induction motor slip shall not exceed10%.

Take corrective actions, including the following:1) islanding from the power company;2) fast clearing of faults;3) uninterruptible power system for control system;4) higher torques for critical motors;5) lower threshold voltage levels for drives and other

critical equipment;6) better performance for generator and excitation sys-

tem.

REFERENCES

[1] General Requirements for Synchronous Machines, ANSI Std. C50.10,1990.

[2] Requirements for Cylindrical Rotor Synchronous Generators, ANSI Std.C50.13, 1977.

[3] Requirements for Combustion Gas Turbine Generators, ANSI Std.C50.14, 1977.

[4] IEEE Test Procedures for Synchronous Machines, IEEE Std. 115, 1995.[5] IEEE Standard Definitions for Excitation Systems for Synchronous Ma-

chines, IEEE Std. 421.1, 1996 (revised 1996).[6] IEEE Guide for the Preparation of Excitation System Specifications,

IEEE Std. 421.4, 1990.[7] Guide for Protective Relaying of UtilityConsumer Interconnections,

IEEE Std. C37.95, 1989 (revised 1994).[8] Guide for Application of Neutral Grounding in Electric Utility Sys-

temsPart II: Grounding of Synchronous Generator Systems, IEEE Std.C62.92.2, 1989 (revised 1993).

[9] IEEE Guide for Generator Ground Protection, IEEE Std. C37.101, 1993.[10] IEEE Guide for AC Generator Protection, IEEE Std. C37.102, 1987

(revised 1990).[11] Generator tripping, in IEEE Tutorial on Protection of Synchronous

Generators. Piscataway, NJ: IEEE Press, 1995, ch. 14.[12] IEEE Guide for Protective Relay Applications to Power Transformers,

IEEE Std. C37.91, 1985 (revised 1990).


[13] Industrial Power Systems Data Book, General Electric Co., Schenectady,NY, 1968.

[14] Guide for Transformers Directly Connected to Generators, IEEE Std.C57.116, 1989 (revised 1994).

[15] M. Shan Griffith, Modern AC generator and control systems: Someplain and painless facts, IEEE Trans. Ind. Applicat., vol. 12, pp.481491, Nov./Dec. 1976.

[16] C. L. Bencel, Maintaining process continuity during voltage dips,IEEE Trans. Ind. Applicat., vol. 18, pp. 324328, July/Aug. 1982.

[17] T. L. Dillman, F. W. Keay, C. Rackowski, J. W. Skooglund, and W. H.South, Brushless Excitation, IEEE Spectrum, pp. 5866, Mar. 1972.

[18] Generator neutral grounding, Genral Electric Co., Schenectady, NY,Pub. GET-1941A, July 1953.

[19] T. R. Beckwitt, Automatic synchronizing considerations and methods,presented at the Western Relay Conf., Oct. 23, 1985.

[20] J. C. Das, Limitations of fault-current limiters for expansion of elec-trical distribution systems, IEEE Trans. Ind. Applicat., vol. 33, pp.10731082, July/Aug. 1997.

Shoaib Khan (M62SM72) was born in Jaunpur,India, in 1936. He received the B.Sc. degree in elec-trical engineering from Benaras Hindu University,Benaras, India, in 1957.He has more than 40 years experience in power

systems engineering, application, and protective re-laying for utilities and heavy industrial plants inNorth America and overseas. Since 1975, he hasbeen with Sandwell Inc., Montreal, PQ, Canada,where he is a Specialist in power systems andprotection. He is also engaged in organizing, de-

veloping, and teaching courses in power systems and protective relaying.Mr. Khan is a member of the IEEE Industry Applications Society and a

Registered Engineer with the Order of Engineers of Quebec, Canada, and theAssociation of Professional Engineers of Ontario, Canada. He is a recipient ofthe IEEE Centennial Medal, and he has been active with the IEEE EducationCommittee, Montreal Section, for over 25 years.

application aspects of generator and excitation system for process plants

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