Application of Cogeneration Islanding Protection Working Group Draft 3 9-19-2003 1 October 6, 2002 1.0 Introduction (Dalke and Mozina) Today there is much interest in connecting Industrial Commercial Generators (ICG s) as qualified Distributed Resources (DR's) to electric power systems. Much of this interest is due to de-regulation of the Electric Power System and development of new industry standards such as that being developed by IEEE P1547 Working Group entitled Draft Standard for Interconnecting Distributed Resources with Electric Power Systems. Industrial and Commercial power users have gensets (ICG s) ranging from stand-by gensets that may operate in parallel with the utility only a few minutes each month during closed transition while testing, to load sharing generators that operate as full time dispatched load sharing units. Within this variety of connection times, situations arise where the DR ICG could become part of an island serving utility load. Even utility companies responding to requests for greater reliability from key customers are intentionally placing ICGDR s as close as possible to the customer s service to provide service reliability thus are having to abide by their own requirements for DR ICG protection during the intentional islanding conditions. Islanding is defined as A condition in which a portion of the utility system that contains both load and distributed resources remains energized while isolated from the remainder of the utility system IEEE Standard Dictionary of Electrical and Electronics Terms Publication 100-2000. At times, upon mutual agreement between the utility system owner and the distributed resource owners, an island is permitted to operate separate from the utility system. Such intentional seperation can be the result of planned response to anomalies in the power system, supervisory actions by the ISO, Independent System Operator, or other initiating actions. In this intentional island situation appropriate actions and practices have been defined and set in place to assure system operation within regulatory commission voltage and frequency requirements, equipment protection provided for and the safety of personnel and the public also provided for.. When an islanding event occurs unintentionally there are several issues to consider. This paper will elaborate on these issues as they relate to how much and what kind of protection the operator of various types of Distributed Resources Industrial Commercial Gensets (ICG s) needs at the Point of Common Coupling (PCC) to ensure the generator is not damaged by fault or abnormal operating conditions during this islanding condition. 2.0 Generator Types (Synchronous & Induction), (Rifaat) II. Generator Types and Basic Modeling for Islanding Studies (Rasheek) 2.1 Introduction:Generator Design and Configuration Thus farat the time of this writing, synchronous generators are the most commonly used machines for converting mechanical energy into electrical energy. Such generators are designed to run at constant (synchronous) speed that corresponds to the grid frequency and the number of poles (2p) in accordance with a well known equation: f p rpm = Hz...(2.1) 60 1
Where: f = System Frequency in Hz p = Number of pairs of poles rpm = Generator speed in rev per minute So, for a generator rotating at 3600 rpm, in a 60 Hz system, the number of pairs of poles is one pair (2 poles). Synchronous generators could be classified in accordance with their cooling methods, pole arrangements (salient and non-salient), excitation system (static and rotating exciters). However, in general, they all consist of a rotating DC field winding (Rotor), and an ac armature winding (Stator), and mechanical structure, which includes cooling systems, lubricating systems and other auxiliaries. Fig 2.1 depicts a conventional hook up of an in-plant synchronous generator in an industrial facility. In addition to synchronous generators, induction generators are used for smaller scale applications where economical benefits exist. In North America, for rating less than 5 MW, induction generators may be of some economical advantage provided technical conditions allow their use. Induction generators are typically of a rugged mechanical structure. They require neither elaborate excitation systems, nor frequent maintenance. In some arrangements same some induction machines could also run as either motors or generators. A good example of such reversible arrangement is the pumping storage facilities, where machines operate as motors at low demand period pumping water to a higher elevation, and reverse their function during peak periods. However, in a simple system configuration, induction generators need to continuously run in parallel with the grid, which provide them with the reference (synchronous) speed, and the necessary reactive power and their self excitation needs. Accordingly, they are not used for emergency generators applications that require black starts and if they must independently set their own synchronous speed. With continuous innovation in cogeneration and non-conventional generation fields, new generation configurations are developed. Thus far, most of such new configurations are based on 2
the modified hook up of conventional generators. Wind generation and its sensitivity to speed is an example. Another example is the cases where a generator is retrofitted on shafts of existing turbine that drives variable speed loads, in order to share the turbine energy and optimize its operations (balance of energy BOE applications). Fig 2.2 shows a non conventional hookup of a generator in BOE applications, where a generator is used in conjunction with converter-inverter sets that would allow changing the variable generated frequency into a constant grid frequency (location dependant 60 or 50 Hz). Distributed generation is an expanding concept in generation, where multiple small generators are located at sparse locations. Micro-turbine applications are a configuration that has been used in distributed generation. By definition micro-turbines are rated 500 kw or less. Micro-turbines could be of a basic miniature gas turbine design that has been used in other industrial applications. Many of such miniature design turbines are rated to rotate at very high speed (up to 96,000 rpm). Earlier in the design development of micro-turbine applications for distributed generation, reduction gearboxes were used to bring the generators to speeds suitable for electrical generation at system frequencies (3600 or 3000 rpm for 60 and 50 Hz systems). Recently, micro-turbine suppliers are leaning towards elimination of the reduction gear, integrating the generator of the turbine shaft, and the use of rectifier/inverter arrangements to get the frequency to a system frequency. In general they are connected to the electrical grid via the Inverter/Converter sets. From an electric power point of view their hook up would be similar to that of the larger BOE applications shown in Fig 2.2. 2.2 Simplified Modeling of Generators in Power System: In a generation or cogeneration configuration, generators are assigned the role of converting mechanical energy into electrical energy and pushing such energy into the interconnected electric system (the grid). In a typical industrial or institutional in-plant generation, or in the case of a distributed generation, there are many possibilities of one or more generators islanding with some loads as shown in Fig 2.3. To evaluate the islanded system dynamic behavior, appropriate generator modeling would be necessary. Several references discussed the modeling of a 3
generator for the purpose of evaluating the impact of occurrence of a transient phenomenon such as islanding of such generators or having them in abnormal system conditions local area system oscillations or system adjacent faults. With the development of user-friendly, affordable computer programs that would simulate system dynamic behavior, modeling generators and grids is no longer a tedious engineering task. In our case, the purpose of modeling of a system would be to examine the impact of islanding on both sides of the split point especially the small island that splits from the large system. It is important however for the system engineer to understand the essence of modeling to avoid conceptual mistakes in interpretations of a computer 4
program results. A generator in a power system set up will have three systems connected: mechanical system, coupling field and electric system. The basic equations that would represent the systems could be driven derived from the block diagram in Fig 2.4. For the mechanical portion of the block: W M Net = W M In W MLoss W M Stored...2.2 For the electrical portion of the block: W E out = W E in W E Loss W E Stored...2.3 For the coupling field portion of the block; W F + W F Loss = WE In + W M In...2.4 In simple terms, Fig 2.4 and equations 2.2, 2.3 and 2.4 tell us that energy is preserved (after neglecting the losses). In a steady state, what goes into the block in a mechanical form comes out from the other end in an electrical form (after deducting the losses). With a sudden a change in either ends, the system balance will be disrupted and will try to establish a new balanced state. 5
Islanding is an example of a possible disruption to the generator system. A portion of the electrical system where electrical generator(s) and electrical loads(s) split from the main system would be called an island. At the moment of islanding, there could be one of three possible scenarios: a. If the island loads are larger than its generation, the electric energy demand will exceed the mechanical energy input, the generators will tend to slow down causing an underfrequency status, b. If the island loads are less than its generations, the electric energy will suddenly exceed the mechanical energy, which would cause a momentary speed up and an over-frequency status. c. If, as in some rare occasions, the island electric loads and generations are almost equal, the change in the prime mover speed will be a minimum change and the island frequency will hardly change. Due to the fact that controlled changes in the mechanical system are slower than the sudden change in the electrical system, a corrective action, such as closing the prime mover valve, may not be fast enough to avert an over-frequency trip on the generator system. It should be mentioned, however, that modern control facilities allow very fast governor control, which???? process system that are capable of successfully island with a load that is smaller than the generator capacity. In the case of islanding with a load that is larger than the generator capacity, load shedding scheme must be implemented in order to re-establish load/generation balance in the island. Using the derivatives of the energy equations above would allow representation of a sudden change in the balance shown in these equations. Such representation is given in number of reference and its solutions provide the bases of many modeling programs. 3.0. Prime Mover Types, (Nichols ) IMPACT OF VARIOUS PRIME MOVERS ON ISLANDING PROTECTION Islanding, or being unintentionally connected to a portion of the utility s system that is separated from their utility generation, is detected primarily by frequency excursions. These frequency excursions are caused by the ability of the prime mover to change speed since it is no longer synchronized with the utility grid generation. The magnitude, rate, and duration of these frequency changes affect the ability to detect an islanding condition. The behavior of the prime mover at this time is affected both by the inherent response of the prime mover to its controller, and to the mode of control in which it is operating. There are three basic modes of control during paralleled operation known as droop, load following, or fixed output. Isochronous speed control is not one of the options while in the parallel mode, as the governor will be unstable since it cannot hold the generator frequency constant if the utility frequency varies. The slope of a governor response in a droop mode has a stable intersection with the fixed frequency of the utility while in parallel, so that the fuel admission to the prime mover will stay constant unless the fixed frequency of the utility changes. If the utility frequency changes the governor will admit more or less fuel in accord with the new intersection point, and the generator output changes accordingly. When separated 6
from the grid generation, the governor will alter the fuel input as a function of the generator speed until its output matches the load remaining connected to the generator. That is, if the load is increased it will bog down the generator and the diminished speed will cause the governor to admit more fuel. If the generator prime mover is operating in a constant power output mode, which is essentially no governing action, after separation from the grid, connected load less than its output will cause it to overspeed, and connecting load in excess of its output will bring it to its knees. If the generator set is operating in the load following mode, normally by holding export or import at the utility interface constant, it will be caused to change its output if the local plant load changes. However if the generator becomes islanded with a portion of the utility load which is not exactly the same value as the export control was set for, the control will become unstable since it is open loop, and any feedback is positive instead of negative. The generator will with either overspeed or shut down in an attempt to correct the amount of power being exported. If the control is regulating for import, the generator will shut down in its futile attempt to re-establish the import level. Except in the unlikely event that the islanded load exactly matches the existing export (including a value of zero) the generator speed will change and be detected by a frequency relay. This will assume that such a frequency excursion is indicative of islanding and will trip the interface breaker, thus terminating the serving of the utility s loads and terminating the constant power or load following mode of control, or perhaps even the droop mode. The rate of change of the generator speed after inception of islanding, while in the constant power mode or the constant import/export mode, will determine the speed of the relay action. In the Droopy mode it will also require a change in the connected load sufficient to change the operating speed to reach the set point of the frequency relay, either as a steady state or transient mode. Performance in the transient mode is a function of the governor capability and the inherent response of the prime mover to the governor s control. The controllers and governors are reactive devices. They must sense a change to initiate a correction. So even in the droop mode, there will be a transient excursion from the droop curve until this correction is accomplished. Various prime movers have various speeds of response as a function of inertia, fuel control, or combustion control. Note that the term fuel, which is being applied to all prime movers, might more properly be called energy, since it may be in the form of steam pressure or water pressure, but admitting fuel to an engine is a widely understood concept. The response of a prime mover is best described as its ability to accept or reject steps of loading. The most familiar prime mover, the gasoline engine is relatively good at both, although it used to require combustion enrichment with the accelerator pump for rapid load pick up. The diesel engine has excellent load rejection because the fuel can be reduced quickly, but suffers from lack of combustion air on load pickup until the turbo-charger can get up to speed. Naturally aspirated engines performed much better but had excessive size, cost, and air pollution. These machines have low inertia. The H factor may be less than 1. Gas fueled piston engines (natural or LPG) tend to be quite limited in load pickup and rejection. The control valves are often relatively slow acting, and there is a compressible column of fuel between them and the cylinders. The single shaft gas turbine has a history of good load acceptance and rejection in the past in that the majority of the turbine loading is the compressor, which does not change with a change in the electrical load. However recent lean burn turbines require critical adjustment to avoid combustion instability. Their 7
scrubbers, if so equipped, also require fine tuning. Inertia of these machines varies from medium to high, with H factors of 2.5 to 6.0. There is one or two small machine with low inertia (H=1) on the market. Steam turbines are at the mercy of the boilers for load pickup, and many larger units cannot stand the thermal shock of large load pickup. Smaller units supplied from a boiler with a good head of steam can be excellent at load pickup. Single cylinder, and even smaller two cylinder (high pressure and low pressure) machines can reject full load without overspeeding. This becomes more difficult on large units with multiple cylinders and re-heat boilers, particularly if the inertia is low. However they are not normally found in industrial plants. Hydraulic turbines (waterwheels) have poor response because of the inertia of the water column precludes rapid changes in its flow. They have excessive overspeed on load rejection. Thus would be quick to trip if islanded. Micro-turbines would be expected to have a fairly good response, but this has not been confirmed as a general characteristic. The variable speed machines do have to change speed to pick up load. Their size precludes the ability to support much load during islanding, and so would trip quickly on under frequency and undervoltage relaying. Photo-voltaic installations with line commutated inverters cannot support load if islanded. Force commutated inverters are more likely to be found on residential installations, which are relatively small and incapable of supporting external loads. These are normally not required to have islanding protection, and are not in the scope of this committee. 4.0 Protection 4.1 Protection Introduction: A common question asked by owners of DR s ICG s is Why do I need all the protection required by the utility I will be operating in parallel with? This is especially true of small DR s ICG s whose unit capacity is not large enough to supply the entire utility circuit load. The State Regulatory Commission makes the interconnection rules include the possibility of a combination of large and small synchronous and induction or self excited DR s ICG s continuing to supply utility loads during the islanding condition. How many dollars the DR ICG owner wants to spend for protective relaying also depends on whether he considers the cost of his genset or the process it is supplying to be worth more or less than the price of the protective equipment. 8
IV.4.21 Impact of Intertie Transformer s Connections Chuck Mozina Impact of Interconnection Transformer Connections on Interconnection Protection Chuck Mozina The major function of interconnection protection is to disconnect the generator when it is no longer operating in parallel with the utility system. Smaller IPPsIPP s and ICG s aare generally connected to the utility system at the distribution level. In the U.S., distribution systems range from 4 to 34.5 KV and are multi-grounded 4-wire systems. The use of this type of system allows single-phase, pole-top transformers, which typically make up the bulk of the feeder load, to be rated at line-to-neutral voltage. Thus, on a 13.8 KV distribution system, single-phase transformers would be rated at 13.8 KV/v3~8 KV. Fig. 4.1 1 shows a typical feeder circuit. Fig. 4.11 Typical 4-Wire Distribution Feeder Circuit Five transformer connections are widely used to interconnect dispersed generators to the utility system. Each of these transformer connections has advantages and disadvantages. Fig. 4.22 shows a number of possible choices and some of the advantages/problems associated with each connection. 9
Fig.4. 2Interconnection Tr ansformer Protection Delta (Pri)/Delta (Sec), Delta (Pri)/Wye-Grounded (Sec) and Wye-Ungrounded (Pri)/Delta (Sec) Interconnect Transformer Connections The major concern with for an interconnection transformer with an ungrounded primary winding is that after substation breaker A is tripped for a ground fault at location F1, the multi-grounded system is ungrounded subjecting the L-N (line-to-neutral) rated pole-top transformer on the unfaulted phases to an overvoltage that will approach L-L voltage. This occurs if the dispersed Industrial Commercial generator is near the capacity of the load on the feeder when breaker A trips. The resulting overvoltages will saturate the pole-top transformer, which normally operates at the knee of the saturation curve as shown in Fig. 4.3 3. 10
Fig.4.3 3 Saturation Curve of Pole-Top Transformers Many utilities use ungrounded interconnection transformers only if a 200% or more overload on the generator occurs when breaker A trips. During ground faults, this overload level will not allow the voltage on the unfaulted phases to rise higher than the normal L-N voltage, avoiding pole-top transformer saturation. For this reason, ungrounded primary windings should be generally reserved for smaller dispersed generatorsicg s where overloads of at least 200% are expected on islanding. Wye-Grounded (Pri)/Delta (Sec) Interconnect Transformer Connections The major disadvantage with this connection is that it provides an unwanted ground fault current for supply circuit faults at F1. Fig.4.4a 4a and Fig..4.4b4b illustrate this point for a typical distribution circuit. Analysis of the symmetrical component circuit in Fig.4.4b 4b also shows that even when the dispersed 11
Fig. 4.4a Single-Line Diagram for Wye-Grounded (Pri) / Delta (Sec) Interconnection Transformer 12
Fig.4. 4b Symmetrical Component Circui tfor Wye- Grounded (Pri) / Delta (Sec) Interconnection Transformer 13
generator ICG is off-line (the generator breaker is open), the ground fault current will still be provided to the utility system if the dispersed generator interconnect transformer remains connected. This would be the usual case since interconnect protection typically trips the generator breaker. The transformer at the dispersed generator site acts as a grounding transformer with zero sequence current circulating in the delta secondary windings. In addition to these problems, the unbalanced load current on the system, which prior to the addition of the dispersed generatoricg transformer had returned to ground through the main substation transformer neutral, now splits between the substation and the dispersed generator transformer neutrals. This can reduce the load-carrying capabilities of the dispersed generatoricg transformer and create problems when the feeder current is unbalanced due to operation of single-phase protection devices such as fuse and line reclosers. Even though the wye-grounded/delta transformer connection is universally used for large generators connected to the utility transmission system, it presents some major problems when used on 4-wire distribution systems. The utility should evaluate the above points when considering its use. Wye-Grounded (Pri)/Wye-Grounded (Sec) Interconnect Transformer Connections The major concern with an interconnection transformer with grounded primary and secondary windings is that it also provides a source of unwanted ground current for utility feeder faults similar to that described in the previous section. It also allows sensitively-set ground feeder relays at the substation to respond to ground fault on the secondary of the dispersed generatoricg transformer (F3). Fig. 4.5a5a and Fig. 4.5b 5b illustrate this point through the analysis of symmetrical component circuitry. C. Intertie Transformer Summary The selection of the interconnection transformer plays an important role in how the ICG will interact with the utility system. There is no universally accepted best connection. All connections have advantages and disadvantages that need to be addressed by the utility in their interconnection guidelines to dispersed generators. The choices of transformer connection also have a profound impact on interconnection protection requirements. 14
Fig.4. 5a Single-Line Diagram for Wye-Grounded (Pri) / Wye-Grounded (Sec) Interconnection Transformer 15
Fig. 4.5b Symmetrical Component Circuit for Wye-Grounded (Pri) Wye-Grounded (Sec) Interconnection Transformer C. Conclusions The selection of the interconnection transformer plays an important role in how the dispersed generator will interact with the utility system. There is no universally accepted best connection. All connections have advantages and disadvantages that need to be addressed by the utility in their interconnection guidelines to dispersed generators. The choices of transformer connection also have a profound impact on interconnection protection requirements. 4.2 Synchronous Generators, (Dalke and Stringer) Location of islanding protection for synchronous generators depends on whether the generator is to continue supplying it s in plant load while separated from the utility. If so, in the following discussin the protective relay discussion should be located so that it will trip the circuit breaker at the Point of Common Coupling (PCC) of the two systems. If plant load is not to be supplied then the protection should operate the generator circuit breaker as quickly as possible. 16
A common practice of utilities is to use transferred tripping to open the PCC anytime the utility breaker is opened. This includes fault and abnormal system conditions plus manual or remote switching operations. The protective relay elements listed in Table 4.1 and shown in Figure 4.2.1 on the next page are discussed below and can be required as backup to the transferred trip system. Cost of transferred trip and its communication channel to the DRICG s on a utility circuit is expensive but provides an effective primary method of preventing islanding occurrences. Intertie Protection Objective Protection Element Device Numbers Detection of loss of parallel operation with utility system 27/59, 81O/U, TT** Fault backfeed detection Phase faults: 51, 67 or 21 Ground faults: 51N, 67N, Unbalanced system conditions 46, 47 Abnormal Power flow detection 32 Restoration synchronism check 25 ** Transfer Trip from Utility Table 4.1 Intertie Protection and Restoration Objectives Insert Figure 4.2.1 here The basic minimum protective relaying for islanding or loss of parallel is a scheme using under and overvoltage (27/59) relaying and under and over frequency (81O/U) relays set for the window of acceptable band limits of voltage and frequency to the utility customers. The undervoltage (27) element will operate for a time-delayed decrease in voltage if the generator does not have the capacity to sustain load after opening of the utility circuit breaker. A time delayed overvoltage (59) element will operate for over excitation of the generator that can occur under light load conditions after opening of the utility breaker. Under frequency condition will usually occur after the utility breaker opens perhaps leaving a load larger than the generator capacity. Over frequency can occur when load is interrupted on an adjacent utility circuit fed from the same utility bus. Consequences to the generator owner of not having the under and over voltage and under and over frequency protection can be damage to the generating unit from exceeding its thermal limits under sustained overload conditions. Also, off frequency operation can cause vibrations to turbine blades leading to mechanical failures. Another consequence could be lawsuits from the utility customers wanting payment for damaged equipment because the DR ICG did not supply power within the Regulatory Commission window of operation for voltage and frequency. The next most important protective elements are those detecting short circuits or faults on the utility system that can be backfed by the DGICG. These are necessary to protect the public and utility workers from unsafe fallen power lines. Fault detectors must be able to detect faults on the longest amount of circuit the utility will have connected, even under load transfer or emergency conditions. The protection must be time coordinated so the fuse or recloser closest to the fault will operate first and keep customer outage area to a minimum. Fault backfeed detection is accomplished with instantaneous and time overcurrent relays (50/51), directional overcurrent (67) relays or impedance (21) relays. The 50/51 non-directional overcurrent protections will operate for fault current flowing in either direction through the PCC. Directional overcurrent (67) protection may be needed to prevent opening the PCC for faults on the local plant system 17
18
when the genset operation mode is to supply local loads when the utility source is open. These voltage polarized overcurrent relays will operate for faults anywhere on the utility system. Impedance relays may be required when the PCC terminates at the low voltage side of the utility transformer such that protection must look through or include the impedance of the transformer and the connected circuits on the high voltage side of the transformer. If the transformer is a delta high side and wye low side, a special zero sequence over voltage (59N) detector connected on the high voltage side of the transformer will be needed to detect single phase to ground faults on the high voltage side. These faults are undetectable by overcurrent protection on the low voltage side of the transformer. Some of the Cconsequences of the ICG not having the utility specified fault protection are exceeding the thermal limits of the generator and lawsuits from the general public from for failing to interrupt fault conditions in a timely manner. Power relays (32) are another type of protection that may be required to detect abnormal power flow, especially if the DR ICG is to operate in parallel with the utility. Power relay elements typically use voltage and current quantities that are essentially in phase to detect real power or watts. These quantities are stable and not varying greatly over a few cycles as a fault condition does. Because they are looking for watts to make them operate, they are not a good means of fault detection. Directional overcurrent fault detectors use a quadrature polarizing design such that the polarizing voltage is lagging the phase current by ninety degrees. The voltage and current each will be fluctuating each cycle during the fault condition. Consequences of not having a power relay when required is to not open the PCC per contract requirements and may be giving away power to the utility. A synchronism check relay (25) is required to supervise the synchronism of the PCC breaker to the utility when restoring the intertie after a separation, Figure 4.2.1. This relay measures the voltage, angle and slip between the utility and the generator and permits closing of the PCC breaker only when the slip angle of the generator is within a safe closing angle. The consequence of not having this restrictive control relay is that the generator could be closed in out of phase causing severe damage to the coupling between the prime mover and the generator. In very severe cases personnel in the vicinity of the genset have been injured from flying parts. For larger generators consideration should be given to applying negative sequence current (46) and or voltage relays (47) as unbalance detectors. These detect severely unbalanced loads on the utility system that can occur during single phase switching operations to transfer load or from operation of fuses to large individual customers or blocks of smaller customers during storms. Consequences of operating during unbalanced load conditions will be exceeding the thermal limits of the generator. References IEEE STD 100-2000 Standard Dictionary of Electrical and Electronic Terms Protective Relaying for the Cogeneration Intertie Revisited C. Mattison Texas A& M Protective Relay Engineers Conference April 15,1996 Protection of Utility/Cogeneration Interconnections Soudi, Tapia, Taylor & Tziouvaras, Western Protective Relay Conference, October 19-21, 1993 19
Protection of Utility/Cogeneration Interconnections Soudi, Tapia, Taylor & Tziouvaras, Western Protective Relay Conference, October 19-21, 1993 Myths of Protecting the Distributed Resource to Electric Power System Interconnection G. Dalke Texas A & M Protective Relay Conference, April 19-22, 2002 Islanding Problems for Non-utility Generation C. Wagner, Texas A & M Protective Relay Engineers Conference, April 13-15, 1992 IEEE Tutorial on the Protection of Synchronous Generators 95 TP 102 IEEE STD 242-2001 Protection and Coordination of Industrial and Commercial Power Systems 4.3 INDUCTION GENERATORS (STRINGER) Intertie protection for locations with induction generators vary only slightly from that of synchronous machines. Induction generators provide real power to the system, but require reactive power. Since induction generators have no source of self-excitation, they must draw their excitation from the system. As a result, they typically run at or above synchronous speed. Smaller induction machines typically cannot sustain the resulting voltage of an islanded system sufficiently to maintain its integrity. After only a few cycles, the system will begin to collapse, with the induction machine providing minimal contribution in the case of a system fault. Larger induction machines can maintain voltage and speed for a much longer time. In some cases, where the generator is of sufficient size to carry the load, the induction generator can remain connected to the islanded system indefinitely. However, since the induction generator lacks self-excitation, the system must provide this either through a connected synchronous generator or connected capacitance. In either case, should sufficient generation be available the islanded system could be maintained, prolonging the abnormal condition that originally caused the island separation. Left unchecked, this could lead to damage of the induction generator, as well as other equipment connected to the islanded system. For these reasons, it is necessary to provide protection that can quickly separate the DSG from the system whenever the supplying utility trips its breaker. In addition, utilities generally employ automatic reclosing of feeders. Since most system faults are momentary in nature, automatic reclosing provides greater reliability to consumers and less down time. However, during automatic switching the DSG IC generator can become out of synchronism with the utility. Should the utility feeder reclose under this condition, severe damage could occur to the DSG ICG equipment; thereby, supporting the need for quick separation from the island. Also, should the generator be able to maintain voltage and speed for the DSG ICG plant loading, high-speed separation would be advantageous to maintaining critical plant loads. Similar to synchronous machines, intertie protection for facilities with induction generators is dependent upon the configuration of the connection and the winding method of the transformer. Figures 1 through 4 indicate some of the more typical connection configurations. Transformers may be wound in a delta-wye, wye-delta, or wye-wye configurations. The connecting utility usually stipulates the specific winding method an DSG ICGmust use. 20
Basic intertie protection for induction machines include those relays as listed in Table 4.3.1. As indicated previously, when a fault or other abnormal operating condition occurs, which results in an islanded separation, the characteristics of the island will change suddenly. Depending upon the connected generation, there may be a significant frequency and/or voltage deviation. If sufficient generation is available, the power flow direction may reverse in an effort to maintain the connected islanded load. Protection must be applied for all of these conditions. Left unprotected, serious damage of the DSG ICGequipment could result, not to mention damage to other utility customers who remain connected to the island. It is imperative that these conditions are detected and separation of the DSG ICG occurs immediately. Table 4.3.1. Protection Application for Various Generator Types Protection Induction Generator Synchronous Generator ANSI Protective Devices Overload X X 27, 81U Fault X X 50/51, 87 Abnormal Frequency X X 81 Underpower X X 32U Directional Power X X 32 O/U Motoring X X Overexcitation X 24 Loss of Excitation X 40Q Overspeed X 59, 81O The various traditional protection methods used for DSG s ICG s with induction machines are discussed below. Undervoltage (27) When an islanding condition occurs, the DSG ICG facility will most likely experience a momentary drop in voltage at the point of intertie. Depending on the available generation, the voltage level could recover slightly and then continue to Drop or it could simply continue to drop until the system becomes unstable and goes black. Instantaneous undervoltage relays can sense this Drop in voltage when the supply line has tripped and provide fast separation from the utility. This becomes advantageous when the utility is using high-speed reclosing. Normally this relay is set to a very sensitive level to detect and provide separation as quickly as possible. However, the disadvantage with this approach is that problems elsewhere on the utility system may produce a voltage Drop at the DSG ICG sufficient enough to cause the relay to operate. Therefore, the pickup should be set such that these nuisance operations are eliminated or at least kept to a very minimum. An alternative is to use a time delay operation to allow the voltage to recover. Time delay undervoltage relays can be used to reduce the nuisance operations as described above or for applications where the generator is capable of isolated operation. According to [1],Reference 1 this can be achieved with a pickup setting of 90 to 95% of nominal voltage and a time delay of one second. Of course, in eliminating nuisance operations, the primary disadvantage of inserting a time delay is that separation is delayed. This could result in loss of stability for the DSG ICG or possibly severe equipment damage. 21
Frequency (81O/81U) When an island condition occurs, the frequency may drop if the generator cannot support the required load. It is necessary to remove the DSG ICG as quickly as possible when this happens. Frequency relays can achieve separation using any of three different methods underfrequency, overfrequency, rate-ofchange of frequency. The amount of frequency deviation will vary depending on the generator and the system. Most frequency relays of today include multiple setting levels in which to coordinate load-shedding schemes. These schemes will typically expand the load tripped with increasing frequency deviation. A deviation of ±5% is considered an extreme condition where the DSG ICG should be separated from the utility. On systems not using a load-shedding scheme, the underfrequency relays should be set with a minimum time delay. Overfrequency relays are used on DG ICG systems that are capable of isolated operation and especially on synchronous machines where the excitation controls can push the speed above the acceptable maximum levels. Overfrequency relays should be set for a maximum pickup of 60.5 Hz and a maximum time delay of 0.1 second. Relays measuring the rate-of-change of frequency have been used sparsely over the past 20 years; however, their application and acceptance for superior operation is growing significantly. As their name implies, these relays measure the rate at which the frequency is changing. A DSG ICG operating under in an unstable islanding condition will experience a greater rate of frequency Drop than that expected from other utility system problems. As a result, the rate-of-change of frequency relay can somewhat distinguish a severe frequency ddrop caused by an islanding condition from other conditions. Therefore, there is no need for a time delay to be inserted, allowing instantaneous operation and separation. Voltage-Dependent Overcurrent (51V) Voltage dependent overcurrent relays come in two types voltage-controlled and voltage-retrained. These relays will sense faults on the system and trip based on the sensed terminal voltage. The voltage ddrop at the DSG ICG intertie point to the utility will vary depending upon where the fault occurs. The farther away from the DSGICG, the less the voltage ddrop will be. Therefore, for a fault on the connected line to the DSGICG, the voltage will most likely drop significantly at the time of the fault. In addition, when the utility trips the line, the voltage will go to zero instantaneously. Voltage dependent relays sense the fault current and adjust their pickup level based upon the voltage measured. Voltage-controlled relays operate like a switch. When the voltage is reduced to a specified level, the relay will allow the operation of the overcurrent function. Therefore, the sensed voltage must be below the relay s setpoint and the fault current must be above its setpoint. The voltage-retrained overcurrent relay adjusts its current pickup as a function of the voltage level deviation from nominal. Most relays will operate for a current at 100% of setting when the voltage is at nominal (i.e. 120V). When the voltage decreases, the current pickup reduces in proportion to the decrease in voltage. For example, if the voltage drops to 60% of nominal (or 72V), the pickup of the current elementpickup will be reduced to 60% of its nominal setting. Assuming a nominal pickup setting of 2.0 amps, the adjusted pickup would be 1.2 amps. The main disadvantage of these relay types is that the timing characteristics are normally a time-delayed function; thereby increasing the time to separation separate from the island. Directional Power (32R) 22
When an islanding condition occurs, the power produced by the DSG ICG will flow from the DSG ICG to the remaining load on the island. This power flow can be measured at the point of intertie. When the power flow to the utility exceeds a specified level, the directional power relay will initiate tripping and separation from the island. The pickup setting should be above the maximum level of power for which the utility receives under contract with the DSGICG. A slight time delay will allow for power flow regulation due to system faults. VECTOR JUMP In addition to these traditional means of protection, another method has been initiated within the last few years. The vector jump relay provides protection for islanding conditions by detecting a significant phase displacement, or vector jump, within the measured voltage signal. As indicated in [2], when an island condition occurs, the DSG ICG will experience a phase shift in its voltage signal. This phase shift characteristic is specific to the occurrence of an islanding condition. Other types of system abnormalities will not produce a waveform of similar characteristics. Therefore, this method provides quick detection of an islanded condition and fast separation. [1] Intertie Protection of Consumer-Owned Sources of Generation, 3 MVA or Less, IEEE Power System Relaying Committee Working Group Report, 88TH0224-6-PWR, IEEE Power Engineering Society Winter Power Conference. [2] M.A. Redfern, O. Usta, and G. Fielding, Protection Against Loss of Utility Grid Supply for a Dispersed Storage and Generating Unit, IEEE Transactions on Power Delivery, Vol. 8, No. 3, July 1993. 5. Conclusion This paper has reviewed how synchronuous and induction generators operate, the impact of different prime movers on Islanding Protection, impact of intertie transformer configurations on protective relaying requirements and protective relay element requirements for both synchronous and induction generators. All of these differenct issues impact the protective relaying required for each unique genset location. Islanding protection requirements are conditional depending on these issues. Islanding protection is based on the art of applying protective relaying. Different types of protection are required thus the cost of protection is much higher for some types of generators and prime movers. Review of these issues in this paper provides a basis for the need for a variety of protective devices and states scenarios of possible damage to either or both the generator and prime mover and the consequences for not providing proper Islanding Protection. 6. 6. References (Combine all into one section??? )References: IEEE STD 100-2000 Standard Dictionary of Electrical and Electronic Terms Protective Relaying for the Cogeneration Intertie Revisited C. Mattison Texas A& M Protective Relay Engineers Conference April 15,1996 Protection of Utility/Cogeneration Interconnections Soudi, Tapia, Taylor & Tziouvaras, Western Protective Relay Conference, October 19-21, 1993 Myths of Protecting the Distributed Resource to Electric Power System Interconnection G. Dalke Texas A & M Protective Relay Conference, April 19-22, 2002 23
Islanding Problems for Non-utility Generation C. Wagner, Texas A & M Protective Relay Engineers Conference, April 13-15, 1992 IEEE Tutorial on the Protection of Synchronous Generators 95 TP 102 IEEE STD 242-2001 Protection and Coordination of Industrial and Commercial Power Systems [ Intertie Protection of Consumer-Owned Sources of Generation, 3 MVA or Less, IEEE Power System Relaying Committee Working Group Report, 88TH0224-6-PWR, IEEE Power Engineering Society Winter Power Conference. Protection Against Loss of Utility Grid Supply for a Dispersed Storage and Generating Unit, IEEE Transactions on Power Delivery, Vol. 8, No. 3, July 1993. M.A. Redfern, O. Usta, and G. Fielding, 24