/M1INEER - Vol. XXXX, No. 03, pp. 53-63,20076 The Institution of Engineers, Sri Lanka

The Challenge of IPP's Plant Characteristics againstthe Power System Security

A. C. S. Wijayatilake

Abstract: When a utility owned new power plant is constructed it is a traditional practice to carry outdetailed power system analysis to identify the most appropriate combination of plant characteristics tobe incorporated into the new power plant since it has to be operated with the rest of the equipmentused in the transmission system complying with the operational policies and standards. Hence, plantfeatures and operational characteristics such as generator parameters, controller settings, excitation,relay settings, power factor and other auxiliary equipment settings etc. are determined based on theoutcome of the detailed power system analysis done by transmission network planners. When systemplanners determine that a power plant feature is needed it is provided.

However, now we are in a competitive environment and Independent Power Producers (IPPs) moreconcentrated about their return on selling power neglecting the importance of coordinated systemdesign and operation. Cost optimization results in removing or limiting certain valuable features fromthe IPP owned power plant which are very important for system operators to maintain the expectedlevel of system security. At the prevailing environment utility has very limited control over determiningthe characteristics of IPP's machines. Resulting plant characteristics are far from optimum from asystem standpoint. As a consequence the transmission network security reduces and increases theprobability of having system blackouts. If there is a lack of long range planning these issues may nothighlight until the operational staff realize that IPPs may not provide traditional plant characteristicsand features when system is subjected to the severe stress. However, then the utility has to introducemore costly transmission solutions to regain the network security.

This paper addresses the technical issues behind this problem.

Introduction

The present electrification level of Sri Lanka is78% and the annual demand for the electricity isincreasing every year by 8% [1]. It is the duty ofthe relevant authorities to increase thegeneration capacity to cope with this highdemand growth. Since the available hydropotential for generating electricity has been fullyutilized by now Sri Lanka has to depend onthermal power generation in the future. Duringsome drought periods in year 2001 more than70% of the daily generation was produced usingthermal plants [2].

Up to 1996, Ceylon Electricity Board (CEB) hadthe monopoly in electricity generation and itwas the responsibility of CEB to prepare theannual generation plan, which describes thetype, place and size of the oncoming generatorsthrough detailed economic analysis. Thus, in thepast, CEB had a direct involvement in variousactivities of power plant connecting processes

such as planning, preliminary designing andfeasibility studies etc. Utility engineers directlyinvolved in these activities with their views andexperience on power system operation andcontrol were an advantage for consultants todesign the most suitable plant to match withneeds of the local grid. At a final stage inconstruction utility engineers participated incommissioning activities and thereby CEB hadan opportunity to foresee and rectify anyproblems, which would affect adversely onsystem performance once the machine isoperated synchronizing with the grid.

However, this situation has been changeddrastically due to the government decision toallow Private Power Producers (IPP) to enter thelocal electricity industry. It has been decidedthat in the future private sector should carry outall new power generation projects and the

Eng. A. C. S. Wijayatilake, B.Sc(Eng), Mphill, MIESL, MIEE,Presently, System Planning Engineer, Ceylon Electricity Board.

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government decided to limit government fundson power generating facility development [3].

Once, this policy was changed, the commercialaspects of power generation were given highpriority over the related technical aspects. IPPalways looks for possibilities of getting a highreturn for their investments. Hence, theirwillingness to generate maximum possiblepower with minimum cost and thereby earn alarge profit. To achieve their target, IPPs try tocut down many traditional featuresincorporated to utility owned generators, whichare not essential merely for power generation,but to enhance the power system security andsafeguard the system from blackouts and severedisturbances. As a result, IPPs reduces thesystem reliability and utility has to do a massiveinvestment on transmission networkreinforcement to compensate the adverse effectsintroduced by IPP plants and to improve thereliability level of the network. However, someadverse effects introduced by IPPs cannot befully offset. The objective of this article is tohighlight the important technical issues behindthe grid connection of IPPs generators.

The discussion is focused on different importantsubtopics as following though all relevant issuesare very much interrelated to each other.

Issues related to the voltage control ofthe network and voltage stability

Voltage at a power system is allowed to varywithin a very narrow range since the largerdeviations adversely effect on the networkperformance as well as lifetime of theequipment connected. At steady statetransmission system voltage is maintainedwithin of the rated value [1]. Maintaining theright voltage profile is therefore theresponsibility of the system operator.

Voltage is a local variable in a power system andit is a function of the reactive power flow at theparticular point. Mathematically therelationship can be expressed as

Voltage(kV)=f(VArgemmted- VAr,oad- VAr,oJ

where the VAr losses can either be positive ornegative depending on the network loading. Forinstance, in Sri Lankan transmission network atday time peak load more equipment consume

reactive power and the VAr IOSM-S , i t r negative.But at minimum load occurring at mid night ismainly resistive and VAr demand is less thanthe VAr generated by the transmission linecapacitance. Thus VAr losses are positive. Theconsequences of failing to achieve the VArbalance can range from excessively low voltageand increased MW losses under heavy loadconditions to excessively high voltage underlight load conditions. Both conditions may resultin damage to the plant and equipmentconnected and seriously reducing the systemsecurity.

It is very clear that reactive power managementis essential in a transmission system to controlthe voltage profile and improve the systemsecurity. Reactive power sources like capacitorbanks are located at load centers to minimize theVAr flow and reduce the loading ontransmission facilities. Though, switched shuntcapacitors are very economical and henceextensively used in the power systems, they aresuitable to maintain the reactive power balanceat steady state or at instances where systemvoltage is dropping at a slow rate. On the otherhand reactive power generated by capacitorswill reduce dramatically when the networkvoltage is reducing and as a consequencecapacitors fail to provide the necessary supportat the most required instances by making thesituation worse. The fast acting reactive powerresources should be located at identified placesin order to provide the reactive powerrequirement when rapid network changes aretaking place i.e. sudden tripping of a largegenerator, heavily loaded line or suddenswitching of large active/reactive power loads,cascaded tripping of equipment due to systemfaults etc. At a severe disturbance, if the reactivepower sources fail to bring the system voltageback to the allowable limit within a limitedperiod, the fast decreasing voltage causes asystem failure by operating under voltage relaysof generator auxiliaries and subsequent trippingof generators connected to the system. At similarsituations network may collapse due to voltageinstability. Therefore it is a practice in systemoperation to have more than the one third of thereactive power support kept available atdynamic sources such as generators, SVCs orsynchronous condensers [4].

Power system planners are very much vigilantin overcoming voltage instability situations

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when system security is concerned and plannedto locate dynamic reactive power resources suchas SVCs or generators having fast reactivepower capability at several suitable places of thenetwork. General operational practice is to usestatic capacitors as much as possible at thesteady state while maintaining the generatorreactive power as a spinning reserve to be usedin system disturbances to avoid system leadingto the voltage instability. Thus, the reactivepower capabilities of the generators are veryimportant for the system security point of view.Hence when a new generator is ordered by autility the transmission planners are mainlyconcerned about the ability of the generator toprovide maximum possible reactive power andopportunities available for enhancing thereactive power capability by manipulating therelevant settings of controllers, limiters andgenerator protective relays favourable to thesystem operations.

Reactive power capability of a generator can beexpressed with the help of a typical capabilitycurve, as shown in Fig.l, provided by thegenerator manufacturer. Generator active poweravailability is dependent on the prime moverselected. The ability of a synchronous generatorto generate reactive power is restricted by theincreases in temperature in the generatorwindings. As indicated in the Fig.l, capabilitycurve limits can be further expanded if the gaspressure of the generator cooling system can beincreased in order to maintain the synchronousgenerator temperature below the electricalinsulation temperature class limit described by

MVAR

J5PS1G

Rotor heatingLimit

0.8V<\a9

heating limit

Core endheating limit

Fig.l: Typical capability curve of a synchronousgenerator

the relevant standards. The figure shows thatwhen the pressure of the generator cooling gas(normally Hydrogen) increases the upperboundary of the capability curve furtherexpands which represents the enhancement ofthe thermal capability of the rotor field.Approximately the upper boundary of thecapability curve is an arc with a center at a valueequal to the short circuit ratio (SCR) in per uniton the VAr axis and a radius of E /Xd where £fisthe field excitation voltage given that thesynchronous generator terminal voltage is oneper unit. The right hand boundary is thesynchronous generator stator current limit. Thecenter of the arc defining this limit is the origin.The lower boundary is the end iron heatinglimits, which occur when the generator isoperated at under excitation limits to absorbVAr. As shown in Fig.l the intersection point ofthe stator and field thermal limit determinesthe power factor and rated capacity of thegenerator.

Suppose a new generator is to be connected tothe system. It is assumed that the prime moverrating is Ipu. If this machine is ordered by IPPthey look for the feasible cost reductionmeasures and are mainly concerned on gettingmaximum possible active power with minimumcost. Reactive power capability is not a matterfor them since there is no payment scheme forIPP's reactive power generation. Hence IPPprefers to select a machine, which has a veryhigh rated power factor. When generator'spower factor is high it's reactive powergeneration is low and as a result the currentflowing through the windings are low. Therebyconductors with smaller cross section can beused in windings and the cost of the windingscan be reduced significantly. In addition to thatthe cost of the cooling system can be furtherreduced due to the reduced thermal losses in thewindings. Similarly the other trend in low costgenerator design is to reduce the Short CircuitRatio (SCR). However, reducing SCR to verylow values results in increasing the windingcost. Therefore SCR is optimized to haveminimum possible value, which can be justifiedin terms of the machine manufacturing cost. TheVAr absorbing capability of the generator isproportional to the SCR. IPPs always prefer tohave low SCR machines since they are notwilling to operate their machines at underexcitation mode to absorb VAr at light load or

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emergency situations where system has excessVAr. Low SCR is achieved by reducing themachine air gap. It will reduce the machineinductance and as a consequence less current isdrawn to the winding resulting in low losseswith consequent savings in machine mmf, size,weight and cost [5]. However if the machine isordered by the utility the utility planning unit ismore concerned about the maximum reactivepower generating and absorbing capability ofthe generator to improve the system security.Definitely the utility will order a generator witha low rated power factor to increase VArgenerating capability and the higher SCR toincrease the under excitation limit operation ofthe generator at emergencies. This situation isclearly presented in Fig.2 where (A) for agenerator with 0.8 power factor with high SCRand (B) for a generator with 0.95 power factorand low SCR. The (B) is the IPP selection due tothe low cost but (A) is the utility selection due tothe flexibility in reactive power control. It isassumed that the prime mover rating is Ipu forboth cases. The figure shows that the machine(A) having 18% larger MVA rating than (B).However, the reactive power capability of (A) is225% larger than (B) with a little moreinvestment. Since SCR is smaller for thegenerator (B) its VAr absorbing capability isvery much lower than the generator (A).

This situation can be easily realized when IPPgenerators presently operating in the networkare compared with utility owned machines.Always-IPP generators are having higher powerfactor ratings above 0.95 and power factor of theutility ordered generator is typically 0.8.Therefore IPP machine will not provide the

generatorrating

Fig.2: Reactive power capability of two differentgenerators connected with same size turbine (A)generator having rated power factor = 0.8 and highSCR (B) generator having rated power factor - 0.95and low SCR

expected reactive power support and systemoperators have to switch on fast actingalternative reactive power sources such as SVCsto face for the emergency system disturbances.Otherwise degrading of the network security bylow cost IPP machines cannot be fully offset.

Even though capacitors are economical reactivepower sources, the generators have a specialty.That is because of the generator suppliedreactive power can be increased more than therated values for a short period to face the criticalsystem disturbances leading to the systemcollapse due to voltage instability [4], Accordingto the ANSI C50.13-1977, presented in Fig.3,stator and rotor current carrying capabilities canbe overloaded between the range approximately200% for 10 seconds and 110% for 2 minutes [6].The transmission planners are more concernedabout this very important capability of thegenerator. That is because during the severedisturbance the generator can tolerate the overloading caused due to the rapid VAr inbalancein the system for a short period. That small timeperiod is sufficient for automatic operation ofthe protection devices or connect/disconnectthe equipment necessary to bring the networkback to the normal situation. At the same timethe spinning reserve will activate and operatorswill reschedule the generation to normalize thesystem. However the generator over loadingcapability will depend on the generator coolingsystem. The utility is always ready to spendadditional expenditure for cooling systemdevelopment to get the short-term overloadcapacity of their generator. However, for IPP itis an immaterial factor and they do not allowoverload operation of their machine for anyreason to avoid the possible life time reductionof generator windings due to high thermalstresses and to minimize the maintenance cost.

250

I 23°1! 21°E 190

§> 17°1 150

| 130

110

90

Stator Current

Field Voltage

10 30 60flme/s

120

Fig.3: Generator stator and field overloadcapabilities as given in ANSI C50.13-1977

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Issues behind the limiter settings andplant controller tuning

IPPs want to minimize their operation cost andprefer to operate their machine at automaticmode rather than frequent intervention of theoperator. Therefore the machines operating atextreme operating conditions are avoided byadopting system automation techniques. It iscommon to introduce limiters on control loopsaiming machines not operating at very criticaloperating points. Similarly limiters areintroduced into machine excitation system asshown in Fig.4 and their settings are adjusted byconsidering both the network and machinerequirements [8]. When generator requirementsare concerned these limiters will avoid themachine operating outside the limits defined inthe capability curve provided by themanufacturer. Thereby windings are protectedfrom high thermal stresses. As a consequencethe lifetime of the generator windings areextended. However, if these limiters are notproperly tuned to match with the networkrequirement, the generator may fail to providethe expected support at severe disturbances andmay lead the network to blackout situation. Thefollowing discussion is on the importance of thetuning of the limiters at the excitation systemshown in Fig.4.

To ensure the generators are not operating otherthan the rated operating points the IPPsmanipulate the settings in Automatic Voltage

Fig.4: Components of Typical Excitation ControlSystem

Regulator (AYR) systems more conservatively.For instance the over excitation limiter settingscan be adjusted more conservatively to avoidoverloading on the stator and rotor windingswhen system voltage is getting down due to adisturbance. At similar occasions the voltage ofthe network should be boosted up immediatelyby pumping Var to the network. To increase theVar production of the generator the generatorexcitation should be increased. The resultinghigh current passing through the stator androtor windings may reach the thermal limit. Thefunction of Over Excitation Limiter (OEL) is tolimit the excitation current to a pre desired valuein order to avoid exceeding the thermal limits ofthe windings. When the generator windingcurrent reaches the maximum possible value analarm is set to inform the operator and if theoperator fails to change the controller fromautomatic mode to the manual mode theexcitation is set at the rated value after anallowable time period. Thereafter the machinecannot control the system voltage any more.Then the generator behaves as a voltagefollowing machine and looses the voltagecontrolling characteristics. OEL settings areinitially set by the manufacturer considering thewinding thermal limits to match with thecapability curve and subsequent fine adjustmentis necessary at the commissioning stage tomatch with the network operations. Generallythe maximum over voltage allowed at busbarsdefined in grid code and transformer saturationlimits defined in transformer standards are themain considerations. The typical settings are110% of nominal bus voltage or 110% of nominalvolt/Hz [7]. The idea is to protect the generatorwindings as well as auxiliaries connected to thegenerator busbar from over voltages atmaximum Var generation of the machine. Whena utility owned generator is commissioned thesesettings are manipulated according to thenetwork conditions but it is common to see thatIPPs want to keep the manufacturer's settingwithout further adjustment. This will affectadversary at some disturbances, which causereactive power deficit in the network. On similaroccasions unnecessary disconnection ofgenerators due to the operation of over voltagerelay of auxiliaries or V/Hz protection relay ofstep up transformer is possible by furtherweakening the system.

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Other important setting is the Under ExcitationLimiter (UEL) setting and it will come into playwhen the machine is absorbing VArs to reducethe higher system voltage. Similar Varabsorption is noticed generally at light loadcondition or when the generator is connected toa long line or at a sudden tripping of a Varabsorbing generator. Absorbing VArs will bringdown the system voltage and the resulting lowexcitation can move the operating point towardsthe stator end heating limit or the generatorstability limit marked at the operating chartpresented in Fig.5. If machine is allowed tooperate with low excitation there is a tendencyfor a generator to loose the synchronism andbecome unstable. Therefore under excitationlimiter will bring the machine back to a predetermined excitation level after a definedperiod and if the UEL cannot take the control ofAVR then machine is tripped by activating theLoss Of Excitation (LOE) relay. If a machine isunable to absorb the excess VAr and subsequenttripping of the unit by activating LOE relay fromthe system may cause the problem more severeand may lead to a total system collapse. Theexact setting of LOE is vital for system stabilityis concerned and the ability of the machine tooperate at extreme ends of the capability curveshould be investigated at the commissioningstage. At commissioning the manufacturersettings of UEL and LOE should be adjusted toget the maximum benefit for the system atsevere disturbances. Otherwise, high voltagedamage to customers or utility equipment ispossible and unnecessary tripping of thegenerator may lead to a total blackout [8].

MVAR I Minimumft- Generation limit Auxiliary bus high

• voltage limit

Turbine~~ Limit

DEL

|

GeneratorTerminal highvoltage limit

MW

LOF

Stability Limit

Auxiliary bus lowvoltage limit

GeneratorTerminal lowvoltage limit

It is clear that the settings of OEL and UEL arethe functions of the winding temperatures.There are advanced adaptive techniquesavailable thereby limiter settings are relatedwith temperature being measured with thesensors embedded at several locations of thewindings. Hence, the maximum VAr capabilityof the machine is possible unlike the fixedlimiter setting assuming the machine is alwaysoperated at rated conditions. Most of the timeutility practice is to provide VAr using capacitorbanks and generators are operated at unitypower factor keeping the VAr spinning reserveavailable for emergencies. Therefore machine isnormally operated with less winding currentthan the rated values. In case of an emergencysimilar machine can be overloaded more thanthe defined period without reaching the thermallimits if excitation limiter settings are set to varywith the actual winding temperature [9]. IPPswill not consider these techniques to minimizetheir budget.

The trend of automation of power plants hasbeen introduced another controller to the AVRloop called VAr/pf controller. The objective ofVAr/pf is to operate the generator at apredetermined power factor and VAr limitirrespective of the network voltages. NormallyVAr/pf controller is introduced as a minor loopof the AVR. This technique is being widelyutilized to control the synchronous motors andlater employed in IPPs owned power plants toreduce the operator intervention. Generatorincorporating VAr/pf controller behaves asvoltage following machines and they cannotcontrol the network voltage any more. Duringtransient events VAr/pf regulators typically donot allow change of machine excitation inresponse to bring the voltages back to theallowable limits. Hence, utility should introducenecessary restrictions at IPP's generatorspecifications to avoid incorporating VAr/pfcontrollers to their machines if those generatorsare expected to be used for controlling thevoltage of the network.

Fig.5 shows the operating region limitation ofthe generator capability curve [6] due to theintroduction of various limiters and associatedprotective devices discussed above.

Fig.5: Limitation of reactive power generationcapability of a synchronous generator

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Issues related to the step-up transformer

Special attention should be given to select asuitable step-up transformer for a power plant.Since the generated power is fed to thetransmission network through the step uptransformer its impedance is a very importantparameter. That is because the voltage of thetransmission network bus bar of the powerplant is dependent on the generator step- uptransformer impedance. The step-uptransformer impedance is normally 10%-15%.Hence, the same amount of voltage drop isnoticed at the high voltage bus bar due to thetransformer impedance. The generators AVRnormally incorporate the drop compensator toovercome the voltage drop due to step-uptransformer impedances and thereby generatorcan control the transmission voltage effectivelyeven though machine is connected to a lowervoltage busbar. Thereby maximum benefit of thegenerator voltage controlling capability can beachieved. Drop compensator parameters areadjusted at the commissioning stage to matchup with the step-up transformer used. Whensystem voltage controlling is concerned, dropcompensator is very much beneficial and utilityshould make sure the availability of this facilityat IPP generator AVR and keep the correctsetting at the commissioning stage.

When generator is not in operation, the auxiliarypower is absorbed through the step-uptransformer. At similar occasions, especially whenthe system is being restored after the blackout, stepup transformer should be able to provide thepermissible voltage to operate the auxiliaries. If thesystem voltage is not within the allowable limit, itis necessary to use small size generator connectedto the auxiliary bus bar to operate auxiliaries andstart the generator. However, by incorporating atap changer to the step-up transformer theauxiliary bus bar voltage can be boosted to therequired level when the machine is re-started afterthe system collapse. Hence, special attentionshould be given to the tap step and tap settings ofthe step-up transformer.

At the critical outage situation when the systemvoltage is decreasing and as a result the statorcurrent limit may be reached for generators withhigh active power production. Subsequently, thecurrent limiters will bring the stator current tothe rated value by reducing the reactive powergeneration as discussed before. At similar

occasions the on load tap changer incorporatedto the step up transformer is very beneficial.Operation of the on load tap changer supportthe machine to generate the maximum possiblereactive power without reaching the currentlimits even at large variations of the systemvoltage.

Hence on load tap changer with right tapsettings defined by considering the transmissionnetwork requirement can improve the systemreliability. This concept is extensively employedin UK transmission network. In UK, everygenerator connected to "Super Grid" has a step-up transformer, equipped with an On Load TapChanger (OLTC). On load tap changers areallowed to respond to the system voltagevariations. System operators of some utilitiesprefer off load tap changers for their generatorstep-up transformers due to the lack of propersupervisory controlling system and softwaretools assisting in decision making. However, thetap changer will increase the cost of thetransformer. The on load tap changer is 15% ofthe total cost of the transformer and alsoincrease the operation and maintenance cost.Therefore IPPs may not support for additionalfeatures such as on load tap changers since theirprime aim is to minimize the budget.

Transient stability issues

The generator running in a system should betransiently stable. On the other hands it shouldbe able to remain in synchronism when it issubjected to a sudden disturbance such as asystem fault or load variation. Generator rotorangle is the measure of transient stability.Theoretically, the rotor angle should be around30° when a machine is operating at the steadystate. The rotor angle will fluctuate as a result ofthe system disturbance, which causes imbalancein the electrical output power of the generatorand the mechanical input power to the machine.Then the rotor angle starts swing and if it settlesat a new equilibrium state then the systemremains in stable. Sometimes larger swings ofthe rotor angle will cause power fluctuations atthe network. At similar occasions system powerflow cannot be predicted. Subsequent operationof protection relays isolates the transmissionslines and makes the situation worse. If the rotorangle is continuously increasing the generatorbecome unstable and it should be immediately

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isolated from the network to avoid damage tothe generator due to pole slipping. Otherwisegenerator will be damaged and cascadedtripping of the transmission lines and otherconnected generators due to power fluctuationsmay cause a blackout. Always the possiblecauses for transient instability are deeplyconsidered in system planning, designing andoperation stages to eliminate the full or partialsystem failures.

The main consideration regarding transientstability of a new generator being connected tothe network is the time it will take to becomeunstable when there is a three-phase shortcircuit fault at the most critical point of thenetwork. This is called the critical clearing timeof the unit. The system should be able to isolatethe fault before it readers the critical clearingtime. Otherwise the generator loosessynchronism. Generally the isolation of thenetwork fault at the transmission system within200ms is a reasonable time margin when therecent development in transmission protectionequipment are concerned. If the generatorbecomes unstable before the network fault isisolated it should be disconnected from thesystem to safeguard both the generator and thenetwork.

The H constant of the generator and rotorcombination is one of the indicators forassessing its transient stability [5]. There areseveral definitions for H constant but the idealdefinition for this discussion can be given asfollowing. " The H constant can be defined ashalf the time it takes the machine to double itsspeed when full load torque is applied on noload." For instance H=l will double its speed in2s if the full load is rejected without change inmechanical torque. There is a rule of thumb insystem planning that H constant should not beless than 1.5s for a generator to be connected tothe transmission system [10].

The modern trend of IFF is to have a very low Hconstant comparing with the typical figures. IPPprefers generators with low H constant mainlydue to the economic advantage of low mass ofrotating parts of the generators. For example therecently connected IPPs to the Sri Lankannetwork have H constant nearly Is and in a fewmachines it is less than Is. Similar machines aregenerally acceptable for standby generators but

not to be operated connected with the nationalgrid. Normally these machines have capacityless than 5MW and a large number of units areoperated at one location to provide the desiredoutput. When system reliability is consideredthese machine reduces the security of the systemand cannot remain in synchronism at a networkdisturbance. The machine reaching to the criticalclearing time before the network disturbance isover should be isolated from the network byactivating the protection system. Hence, toprotect the generator and safeguard the systemfrom a blackout, the generator has to be isolatedfrom the network immediately. Otherwise thesystem should be operated with a largerspinning reserve available at fast acting units tocompensate similar generator disconnectionsfrequently occurring at network disturbances. Inaddition to this very high rotor angle oscillationscan be noticed at low inertia machines even atsmall system disturbances. To offset the adverseeffect of low inertia machines a large investmentis necessary for utility to re-install high-speedprotection devices and strong transmissioninterconnections. However, the rotor anglefluctuations of the low inertia machines cannotbe completely eliminated. If very low inertiamachines are available in a system the bestavailable option is to retrofit a flywheel. Therebythe H constant can be further increased. Alwaysthe utility should decide the minimum possiblemachine inertia constant and must be moreconcerned about the related issues on transientstability of the network when the low inertiagenerator is connected to the network.

Incorporating very fast acting exciters withhigher ceiling voltage and response ratio alsoassists in improving the transient stability of thegenerator. Static type exciters are more preferredsince its time constant is in the range of O.ls dueto the lack of rotating elements. Fast exciter canchange the generator terminal voltage rapidlyand the system transient stability can beretained by increasing the terminal poweroutput of the generator at severe disturbances.System planners prefer to have fast actingexciters for the machines connected to thetransmission system on system securitygrounds. At extreme operating conditions thethermal capability of exciters will determine theability of the machine to remain in synchronism.The insulation level of the exciters and the high

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voltage stress on the winding are the limitingfactors of the excitation system. Similar to thegenerators the exciters can also be overloadedfor a short period in system disturbances.However, in order to do that additionalprotection and cooling equipments arenecessary. But IPPs will not agree to invest foradditional features necessary for improvingnetwork reliability and they want to incorporatethe excitation system satisfying the minimumoperating requirements to match with theirfinancial constraints.

Issues related with the plant protection

IPPs are more concerned about the protection oftheir machines and always want them to beisolated from the network when systemdisturbances are taking place. There are severalprotection devices incorporated to the generatorin order to identify the network disturbances inadvance and ensure the subsequentdisconnection of the machine from the system.For this purpose under or over voltage/frequency relays and rate of change of frequencyrelays (ROCOF), out of step protection relays arecommonly used. The utility should be moreconcerned about the setting of these devices tominimize the unnecessary disconnection ofgenerators even at small system perturbationstaking place frequently such as disconnection ofsmall generator at peak load period etc. Atsimilar network disturbances the decrease involtage and frequency is taking place. Theincorrect setting of under/over, voltage/frequency may disconnect either plant auxiliaryor/and the generator from the networkGenerator tripping further weakens the systemby accelerating the frequency falling rate. Apartfrom that it will disturb the VAr balance of thenetwork. Eventually system may collapse due totransient or voltage instability. At similarinstances proper coordination of abovediscussed plant protecting relays with networkdisturbance recovery measures such as loadshedding schemes or application of secondaryspinning reserve etc. is extremely important [11].

Hence, the machine should be designed to be inoperation and provide the maximum possiblepower within the voltage and frequencyvariation ranges defined in the grid code oroperational procedures. According to theoperational practice under system contingencies

Generator BusbarVoltage %

Fig.6: The acceptable operating limits recommendedfor thermal units of Sri Lankan power system.

the transmission voltage variation should be inthe range of -10% and 5% and the generatorsand auxiliaries should be able to operatecontinuously providing the maximum possiblepower if the system frequency is within 50.5Hzto 49Hz. At voltages and frequencies of outsidethe normal operating range but within themaximum allowable limits the total power cannot be expected from the machine butdepending on the plant type a fraction of thepower should be available for at least smallperiod such as 30 minutes. The maximumallowable voltage is a transmission systemdesign parameter and the minimum allowablevoltage is determined by considering thebehavior of the plant auxiliaries. The minimumand maximum operating frequency will bedependent on the prime mover characteristics ofthe plant. These limits should be clearlymentioned at the utility generator specification.Fig. 6 shows the acceptable operating limits forthermal units concerning probable tolerances offrequency and voltage fluctuations at normaland transient states of the Sri Lankan powersystem. Special attention should be made at thecommissioning stage to verify the settings ofunder/over frequency and voltage relays ofplant auxiliaries.

IPP plants are normally incorporated withROCOF relays to safeguard machines from fastdrop in frequency. ROCOF relay settings of thegenerating plants should be determined byconsidering realistic critical outages of the entiretransmission system. The maximum impact onthe system frequency takes place due to thesudden tripping of a large machine or a heavilyloaded line when the system has very smallload. At similar occasions the fast drop infrequency results in operating ROCOF relaysand disconnecting machines thereby furtherincreasing the frequency falling rate. ROCOF

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relay of IPP plants is set just by considering as aplant protection mean without getting the viewsof system operators. Generally, relay is set toactivate even at small frequency disturbancesthough the system frequency can be restoredwithin few seconds. Hence, it is correct toassume that majority of IPP machinesdisconnects from the system even at a smalldisturbance. Therefore system should beoperated with higher spinning reserveconsidering the possible generation deficit dueto the disconnection of IPPs at criticaldisturbances. Therefore several fast actinggenerating units have to be operated below therated operating load to maintain spinningreserve irrespective of the economic operationprinciples to safeguard the system fromblackouts. The utility planners should fullyunderstand the similar hidden expenditure to beborne by the utility when an IPP plant isoperated at the system and the technicalspecification should be thoroughly revised toinclude necessary provisions at least tominimize their adverse effects.

Power plant operational issues

The utility owned plant operators are fullytrained about the power plant features andtransmission network behavior at theemergency situations. They have been welltrained on manual operation of the generator atsystem disturbances and support to the networkoperator to overcome possible system failures.For example if machine excitation has reached tothe maximum level and alarms are ringing priorto disconnection of the generator from thesystem the well trained operator can takeoverthe manual operation until another machine isstarted somewhere else in the network toreplace the active and reactive power providedby the faulty generator. Otherwise the suddendisconnection may overload other transmissionfacilities and load shedding may be necessary torestore the system frequency. Instead of suddenautomatic disconnection of the machine due tothe minor internal faults such as ground fault atfield winding, out of service AYR, excitationlimited by slip ring arcing, load limited by a fuelsupply problem etc., the utility plant operator iscapable of manually operating the machine for areasonable time period sufficient for networkoperator to reschedule the generation. The risk

of damage to the plant is accepted for the greatervalue of the reduced risk of having a blackout.However, IPPs always prefer to have automaticcontrol for their machines to minimize theoperator intervention and will not sacrificelifetime of their machines for the benefit of thenetwork.

Conclusions:

The following conclusions can be made basedon the above discussion.

1. IPPs main objective is to get a good returnfor their investment and as a consequencethe utility has to sacrifice the systemreliability.

2. The generator parameters and the expectedbehavior of the plant at operational voltageand frequency ranges should be clearlyindicated at the specifications given to IPPsby the utility.

3. Engineers of the utility should activelyparticipate for power plant commissioningand should come to compromise with IPPsfor protection settings and controller tuningfavourable to the system operations.

4. Many problems are due to the non-paymentfor IPPs for their reactive power generation.Utility should think about a method toencourage IPPs for reactive powergeneration by introducing payment schemefor VArh generated when generator powerfactor is kept below 0.9 or some reasonablevalue.

5. Detailed power system analysis should becarried out under the feasibility study toidentify possible problems in advance andto suggest remedial measures.

6. Power plant operators should be welltrained to face for generator operation atnetwork disturbances and at least IPPsshould be persuaded to ensure the operationof their machines at some previously agreedupon problematic conditions.

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References

1. Statistical Digest ofCEB -2006

2. Statistical Digest ofCEB -2001

3. Power System Policy Directions by Ministry ofIrrigation and Power in 1998

4. Power System Operation by Robert H. Miller andjames H. malinowski

5. Power System Engineering by Nagrath and kothari

6. NERC (North American Electric Reliability Council)operating Manual

7. M.M. Adibi and D.P. Milanicz " ReactiveCapability Limitation of Synchronous machines",IEEE Transactions on Power Systems, Vol.9, No.l,pp. 29-40, February 1984.

8. J.R. Ribeiro, "Minimum Excitation Limiter effectson Generator Response to system Disturbances",IEEE transactions on energy Conversion, Vol.6,No.l,pp.29-38, March 1991.

9. C.W. Taylor, "Survey of effective and practicalsolutions for longer term Voltage Stability",International Journal of Electrical Power andEnergy Systems, Vol.15, No.4, pp. 217-220,August 1993.

10. H.J. Langley " Inertia of Small Generators" IEEPower Engineering Journal, pp. 196,Vol. 14,Number 4

11. JL.H. Fink and K. Carlsen " Operating understress and Strain" IEEE Spectrum, pp.48-53,March 1978

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