1PARALLEL 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. This session is expected togive you an understanding of:

Generator operating configurations Control of Prime Mover speed and real power Control of Generator voltage and reactive power

In simple form, a generator set connected to some load is an islanded power system, andthe operation of such an islanded system has been discussed. Voltage regulation main-tains constant bus voltage, and speed governing maintains constant frequency. Load onthe generator set is totally determined by the load demand. With only one source of power,there are no issues with load sharing. For voltage and frequency control, the simple func-tions of an automatic voltage regulator (AVR) and a speed governor will suffice to keepvoltage and frequency of the power system on target, accommodating changes in loaddemand as needed. Increases in real or reactive power will cause changes in voltage andfrequency, and the control circuits will adjust fuel and excitation to restore the nominalvalues. There is no need for any kind of load sharing equipment such as droop compensa-tion.

Figure 1: Islanded Power System

Next up in complexity is a system of two or more generators connected to a common bus.This configuration was covered with regard to excitation control when we spoke earlier inthe course about generators operating in parallel. In this configuration, voltage droop orcross current compensation were methods used to share the reactive load. In this session,we will briefly discuss the application of governor controls that will provide for droop orisochronous load sharing of the real power.

2Figure 2: Multiple Paralleled Generators

Finally, the operation of one or more generators in parallel with a network, such as a utilitypower system, is often considered the most complex generator operation mode. Thismode will be the focus of this session.

Networks or BusWhats the difference??

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 networks 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.

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 connection pointbeing an industrial plant served by a 10MVA transformer. With the transformer being fedfrom a line having a capacity of 150MVA, any changes in load flow caused by fuel or exci-tation changes at the 100kW generator will have no measurable effect on the voltage andfrequency of the transformer secondary. This is also referred to as the stiffness of the grid.

3Figure 3: 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 set point value. Sincethis control loop is closed, stability of the control system must be provided for. The blockdiagram in Figure 4 illustrates a common way of providing the second control loop forregulating real power load. The set point 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 4: Alternative Control Strategy

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

4Parallel 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*I*cos.

1000First, let's discuss the governor controls.

Definitions

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

A: Droop: Refer to Figure 5. 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 5 illustrates a governor with 3.3% droop. Notice the no loadspeed is set to 62 hz and at full load the prime movers speed has decreased to 60 hz.

Figure 5: Droop Governor (3.3% droop)

B: Isochronous: Refer to Figure 6. When an engine has an isochronous governor, the primemover will maintain its set speed throughout its entire horsepower range. An isochronousgovernor is said to have zero droop. Figure 6 illustrates a governor with zero droop. Noticethe no load speed is set at 60 hz and at full load the prime movers speed remains at 60hz.

Figure 6: Isochronous Governor

5C: Real Power is horsepower produced from the prime mover converted to kilowatts by thegenerator. KW=EL-L* 3*I*cos. In this formula, cos 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.

Paralleled Generators and kW Load Sharing Control

With two or more generators operating in parallel, the load will demand the power it re-quires as long as the bus voltage and frequency are maintained. From the view at the load,power supply from one generator, two generators in parallel, or a generator and a utility,the view is the same as long as the bus voltage and frequency are maintained.

For two or more generators connected in parallel, we can look to the solution offered for theAVR in the talk earlier this week of voltage droop. For control of real power (kW), two gen-erators must have the ability to adjust fuel in response to load changes while somehowallowing for adjustment of the load sharing between two generators. The most commonway, and the oldest technique is to use speed droop compensation to do the job. To seewhat speed droop really is, lets consider a single generator connected to a variable load.If the governor is selected and adjusted to provide 5% speed droop, the governor willcause the engine speed to be a function of the real power loading as illustrated by thedroop curve below.

Figure 7: Generators Paralleled to Common Bus

The graph illustrates the decrease in speed that will occur at any load in kW on the genera-tor output. To utilize this scheme with multiple generators, a very common practice withdroop governors is to set one machine as the lead machine by adjusting droop to zero(Isochronous or constant speed) droop. This machine is connected to the bus first andremoved only when the bus is shut down. This machine will maintain bus frequency con-stant at any level of load within its capacity. If the load begins to approach the maximum

6capacity of this lead unit, a second generator is started, synchronized, and paralleled withthe lead unit. The second unit may have 3-5% droop set to allow for the adjustment of loadby the operator.

Figure 8: Speed Droop

With speed matched and phase angle matched, the breaker may be closed, and thesecond unit will be operating in parallel with no load. The operator may now adjust speedup to begin taking some of the load from the lead unit. The kW load will not change withadded or removed load from the bus, as all changes in load demand will be picked up bythe lead unit.

With increasing load, if the lead unit again approachs its maximum capacity, it will benecessary to add a third generator to the bus, again operating in droop, set to the samedroop as the second generator. It will be synchronized and loaded like the second unit,operating at fixed load with changes in load demand. When load decreases and the leadunit is operating too lightly loaded, a generator (the second or third machine) must beremoved from the bus by unloading it and tripping its breaker.

With electric governors, it is also possible to operate two or more governors in parallelwithout having in droop in speed, the so-called Isochronous control. With this type of con-trol, an external module or a built-in governor circuit connected to measure generator voltsand amps is able to measure kW load on the generator it is controlling. The external mod-ule is often referred to as a load sensing module. Connections to CTs and PTs on the outputof the generator supply the necessary information to the governor control. The calculatedkW load of the generator is compared with a voltage from the Load Lines tying all thegovernors of the generators able to operate together. This voltage is representative of thetotal demand of the load. Using the speed adjust, the operator can set the amount of loadfor each generator operating in parallel. Each generator, in turn, monitors the total loadusing the voltage level on the load lines and adjusts fuel to keep its proportional share ofload as the load varies up and down.

7Figure 9: Governor with LSM

But our real interest here is operating a generator in parallel with a network, such as a utilitygrid. In this case, the utility can be considered like the lead machine in our previous ex-ample, operating at a fixed frequency regardless of the load. Therefore, the generatorbeing connected to the load bus can be equipped with a droop governor system, withdroop adjusted between 3-5%, and the operator may synchronize, connect the generator inparallel with the network, and with the speed droop characteristic, the operator can in-crease the set point of the speed governor and take on load. Because the utility frequencyis very stable, it is easy to set the desired load and expect it to remain constant. Only somechange in the utility frequency would cause the load to change. Using the example of 5%droop, a change in frequency on the grid of 1% will cause a change in the generator loadof 20% of the generator rating.

Figure 10: Parallel With Utility Grid

8Instead of a droop governor, if the generator is equipped with an electric governor withisochronous load sharing capability, could the generator be paralleled and operated onthe utility network? Yes, and in two different ways. One way is to equip the utility with a loadsharing module (LSM) and connect the load sharing lines between the generator LSM andthe utility LSM. Connected in this fashion, the utility and the generator would share the load,with the sharing ratio determined by the PT and CT ratios used to feed the two LSMs.

Figure 11: Generator and Utility with Isochronous Sharing

A second way to use the Isochronous speed governor is to feed a dc voltage, adjustableby a control by the operator, to set the voltage to the LSM to load up the generator when it isconnected on line. Since the speed governor LSM compares its kW load to the voltage onthe load lines, the load line voltage will cause the generator to take on load until its LSMsees equal load to the load line voltage. With this connection, the kW load is maintainedconstant at a level determined by the operator. To operate the generator at no load, onemay short out the load lines. Opening up this switch to allow a fixed voltage on the loadlines then ramps up the load on the generator, but this contact should only be openedwhen the generator is on line and paralleled to the utility. The utility is once again acting asthe lead generator and must supply the additional load as required. This mode of opera-tion is often referred to as Base Loading, but this term is most often applied to large utilitypower generators used to operate the generator at or near rated load continuously for mosteconomical operation.

9Figure 12: Base Loading the Generator

Another mode of operation for a generator connected to a utility is the Peak Shavingmode. In this mode of operation, it is required for the utility to supply all power up to somemaximum limit, then the generator is required to pick up all load in excess of the limit. Toimplement this system, the LSM may be used to measure the output kW of the generator.Next, if a signal (dc voltage) is applied to the load lines representing the power demandthat exceeds the limit, then the generator output will follow the variations in load that ex-ceed the maximum limit. Using the load lines in the right way allows a versatile control ofthe generator loading, if a black box exists to supply the necessary signals to the LSM. Thisfunction is sometimes referred to as import control, meaning the control of power importedfrom the utility grid.

Figure 13: System 1 (Generator Bus Constant)

While operating the onsite generators in a peak shaving application, it might be necessaryto "sequence" the generators by determining when to start a specific generator and have itstart to supply load. This sequencing can be done by some external means. For example,a distributed control system might be utilized to determine which generators are to beoperated at what loads and in what order. A PLC also can be used for this task, and somegenerator control devices can be used to accomplish this control scheme.

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Figure 14: Typical load sharing interconnection

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If the controller has a Demand Start/Stop feature, it can be utilized to determine the controlof the generators. If the system demand is above the configured level setting for thespecified time, and sequencing is enabled, the unit will start, close its breaker, and take onload at the programmed load rate. Note that the unit will not start if sequencing is notenabled. If the unit is the only one on the load, it will provide the full load. If the load dropsbelow the Stop level for the specified time, the unit will unload at the programmed loadrate, open its breaker, and stop. Sequencing also can be determined by parametersincluding Engine Run Time, Generator Size, and even the generator's Hours to Maintenanelevel.

Figure 15: Base Load the Utility

One other mode of operation may be used, referred to as export control. In this mode, thepower supplied to the utility grid may be regulated. Up to this point, all the operations wehave contemplated have primarily assumed that utility power would always be supplied insome quantity to an electric supply system that happens to also include a generator. But itmay be necessary in some applications to sell power to the utility. This operation causespower to flow into the utility system during operation of the generator, with the expectationthat the utility will pay for the power exported from the generator. If it is required to maintaina constant flow of power from the generator, we saw that the LSM can be connected to anadjustable dc voltage on the load lines, and the governor will adjust fuel to maintain thegenerator load at the level commanded by the dc voltage on the load lines. It is also pos-sible to operate in an export mode that maintains a constant power flow into the utility gridby connecting an LSM on the utility system, with CT polarity reversed from the normalconnection. By measuring the power exported to the utility grid, the LSM can cause thespeed governor to adjust fuel to maintain a constant utility power level. Of course, thegenerator must have sufficient capacity to supply all load at the generator location, plus theexported power to the utility.

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Figure 16: System 2 (Utility Bus Constant)

Figure 17: Export Power Control of Generator Load

Finally, the last mode we will consider is commonly referred to as Combined Heating andPower (CHP) or Cogeneration. In some applications where steam is required for some kindof process, a prime mover can supply steam through heat recovery and generate electricpower. For high efficiency of operation, it is often attractive to use the steam as the primaryoutput from the genset and use any excess energy to generate electric power. In this case,the speed governor and LSM can be used with steam controls to regulate the supply ofsteam by adjusting electrical load as needed to maintain the steam flow and temperature.By supplying the load line inputs with a dc voltage corresponding to the electrical loadrequired to support the steam supply, the load module can adjust the fuel to meet thedemand.

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Figure 18: Combined Heating and Power Control

In summary, a governor system to meet the needs of an application can be configuredusing available components from manufacturers of governing equipment. Applicationspecialists in governor controls can assist with equipment specs and selection once youcan describe for them the kind of operation you require. With the increasing availability ofmultifunction digital products, many of the functions needed to implement some theschemes above can be obtained in a single control system and programmed to performthe functions needed.

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 in quadra-ture exactly like the arrangement in the droop circuit. By comparing the measured kvarload with the set point, adjustable for leading or lagging reactive load, the generator willsupply a constant reactive current to the bus regardless of load demand and variation inbus 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 Kilovolt Amp(VA or kVA). The reactive power is the third leg of the triangle and is expressed as VoltAmperes 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 size

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generators, 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 19: 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 treat theinfinite source as another generator to be paralleled to and connect the voltage regulator inthe droop mode.

Figure 20: 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 the grid,this approach works even better due to the impedance of the transformer. Adding droop tothe voltage regulator is, in a sense, like adding impedance to the line, so a large trans-former helps in this type of paralleling. If the grid is not very stiff, then paralleling in the

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droop mode may be satisfactory. This way, an operator can monitor and make adjustmentsas 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 connected incross 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 21: Cross Current Compensation

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 connected incross current? The answer is that the cross current connections may be disabled when themain tie breaker is closed. Breaking the loop in any one spot will disable the cross currentcompensation. An example is as follows:

Figure 22: Scheme to Disable Cross Current

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It may seem that connecting the regulators in droop to parallel to the grid is the best way tooperate. 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 set point. 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.

Figure 23: Alternative Control Strategy

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The second type of control loop measures the power factor or the angle of generator cur-rent 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 var meterand 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.

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

As angle changes, the power factor changes.

Figure 24: Constant kVAR Level

As the kW changes, the angle stays the same, the kVAR level changes. Since we are regu-lating the angle, the cosine of the angle stays the same.

Figure 25: Constant Power factor Load

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Adding an additional component to the excitation system is relatively easy. A basic blockdiagram is shown in Figure 26.

Figure 26: VAR/PF Controller with Static Exciter

Figure 27 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 27: SCP-250 Faceplate

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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.

Figure 28 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 volt-age exceeding 4% would overload the generator, causing excessive heating in the fieldwinding as well as the power semiconductors of the automatic voltage regulator. The VAr/PF controller regulates at a programmed operating point and is insensitive to changes inthe bus 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 28: Voltage Regulator Droop versus Var/PF Control Regulation

Figure 28 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 approach

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are the coordination of the overall control loop so stability is achieved and the wear andtear of a constantly moving M.O.P. or reference adjuster.

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

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,it may 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 29, an advantageous locus of operatingpoints 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 heating mayoccur at minimum kilowatts. Therefore, the use of a maximum excitation limiter is sug-gested to override the kVA controller at exceedingly low values of kW to help ensure saferotor field heating. The system offers a benefit in improved power factor because of the50% increase in lagging kVAr. The percent improvement in power factor is determined bythe amount of kilowatt load on the generator. The more kilowatt load, the less kVA for varimproving.

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

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Figure 29: Generator Capability Curve

Figure 29 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.

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Figure 30: Power Factor Correction

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

Figure 31: In-house Generation

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 limit theamount 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.

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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 (90 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 32. 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 32: 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 33. 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.

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Figure 33: 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 34: Generator Reactive Capability Curve

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Figure 35: 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 current tothe 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 instan-taneous 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 36: Overexcitation Limiter Limits Max. Field Current

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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 scheme maybe coordinated with the generator capability. When an older machine is upgraded withnew excitation, it may not be possible to obtain the rotor thermal capacity curve to allowaccurate setting of the relay. Standard practice is to choose a conservative setting to makesure limiter operation keeps the field temperature within safe limits.

Figure 37: 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 and

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high currents from doing severe damage to the machine. The preferred characteristic forunderexcitation 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 38: 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.

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Figure 39: Combined Limiters