Determining the Impact of Distributed Generation on Power Systems: Part 1 - Radial Distribution Systems

Philip P. Barker Robert W. de Mello

Power Technologies, Inc.

I n trod uct ion

Distributed Generation (DG) is predicted to play an increasing role in the electric power system of the near fiture. Distributed generation is by definition that which is of limited size (roughly 10 MW or less) and interconnected at the substation, distribution feeder or customer load levels. DG technologies include photovoltaics, wind turbines, fuel cells, small 8z micro sized turbine packages, stirling-engine based generators, and intemal combustion engine-generators. These technologies are entering a period of rapid expansion and commercialization. For example, commercial-grade residential-scale fuel cells will arrive within the next 2 or 3 years with expectations of millions of installed units within the next 10 years. Photovoltaic programs are aggressively growing with plans to have nearly one million rooftops equipped with PV within a decade. Wind farms are springing up worldwide with more than 3000 MW of new wind capacity to be installed in the year 2000 alone. Even conventional internal combustion engine-generator and small gas turbine installations are increasing as commercialhdustrial electricity users install them for reliability and peak shaving applications. In fact, studies have predicted that distributed generation may account for up to 20% of all new generation going online by the year 2010. With so much new distributed generation being installed, it is critical that the power system impacts be assessed accurately so that these DG units can be applied in a manner that avoids causing degradation of power quality, reliability, and control of the utility system. This paper is the first in a two part series reviewing some of the concerns of DG application and methodologies for assessing the system impacts. This first paper focuses primarily on radial distribution systems while the second paper focuses on low voltage distribution networks and dynamic stability issues.

Analyzing DG Impacts

DG on Distribution Systems Distribution systems, whether they are radial type systems found in rural or suburban areas, or network type systems found in urban areas are generally designed to operate without any generation on the distribution system or at customer loads. The introduction of generation sources on the distribution system can significantly impact the flow of power and voltage conditions at customers and utility equipment. These impacts may manifest themselves either positively or negatively depending on the distribution system operating characteristics and the DG characteristics. Positive impacts are generally called “system support benefits,” and include:

0

0 Loss reduction 0

Improved utility system reliability

Voltage support and improved power quality

Transmission and distribution capacity release Deferments of new or upgraded TBD infrastructure

Achieving the above benefits is in practice much more difficult than is often realized. The DG sources must be reliable, dispatchable, of the proper size and at the proper locations. They must also meet various other operating criteria. Since many DGs will not be utility owned or will be variable energy sources such as

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solar and wind, there is no guarantee that these conditions will be satisfied and that the full system support benefits will be realized. In fact, power system operations may be adversely impacted by the introduction of DG if certain minimum standards for control, installation and place.ment are not maintained. This paper will not address how to achieve equipment deferments or T&D capacity release with DG; that is a comprehensive topic in itself that is best dealt with in a separate paper. Rather, this paper is focusing on the voltage quality, loss reduction and reliability factors associated with DG. For DG to have a positive benefit in these areas, it must at least be suitably “coordinated“ with the system operating philosophy and feeder design. This means addressing issues related to voltage regulation, voltage flicker, harmonic distortion, islanding, grounding compatibility, overcurrent protection, capacity limits, reliability and other factors. The larger the aggregate DG capacity on a circuit relative to the feeder capacity and demand, the more critical is this “coordination” with these factors.

Voltage Regulation and Losses Radial distribution systems are normally regulated using load-tap-changing transformers at substations, supplementary line regulators on feeders, and switched capacitors on feeders. Through the application of these devices customer service voltages are usually maintained within the ranges specified in IEEE Standard C84.1[’]. Voltage regulation practice is based on radial power flows from the substation to the loads and DG introduces “meshed” power flows that interfere with the effectiveness of standard voltage regulation practice.

As an example, if a DG unit is applied just downstream of a voltage regulator or LTC transformer that is using considerable line drop compensation (as is shown in Figure I), then the regulation controls will be unable to properly measure feeder demand. Figure 1 shows the voltage profiles that can occur under these conditions with and without DG. Note that with distributed generation the voltage becomes lower on the feeder. In this example the voltage is reduced because the DG reduces the observed load at the line drop compensator control. This confuses the regulator into setting a voltage lower than is required to maintain adequate service levels at the tail end of the feeder. This is the opposite effect of “voltage support”, a commonly touted benefit of DG. Movement of the DG unit to the upstream side of the regulator (if possible) or additional regulator controls to compensate for the DG output are solutions to this problem, but they bring their own set of issues.

Substation r--------------- I

~~~~ I ------ - - - - - - - - - - I

- >” 2 p: - Area Voltago of Low

Gen

i i Feeder voltage profile at peak

demand with DG Unit Off

I

Feeder voltage profile at peak demand with DG Unit On -----

............................................................................................................................... ------z-,- - -- .--. _-_. * ................................................. -----____ L v v r ANXl Limit Row. A Linil(99.i ~~1111eI

End of Feeder

Substation Bur

Location

Figure 1 - Example of DG unit interfering with voltage regulation1 on a distribution feeder. Line drop compensation must be employed a t the LTC control to result in thie indicated voltage profiles.

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DG may also result in high voltage at some electric customers. For example, a small residential DG system that shares a common distribution transformer with several other residences may raise the voltage on the secondary enough to cause high voltage at these customers. This can occur if the distribution transformer serving these customers is located at a point on the feeder where the primary voltage is near or above the ANSI upper limit (126+ volts on a 120 volt base). Normally, without DG, there would be voltage drop across the distribution transformer and secondary conductors and voltage at the customer service entrances would be less than the primary. The presence of the DG may introduce reverse power flow to counteract this normal voltage drop, perhaps even raising voltage somewhat, and the service voltage may actually be higher at the customer services than on the primary side of the distribution transformer; it may even exceed the ANSI upper limit.

The preceding examples have shown ways that both high or low service voltage can occur due to the incompatibility of DG with the radial power flow based voltage regulation approach used on most utility systems. As a result, the DG influence on voltage for any potential application shodd always be assessed to insure that no customers will be adversely impacted.

An accurate way to analyze the voltage regulation behavior of a system with DG is to run a power flow simulation using software capable of analyzing multiple sources on the distribution system and the operation of voltage regulators. The phase angle of the injected DG current relative to the utility system voltage must be considered as well as the impedance characteristics of the line. In this analysis, it is important to recognize that the DG injected power may result in a voltage that is within limits at the DG site but could be out of limits farther downstream.

To determine if the DG will cause a significant impact on the feeder voltage, the size and location of the DG, the voltage regulator settings, and impedance characteristics of the line must be considered. If line drop compensation is used by the regulator, then DG units interconnected within the regulator’s zone and downstream of the constant voltage point (CVP) will support (increase) the feeder voltage below the CVP. Those above the CVP will lower the voltage below the CVP. If voltage support is the key reason for using DG, then DG placement downstream of the CVP is crucial to meeting this objective (the farther downstream of the CVP, then the greater the support). The values of line-drop-compensation utilized will determine the CVP location on the feeder. Note that when no line-drop-compensation is used, the CVP is at the regulator device itself.

In essentially all cases the impact on the feeder primary will be negligible for any individual residential scale DG unit (<lOkW). However, when the aggregate capacity of many small units deployed reaches a critical threshold or when the capacity of a single unit is large enough, then voltage regulation studies are desirable to insure that the feeder voltage will be maintained within appropriate limits. The aggregate DG capacity threshold for which studies become appropriate depends on many factors. However, a reasonable rule-of-thumb is that if the injected current (measure at the primary level) is less than 5% of the feeder loading at the interconnection point and if all customers had satisfactory voltage prior to the addition of the DG, then a voltage problem on the primary is unlikely. Much above 5% injection and there is more reason to worry about potential impacts. For shared secondaries with DG even a small generator that injects less than 5% at the primary level could pose a voltage regulation risk to customers sharing the secondary. Thus, analysis of voltage conditions will almost always need to consider impacts on the secondary where the DG is located.

Distributed generation will also impact losses on the feeder. DG units can be placed at optimal locations where they provide the best reduction in feeder losses. Siting of DG units to minimize losses is like siting capacitor banks for loss reduction. The only difference is that the DG units will impact both the real and reactive powerflow. Capacitors only impact the reactive power flow. Most generators will be operated between 0.85 Lagging and 1.0 power factor, but some inverter technologies can provide reactive compensation (leading current). A good loadflow analysis software should be able to model the effects on system losses. On feeders where losses are high, a small amount of strategically placed DG with an output of just IO-20% of the feeder demand can have a significant loss reduction benefit for the system. Unfortunately, most utilities don’t have control over the siting locations, since DG is usually customer

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owned. Nonetheless, for utilities that are moving forward with their own DG programs, optimal siting of units can increase the performance of the system.

Larger DG units must be sited with consideration of feeder capacity limits. In some cases overhead lines and cables may be thermally limited meaning that the DG can inject power that exceeds the line’s thermal limit without causing a voltage problem on the feeder. The power flow analysis should%“flag” the locations where capacity constraints will be an issue from a thermal as well as a voltage perspective. In general, a DG at a location that is thermally limited is not connected at the optimal point from a “power loss” perspective.

Voltage Flicker DG may cause noticeable voltage flicker. Flicker can be either a simpk: issue or a complex issue as far as its analysis and mitigation are concerned. From the simple perspective. it can be the result of starting a machine (e.g. induction generator) or step changes in DG output which result in a significant voltage change on the feeder. If a generator starts, or its output fluctuates fiequently enough, flicker of lighting loads may be noticeable to customers. One approach is to determine the magnitude and number of changes of voltage occurring per unit time and see if these are above the visibility or irritation threshold levels of the GE flicker curve[*] (see Figure 2). If above the thre:shold, or if customer complaints occur, mitigation must be considered. Mitigation approaches include reduced voltage starts on1 induction generators as well as speed matching. Synchronous generators might require tighter synchronization and voltage matching. Inverters might be controlled to limit inrush currents and changes in output levels. A less technical approach to reduce flicker involves placing constraints on when and how often DG operators may start and change the output of DG systems. In the case of wind and solar energy systems, the outputs will fluctuate significantly as the sun and wind intensity change. Fortunately, these fluctuations tend to be smoother than step changes associated with the GE flicker curve. For this reason, the GE flicker curve is a conservative curve for assessing some types of solar and wind induced voltage fluctuations.

Figure 2 - GE Flicker Curve showing the “borderline of irritation” (see IEEE 519-1992 for further details)

Determination of the risk of flicker problems due to basic generator starting conditions or output fluctuations is fairly straightforward using the flicker curve approach, Imticularly if the rate of these fluctuations is well defined, the fluctuations are “step” changes and there are no complex dynamic interactions of equipment. The dynamic behavior of machines and their interactions with upstream voltage regulators and generators can complicate matters considerably. For ex:unple, it is possible for output fluctuations of a DG (even smoother ones @om solar or wind systems) to cause hunting of an upstream regulator and, while the DG fluctuations alone may not create visible flicker, the hunting regulator may

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create visible flicker. Thus, flicker can involve factors beyond simply starting and stopping of generation machines or their basic fluctuations. Dealing with these interactions requires an analysis that is far beyond the ordinary voltage drop calculation performed for generator starting. Identifying and solving these types of flicker problems when they arise can be difficult and the engineer must have a keen understanding of the interactions between the DG unit and the system. To model this on a computer requires good models of the distributed generators (which are often not available) and their interactions with utility system equipment. A software analysis package with the ability to analyze the dynamic behavior of systems is helpful for this type of study. It may also be necessary to perform system measurements to assess voltage and power flow oscillations and to identify how equipment controls can be "tuned" or modified to reduce flicker. In some cases, these dynamic flicker problems can be solved without a detailed study by simply performing an adjustment of a control element until the measured flicker disappears. In other cases, the fix is allusive and requires considerable investigation to solve.

Harmonics Distributed generators may introduce harmonics. The type and severity will depend on the power converter technology and interconnection configuration. In the case of inverters, there has been particular concem over the possible harmonic current contributions they may make to the utility system. Fortunately, these concems are in part due to older SCR type power inverters that are line commutated and produce high levels of harmonic current. Most new inverter designs are based on IGBTs that use pulse width modulation to generate the injected "sine" wave. These newer inverters are capable of generating a very clean output and they should normally satisfy the IEEE 519-1992 requirements (see Table 1 below).

A l l o w e d L e v e l Re la t ive to F u n d a m e n t a l ( 0 d d harm o n i cr )* H a r m o n i c O r d e r

< 1 1 ' b 4 %

< 1 Ith to c 17Ib 2%

C 17th to < 23'' I . 5 %

0.6%

35th or greater 0.3%

c 23rd to < 35thth

Total Harmonic Distortion 5%

'Even harmonics are limited to 25% of odd valuer

Table 1. Harmonic Current Injection Requirements for Distributed Generators Per IEEE 519-1992.

Rotating generators such as synchronous generators can be another source of harmonics. Depending on the design of the generator windings (pitch of the coils), core non-linearity's, grounding and other factors, there can be significant harmonics. Triple harmonics are additive in the neutral; and the third harmonic is often the most prevalent. Synchronous generators are often specified with a 2/3 pitch for the windings since this produces much less third harmonic than those with other pitches. Unfortunately a 213 pitch machine has a lower impedance to third harmonic and may cause more harmonic current to flow from other sources connected in parallel with it. The grounding arrangement of the generator and step-up transformer will play a major role in limiting the feeder penetration of harmonics. Arrangements can be selected to block or reduce third harmonic injection to the utility system. This would tend to confine it to the DG site only.

In general, harmonic contributions from DG units are probably not as much of an issue as some of the other problems discussed in this paper. Nonetheless, there are specific instances where problems have been identified such as levels of distortion which exceed the IEEE-5 19 standard, resonance with capacitor banks, or problems with equipment that are sensitive to harmonics. In extreme cases, equipment at the DG site may need to be derated due to added heating caused by harmonics. Any DG installation design should be reviewed to determine its compliance with IEEE 5 19 and whether harmonics will be confined to the DG site or also injected into the utility system. For larger DG units or cases involving complex harmonic

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problems, measurements and modeling of the system harmonics may be required to assess conditions. Any analysis should consider the impact of DG currents on the background utility voltage distortion levels. The limits for utility system voltage distortion are 5% far THD and 3% for any individual harmonic.

Impact on Short Circuit Levels The fault contribution from a single small DG unit is not large, howevw, the aggregate contributions of many small units, or a few large units, can alter the short circuit levels enough to cause fuse-breaker miscoordination. This could affect the reliability and safety of the distribution system. As an example, Figure 3 shows a typical fused lateral on a feeder where fuse saving [fault selective relaying] is utilized. If DG units are added to the system, the fault current inay become large enough that the lateral fuse no longer coordinates with the feeder circuit breaker during a fault. This would lead to unnecessary fuse operations and decreased reliability on the lateral.

su

Breaker

,& Fault

Figure 3 - Fault contributions due to DG units 1,2 and 3 may increase the short circuit levels to the point where fuse-breaker coordination is no longer achieved!

Typical short circuit levels of DG power converters are characterized in Table 2 and references [5][6][7] and [SI. For inverters, the fault contributions will dlepend on the maxirnum current level and duration for which the inverter manufacturer’s current limiter is set to respond. On some inverters fault contributions may last for less than a cycle, in other cases it can be much longer. For synchronous generators, the current contribution depends on the prefault voltage, subtransient and transient reactances of the machine, and exciter characteristics. Induction generators can also contribute to faults as long as they remain excited by any residual voltage on the feeder. For most induction generators, the significant current would only last a few cycles and would be determined by dividing the prefault voltage by the transient reactance of the machine, Even though a few cycles is a short time, it is long enough to impact fuse-breaker coordination and breaker duties in some cases.

00-400% (duratior

Starting at 500-1 00 ~ Generator - anddecayingto200-400%~cles I

Induction Generator or Selfbcited S nchronous Generator

500-1 000% forJrst,kw cycles and decaying to a negligible amount within 10

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Using the table above, a 1000 kW synchronous generator would contribute a peak fault current on a 13.2 kV primary feeder of about 218 to 437 Amps to a fault for the first few cycles. This compares with typical distribution circuits have primary fault currents ranging from about 100 amperes (at remote fringe areas) to more than 10,000 amperes near the substation. Thus, the current contribution from DG units is enough to impact fuse coordination in some cases, especially in weaker parts of the system. Table 2 represents the worst case fault contributions and is only meant as an illustrative guide. For accurate analysis, the generator data should always be obtained from the manufacturer. In addition, Table 2 is for faults at the generator terminals. The contributions will decrease the farther the generator is from the fault. The configuration and impedance of the DG site step-up transformer will also play a role. For example, a DG interface configuration that does not provide a zero sequence path to the utility system will not contribute to ground faults on the primary side.

When a single generator is added to the system, a manual calculation of the peak fault currents based on manufacturers data can be performed to screen for a serious impact on the existing short circuit levels. For multiple generation devices scattered throughout the system or large generators, the only accurate approach is to perform a software based short circuit analysis which correctly models the short circuit behavior of the generators. In many cases, the DG units won’t pose a threat to existing coordination; only a relatively few cases may require changes in protection settings.

Grounding and Transformer Interface Distributed generation must be applied with a transformer configuration and grounding arrangement compatible with the utility system to which it is to be connected. Otherwise, voltage swells and overvoltages may be imposed on the utility system that damage utility or customer equipment.

Most U.S. distribution systems are four-wire-multigrounded-neutral systems that are defined as being effectively grounded with respect to the substation source. For a single line to ground fault, this arrangement limits the voltage rise on unfaulted phases to about 125 to 135% of the prefault conditionr31141. By IEEE definition, effective grounding means that the positive sequence reactance is greater than the zero sequence resistance (XI>%) and the zero sequence reactance is less than three times the positive sequence reactance (3X1>X,). Use of a DG source that does not appear as an effectively grounded source connected to such systems may lead to overvoltages during line to ground faults on the utility system. This condition is especially dangerous if a generation island develops and continues to serve a group of customers on a faulted distribution system. Customers on the unfaulted phases could in the worst case see their voltage increase to 173% of the prefault voltage level for an indefinite period. At this high level, utility and customer equipment would almost certainly be damaged. Saturation of distribution transformers will help slightly to limit this voltage rise. Nonetheless, the voltage can still become quite high (1 50% or higher). For example, marginally rated lightning arresters would probably fail in less than 5 seconds if the voltage reached just 150% of the prefault condition 14].

To avoid problems, all DG sources on multigrounded neutral systems that are large enough to sustain an island should present themselves to the utility system as an effectively grounded source. If they do not, they should use appropriate protective relaying to detect primary side ground fault overvoltages and quickly trip off-line (instantaneous trip). The former approach is preferred since it limits by design the voltage swells that the system will see during a fault. The latter approach, while used successfully in many installations, could subject the customer to many cycles of severe overvoltage prior to the DG unit being cleared f?om the system. And if the DG is not cleared quickly enough, equipment could be damaged.

Some common transformer configurations found at DG sites are shown Table 3. Not all of these provide effective grounding. Use of an adjacent grounding transformer bank is one approach for creating a DG source that behaves as an effectively grounded source when the step-up transformer does not provide effective grounding. It should be noted that any additional grounding sources on the system, whether it is by a grounding bank or by using an appropriate step-up transformer winding arrangement, will have the effect of reducing (diverting) the zero sequence return current seen at the substation that arises from line to ground faults on the feeder. The amount of current diverted is determined by the ratio of the DG grounding source impedance to the substation grounding impedance. This effect has the impact of desensitizing the

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ground fault relaying at the substation since the substation will see letss current for a given magnitude line to ground fault out on the feeder. To asses the implact of this problem, the grounding source impedance of the DG site must be analyzed to insure that it won’t divert more than a small fraction of the fault current (perhaps 10% as a rule of thumb). For smaller DG units it usually is not an issue. For a larger unit acting as a ground source or for cases involving many small units acting together as ground sources, the short circuit studies need to identify the impact of this and see if any changes are required in relay pickup settings. A grounding resistance can be used on the DG ground source neutral connection to limit the impact. This also helps to reduce circulating current in any delta winding of the transfarmer,that are caused by zero sequence voltages on the feeder.

Wye-grounded/Delta

Proper review of the generator characteristics and utility system design prior to installation of the DG unit can insure that grounding compatibility problems are dealt with appropriately. Grounding compatibility is crucial to insure that power quality and reliability are not degraded b-y the addition of DG units.

grounded and meets neutral impedance requirements Typically provides effective grounding regardless of

Table 3 - Some transformer arrangements used for DG sites

- or I suitably sized primaryside grounding bank is provided I

grounding bank is provided or if the generator is wye-

Delta/Delta Wye-groundeWye grounded

I generator grounding arrangement

Islanding Islanding occurs when the distributed generator (or group of distributed generators) continues to energize a portion of the utility system that has been separated from the main utility system (see Figure 4). This separation could be due to operation of an upstream breaker, fuse, or automatic sectionalizing switch. Manual switching or “open” upstream conductors could also lead to islanding. Islanding can occur only if the generator(s) can self excite and sustain the loaid in the islanded section. In most cases it is not desirable for a DG to island with any part of the utility systfem because this can lead to safety and power quality problems that will affect the utility system and lOi5dS. For example, if an island develops on a feeder during standard reclosing operations, the islanded DG units will quickly drift out of phase with the utility system during the “dead period.” Then, when a reclose occurs, the utility will connect out of phase with the island if reclose blocking into an energized circuit is not provided at the breaker control. This can cause damage to utility equipment, the DG units supporting the island, and customer 1,oads. Islanding also increases the likelihood that DG sources may be allowed to subject the island to out of range voltage and frequency conditions during its existence. And it can pose a serious safety threat during downed conductors and utility repair operations since the public and utility workers may be exposed to circuits that otherwise would be de-energized. Finally, islanding can hinder service restoration by requiring line crews to spend extra time disabling the island conditions. This will impact reliability indices such as SAIDI.

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SUBSTATION FEEDER --3 E+m A

Utility crew opens switch

This area of primary stili en erg ized

House with Fuel Cell and

grid connected inverter

Figure 4 - Islanding can happen in a variety of circumstances. Proper protection must be provided to avoid islanding in all typical applications of DG. Most utilities and the IEEE have standards specifying the protection required to help prevent island development. Active anti-islanding is a robust new protection approach being applied to inverters.

To prevent islanding, a DG unit operating in parallel with the utility system should in a timely manner sense a significant voltage sag or discontinuity of service on the utility side and disconnect from the system. Many utilities have standards that require that this time be about 10 cycles or less for serious feeder disturbances (deep voltage sags or interruptions). IEEE has also developed standards; for example, IEEE 929 recommends that small photovoltaic inverters should initiate a disconnect within 6 cycles for such events [’I. This is fast enough to allow the DG’s to disconnect prior to the fastest reclosing times used in the industry.

Voltage and frequency relays are used as a means of anti-island protection. In most cases, if a generator becomes islanded, it will not be able satisfy the sudden change in its load without a significant change in voltage and/or frequency and the relays will trip the unit off line. This type of anti-islanding protection is called “passive.” Passive protection can be fooled if the generator is able to carry the load of the island without a substantial change in voltage or frequency so, as a further safeguard, many smaller inverters today also use what is called “active” anti-islanding protection. One common “active” approach is for the inverter to be “tuned” to operate while islanded at a frequency other than 60 Hz. While the utility signal is present the inverter is “forced” to operate at 60 Hz. During an intemption, it will drift to its natural “tuned” frequency once the “forcing utility voltage function” disappears (that is when it becomes islanded). In the process of drifting to the natural inverter frequency, the unit will trip its internal frequency relays, which are set to trip for a deviation from power frequency outside the range of 59.3 to 60.5 Hz. Active anti- islanding is more robust than passive, but even it cannot guarantee that an island won’t develop in some rare cases. Some active anti-islanding techniques developed by Sandia Laboratories are discussed in reference [9].

Since islanding can cause severe voltage quality and reliability problems, the proper use and setting of anti- islanding controls is one of the more important issues for DG installations. For small photovoltaic inverters IEEE standards are already available which describe the settings and types of controls required [’I. For other types of inverters and larger installations, the settings and controls required are still being defined. IEEE has a new standard under development (IEEE P1547) which will address all DG sizes and technologies. Most utilities and many state energy commissions also have standards that address the islanding issues.

Intentional Islanding for Re/iabi/ify The implementation of DG can increase reliability of electric service if units are configured to provide “backup- islands” during upstream utility source outages. To be effective this requires reliable DG units

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and carehl coordination of utility sectionalizing and protection equipment. Any time such a scheme is implemented it needs to be well planned to avoid causing problems. Figure 5 shows one scheme where an upstream automatic switch is used to island a section of a distribution feeder. For this approach to work the switch must open during upstream faults and the generators must be able to cany the load on the islanded section maintaining suitable voltage and frequency levels at all island’ed loads. Unless a static switch is employed, this scheme would usually result in a momentary interruption to the island since the DG would necessarily trip during the voltage disturbance caused by the upstream fault. A DG assigned to carry the island must be able to restart and pickup the island load after the switch has opened. Power flow analysis of island scenarios must be performed to insure that proper voltage regulation is maintained and to establish that the DG can handle inrush during “starting” ofthe island. The DCi unit must be able to load follow during islanded operation and the switch will need to sense if a fault current has occurred downstream of the switch location and send a signal to block islanding if a fault has occurred within the island zone. When utility power is restored on the utility side, the switch must not close unless the utility and “island” are tightly in synchronism. This requires measuring the voltage on both sides of the switch and transmitting that information to the DG unit supporting the island so that it can “synchronize” with the utility and allow reconnection. Overall, this is complicated but new automated switch technologies and communications approaches make this scheme much more practical than in past years.

Area slupported

during utility 1 outage

Substation

Figure 5 - Intentional islanding of a portion of a distribution feeder with a DG will require considerable planning and control efforts to work safely and properly. Such an implementation could improve reliability on a rural feeder without autoloop capability.

Conclusions

DG has much potential to improve distribution system performance and it should be encouraged. However, distribution system designs and operating practices are normally based on radial power flows and this creates a special challenge to the successful introduction of distributed generation. This paper has described a few of the issues that must be considered to insure that DG will not degrade distribution system power quality, safety or reliability. This paper focused on radial systems, ahhough some of the issues discussed are common to low voltage distribution networks. For a review of low voltage network considerations and other issues related to DG dynamics, the second paper (Part 2) of this series is referenced [lo].

It is clear that detailed analysis and special equipment to prevent protilems will be required in many cases where larger DG units are applied. However, it is important to recognize that due to the economics of small DG installations, a detailed study can not be performed for every small DG installation. That would be too much of a burden from a cost perspective on both the utility and DG operators (or whoever ends up paying for the studies). To resolve this issue, DG applications need to be screened with a “very low cost

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methodology’’ to determine which ones warrant careful study versus which ones can be successfully operated just by meeting basic requirements. From this perspective, there are probably three categories of DG installation:

1. Those that can clearly be installed per codes and standards without any special requirements 2. Those that are borderline (may need some limited special studies or have limited additional

equipment requirements) 3. Those that are clearly in need of detailed system impact studies and addition equipment

requirements

The capacity rating alone of a DG unit is not sufficient information to determine whether the installation is in Category 1,2 or 3. The factors that determine system impacts include not only the size, but the dynamic characteristics of the generator, the characteristics of the distribution system at the point of interconnection and the presence of other customers on the same secondary. As an example, it is possible for a 1000 kW DG connected at a stiff 12 MVA substation bus to cause less impact on system voltage than a 25 kW DG operating on the secondary of a 50 kVA distribution transformer serving many customers!

To avoid requiring costly impact studies for all but those applications that actually need them, proposed DG projects can be screened based on factors such as:

Utility system fault levels at the point of DG interconnection The size of the DG unit, its intended mode of operation and expected output fluctuations Aggregate capacity of DG on the system The DG short circuit level and duration Secondary configuration of the DG site (including presence of adjacent customers) Feeder voltage regulation practice The transformer and grounding compatibility of the system Size of generation relative load at the interconnection point Type of power converter.

These and other factors will determine the likelihood of causing a significant impact on the system and adjacent customers. The screening can be done manually or it can be done automatically by software based screening tools. A typical software screening tool would lead the user through a series of questions about the utility system characteristics and the DG unit characteristics and would perform various calculations to identify if the proposed DG installation needs a detailed study or can be installed without significant concern of adverse impacts. Generally, the larger installations will most commonly need special studies and attention but there will be smaller units that occasionally may require specialized study. Effective screening tools of this nature that consider factors on both the utility side and DG side of the system are under development and are strongly needed in the industry to streamline processing of an almost explosive growth in DG interconnection applications and projects. This will help to promote DG and maintain adequate safeguards to protect utility system reliability, safety and performance.

References

1. Voltage Ratings of 60 Hz Electric Power Systems, ANSVIEEE (284.1-1995, Published by Institute of Electrical and Electronic Engineers, 1995

2. IEEE Recommended Practices and Requirements for Harmonic Control in Electric Power Systems, IEEE Standard 5 19-1992, Published by Institute of Electrical and Electronic Engineers, 1992

3. IEEE Guide for the Application of Neutral Grounding in Power Systems, Parts 1-4, IEEE Std. C63.92 Parts 1-4, , Published by Institute of Electrical and Electronic Engineers, 1992

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~~ ~ ~~

4. IEEE Guide for the Application of metal Oxide Surge Arresters for Alternating Current Systems, IEEE Std. C62.22-1997, Published by Institute of Electrical and Electronic Engineers, 1998

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