1

PARALLEL OPERATION WITH A NETWORK SYSTEM

The purpose of this discussion is to address the concerns of and the techniques requiredto successfully parallel synchronous generators to a network.

A network consists of two or more buses connected together by one or more power lineswhose impedance compared to the capacity of the network generating capacity cannot beneglected. Contrast this definition with that of a bus whose impedance is so low that it canbe neglected. This difference makes analyzing the network's flow of current and the volt-age drop calculations much more difficult than the paralleled generators with loads allconnected to a common bus. When we are able to neglect the bus resistance and reac-tance, the solution to current flow and voltage drops is very simple. Large electric powersystems typical of our electric utility can only be analyzed by considering them to be net-work systems. It would not be economically feasible to transport power the way utilitiescurrently do if the connections between loads and generators were required to have resis-tance and reactance negligible compared to the system capacity. With the capacity ofcomputers to perform complex calculations very quickly, however, the analysis of powersystem load flow is greatly simplified compared to the slide rule days.

Figure 1: Paralleled Systems

One way to simplify the analysis of network operation is to adopt the concept of "infinitebus" for the network. This assumption can be used if the capacity of the network at a pointof interconnection is at least 10 times greater than the capacity of equipment connecting tothe network. The concept holds true when the network voltage and frequency are notchanged when real and reactive currents change at the point of connection. An example isa generator connected to a network, with generator size of 100kW and the connectionpoint being an industrial plant served by a 10MVA transformer. With the transformer beingfed from a line having a capacity of 150MVA, any changes in load flow caused by fuel orexcitation changes at the 100kW generator will have no measurable effect on the voltageand frequency of the transformer secondary. This is also referred to as the stiffness of thegrid.

2

Figure 2: Typical Paralleled System

To control the real power flow from the 100kW generator, the problem has changed fromthe load sharing scheme needed for multiple generators serving an isolated load. Now thecontrol scheme must regulate the real power load from the generator to the plant busbased on some other criteria than just load sharing. To perform this function, another blockis added to the basic control loop of the speed governor establishing a desired kW loadsetpoint and adjusting fuel to the prime mover to maintain load at the setpoint value. Sincethis control loop is closed, stability of the control system must be provided for. The blockdiagram in Figure 3 illustrates a common way of providing the second control loop forregulating real power load. The setpoint may be a fixed value at or near full load, a controlsystem designed to maintain steam pressure to a varying load while using the excesscapacity of the prime mover to generate electricity, or to keep the utility power supplybelow some maximum demand limit. By regulating the generator load kW, any variation infrequency from the network will cause only momentary deviation in real load until thecontrol loop senses the deviation in load and corrects by adjusting fuel.

Figure 3: Alternative Control Strategy

3

To help explain this approach, let's review some basic governor controls.

Parallel Operation Of The Governor And Real Power

In paralleling multiple generators it is important to recognize that there are two fundamen-tal control loops: the governor control loop and the voltage regulator control loop. Thegovernor controls the real power portion of the generator, kW=EL-L* 3*�*cosφ.

1000First, let's discuss the governor controls.

Definitions

Before one can fully retain the information to be presented, it is imperative to recognizeand understand the following terms.

A: Droop: Refer to Figure 4. When a prime mover has a droop governor, the prime moversimply decreases in speed as load is applied. A droop governor will usually have between3% to 10% droop. Figure 4 illustrates a governor with 3.3% droop. Notice the no loadspeed is set to 62 hz and at full load the prime mover’s speed has decreased to 60 hz.

Figure 4: Droop Governor (3.3% droop)

B: Isochronous: Refer to Figure 5. When an engine has an isochronous governor, theprime mover will maintain its set speed throughout its entire horsepower range. An isoch-ronous governor is said to have zero droop. Figure 5 illustrates a governor with zerodroop. Notice the no load speed is set at 60 hz and at full load the prime mover’s speedremains at 60 hz.

Figure 5: Isochronous Governor

4

C: Real Power is horsepower produced from the prime mover converted to kilowatts by thegenerator. KW=EL-L* 3*�*cosφ. In this formula, cosφ is the power factor. 1000

D: Reactive Power is the power that is required by the inductive and capacitive loads. In apurely resistive load there is no reactive power. In a paralleled system the generators canproduce reactive power which circulates among the generators called circulating current.Circulating currents are not desired and are controlled by the generator excitation.

Paralleling Generators with Droop Governors

Systems produced today seldom are designed with droop. This is because most loadsrequire the generator frequency to remain constant and, as defined, droop governorsdecrease in speed with an increase in load.

The operation of synchronizing requires that the generator’s voltage, frequency and phasehave to be matched and a circuit breaker tying the generators together be closed. Thismagnetically locks the generators together, forcing them to operate at the same speed. Allthat has to be done now is to control the power distributed between the generators. Thepower required by the load is fixed.

With the prime movers equipped with droop governors, it is important that both governorsbe set the same if the generators are expected to share load equally. This means each onehas to be set to the same speed. Each one has to be calibrated with the same percentageof droop. With the speed and droop set the same, the prime movers will equally share theload. Refer to figure 6.

With droopgovernors, theportion of loadsupplied by eachgenerator iscontrolled.

Figure 6: Paralleling Generators with Droop Governors

5

Figure 6 illustrates the droop curve and load of two paralleled generators. Notice the simi-larity between this figure and Figure 4. The difference is that we have added the secondgovernor curve and the vertical axis is labeled both “speed” and “power”. The addition ofpower illustrates that when the speed setting is increased on one paralleled generator, thatgenerator will assume a greater portion of load. The inverse occurs when the speed settingis decreased on a paralleled generator. When the speed setting is changed in relationshipto the speed setting of the other generator, the actual speed of the prime mover does notvary from the other generator. The torque from the prime mover is changed, thus changingthe power output.

The question may be asked: How are the mechanical governors capable of sharing theload? This can simply be determined by analyzing the performance (droop) characteristicsof the mechanical governor. Refer to Figures 7 through 10.

Figure 7 shows two generators, each with a droop governor. As load varies, the kW de-mand changes cause the generator speed to follow the droop curve, decreasing speed asload increases and increasing speed as load decreases.

Passes above63Hz at 0%load, 60Hz at100%.

Figure 7: Droop Curves

6

Figure 8: Loading of Generators

To parallel the second generator with generator 1 operating at 100% load and 60Hz, thenormal synchronizing method matches generator frequency (speed) to the bus (Gen 1).This adjustment of the speed setting causes the droop curve to be in the position shown inFigure 8 at the time of breaker closure, operating at 60Hz and no load.

As the load on generator #2 is increased, the load on generator #1 decreases. As theload on #1 decreases, the speed increases. When generator #2 is at 25% load, generator#1 is loaded to 75% and the speed is at approximately 59.8Hz. As the loads are balancedto 50/50 each generator, the speed has increased to 61.5Hz. At this point both generatorsare at the same relative load and speed. An operator must then decrease both governorsetpoints down to 60Hz.

7

Figure 9: Balanced Load

At this point, if the total load increases, the governors will share the increase proportion-ately. If generator #2 tries to take more of the load, its speed setting is raised.

By raising its speed setting, generator #2 picks up some load from generator #1, due tothe shift of the droop curve of generator #2 and the action of the droop curve of generator#1. With only two generators in parallel, the total kW demand of the load must come fromthe two generators, so the sum of the kW supplied by the two generators must equal theload kW. In addition, by the action of paralleling, the two generators must maintain exactlythe same frequency. Any increase in power output from one of the generators results in acorresponding decrease in speed, based on the droop curve. The other unit will not allowthe decrease in speed because its droop curve, seeing a decrease in load, attempts toincrease the speed setting, keeping them in balance.

As the total load increases from 50% to 100%, the paralleled generators will share the loadequally but the system frequency will decrease along the droop curves as in Figure 10.

8

Figure 10: Load Changes

This is a dynamic system with power demand constantly changing on the system. Thedroop characteristics of the mechanical governors are a stabilizing mechanism in a parallelsystem. Simply put, as load attempts to change among the generators the droop governorstabilizes and proportions the load.

Paralleling Generators with Isochronous Governor

Isochronous governing has became the governor of choice in today’s industry. The reasonis the governor’s ability to maintain a constant set speed throughout the prime mover’spower range.

Unlike droop governors, isochronous governors by themselves are not capable of control-ling paralleled generators. Isochronous governors require additional controls to be ca-pable of paralleling. These controls will be discussed later in this document. At this time itis important to understand why isochronous governors by themselves cannot be paral-leled.

Figure 11 illustrates two generators running independently. The speed on generator #1 isset at 60Hz. The speed on generator #2 is set to 60.2Hz. Remember, isochronous gover-nors are designed to control at exactly their set speed. If these generators were paralleled,the generators would be forced to match speeds. Generator #1 would be pulled up to60.1Hz and generator #2 would be pulled down to 60.1Hz. The governor on generator #1would sense the actual speed to be too high and the governor on generator #2 wouldsense the actual speed to be too low. Governor 1 would respond by reducing fuel andgovernor 2 would respond by increasing fuel. The effect would be generator #2 taking allthe load and motorizing generator #1.

9

Figure 11: Generators Running Independently

In order to parallel isochronous generators, it is necessary to add controls to each governor.These controls are designed to measure the real power out of each generator and com-pare the measured value with total load via the load lines. If the power levels are unbal-anced, the added controls send a power setting output to the speed input of the isochro-nous governor. The governor will increase or decrease the power of the prime mover toshare the load properly between all paralleled generators. Refer to Figure 12 for a visualdiagram of a typical load sharing system.

Figure 12: Typical Load Sharing System

Paralleling Generators To An Infinite Bus

When paralleling generators to an infinite bus there are two systems used. System 1 holdskW load of the generator bus constant and allows the utility to provide the remainder of theload demand. System 2 reverses this action, holding the utility bus kW load constant andforcing the generator bus to provide the remainder of the load demand.

10

System 1

Implementing system 1 requires addition of a load control module. To set the power levelfor system 1, a load control module is added to the load sharing controls that biases thecommunication lines which balance the load between generators. For example. if thevoltage on the communication lines is 0 to 3 volts dc, adding a linear signal with 0 voltsbeing no load and 3 volts being maximum rated load of the generator sets changes theload on all paralleled generators simultaneously. If one wants the generator system toproduce 50% of rated load, a 1.5 volt dc signal is biased to the communication lines.

System 1 is not desirable in all applications. A problem arises if the load’s power leveldrops below the generator bus set level. The generator bus will export power into theUtility network.

Figure 13: System 1 (Generator Bus Constant)

System 2

System 2 control requires additional hardware compared to system 1. Controls are addedto the utility to monitor the power level imported. These controls compare a set power levelto an actual power level and adjust the bias to the load lines. The adjustment to the com-munication lines forces the generator bus to increase power out when load increases anddecrease power out when load is decreased. This dynamic action controls the generatorbus output while holding the utility at a constant power level. Unlike system 1 where powercan be exported, system 2 prevents power from being exported into the utility.

11

Figure 14: System 2 (Utility Bus Constant)

Frequency variations in U.S. power networks are normally very small unless a lack ofsufficient generating capacity occurs due to malfunctions of the system. If the frequency ofthe network should change significantly, the small generator has no choice but to follow,with tripping of protective relays disconnecting it very quickly to avoid damage to themachine when frequency exceeds normal operating conditions.

If the generator is a large utility plant, the real power load is dispatched or controlled by anoperator to keep the network frequency at 60 Hz and to share the load between plants.The utility practices good economy by taking the power demand from those plants able tosupply the power at lowest cost per kWh (Kilowatt hour). On large systems, the solution toproviding power at lowest production cost requires a sizable computer with a model of thenetwork to continually evaluate the load demand and its location on the network in order toshift the generation of the power among the plants. When the solution to the needs iscalculated, the dispatcher calls for power to be supplied from the plants, either by remotecontrol to each plant or by sending dispatch requirements to the plant operators. Loadprofiles are well established for normal workdays, weekends, etc. so the problem can besolved for a given profile, and each plant can follow the profile until some deviation re-quires a change in operating instructions. In large utility plants the network voltage andfrequency are affected by changes in the plant load levels, making it necessary to solvethe load flow of the network in order to keep the network operation within acceptablepower quality limits.

12

Parallel Operation of the Excitation System

To control the reactive power from the 100kW generator, a similar control loop to the speedgovernor kW regulator is used to measure one of two parameters of the generator; the firstis reactive power flow, measured by current and voltage transformers connected inquadrature exactly like the arrangement in the droop circuit. By comparing the measuredkvar load with the setpoint, adjustable for leading or lagging reactive load, the generatorwill supply a constant reactive current to the bus regardless of load demand and variationin bus voltage.

To help understand what we are discussing, the power triangle is a good tool to use.Across the bottom axis is the real power expressed in Watts or Kilowatts (W or kW). Alongthe hypotenuse of the triangle is the apparent power expressed in Volt Amp or KilovoltAmp (VA or kVA). The reactive power is the third leg of the triangle and is expressed asVolt Amperes reactive or Kilovolt Amperes Reactive (VArs or kVArs).

The cosine of the angle is referred to as a Power Factor, a measure of the ratio of reactivepower to resistive power. For power factor of 1.00, the current is in phase with the voltage,and the reactive load is zero. Power factor of 0.8 is the rating of most small to medium sizegenerators, indicating that it is designed to deliver 80% of rated current as resistive load,and 60% of load current as inductive reactive load current (0.8 is cosine of 36.9 degrees,sine of 36.9 degrees is 0.6). This rating of the machine indicates the thermal capability ofthe stator windings on a continuous basis at maximum ambient temperature. This ratingalso indicates the thermal capability of the rotor windings on a continuous basis at maxi-mum ambient temperature. The machine voltage and frequency rating give the thermalrating of the core of the machine at maximum voltage and nominal speed.

Figure 15: Power Triangle

Two parameters, reactive power and power factor, are the ones that the excitation systemcan control. The question is then raised as to how this is done. One approach is to treatthe infinite source as another generator to be paralleled to and connect the voltage regula-tor in the droop mode.

13

Figure 16: Typical Droop Connection

In this method, the droop adjustment is made just as if the generator were paralleled withanother generator. If there is also a step up transformer between the generator and thegrid, this approach works even better due to the impedance of the transformer. Addingdroop to the voltage regulator is, in a sense, like adding impedance to the line, so a largetransformer helps in this type of paralleling. If the grid is not very stiff, then paralleling in thedroop mode may be satisfactory. This way, an operator can monitor and make adjust-ments as required to maintain bus voltage and reactive load sharing.

Now the question is asked that if generators can be paralleled with the regulators in thedroop mode, can I parallel with the regulators connected in reactive differential or crosscurrent. The answer to this is that it is not recommended. If we review what a cross currentloop looks like to the voltage regulators, we can see why. Since the regulators connectedin cross current expect that a change in its compensation circuit will cause a change in theother circuits, there will not be a change in the infinite grid no matter what the regulatordoes.

Figure 17: Cross Current Compensation

14

Since many generator power systems must support load in a mode not paralleled to thegrid and at some point will also parallel with the grid, how can the systems be connectedin cross current? The answer is that the cross current connections may be disabled whenthe main tie breaker is closed. Breaking the loop in any one spot will disable the crosscurrent compensation. An example is as follows:

Figure 18: Scheme to Disable Cross Current

It may seem that connecting the regulators in droop to parallel to the grid is the best wayto operate. However, compared to the frequency, bus voltage is subject to much greatervariation, and the source of the variation may be local changes in load or network voltagevariations which occur because of line losses changing with load or changes in networkoperating voltage from daytime to nighttime levels. Regardless of the cause, the effect on adroop compensated generator would be changing reactive load levels. Most regulatorshave a maximum 6-8% droop setting. If the grid voltage goes higher than the droop set-ting, the regulator decreases its output and a generator is paralleled and must start import-ing VArs to operate at the high bus voltage level. This could cause the generator to be-come underexcited, start slipping poles, and become damaged.

Conversely, if the voltage on the grid decreases, the regulator tries to drive the voltageback to its setpoint. Since by definition the grid is infinite, the generator cannot restore thevoltage. As the excitation increases the generator starts exporting VArs into the grid. Thissituation can cause excess heating of the generator rotor windings as well as the distribu-tion transformer. This is a potentially damaging situation for the generator.

Automatic VAr/Power Factor Regulation

Adding a var regulator to the excitation system and operating in the var regulation modeallows maximum utilization of the generator reactive load capability independent of realpower load. Alternatively, the var regulator may be set to maintain the generator reactiveload at zero, if the vars are not bringing in revenue, to keep the generator as cool as pos-sible while supplying the revenue-producing real power to the load. With VAr regulation,the changes in bus voltage which can cause VAr load variations are compensated byadjustment to the avr setpoint voltage. The result is a constant VAr load on the generatorwithout any operating intervention.

15

Figure 19: Alternative Control Strategy

The second type of control loop measures the power factor or the angle of generatorcurrent with relation to the voltage. In this control mode, the reactive load is regulated as apercentage of the real power load, tracking any changes in real power to keep the percent-age constant. This form of control is often preferred by operating personnel trained to keepthe power factor constant in their manual control practices. Many generators are equippedwith a power factor meter and a kW meter in addition to volts, amps and frequency. In thisconfiguration, a var regulator can produce some readings on a pf meter which will alarmsome operators trained to keep power factor to 0.8 or higher. However, use of var regula-tion does not add any risk to the generator if operating at rated kvar and 10% of rated kW.The power factor of this load is 0.54 pf at 84% of rated generator current. The generator isable to operate safely under at this condition. Power factor regulation may be selected as acontrol option if desired, but by replacing the traditional power factor meter with a varmeter and regulating the reactive load, better use of machine capacity may result.

There are three basic ways to add VAr/power factor regulation to an excitation system.They are:

1) Add additional component to the system,2) Integrate VAr/Power factor control into the regulator itself, and3) Programmable Logic Controller.

16

No matter which approach is used, the technique is doing one of the following:

As angle changes, the power factor changes.

Figure 20: Constant kVAR Level

As the kW changes, the angle stays the same, the kVAR level changes. Since we areregulating the angle, the cosine of the angle stays the same.

Figure 21: Constant Power factor Load

Adding an additional component to the excitation system is relatively easy. A basic blockdiagram is shown in Figure 22.

17

Figure 22: VAR/PF Controller with Static Exciter

Figure 23 shows the faceplate of the Basler Electric SCP-250. Setting on the SCP-250 isfrom .6 power factor leading to .6 power factor lagging when in the power factor controlmode.

Figure 23: SCP-250 Faceplate

In the VAr control mode the adjustment is either to produce or absorb VArs. The VAr rangeadjustment sets up the limits at either end of the potentiometer travel.

18

Figure 24 illustrates a generator that is equipped with a solid state voltage regulator havingreactive voltage droop compensation. The graph illustrates the effect of bus voltagechanges on the reactive/ampere load on the generator. If the bus voltage drops by 6%, thereactive/ampere generator load will change from 0 - 75%. A further decrease in bus voltageexceeding 4% would overload the generator, causing excessive heating in the field wind-ing as well as the power semiconductors of the automatic voltage regulator. The VAr/PFcontroller regulates at a programmed operating point and is insensitive to changes in thebus voltage. Field heating increases (higher excitation current) as lagging reactive loadincreases. Keeping the lagging VAr load under control protects the generator field fromoverheating. This function can be performed by an operator, or the VAr/PF controller auto-mates the control function.

Figure 24: Voltage Regulator Droop versus Var/PF Control Regulation

Figure 24 also illustrates the condition where the bus voltage may increase, causing aleading power factor condition on the generator. Here, the voltage regulator will decreaseexcitation following the characteristic slope of the reactive compensation circuit. This willkeep the system in synchronism. If the bus voltage rises excessively, however, leading VArload will increase, leading to a reduction in the field excitation and causing possible loss ofmachine synchronism.

The other two techniques used to regulate VArs or power factor follow the same basicconnections of the voltage and current sensing as well as control. There is a voltage inputand a current input at some phase angle difference as well as a means to turn the controlon/off. As with the SCP-250, this is typically a 52b control off the main tie breaker.

In PLC (Programmable Logic Controller) control, the excitation is sometimes controlled bya DC input into the regulator similar to the SCP-250. However, sometimes the PLC will haveoutput contacts to control a motor operated potentiometer or reference adjuster to changethe regulator's setpoint to change excitation. The only potential drawbacks to this ap-proach are the coordination of the overall control loop so stability is achieved and the wearand tear of a constantly moving M.O.P. or reference adjuster.

There are other uses for VAr/power factor regulation. One is kVA control.

19

kVA Control

In some industrial applications such as paper mills, large induction motor loads may exist.Precious VArs are robbed from the system resulting in low power factor. Cost penalties arealso often realized because of this low power factor. To improve the plant power factor,capacitors are often utilized across the line to restore kVArs. This method is very effective,but also very expensive. For paper companies where power plant generation is available, itmay be desirable for these generators to restore kVArs in the system by forcing them tooperate overexcited along the kVA limit of the generator. The method enables maximumutilization of the generator, especially when available kilowatts are minimum.

A kVA controller is connected so the sensed voltage is shifted 30 degrees leading from thenormal quadrature connection. Referencing Figure 25, an advantageous locus of operat-ing points is obtained. As kW load decreases, the vector 0-D moves to 0-C, O-B, and finally0-A approximately following the kVA limit of the generator. Armature and field current at0-A is slightly greater than 0-B. The lagging kVAr has increased almost 50%, providinggreater utilization of the machine. The capability curve suggests that rotor field heatingmay occur at minimum kilowatts. Therefore, the use of a maximum excitation limiter issuggested to override the kVA controller at exceedingly low values of kW to help ensuresafe rotor field heating. The system offers a benefit in improved power factor because ofthe 50% increase in lagging kVAr. The percent improvement in power factor is determinedby the amount of kilowatt load on the generator. The more kilowatt load, the less kVA forvar improving.

The VAr/Power Factor Controller regulates at a programmed quantity of VAr or powerfactor to assure sufficient excitation on the field under all types of load.

Figure 25: Generator Capability Curve

20

Figure 25 is a description of the controller's operation. A vector O-D is used to represent full.8 Power Factor output of the generator. With "var" regulation, if the kW is decreased pro-gressively, the vector O-D will move in a horizontal manner to O-C', O-B' and finally O-A'regulating the "var" quantity regardless of kW changes.

Power Factor Correction

The other use is for power factor correction. Using an unloaded motor as a synchronouscondenser and producing only VArs, it is possible to regulate a plant power factor com-pared to the utility input.

Figure 26: Power Factor Correction

It is also possible to regulate the power factor of your plant with your in-house generation.

Figure 27: In-house Generation

21

This configuration allows the user to regulate the VArs at the point where the CT is con-nected. Since the power factor/VAr regulator is controlling the excitation output, there is aneed to limit its range of control. On the SCP-250 the adjustment to help with this limiting isthe output limit adjust. The output is ±3VDC. If we limit this to some other value we limitthe amount of excitation the SCP-250 can control.

This, however, is not the optimum approach. A better choice is the addition of minimumand maximum excitation limits. To understand why, let's examine a synchronous generatorin regard to excitation and synchronism.

EXCITATION LIMITERS

What is Generator Synchronism?

The synchronous generator can be represented by a capability curve which shows theelectrical watts and VAr limit of the generator. These quantities are related to the permis-sible temperature rise of the generator windings and the mechanical limits of the system.The electrical watts are limited by the horsepower of the prime mover and by the heating ofthe rotor and the stator windings.

Under varying conditions, the automatic voltage regulator could command abnormally lowfield current due to higher than normal infinite bus voltage. If this occurs, the synchronizingtorque is reduced, allowing the rotor of the synchronous machine to advance beyond acritical power angle (δ90 degrees) resulting in loss of generator synchronism.

To better understand the term generator synchronism, imagine a rubber clutch connectingthe shaft of two engines. See Figure 28. As long as the speed remains constant on bothengines, the rubber clutch will lock the two shafts without distorting its own natural shape.But if one machine begins increasing speed, causing the other to lag, the clutch will beforced to stretch.

Figure 28: Two Engines Connected by a Rubber Clutch

If the speed continues to increase, causing a greater speed difference, the rubber clutchwill eventually stretch beyond its limits and break. The change in the relative shape of theclutch is synonymous with the power angle changing between the generator rotor andstator. In the generator at the time the power angle has advanced beyond the critical angleof 90 degrees, the system has lost synchronism. See Figure 29. The rubber clutch repre-sents the magnetic flux between the generator rotor and stator which enables the power tobe transferred from the prime mover to the distribution system.

22

Figure 29: Power Relationship versus Displacement Angle

The maximum allowed elasticity of the rubber clutch is defined as the stability limit of thegenerator, and each generator has the capability curve which defines this limit. As long assufficient excitation is maintained in the field for the generator load, synchronism is as-sured.

Figure 30: Generator Reactive Capability Curve

23

Figure 31: Static Exciter Excitation Limiting

Overexcitation is designed to protect the machine during operation at lagging power factorbeyond the machine rating, but generally the machine limit of overexcitation is rotor over-heating (high field current). To prevent rotor overheating, measuring the excitation currentto the rotating field of the generator and cutting back the excitation current after some timedelay is the most widely accepted way. A higher instantaneous or hard limit may also be afunction included in the limiter. If excitation with very high forcing voltage is used, an in-stantaneous limiter can keep the excitation current during forcing to a lower level than theforcing voltage would otherwise drive it, gaining faster generator response from highforcing, both positive and negative, without need for more cost in the rotor, brushes, andslip rings to handle high forcing currents.

Figure 32: Overexcitation Limiter Limits Max. Field Current

24

To sufficiently protect the rotor, it is necessary to know the thermal capability of the rotorunder worst case conditions. If the rotor is operating at maximum continuous current andthe load demand moves the excitation higher, then you must know how long the field willtake before temperature of the rotor exceeds its upper limit. With a curve plotting thermallimit based on full load operation prior to the higher current, the overexcitation schememay be coordinated with the generator capability. When an older machine is upgradedwith new excitation, it may not be possible to obtain the rotor thermal capacity curve toallow accurate setting of the relay. Standard practice is to choose a conservative setting tomake sure limiter operation keeps the field temperature within safe limits.

Figure 33: Rotor Angle or Underexcitation Limiter

Underexcitation is designed to protect the machine during operation at leading powerfactor. To perform its function, the underexcitation limiter measures stator voltage, current,and phase angle. The primary concern for this limiter is the possible loss of synchroniza-tion with the stator resulting from a magnetic field strength too low to keep the rotor fromslipping poles. Machines operating in parallel with an electrical network are most suscep-tible to this possibility, mainly instigated by some fault on the network being cleared by abreaker, and the resultant fast recovery of the system voltage when low magnetic field isavailable to maintain the rotor angle less than 90 degrees. Internally, the rotor angle of themachine is a function of the excitation current and real power load. The rotor angle in-creases from zero as load increases and decreases with increased excitation current. If therotor angle is too close to the hypothetical 90 degree angle at which pole slip is certain, atransient load change can cause rotor torque to exceed the synchronizing torque existingbetween the rotor and stator. By limiting excitation to give a smaller rotor angle, the possi-bility of pole slip is reduced. This area of limiting can contribute greatly to the ability of themachine to be used in either leading or lagging power factor operation without concern forthe possibility of pole slip. Avoiding pole slip prevents very high mechanical stresses andhigh currents from doing severe damage to the machine. The preferred characteristic for

25

underexcitation limiting is referred to by some manufacturers as Rotor Angle Limiting. Thismeans simply that the limiter monitors stator volts and amps, and will provide limiting toallow full stator current at leading power factors near 1.0, increasing excitation and de-creasing stator current along a circular curve as the power factor moves further into theleading power factor area.

Figure 34: Stator Current Limiting

To complete the machine protection, add the stator current limiter. This function acceptscurrent from generator current transformers, and begins to reduce excitation if the statorcurrent exceeds the maximum for too long. The time is a function of the generator thermalcapacity, thus the stator current may be instantaneously limited, inverse time delay limited,or both. Setting the instantaneous limit to protect the machine for fault currents and settingthe time delay for thermal protection gives a high level of protection for the machine.

26

Figure 35: Combined Limiters

Basler Electric HeadquartersRoute 143, Box 269,Highland Illinois USA 62249Phone 618/654-2341Fax 618-654-2351

Basler Electric InternationalP.A.E. Les Pins, 67319Wasselonne Cedex FRANCEPhone (33-3-88) 87-1010 Fax(33-3-88) 87-0808

If you have any questions or needadditional information, please contact

Basler Electric Company.Our web site is located at:

http://www.basler.come-mail: info@basler.com

Basler Electric HeadquartersRoute 143, Box 269,Highland Illinois USA 62249Phone +1 618.654.2341Fax +1 618.654.2351

Basler Electric InternationalP.A.E. Les Pins, 67319 WasselonneCedex FRANCEPhone +33 3.88.87.1010Fax +33 3.88.87.0808

If you have any questions or needadditional information, please contact

Basler Electric Company.Our web site is located at:

http://www.basler.come-mail: info@basler.com