PARALLEL OPERATION WITH A NETWORK SYSTEM The 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 voltage 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 reactance, 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 network 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 resistance 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 Systems One 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 System To 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 Strategy
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 fundamental control loops: the governor control loop and the voltage regulator control loop. The governor controls the real power portion of the generator, kW=E L-L* 3 *1*cosφ. 1000 First, let's discuss the governor controls. Definitions Before 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 isochronous 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 Governor
C: Real Power is horsepower produced from the prime mover converted to kilowatts by the generator. generator. KW= KW = EL-L* 3 *1*cosφ. In this formula, cos φ is the power factor. 1000 D: 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 Paralleling Generators with Droop Governors Systems 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 droop governors, the portion of load supplied by each generator is controlled.
Figure 6: Paralleling Generators with Droop Governors
Figure 6 illustrates the droop curve and load of two paralleled generators. Notice the similarity 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 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 demand changes cause the generator speed to follow the droop curve, decreasing speed as load increases and increasing speed as load decreases.
Passes above 63Hz at 0% load, 60Hz at 100%.
Figure 7: Droop Curves
Figure 8: Loading of Generators To parallel the second generator with generator 1 operating at 100% load and 60Hz, the normal synchronizing method matches generator frequency 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 Load At this point, if the total load increases, the governors will share the increase proportionately. 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, #1 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 Changes This 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 Paralleling Generators with Isochronous Governor Isochronous governing has became the governor of choice in today’s industry. The 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 controlling paralleled generators. Isochronous governors require additional additional controls to be capable 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 paralleled. Figure 11 illustrates two generators running independently. independently. The speed on generator #1 is set at 60Hz. The speed on generator #2 is set to 60.2Hz. Remember, isochronous governors 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. 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 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 compare the measured value with total load via the load lines. If the power levels are unbalanced, the added controls send a power setting output to the speed input of the isochronous 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 Typical Load Sharing System
Paralleling Generators To An Infinite Bus When 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 1 Implementing 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 2 System 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 communication 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 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 requires 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 System To 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. 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). 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 maximum 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 Triangle Two parameters, reactive power and power pow er factor, factor, are the ones o nes 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 regulator in the droop mode.
Figure 16: Typical Droop Connection In 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 adjustments 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 Compensation
Since 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 Current It 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 setting, the regulator decreases its output and a generator is paralleled and must start importing VArs to operate at the high bus voltage level. This could cause the generator to become 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 distribution 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 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 possible 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 Strategy
The 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 percentage 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 regulation 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) 2) 3)
Add ad addi diti tion onal al comp compo one nent nt to the the syst system em,, Inte Integr grat ate e VAr VAr/P /Powe owerr ffact actor or contr control ol into into the the regul regulato atorr its itself elf,, and and Programmable Lo Logic Co 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 Level As 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 Load
Adding 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 Exciter Figure 23 shows the faceplate of the Basler Electric SCP-250. Setting on the SCP-250 SCP-250 is from .6 power factor leading to .6 power factor lagging when in the power factor control mode.
Figure 23: SCP-250 Faceplate In 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 winding 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 automates 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 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 c ontrol off the main tie breaker. 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, 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 approach are the coordination of the overall control loop so stability is achieved and the wear and tear tea r of a constantly cons tantly moving M.O.P M.O.P. or reference adjuster. 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 are also often realized because bec ause of this low power pow er factor. To improve the plant power p ower 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 operating 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 at 0-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 o n the field under all types of load.
Figure 25: Generator Capability Curve
Figure 25 is a description of the controller's operation. A vector O-D is used to represent full .8 Power Factor Factor output of the generator. generator. With "var" regulation, if the kW is decreased progressively, the vector O-D will move in a horizontal manner to O-C', O-B' and finally O-A' 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 synchronous condenser and producing only VArs, it is possible to regulate a plant power factor compared 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
This configuration allows the user to regulate the VArs at the point where the CT is connected. Since the power factor/VAr regulator is controlling the excitation output, there is a need to limit its range of control. On the SCP-250 the adjustment to help with this limiting is the output limit adjust. The output is ±3VDC. If we limit this to some other value we limit the amount of excitation ex citation the SCP-250 can control. This, however, is not the optimum approach. A better choice is the addition of minimum and maximum excitation limits. To understand why, let's examine a synchronous generator in regard to excitation and synchronism. EXCITATION LIMITERS What is Generator Synchronism? The synchronous generator can be represented by a capability curve which shows the electrical watts and VAr limit of the generator. generator. These quantities are related to the permissible 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 of the rotor and the stator windings. Under varying conditions, the automatic voltage regulator could command abnormally low field current due to higher than normal infinite bus voltage. If this occurs, the synchronizing torque is reduced, allowing the rotor of the synchronous machine to advance beyond a critical power angle (δ90 degrees) resulting in loss of generator synchronism. To better understand the term generator synchronism, imagine a rubber clutch connecting the shaft of two engines. See Figure 28. As long as the speed remains constant on both engines, 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 be forced to stretch.
Figure 28: Two Engines Connected by a Rubber Clutch If the speed continues to increase, causing a greater speed difference, the rubber clutch will eventually stretch beyond its limits and break. The change in the relative shape of the clutch is synonymous with the power angle changing between the generator rotor and stator. In the generator at the time the power angle has advanced beyond the critical angle of 90 degrees, the system has lost synchronism. See Figure 29. The rubber clutch represents the magnetic flux between the generator rotor and stator which enables the power to be transferred from the prime mover to the distribution system.
Figure 29: Power Relationship versus Displacement Angle The maximum allowed elasticity of the rubber clutch is defined as the stability limit of the generator, and each generator has the capability curve which defines this limit. As long as sufficient excitation is maintained in the field for the generator load, synchronism is assured.
Figure 30: Generator Reactive Capability Curve
Figure 31: Static Exciter Excitation Limiting Overexcitation Overexcitation is designed to protect the machine during operation at lagging power factor beyond the machine rating, but generally the machine limit of overexcitation is rotor overheating (high field current). To prevent rotor overheating, measuring the excitation current to the rotating field of the generator and cutting back the excitation current after some time delay is the most widely accepted way. A higher instantaneous or hard limit may also be a function included in the limiter. If excitation with very high forcing voltage is used, an instantaneous limiter can keep the excitation current during forcing to a lower level than the forcing voltage would otherwise drive it, gaining faster generator response from high forcing, both positive and negative, without need for more cost in the rotor, brushes, and slip rings to handle high forcing currents.
Figure 32: Overexcitation Limiter Limits Max. Field Current
To sufficiently protect prote ct the rotor, rotor, it is necessary to know k now the thermal capa capability bility of the rotor under worst case conditions. If the rotor is operating at maximum continuous current and the load demand moves the excitation higher, then you must know how long the field will take before temperature of the rotor exceeds its upper limit. With a curve plotting thermal limit based on full load operation prior to the higher current, the overexcitation scheme may be coordinated with the generator capability. When an older machine is upgraded with new excitation, it may not be possible to obtain the rotor thermal capacity curve to allow accurate setting of the relay. Standard practice is to choose a conservative setting to make sure limiter operation keeps the field temperature within safe limits.
Figure 33: Rotor Angle or Underexcitation Limiter Underexcitation Underexcitation is designed to protect the machine during operation at leading power factor. factor. To To perform its function, fu nction, the underexcitation un derexcitation limiter measures stator voltage, current, and phase angle. The primary concern for this limiter is the possible loss of synchronization with the stator resulting from a magnetic field strength too low to keep the rotor from slipping poles. Machines operating in parallel with an electrical network are most susceptible to this possibility, mainly instigated by some fault on the network being cleared by a breaker, and the resultant fast recovery of the system voltage when low magnetic field is available to maintain the rotor angle less than 90 degrees. Internally, the rotor angle of the machine is a function of the excitation current and real power load. The rotor angle increases from zero as load increases and decreases with increased excitation current. If the rotor angle is too close to the hypothetical 90 degree angle at which pole slip is certain, a transient load change can cause rotor torque to exceed the synchronizing torque existing between the rotor and stator. By limiting excitation to give a smaller rotor angle, the possibility of pole slip is reduced. This area of limiting can contribute greatly to the ability of the machine to be used in either leading or lagging power factor operation without concern for the possibility of pole slip. Avoiding pole slip prevents very high mechanical stresses and high currents from doing severe damage to the machine. The preferred characteristic for
underexcitation limiting is referred to by some manufacturers as Rotor Angle Limiting. This means simply that the limiter monitors stator volts and amps, and will provide limiting to allow full stator current at leading power factors near 1.0, increasing excitation and decreasing stator current along a circular curve as the power factor moves further into the leading power factor area.
Figure 34: Stator Current Limiting To complete the machine protection, add the stator current limiter. This function accepts current from generator current transformers, and begins to reduce excitation if the stator current exceeds the maximum for too long. The time is a function of the generator thermal capacity, 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 setting the time delay for thermal protection gives a high level of protection for the machine.
Figure 35: Combined Limiters
If you have any questions or need additional information, please contact Basler Electric Company. Company. Our web site is located at: http://www.basler.com e-mail:
[email protected]
Basler Electric Headquarters Route 143, Box 269, Highland Illinois USA 62249 Phone 618/654-2341 Fax 618-654-2351
Basler Electric International P.A.E. Les Pins, 67319 Wasselonne Cedex FRA FRANCE NCE Phone (33-3-88) 87-1010 Fax (33-3-88) 87-0808
If you have any questions or need additional information, please contact Basler Electric Company . Our web site is located at: http://www.basler.com e-mail:
[email protected]
Basler Electric Headquarters Route 143, Box 269, Highland Illinois USA 62249 Phone +1 618.654.2341 Fax +1 618.654.2351
Basler Electric International P.A.E. Les Pins, 67319 Wasselonne Cedex FRANCE Phone +33 3.88.87.1010 Fax +33 3.88.87.0808
