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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 qualifiedDistributed Resources (DR's) to electric power systems. Much of this interest is due to de-regulation ofthe Electric Power System and development of new industry standards such as that being developed byIEEE P1547 Working Group entitled “Draft Standard for Interconnecting Distributed Resources withElectric Power Systems”. Industrial and Commercial power users have gensets (ICG’s) ranging fromstand-by gensets that may operate in parallel with the utility only a few minutes each month during closedtransition 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 islandserving utility load. Even utility companies responding to requests for greater reliability from keycustomers are intentionally placing ICGDR’s as close as possible to the customer’s service to provideservice reliability thus are having to abide by their own requirements for DR ICG protection during theintentional islanding conditions.

Islanding is defined as “A condition in which a portion of the utility system that contains both load anddistributed resources remains energized while isolated from the remainder of the utility system” IEEEStandard 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 theresult of planned response to anomalies in the power system, supervisory actions by the ISO, IndependentSystem Operator, or other initiating actions. In this intentional island situation appropriate actions andpractices have been defined and set in place to assure system operation within regulatory commissionvoltage and frequency requirements, equipment protection provided for and the safety of personnel andthe public also provided for..

When an islanding event occurs unintentionally there are several issues to consider. This paper willelaborate on these issues as they relate to how much and what kind of protection the operator of varioustypes of Distributed Resources Industrial Commercial Gensets (ICG’s) needs at the Point of CommonCoupling (PCC) to ensure the generator is not damaged by fault or abnormal operating conditions duringthis 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 usedmachines for converting mechanical energy into electrical energy. Such generators are designedto run at constant (synchronous) speed that corresponds to the grid frequency and the number ofpoles (2p) in accordance with a well known equation:

)1.2(..............................60

Hzrpmp

f×

=

2

Where:f = System Frequency in Hzp = Number of pairs of polesrpm = 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 onepair (2 poles).

Synchronous generators could be classified in accordance with their cooling methods, polearrangements (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 otherauxiliaries. Fig 2.1 depicts a conventional hook up of an in-plant synchronous generator in anindustrial facility.

In addition to synchronous generators, induction generators are used for smaller scaleapplications where economical benefits exist. In North America, for rating less than 5 MW,induction generators may be of some economical advantage provided technical conditions allowtheir use. Induction generators are typically of a rugged mechanical structure. They requireneither elaborate excitation systems, nor frequent maintenance. In some arrangements samesome induction machines could also run as either motors or generators. A good example of suchreversible arrangement is the pumping storage facilities, where machines operate as motors atlow demand period pumping water to a higher elevation, and reverse their function during peakperiods. However, in a simple system configuration, induction generators need to continuouslyrun in parallel with the grid, which provide them with the reference (synchronous) speed, and thenecessary reactive power and their self excitation needs. Accordingly, they are not used foremergency generators applications that require black starts and if they must independently settheir own synchronous speed.

With continuous innovation in cogeneration and non-conventional generation fields, newgeneration configurations are developed. Thus far, most of such new configurations are based on

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the modified hook up of conventional generators. Wind generation and its sensitivity to speed isan example. Another example is the cases where a generator is retrofitted on shafts of existingturbine that drives variable speed loads, in order to share the turbine energy and optimize itsoperations (balance of energy “BOE” applications). Fig 2.2 shows a non conventional hookup ofa generator in BOE applications, where a generator is used in conjunction with converter-invertersets 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 generatorsare located at sparse locations. Micro-turbine applications are a configuration that has been usedin distributed generation. By definition micro-turbines are rated 500 kW or less. Micro-turbinescould be of a basic miniature gas turbine design that has been used in other industrialapplications. Many of such miniature design turbines are rated to rotate at very high speed (up to96,000 rpm). Earlier in the design development of micro-turbine applications for distributedgeneration, reduction gearboxes were used to bring the generators to speeds suitable for electricalgeneration 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 thegenerator of the turbine shaft, and the use of rectifier/inverter arrangements to get the frequencyto a system frequency. In general they are connected to the electrical grid via theInverter/Converter sets. From an electric power point of view their hook up would be similar tothat 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 convertingmechanical energy into electrical energy and “pushing” such energy into the interconnectedelectric system (the grid). In a typical industrial or institutional in-plant generation, or in the caseof a distributed generation, there are many possibilities of one or more generators islanding withsome loads as shown in Fig 2.3. To evaluate the islanded system dynamic behavior, appropriategenerator modeling would be necessary. Several references discussed the modeling of a

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generator for the purpose of evaluating the impact of occurrence of a “transient” phenomenonsuch as “islanding” of such generators or having them in abnormal system conditions “local areasystem oscillations or system adjacent faults. With the development of user-friendly, affordablecomputer programs that would simulate system dynamic behavior, modeling generators andgrids is no longer a tedious engineering task. In our case, the purpose of modeling of a systemwould be to examine the impact of islanding on both sides of the split point especially the smallisland that splits from the large system. It is important however for the system engineer tounderstand the essence of modeling to avoid conceptual mistakes in interpretations of a computer

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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 representthe systems could be driven derived from the block diagram in Fig 2.4.

For the mechanical portion of the block:

2.2...................StoredMMLossInM WWWWNetM −− −−=

−

For the electrical portion of the block:

3.2..................StoredELossEinEoutE WWWW −−−− −−=

For the coupling field portion of the block;

4.2..........................InMInELossFF WWWW −−− +=+

In simple terms, Fig 2.4 and equations 2.2, 2.3 and 2.4 tell us that energy is preserved (afterneglecting the losses). In a steady state, what goes into the block in a mechanical form comesout from the other end in an electrical form (after deducting the losses). With a sudden a changein either ends, the system balance will be disrupted and will try to establish a new balanced state.

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Islanding is an example of a possible disruption to the generator system. A portion of theelectrical system where electrical generator(s) and electrical loads(s) split from the main systemwould be called an “island”. At the moment of islanding, there could be one of three possiblescenarios:

a. If the island loads are larger than its generation, the electric energy demand will exceedthe mechanical energy input, the generators will tend to slow down causing an under-frequency status,

b. If the island loads are less than its generations, the electric energy will suddenly exceedthe mechanical energy, which would cause a momentary speed up and an over-frequencystatus.

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 frequencywill hardly change.

Due to the fact that controlled changes in the mechanical system are slower than the suddenchange 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 bementioned, 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 thegenerator capacity. In the case of islanding with a load that is larger than the generatorcapacity, load shedding scheme must be implemented in order to re-establish load/generationbalance in the island.

Using the derivatives of the energy equations above would allow representation of a suddenchange in the balance shown in these equations. Such representation is given in number ofreference 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 fromtheir utility generation, is detected primarily by frequency excursions. These frequency excursions arecaused by the ability of the prime mover to change speed since it is no longer synchronized with theutility grid generation. The magnitude, rate, and duration of these frequency changes affect the ability todetect an islanding condition.

The behavior of the prime mover at this time is affected both by the inherent response of the prime moverto its controller, and to the mode of control in which it is operating. There are three basic modes ofcontrol during paralleled operation known as droop, load following, or fixed output. Isochronous speedcontrol is not one of the options while in the parallel mode, as the governor will be unstable since itcannot 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 theutility while in parallel, so that the fuel admission to the prime mover will stay constant unless the fixedfrequency of the utility changes. If the utility frequency changes the governor will admit more or less fuelin accord with the new intersection point, and the generator output changes accordingly. When separated

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from the grid generation, the governor will alter the fuel input as a function of the generator speed until itsoutput matches the load remaining connected to the generator. That is, if the load is increased it will “bogdown” 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 nogoverning action, after separation from the grid, connected load less than its output will cause it tooverspeed, 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 theutility interface constant, it will be caused to change its output if the local plant load changes. However ifthe generator becomes islanded with a portion of the utility load which is not exactly the same value asthe export control was set for, the control will become unstable since it is open loop, and any feedback ispositive instead of negative. The generator will with either overspeed or shut down in an attempt tocorrect the amount of power being exported. If the control is regulating for import, the generator will shutdown 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 valueof zero) the generator speed will change and be detected by a frequency relay. This will assume that sucha frequency excursion is indicative of islanding and will trip the interface breaker, thus terminating theserving of the utility’s loads and terminating the constant power or load following mode of control, orperhaps even the droop mode.

The rate of change of the generator speed after inception of islanding, while in the constant power modeor the constant import/export mode, will determine the speed of the relay action. In the Droopy mode itwill also require a change in the connected load sufficient to change the operating speed to reach the setpoint of the frequency relay, either as a steady state or transient mode. Performance in the transient modeis a function of the governor capability and the inherent response of the prime mover to the governor’scontrol.

The controllers and governors are reactive devices. They must sense a change to initiate a correction. Soeven in the droop mode, there will be a transient excursion from the droop curve until this correction isaccomplished. Various prime movers have various speeds of response as a function of inertia, fuelcontrol, or combustion control. Note that the term fuel, which is being applied to all prime movers, mightmore properly be called energy, since it may be in the form of steam pressure or water pressure, butadmitting 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. Themost familiar prime mover, the gasoline engine is relatively good at both, although it used to requirecombustion enrichment with the accelerator pump for rapid load pick up. The diesel engine has excellentload rejection because the fuel can be reduced quickly, but suffers from lack of combustion air on loadpickup until the turbo-charger can get up to speed. Naturally aspirated engines performed much better buthad excessive size, cost, and air pollution. These machines have low inertia. The H factor may be lessthan 1.

Gas fueled piston engines (natural or LPG) tend to be quite limited in load pickup and rejection. Thecontrol valves are often relatively slow acting, and there is a compressible column of fuel between themand the cylinders.

The single shaft gas turbine has a history of good load acceptance and rejection in the past in that themajority of the turbine loading is the compressor, which does not change with a change in the electricalload. However recent lean burn turbines require critical adjustment to avoid combustion instability. Their

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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 thethermal shock of large load pickup. Smaller units supplied from a boiler with a good head of steam canbe excellent at load pickup. Single cylinder, and even smaller two cylinder (high pressure and lowpressure) machines can reject full load without overspeeding. This becomes more difficult on large unitswith multiple cylinders and re-heat boilers, particularly if the inertia is low. However they are notnormally found in industrial plants.

Hydraulic turbines (waterwheels) have poor response because of the inertia of the water column precludesrapid changes in its flow. They have excessive overspeed on load rejection. Thus would be quick to tripif islanded.

Micro-turbines would be expected to have a fairly good response, but this has not been confirmed as ageneral characteristic. The variable speed machines do have to change speed to pick up load. Their sizeprecludes the ability to support much load during islanding, and so would trip quickly on under frequencyand undervoltage relaying.

Photo-voltaic installations with line commutated inverters cannot support load if islanded. Forcecommutated inverters are more likely to be found on residential installations, which are relatively smalland 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 allthe protection required by the utility I will be operating in parallel with?” This is especially true of smallDR’s ICG’s whose unit capacity is not large enough to supply the entire utility circuit load. The StateRegulatory Commission makes the interconnection rules include the possibility of a combination of largeand small synchronous and induction or self excited DR’s ICG’s continuing to supply utility loads duringthe islanding condition. How many dollars the DR ICG owner wants to spend for protective relayingalso depends on whether he considers the cost of his genset or the process it is supplying to be worthmore or less than the price of the protective equipment.

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IV.4.21 Impact of Intertie Transformer s Connections Chuck MozinaImpact of Interconnection Transformer Connections

on Interconnection ProtectionChuck Mozina

The major function of interconnection protection is to disconnect the generator when it is no longeroperating in parallel with the utility system. Smaller IPPsIPP’s and ICG’s aare generally connected to theutility system at the distribution level. In the U.S., distribution systems range from 4 to 34.5 KV and aremulti-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 13.8KV distribution system, single-phase transformers would be rated at 13.8 KV/v3~8 KV. Fig. 4.1 1 showsa 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 ofpossible choices and some of the advantages/problems associated with each connection.

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Fig.4. 2Interconnection Transformer 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 thatafter substation breaker A is tripped for a ground fault at location F1, the multi-grounded system isungrounded subjecting the L-N (line-to-neutral) rated pole-top transformer on the unfaulted phases to anovervoltage that will approach L-L voltage. This occurs if the dispersed Industrial Commercial generatoris near the capacity of the load on the feeder when breaker A trips. The resulting overvoltages willsaturate the pole-top transformer, which normally operates at the knee of the saturation curve as shown inFig. 4.3 3.

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Fig.4.3 3 Saturation Curve of Pole-Top Transformers

Many utilities use ungrounded interconnection transformers only if a 200% or more overload on thegenerator occurs when breaker A trips. During ground faults, this overload level will not allow the voltageon the unfaulted phases to rise higher than the normal L-N voltage, avoiding pole-top transformersaturation. For this reason, ungrounded primary windings should be generally reserved for smallerdispersed generatorsICG’s where overloads of at least 200% are expected on islanding.

Wye-Grounded (Pri)/Delta (Sec) Interconnect Transformer ConnectionsThe 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 distributioncircuit.

Analysis of the symmetrical component circuit in Fig.4.4b 4b also shows that even when the dispersed

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Fig. 4.4a Single-Line Diagram for Wye-Grounded (Pri) /Delta (Sec) Interconnection Transformer

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Fig.4. 4b Symmetrical Component Circui tfor Wye-Grounded (Pri) / Delta (Sec) Interconnection Transformer

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generator ICG is off-line (the generator breaker is open), the ground fault current will still be provided tothe utility system if the dispersed generator interconnect transformer remains connected. This would bethe usual case since interconnect protection typically trips the generator breaker. The transformer at thedispersed generator site acts as a grounding transformer with zero sequence current circulating in the deltasecondary windings. In addition to these problems, the unbalanced load current on the system, whichprior to the addition of the dispersed generatorICG transformer had returned to ground through the mainsubstation transformer neutral, now splits between the substation and the dispersed generator transformerneutrals. This can reduce the load-carrying capabilities of the dispersed generatorICG transformer andcreate problems when the feeder current is unbalanced due to operation of single-phase protection devicessuch as fuse and line reclosers. Even though the wye-grounded/delta transformer connection is universallyused for large generators connected to the utility transmission system, it presents some major problemswhen used on 4-wire distribution systems. The utility should evaluate the above points when consideringits use.

Wye-Grounded (Pri)/Wye-Grounded (Sec) Interconnect Transformer ConnectionsThe 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 tothat described in the previous section. It also allows sensitively-set ground feeder relays at the substationto respond to ground fault on the secondary of the dispersed generatorICG transformer (F3). Fig. 4.5a5aand Fig. 4.5b 5b illustrate this point through the analysis of symmetrical component circuitry.

C. Intertie Transformer SummaryThe 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 haveadvantages and disadvantages that need to be addressed by the utility in their interconnection guidelinesto dispersed generators. The choices of transformer connection also have a profound impact oninterconnection protection requirements.

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Fig.4. 5a Single-Line Diagram for Wye-Grounded (Pri) /Wye-Grounded (Sec) Interconnection Transformer

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Fig. 4.5b Symmetrical Component Circuit for Wye-Grounded (Pri) Wye-Grounded (Sec)Interconnection Transformer

C. ConclusionsThe 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 connectionshave advantages and disadvantages that need to be addressed by the utility in their interconnectionguidelines to dispersed generators. The choices of transformer connection also have a profound impact oninterconnection protection requirements.

4.2 Synchronous Generators, (Dalke and Stringer)

Location of islanding protection for synchronous generators depends on whether the generator is tocontinue supplying it’s in plant load while separated from the utility. If so, in the following discussin theprotective relay discussion should be located so that it will trip the circuit breaker at the Point of CommonCoupling (PCC) of the two systems. If plant load is not to be supplied then the protection should operatethe generator circuit breaker as quickly as possible.

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A common practice of utilities is to use transferred tripping to open the PCC anytime the utility breaker isopened. 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 discussedbelow and can be required as backup to the transferred trip system. Cost of transferred trip and itscommunication channel to the DRICG’s on a utility circuit is expensive but provides an effective primarymethod 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 andovervoltage (27/59) relaying and under and over frequency (81O/U) relays set for the window ofacceptable band limits of voltage and frequency to the utility customers. The undervoltage (27) elementwill operate for a time-delayed decrease in voltage if the generator does not have the capacity to sustainload after opening of the utility circuit breaker. A time delayed overvoltage (59) element will operate forover excitation of the generator that can occur under light load conditions after opening of the utilitybreaker. Under frequency condition will usually occur after the utility breaker opens perhaps leaving aload larger than the generator capacity. Over frequency can occur when load is interrupted on anadjacent utility circuit fed from the same utility bus.

Consequences to the generator owner of not having the under and over voltage and under and overfrequency protection can be damage to the generating unit from exceeding its thermal limits undersustained overload conditions. Also, off frequency operation can cause vibrations to turbine bladesleading to mechanical failures. Another consequence could be lawsuits from the utility customerswanting payment for damaged equipment because the DR ICG did not supply power within theRegulatory Commission window of operation for voltage and frequency.

The next most important protective elements are those detecting short circuits or faults on the utilitysystem that can be backfed by the DGICG. These are necessary to protect the public and utility workersfrom unsafe fallen power lines. Fault detectors must be able to detect faults on the longest amount ofcircuit the utility will have connected, even under load transfer or emergency conditions. The protectionmust be time coordinated so the fuse or recloser closest to the fault will operate first and keep customeroutage 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 overcurrentprotections will operate for fault current flowing in either direction through the PCC. Directionalovercurrent (67) protection may be needed to prevent opening the PCC for faults on the local plant system

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when the genset operation mode is to supply local loads when the utility source is open. These voltagepolarized overcurrent relays will operate for faults anywhere on the utility system. Impedance relays maybe required when the PCC terminates at the low voltage side of the utility transformer such that protectionmust look through or include the impedance of the transformer and the connected circuits on the highvoltage side of the transformer. If the transformer is a delta high side and wye low side, a special zerosequence over voltage (59N) detector connected on the high voltage side of the transformer will beneeded to detect single phase to ground faults on the high voltage side. These faults are undetectable byovercurrent 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 thethermal limits of the generator and lawsuits from the general public from for failing to interrupt faultconditions 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 usevoltage and current quantities that are essentially in phase to detect real power or watts. These quantitiesare stable and not varying greatly over a few cycles as a fault condition does. Because they are looking forwatts to make them operate, they are not a good means of fault detection. Directional overcurrent faultdetectors use a quadrature polarizing design such that the polarizing voltage is lagging the phase currentby 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 contractrequirements 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 utilitywhen restoring the intertie after a separation, Figure 4.2.1. This relay measures the voltage , angle andslip between the utility and the generator and permits closing of the PCC breaker only when the slip angleof 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 ofphase causing severe damage to the coupling between the prime mover and the generator. In very severecases 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 orvoltage relays (47) as unbalance detectors. These detect severely unbalanced loads on the utility systemthat can occur during single phase switching operations to transfer load or from operation of fuses tolarge individual customers or blocks of smaller customers during storms.

Consequences of operating during unbalanced load conditions will be exceeding the thermal limits of thegenerator.

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 RelayEngineers Conference April 15,1996

“Protection of Utility/Cogeneration Interconnections” Soudi, Tapia, Taylor & Tziouvaras, WesternProtective Relay Conference, October 19-21, 1993

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“Protection of Utility/Cogeneration Interconnections” Soudi, Tapia, Taylor & Tziouvaras, WesternProtective Relay Conference, October 19-21, 1993

“Myths of Protecting the Distributed Resource to Electric Power System Interconnection” G. Dalke TexasA & M Protective Relay Conference,April 19-22, 2002

“Islanding Problems for Non-utility Generation” C. Wagner, Texas A & M Protective Relay EngineersConference, April 13-15, 1992

“IEEE Tutor ial on the Protection of Synchronous Generators” 95 TP 102

IEEE STD 242-2001 “Protection and Coordination of Industrial and Commercial Power Systems”

4.3INDUCTION GENERATORS (STRINGER)

Intertie protection for locations with induction generators vary only slightly from that of synchronousmachines. Induction generators provide real power to the system, but require reactive power. Sinceinduction 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 systemsufficiently to maintain its integrity. After only a few cycles, the system will begin to collapse, with theinduction 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, wherethe generator is of sufficient size to carry the load, the induction generator can remain connected to theislanded system indefinitely. However, since the induction generator lacks self-excitation, the systemmust provide this either through a connected synchronous generator or connected capacitance. In eithercase, should sufficient generation be available the islanded system could be maintained, prolonging theabnormal condition that originally caused the island separation. Left unchecked, this could lead todamage of the induction generator, as well as other equipment connected to the islanded system. For thesereasons, it is necessary to provide protection that can quickly separate the DSG from the system wheneverthe supplying utility trips its breaker.

In addition, utilities generally employ automatic reclosing of feeders. Since most system faults aremomentary 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 theutility. Should the utility feeder reclose under this condition, severe damage could occur to the DSG ICGequipment; thereby, supporting the need for quick separation from the island. Also, should the generatorbe able to maintain voltage and speed for the DSG ICG plant loading, high-speed separation would beadvantageous to maintaining critical plant loads.

Similar to synchronous machines, intertie protection for facilities with induction generators is dependentupon the configuration of the connection and the winding method of the transformer. Figures 1 through 4indicate 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 windingmethod an DSG ICGmust use.

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Basic intertie protection for induction machines include those relays as listed in Table 4.3.1. As indicatedpreviously, when a fault or other abnormal operating condition occurs, which results in an islandedseparation, the characteristics of the island will change suddenly. Depending upon the connectedgeneration, there may be a significant frequency and/or voltage deviation. If sufficient generation isavailable, 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 DSGICGequipment could result, not to mention damage to other utility customers who remain connected tothe island. It is imperative that these conditions are detected and separation of the DSG ICG occursimmediately.

Table 4.3.1. Protection Application for Various Generator Types

Protection InductionGenerator

SynchronousGenerator

ANSI ProtectiveDevices

Overload X X 27, 81UFault X X 50/51, 87Abnormal Frequency X X 81Underpower X X 32UDirectional Power X X 32 O/UMotoring X XOverexcitation X 24Loss of Excitation X 40QOverspeed X 59, 81O

The various traditional protection methods used for DSG’s ICG’s with induction machines are discussedbelow.

Undervoltage (27)

When an islanding condition occurs, the DSG ICG facility will most likely experience a momentary dropin voltage at the point of intertie. Depending on the available generation, the voltage level could recoverslightly and then continue to Drop or it could simply continue to drop until the system becomes unstableand goes black.

Instantaneous undervoltage relays can sense this Drop in voltage when the supply line has tripped andprovide fast separation from the utility. This becomes advantageous when the utility is using high-speedreclosing. Normally this relay is set to a very sensitive level to detect and provide separation as quickly aspossible. However, the disadvantage with this approach is that problems elsewhere on the utility systemmay 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 veryminimum. 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 forapplications where the generator is capable of isolated operation. According to [1],Reference 1 this can beachieved 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 thatseparation is delayed. This could result in loss of stability for the DSG ICG or possibly severe equipmentdamage.

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Frequency (81O/81U)

When an island condition occurs, the frequency may drop if the generator cannot support the requiredload. It is necessary to remove the DSG ICG as quickly as possible when this happens. Frequency relayscan achieve separation using any of three different methods – underfrequency, overfrequency, rate-of-change of frequency.

The amount of frequency deviation will vary depending on the generator and the system. Most frequencyrelays of today include multiple setting levels in which to coordinate load-shedding schemes. Theseschemes will typically expand the load tripped with increasing frequency deviation. A deviation of ±5% isconsidered an extreme condition where the DSG ICG should be separated from the utility. On systems notusing 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 especiallyon synchronous machines where the excitation controls can push the speed above the acceptablemaximum levels. Overfrequency relays should be set for a maximum pickup of 60.5 Hz and a maximumtime 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 nameimplies, these relays measure the rate at which the frequency is changing. A DSG ICG operating under inan unstable islanding condition will experience a greater rate of frequency Drop than that expected fromother utility system problems. As a result, the rate-of-change of frequency relay can somewhat distinguisha severe frequency dDrop caused by an islanding condition from other conditions. Therefore, there is noneed 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 voltagedDrop at the DSG ICG intertie point to the utility will vary depending upon where the fault occurs. Thefarther away from the DSGICG, the less the voltage dDrop will be. Therefore, for a fault on theconnected line to the DSGICG, the voltage will most likely drop significantly at the time of the fault. Inaddition, 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 voltagemeasured. Voltage-controlled relays operate like a switch. When the voltage is reduced to a specifiedlevel, the relay will allow the operation of the overcurrent function. Therefore, the sensed voltage mustbe 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 leveldeviation from nominal. Most relays will operate for a current at 100% of setting when the voltage is atnominal (i.e. 120V). When the voltage decreases, the current pickup reduces in proportion to the decreasein voltage. For example, if the voltage drops to 60% of nominal (or 72V), the pickup of the currentelementpickup will be reduced to 60% of its nominal setting. Assuming a nominal pickup setting of 2.0amps, the adjusted pickup would be 1.2 amps.

The main disadvantage of these relay types is that the timing characteristics are normally a time-delayedfunction; thereby increasing the time to separation separate from the island.

Directional Power (32R)

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When an islanding condition occurs, the power produced by the DSG ICG will flow from the DSG ICGto the remaining load on the island. This power flow can be measured at the point of intertie. When thepower flow to the utility exceeds a specified level, the directional power relay will initiate tripping andseparation from the island.

The pickup setting should be above the maximum level of power for which the utility receives undercontract 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 fewyears. The vector jump relay provides protection for islanding conditions by detecting a significant phasedisplacement, or vector jump, within the measured voltage signal. As indicated in [2], when an islandcondition occurs, the DSG ICG will experience a phase shift in its voltage signal. This phase shiftcharacteristic is specific to the occurrence of an islanding condition. Other types of system abnormalitieswill not produce a waveform of similar characteristics. Therefore, this method provides quick detectionof an islanded condition and fast separation.

[1] ”Intertie Protection of Consumer-Owned Sources of Generation, 3 MVA or Less,” IEEE PowerSystem Relaying Committee Working Group Report, 88TH0224-6-PWR, IEEE Power EngineeringSociety Winter Power Conference.

[2] M.A. Redfern, O. Usta, and G. Fielding, “Protection Against Loss of Utility Grid Supply for aDispersed 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 differentprime movers on Islanding Protection, impact of intertie transformer configurations on protective relayingrequirements 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 isbased on the art of applying protective relaying. Different types of protection are required thus the cost ofprotection is much higher for some types of generators and prime movers. Review of these issues in thispaper provides a basis for the need for a variety of protective devices and states scenarios of possibledamage to either or both the generator and prime mover and the consequences for not providing properIslanding 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 RelayEngineers Conference April 15,1996

“Protection of Utility/Cogeneration Interconnections” Soudi, Tapia, Taylor & Tziouvaras, WesternProtective Relay Conference, October 19-21, 1993

Myths of Protecting the Distributed Resource to Electric Power System Interconnection” G. Dalke TexasA & M Protective Relay Conference, April 19-22, 2002

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“Islanding Problems for Non-utility Generation” C. Wagner, Texas A & M Protective Relay EngineersConference, 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 SystemRelaying Committee Working Group Report, 88TH0224-6-PWR, IEEE Power Engineering SocietyWinter Power Conference.

“Protection Against Loss of Utility Grid Supply for a Dispersed Storage and Generating Unit,” IEEETransactions on Power Delivery, Vol. 8, No. 3, July 1993. M.A. Redfern, O. Usta, and G. Fielding,