发电机并联负载分配

PARALLEL OPERATION WITH A NETWORK SYSTEMThe purpose of this discussion is to address the concerns of and the techniques required to successfully parallel synchronous generators to a network.A network consists of two or more buses connected together by one or more power lines whose impedance compared to the capacity of the network generating capacity cannot be neglected. Contrast this definition with that of a bus whose impedance is so low that it can be 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 all connected 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 power systems 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 utilities currently 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 of computers to perform complex calculations very quickly, however, the analysis of power system load flow is greatly simplified compared to the slide rule days.Figure 1: Paralleled SystemsOne way to simplify the analysis of network operation is to adopt the concept of "infinite bus" for the network. This assumption can be used if the capacity of the network at a point of interconnection is at least 10 times greater than the capacity of equipment connecting to the network. The concept holds true when the network voltage and frequency are not changed when real and reactive currents change at the point of connection. An example is a generator connected to a network, with generator size of 100kW and the connection point being an industrial plant served by a 10MVA transformer. With the transformer being fed from a line having a capacity of 150MVA, any changes in load flow caused by fuel or excitation changes at the 100kW generator will have no measurable effect on the voltage and frequency of the transformer secondary. This is also referred to as the stiffness of the grid.Figure 2: Typical Paralleled SystemT o control the real power flow from the 100kW generator, the problem has changed from the load sharing scheme needed for multiple generators serving an isolated load. Now the control scheme must regulate the real power load from the generator to the plant bus based on some other criteria than just load sharing. To perform this function, another block is added to the basic control loop of the speed governor establishing a desired kW load setpoint and adjusting fuel to the prime mover to maintain load at the setpoint value. Since this control loop is closed, stability of the control system must be provided for. The block diagram in Figure 3 illustrates a common way of providing the second control loop for regulating real power load. The setpoint may be a fixed value at or near full load, a control system designed to maintain steam pressure to a varying load while using the excess capacity of the prime mover to generate electricity, or to keep the utility power supply below some maximum demand limit. By regulating the generator load kW, any variation in frequency from the network will cause only momentary deviation in real load until the control loop senses the deviation in load and corrects by adjusting fuel.Figure 3: Alternative Control StrategyT o help explain this approach, let's review some basic governor controls.Parallel Operation Of The Governor And Real PowerIn 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*1*cosφ. 1000First, let's discuss the governor controls.DefinitionsBefore one can fully retain the information to be presented, it is imperative to recognize and understand the following terms.A: Droop: Refer to Figure 4. When a prime mover has a droop governor, the prime mover simply decreases in speed as load is applied. A droop governor will usually have between 3% to 10% droop. Figure 4 illustrates a governor with 3.3% droop. Notice the no load speed 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, the prime 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 zero droop. Notice the no load speed is set at 60 hz and at full load the prime mover’s speed remains at 60 hz.Figure 5: Isochronous GovernorC: Real Power is horsepower produced from the prime mover converted to kilowatts by the generator. KW=E L-L * 3*1*cos φ. In this formula, cos φ is the power factor. 1000D: Reactive Power is the power that is required by the inductive and capacitive loads. In a purely resistive load there is no reactive power. In a paralleled system the generators can produce 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 GovernorsSystems produced today seldom are designed with droop. This is because most loads require the generator frequency to remain constant and, as defined, droop governors decrease in speed with an increase in load.The operation of synchronizing requires that the generator’s voltage, frequency and phase have to be matched and a circuit breaker tying the generators together be closed. This magnetically locks the generators together, forcing them to operate at the same speed. All that has to be done now is to control the power distributed between the generators. The power required by the load is fixed.With the prime movers equipped with droop governors, it is important that both governors be set the same if the generators are expected to share load equally. This means each one has to be set to the same speed. Each one has to be calibrated with the same percentage of droop. With the speed and droop set the same, the prime movers will equally share the load. Refer to figure 6.With droopgovernors, theportion of loadsupplied by eachgenerator iscontrolled.Figure 6: Paralleling Generators with Droop GovernorsFigure 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 second governor curve and the vertical axis is labeled both “speed” and “power”. The addition of power illustrates that when the speed setting is increased on one paralleled generator, that generator will assume a greater portion of load. The inverse occurs when the speed setting is decreased on a paralleled generator. When the speed setting is changed in relationship to the speed setting of the other generator, the actual speed of the prime mover does not vary from the other generator. The torque from the prime mover is changed, thus changing the power output.The question may be asked: How are the mechanical governors capable of sharing the load? This can simply be determined by analyzing the performance (droop) characteristics of 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 as load increases and increasing speed as load decreases.Passes above63Hz at 0%load, 60Hz at100%.Figure 7: Droop CurvesFigure 8: Loading of GeneratorsT o parallel the second generator with generator 1 operating at 100% load and 60Hz, the normal 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 in Figure 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 the load 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 balanced to 50/50 each generator, the speed has increased to 61.5Hz. At this point both generators are at the same relative load and speed. An operator must then decrease both governor setpoints down to 60Hz.Figure 9: Balanced LoadAt 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 to the 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 from the two generators, so the sum of the kW supplied by the two generators must equal the load kW. In addition, by the action of paralleling, the two generators must maintain exactly the same frequency. Any increase in power output from one of the generators results in a corresponding decrease in speed, based on the droop curve. The other unit will not allow the decrease in speed because its droop curve, seeing a decrease in load, attempts to increase the speed setting, keeping them in balance.As the total load increases from 50% to 100%, the paralleled generators will share the load equally but the system frequency will decrease along the droop curves as in Figure 10.Figure 10: Load ChangesThis is a dynamic system with power demand constantly changing on the system. The droop characteristics of the mechanical governors are a stabilizing mechanism in a parallel system. Simply put, as load attempts to change among the generators the droop governor stabilizes and proportions the load.Paralleling Generators with Isochronous GovernorIsochronous governing has became the governor of choice in today’s industry. The reason is the governor’s ability to maintain a constant set speed throughout the prime mover’s power 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 it is important to understand why isochronous governors by themselves cannot be paral-leled.Figure 11 illustrates two generators running independently. The speed on generator #1 is set 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 to 60.1Hz and generator #2 would be pulled down to 60.1Hz. The governor on generator #1 would sense the actual speed to be too high and the governor on generator #2 would sense the actual speed to be too low. Governor 1 would respond by reducing fuel and governor 2 would respond by increasing fuel. The effect would be generator #2 taking all the load and motorizing generator #1.Figure 11: Generators Running IndependentlyIn 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 to share the load properly between all paralleled generators. Refer to Figure 12 for a visual diagram of a typical load sharing system.Figure 12: Typical Load Sharing SystemParalleling Generators T o An Infinite BusWhen paralleling generators to an infinite bus there are two systems used. System 1 holds kW load of the generator bus constant and allows the utility to provide the remainder of the load demand. System 2 reverses this action, holding the utility bus kW load constant and forcing the generator bus to provide the remainder of the load demand.System 1Implementing system 1 requires addition of a load control module. To set the power level for system 1, a load control module is added to the load sharing controls that biases the communication lines which balance the load between generators. For example. if the voltage on the communication lines is 0 to 3 volts dc, adding a linear signal with 0 volts being no load and 3 volts being maximum rated load of the generator sets changes the load on all paralleled generators simultaneously. If one wants the generator system to produce 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 level drops below the generator bus set level. The generator bus will export power into the Utility network.Figure 13: System 1 (Generator Bus Constant)System 2System 2 control requires additional hardware compared to system 1. Controls are added to the utility to monitor the power level imported. These controls compare a set power level to 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 and decrease power out when load is decreased. This dynamic action controls the generator bus output while holding the utility at a constant power level. Unlike system 1 where power can be exported, system 2 prevents power from being exported into the utility.Figure 14: System 2 (Utility Bus Constant)Frequency variations in U.S. power networks are normally very small unless a lack of sufficient generating capacity occurs due to malfunctions of the system. If the frequency of the 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 the machine when frequency exceeds normal operating conditions.If the generator is a large utility plant, the real power load is dispatched or controlled by an operator 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 to supply the power at lowest cost per kWh (Kilowatt hour). On large systems, the solution to providing power at lowest production cost requires a sizable computer with a model of the network to continually evaluate the load demand and its location on the network in order to shift the generation of the power among the plants. When the solution to the needs is calculated, the dispatcher calls for power to be supplied from the plants, either by remote control to each plant or by sending dispatch requirements to the plant operators. Load profiles are well established for normal workdays, weekends, etc. so the problem can be solved 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 and frequency are affected by changes in the plant load levels, making it necessary to solve the load flow of the network in order to keep the network operation within acceptable power quality limits.Parallel Operation of the Excitation SystemT o control the reactive power from the 100kW generator, a similar control loop to the speed governor kW regulator is used to measure one of two parameters of the generator; the first is reactive power flow, measured by current and voltage transformers connected in quadrature exactly like the arrangement in the droop circuit. By comparing the measured kvar load with the setpoint, adjustable for leading or lagging reactive load, the generator will supply a constant reactive current to the bus regardless of load demand and variation in bus voltage.T o 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). Along the 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 Volt 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 reactive power 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 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 of the stator windings on a continuous basis at maximum ambient temperature. This rating also 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 thermal rating of the core of the machine at maximum voltage and nominal speed.Figure 15: Power TriangleT wo parameters, reactive power and power factor, are the ones that the excitation system can control. The question is then raised as to how this is done. One approach is to treat the infinite source as another generator to be paralleled to and connect the voltage regula-tor in the droop mode.Figure 16: Typical Droop ConnectionIn this method, the droop adjustment is made just as if the generator were paralleled with another 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 to the voltage regulator is, in a sense, like adding impedance to the line, so a large transformer helps in this type of paralleling. If the grid is not very stiff, then paralleling in the droop 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 the droop mode, can I parallel with the regulators connected in reactive differential or cross current. The answer to this is that it is not recommended. If we review what a cross current loop looks like to the voltage regulators, we can see why. Since the regulators connected in cross current expect that a change in its compensation circuit will cause a change in the other circuits, there will not be a change in the infinite grid no matter what the regulator does.Figure 17: Cross Current CompensationSince many generator power systems must support load in a mode not paralleled to the grid and at some point will also parallel with the grid, how can the systems be connected in cross current? The answer is that the cross current connections may be disabled when the main tie breaker is closed. Breaking the loop in any one spot will disable the cross current compensation. An example is as follows:Figure 18: Scheme to Disable Cross CurrentIt may seem that connecting the regulators in droop to parallel to the grid is the best way to operate. However, compared to the frequency, bus voltage is subject to much greater variation, and the source of the variation may be local changes in load or network voltage variations which occur because of line losses changing with load or changes in network operating voltage from daytime to nighttime levels. Regardless of the cause, the effect on a droop compensated generator would be changing reactive load levels. Most regulators have 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 voltage back to its setpoint. Since by definition the grid is infinite, the generator cannot restore the voltage. As the excitation increases the generator starts exporting VArs into the grid. This situation 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 RegulationAdding a var regulator to the excitation system and operating in the var regulation mode allows maximum utilization of the generator reactive load capability independent of real power load. Alternatively, the var regulator may be set to maintain the generator reactive load 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 by adjustment to the avr setpoint voltage. The result is a constant VAr load on the generator without any operating intervention.Figure 19: Alternative Control StrategyThe second type of control loop measures the power factor or the angle of generator current with relation to the voltage. In this control mode, the reactive load is regulated as a percentage 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 keep the power factor constant in their manual control practices. Many generators are equipped with a power factor meter and a kW meter in addition to volts, amps and frequency. In this configuration, a var regulator can produce some readings on a pf meter which will alarm some 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 is able to operate safely under at this condition. Power factor regulation may be selected as a control option if desired, but by replacing the traditional power factor meter with a var meter 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.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 LevelAs the kW changes, the angle stays the same, the kVAR level changes. Since we are regulating the angle, the cosine of the angle stays the same.Figure 21: Constant Power factor LoadAdding an additional component to the excitation system is relatively easy. A basic block diagram is shown in Figure 22.Figure 22: VAR/PF Controller with Static ExciterFigure 23 shows the faceplate of the Basler Electric SCP-250. Setting on the SCP-250 is from .6 power factor leading to .6 power factor lagging when in the power factor control mode.Figure 23: SCP-250 FaceplateIn the VAr control mode the adjustment is either to produce or absorb VArs. The VAr range adjustment sets up the limits at either end of the potentiometer travel.Figure 24 illustrates a generator that is equipped with a solid state voltage regulator having reactive voltage droop compensation. The graph illustrates the effect of bus voltage changes on the reactive/ampere load on the generator. If the bus voltage drops by 6%, the reactive/ampere generator load will change from 0 - 75%. A further decrease in bus voltage exceeding 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/PF controller regulates at a programmed operating point and is insensitive to changes in the bus voltage. Field heating increases (higher excitation current) as lagging reactive load increases. Keeping the lagging VAr load under control protects the generator field from overheating. 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 RegulationFigure 24 also illustrates the condition where the bus voltage may increase, causing a leading power factor condition on the generator. Here, the voltage regulator will decrease excitation following the characteristic slope of the reactive compensation circuit. This will keep the system in synchronism. If the bus voltage rises excessively, however, leading VAr load will increase, leading to a reduction in the field excitation and causing possible loss of machine synchronism.The other two techniques used to regulate VArs or power factor follow the same basic connections of the voltage and current sensing as well as control. There is a voltage input and a current input at some phase angle difference as well as a means to turn the control on/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 by a DC input into the regulator similar to the SCP-250. However, sometimes the PLC will have output contacts to control a motor operated potentiometer or reference adjuster to change the 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 wear and tear of a constantly moving M.O.P. or reference adjuster.There are other uses for VAr/power factor regulation. One is kVA control.kVA ControlIn 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 are also often realized because of this low power factor. T o 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 to operate overexcited along the kVA limit of the generator. The method enables maximum utilization of the generator, especially when available kilowatts are minimum.A kVA controller is connected so the sensed voltage is shifted 30 degrees leading from the normal 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 finally 0-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%, providing greater utilization of the machine. The capability curve suggests that rotor field heating may occur at minimum kilowatts. Therefore, the use of a maximum excitation limiter is suggested to override the kVA controller at exceedingly low values of kW to help ensure safe rotor field heating. The system offers a benefit in improved power factor because of the 50% increase in lagging kVAr. The percent improvement in power factor is determined by the amount of kilowatt load on the generator. The more kilowatt load, the less kVA for var improving.The VAr/Power Factor Controller regulates at a programmed quantity of VAr or power factor to assure sufficient excitation on the field under all types of load.Figure 25: Generator Capability Curve。