Integrating Distributed Resource

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Integrating Distributed Resources into

Electric Utility Distribution System

EPRI White Paper

Technical Repor


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EPRI Project ManagerD. Herman

EPRI 3412 Hillview Avenue, Palo Alto, California 94304 PO Box 10412, Palo Alto, California 94303 USA800.313.3774 650.855.2121 [email protected] www.epri.com

Integrating Distributed Resourcesinto Electric Utility Distribution

SystemsEPRI White Paper

1004061

Technology Review, December 2001


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DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS ANACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCHINSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THEORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:

(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I)WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, ORSIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESSFOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON ORINTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUALPROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'SCIRCUMSTANCE; OR

(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER(INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVEHAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOURSELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD,PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT.

ORGANIZATION(S) THAT PREPARED THIS DOCUMENT

EPRI PEAC Corporation

ORDERING INFORMATION

Requests for copies of this report should be directed to EPRI Customer Fulfillment, 1355 Willow Way,Suite 278, Concord, CA 94520, (800) 313-3774, press 2.

Electric Power Research Institute and EPRI are registered service marks of the Electric PowerResearch Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric PowerResearch Institute, Inc.

Copyright 2001 Electric Power Research Institute, Inc. All rights reserved.


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CITATIONS

This report was prepared by

EPRI PEAC Corporation942 Corridor Park BoulevardKnoxville, TN 37932

Principal InvestigatorP. Barker

This report describes research sponsored by EPRI.

The report is a corporate document that should be cited in the literature in the following manner:

Integrating Distributed Resources into Electric Utility Distribution Systems: EPRI White Paper,

EPRI, Palo Alto, CA: 2001. 1004061.

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REPORT SUMMARY

This EPRI white paper is about understanding electric power engineering issues related tointegrating distributed resources (DR) into utility distribution systems. It is an overview designedfor all stakeholders rather than a rigorous technical engineering guide. A major goal of the paperis to move discussion of integration issues toward solutions.

BackgroundCustomer-owned electric generation is not a new phenomenon. From the early days of

developing a wide-area electric power system, the value of using local fuels for on-sitedistributed resources and co-generating electricity with local heat recovery has beendemonstrated. Integrating these systems into the transmission or distribution systems of localelectric utilities has been engineered on a case-by-case basis, taking into account unique aspectsof each site. Today, the emergence of promising new distributed resources technologies hasraised expectations that distributed resources could become widespread. The distributed powerindustry is asking for uniform connection requirements, faster permitting procedures, andminimization of special studies. A U.S. government report in 2000 identified delays anddifficulties in interconnection as barriers for distributed power projects. On the other hand, utilitysystem engineers are concerned that many small generators or a single and relatively largedistributed generator might adversely affect the electrical performance of distribution feeders.

The idea that uniform connection requirements can cover the wide variety of technical situationshas not been accepted. Cases have been sited that support both positions.

ObjectivesTo educate regulators/policy makers, DR developers, and other stakeholders on the complexitiesof integrating DR into the distribution system and to translate the technical language of DRexperts into language that all stakeholders can understand.

ApproachThe project team looked at technical questions regarding the safe and effective installation ofdistributed resources. Team members started with a fundamental description of electrical

distribution systems, then addressed issues that arise when distributed resources are added to thesystem. They addressed tradeoffs between maintaining simple and uniform connectionrequirements and achieving a safe and effective interface in the wide variety of connectionpossibilities.

Only part of the teams effort was to explain the grids inherent problems (for example, the gridwas not originally designed for two-way power flow). They also worked to send a positivemessage that the utility industry is working to make DR integration as simple as possible for DRdevelopers while preserving grid reliability and performance standards.

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ResultsBetter understanding of technical issues assists regulators and others responsible for settingpublic policy, rules, and standards for interconnection at state and local levels. Though technicalissues explained in the report also assist technically trained decision makers, they have beenwritten in terms that all stakeholders can understand. These explanations serve as a tool for

utility planners, energy providers, and system designers to balance needs of distributed resourceswith safety and reliability needs of the public power supply. Most of the technical issuesaddressed are relatively complex and are expected to continue to receive some level of debateamong various stakeholders. Effective compromises will come from more trials and hands-onexperience with DR installations.

EPRI PerspectiveAdvances in DR technologies and restructuring of the electric utility industry are simultaneouslyfostering increased interest in DR. When effectively integrated into an electric power system, DRcan be used to provide energy, capacity, and various ancillary services such as voltageregulation, power quality improvement, and emergency power supply. Misapplication of DR can

adversely impact both the private user and the public power supply. Understanding the issueswill enable stakeholders to effectively address interconnection and system integration concerns.This white paper will help all stakeholders involved in DR applications discuss and addresspotential issues in the system design stage.

KeywordsDistributed resourcesIntegrationDistribution impactsInterconnection rulesDistributed generation

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CONTENTS

1EXECUTIVE SUMMARY ..................................................................................................... 1-1

Overview and Key Issues ................................................................................................... 1-1

Power System Compatibility With DR................................................................................. 1-3

The Probability of DR Affecting the Public Power System .................................................. 1-3

DR Integration Solutions..................................................................................................... 1-4

2INTRODUCTION ................................................................................................................. 2-1

Focus of This Report .......................................................................................................... 2-1

Distributed Resources Technologies .................................................................................. 2-2

Value of Distributed Resources to the Transmission and Distribution System .................... 2-5

Impact of Distributed Resource Ownership on Interconnection........................................... 2-7

Interconnection Costs......................................................................................................... 2-8

The Compatibility of Distributed Resources and Distribution Systems................................ 2-9

Anatomy of a Distributed Resource ...................................................................................2-11

Role of the Utility System Design ......................................................................................2-13

Summary...........................................................................................................................2-14

3THE DISTRIBUTION SYSTEM............................................................................................ 3-1

Distribution System Topologies .......................................................................................... 3-1

Radial Systems .................................................................................................................. 3-2

Voltage Levels and Capacity of Radial Distribution Systems .............................................. 3-4

Faults and Protective Devices on Radial Systems.............................................................. 3-4

Networks ............................................................................................................................ 3-8Voltage Regulation of Power Distribution Systems............................................................3-11

4THE IMPACTS OF DISTRIBUTED RESOURCES ON DISTRIBUTION SYSTEMS............. 4-1

Introduction ........................................................................................................................ 4-1

Data Needed to Evaluate DR Impacts ................................................................................ 4-1

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Sensitivity of Power System to Location of Distributed Resources...................................... 4-2

Distributed Resources at the Distribution Substation .......................................................... 4-4

Distributed Resources on the Primary Feeder and Secondary Lines .................................. 4-7

Losses and Reactive Power Flow......................................................................................4-11

Impact of Power Factor on Losses ....................................................................................4-12

Current Ratings and Capacity Issues ................................................................................4-12

Safety................................................................................................................................4-14

Impact on Fault Conditions................................................................................................4-15

Transient Recovery Voltage..........................................................................................4-15

Fault Levels..............................................................................................................4-15

Impact of Fault Contributions of Distributed Resources on Lateral Fusing Practice ...........4-19

Impact of Reverse Flow Fault Contributions on Sectionalizers, Reclosers, and CircuitBreakers............................................................................................................................4-21

Size Limits Where Distributed Resource Fault Contributions Become an Issue.................4-23

Grounding Compatibility ....................................................................................................4-24

Ground Fault Overvoltage on a Four-Wire System .......................................................4-30

Small Generators and Ground Fault Overvoltages........................................................4-32

Transformers and Grounding........................................................................................4-33

Use of Existing, Three-Phase Transformer ...................................................................4-34

Transformers for Single-Phase Distributed Resources..................................................4-34

Circulating Currents in Transformer Windings...............................................................4-35

Impact of Grounded, Distributed Resource on Feeder Fault Sensing ................................4-36

Single-Phasing of Transformer Banks with Grounded-Wye and Delta Connections......4-39

Transformer and Grounding Issues that Impact the Distributed Resource Itself............4-40

Overall Conclusions on Transformers and Grounding...................................................4-41

Service Reliability ..............................................................................................................4-43

Islanding of Distributed Resources on Radial Systems......................................................4-43

Intentional Islanding......................................................................................................4-49

Avoiding Islanding on Network Systems and Interactions with Network Protectors.......4-50

Voltage and Frequency Control.........................................................................................4-55

Stability .............................................................................................................................4-60

Sags, Swells, and Momentary Interruptions.......................................................................4-61

Harmonics .........................................................................................................................4-62

Overvoltages .....................................................................................................................4-65

Flicker ...............................................................................................................................4-65

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5SUMMARY AND INTERCONNECTION SOLUTIONS......................................................... 5-1

Screening of Potential DR Interconnections ....................................................................... 5-1

Standardized Interconnection Requirements ...................................................................... 5-4

Interconnection Equipment at a Typical Site....................................................................... 5-5

Relays for Protection of Synchronous and Induction Generators.......................................5-11

Relays for Protection of Inverters ......................................................................................5-13

Relay Functions.................................................................................................................5-14

Suitable Voltage and Frequency Operating Window..........................................................5-15

Synchronization.................................................................................................................5-16

Non-Exporting DR as an Alternative to Employing Protection Functions ...........................5-17

Fast-Acting Directional Protection .....................................................................................5-18

Communication .................................................................................................................5-19

Overall Conclusions on the Complexity of Interconnection ................................................5-20

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LIST OF FIGURES

Figure 2-1 Example of Installation Using Reciprocating Engines and Combining the Heatand Power Functions (Courtesy Caterpillar Corp.)........................................................... 2-3

Figure 2-2 Example of Building-Integrated Photovoltaic System (left) and Large-ScalePhotovoltaic Concentrator System (Right) (Photographs Courtesy of NREL) ................. 2-4

Figure 2-3 Example of a Microturbine With a Rating of Approximately 28 kW(Photograph Courtesy of Capstone) ................................................................................ 2-4

Figure 2-4 Example of 200-kW Fuel Cell at Sunstrand Data Center in Windsor Locks,Conn. (Photograph Courtesy of International Fuel Cell, Inc)............................................ 2-5

Figure 2-5 A Distribution System of the Future Showing a Wide Range of InterconnectedGeneration Devices........................................................................................................2-10

Figure 2-6 Interconnection of Distributed Resources and the Utility System Is Defined bythe Type of Prime Energy Source (Top Row), the Type of Power Conversion(Middle Row) and the Utility System Interface and Protection Equipment in Use(Bottom Row) .................................................................................................................2-12

Figure 3-1 Examples of Distributed Resources Interconnected With the Power System.The Shaded Region Shows Where Distributed Generation Might be Interfaced. ............. 3-1

Figure 3-2 Classic Radial Distribution System......................................................................... 3-3

Figure 3-3 A Radial Distribution System Using the Auto-Loop Concept .................................. 3-3

Figure 3-4 Low-Voltage Spot Network Configuration (Note: Arrows Show the NormalDirection of Power Flow.) ................................................................................................ 3-8

Figure 3-5 Portion of a Low-Voltage Grid Network .................................................................. 3-9

Figure 3-6 Example of Network Protector and Primary Feeder Circuit Breaker Isolating aFaulted Primary Cable (Note: Arrows Show Direction of Power Flow to Fault.) ..............3-11

Figure 3-7 Voltage Regulation Devices Used on Distribution Systems IncludeLoad-Tap-Changing Transformers, Feeder Regulators, and Switched Capacitors .........3-12

Figure 4-1 Placement of Distributed Resource at the Substation Will Generally Impactthe Feeder Less Because of the Lower Impedance of the Substation ............................. 4-6

Figure 4-2 Voltage Profiles With and Without a Large Amount of Distributed Resources

Connected at the Substation ........................................................................................... 4-6Figure 4-3 Fault on an Adjacent Circuit Causes a Nuisance Trip of a Distribution Feeder

because of the Backfeed of Fault Current from Distributed Resources (G1, G2, andG3) .................................................................................................................................. 4-7

Figure 4-4 Evaluation Points Where the Stiffness Ratio Should Be Evaluated...................... 4-9

Figure 4-5 Optimal Location for a Distributed Resource to Reduce Feeder Losses................4-11

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Figure 4-6 An Example of Fault Contributions from Distributed Resources Being Addedto the Contribution from the Substation Source and Increasing the Fault Level onthe Lateral ......................................................................................................................4-16

Figure 4-7 Contribution of Fault Current From Typical Rotating Generators During theSub-Transient, Transient, and Steady State Time Frames .............................................4-17

Figure 4-8 An Example of How Fuse-Saving Coordination Is Impacted by Use ofDistributed Resources ....................................................................................................4-20

Figure 4-9 Distributed Resource Located on the Branch Circuit Contributes Fault CurrentCausing Confusion to Sectionalizing Switch C ...............................................................4-22

Figure 4-10 Example of Nuisance Tripping on the Feeder With Distributed Resource............4-23

Figure 4-11 Grounding of a Four-Wire, Multi-Grounded-Neutral Distribution System .............4-25

Figure 4-12 Example of the Three-Wire, Ungrounded Primary System..................................4-26

Figure 4-13 Example of Effective Grounding..........................................................................4-28

Figure 4-14 Example of a Three-Wire, 13.8-kV Ungrounded System During a Fault toEarth ..............................................................................................................................4-30

Figure 4-15 Example of a Four-Wire System Experiencing a Fault The Overvoltage onthe Distribution Circuit Is Fed by an Ungrounded Generator (With Respect to UtilityPrimary) During a Ground Fault. Note That the Generator Ground Connection onthe Wye Side of the Transformer Does Not Make the Delta on the High-VoltagePrimary Side Appear to Be Grounded. ...........................................................................4-31

Figure 4-16 Use of a Ground-Fault-Overvoltage Detection Scheme to Trip anUngrounded Generator and Limit the Duration of Overvoltages .....................................4-32

Figure 4-17 Four Commonly Used Transformer Arrangements and the Way TheyAppear From a Grounding Perspective to the Primary Utility Distribution System...........4-33

Figure 4-18 A Typical, Small (


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Figure 4-27 Illustration of the Concept Used in IEEE Standard P1547...................................4-47

Figure 4-28 Anti-Island Protection Can Be Arranged as Shown Here to Isolate theDistributed Resource From the Utility System But Continue to Operate a LocalCustomer Facility............................................................................................................4-49

Figure 4-29 An Example of Intentional Islanding Where a DR Has Been Strategically

Placed Downstream of a Recloser..................................................................................4-50Figure 4-30 Low-Voltage, Spot Network Under Normal Operating Conditions........................4-51

Figure 4-31 Low-Voltage Spot Network With One of the Primary Feeder Cables Faulted ......4-52

Figure 4-32 Example of Distributed Resource With a Capacity Large Enough to Exceedthe Network Load ...........................................................................................................4-53

Figure 4-33 Voltage Profile on a Distribution Circuit With and Without DistributedResources ......................................................................................................................4-57

Figure 4-34 Voltage Profile on a Distribution Feeder with Distributed Resource Addednear a Voltage Regulator Station....................................................................................4-58

Figure 4-35 Injected Power From a Distributed Resource at One Customer May

Influence Others on the Same Secondary ......................................................................4-59Figure 4-36 Comparison of Ideal Sinusoidal Wave and a Severely Distorted Wave...............4-63

Figure 4-37 GE Flicker Curves...............................................................................................4-66

Figure 5-1 The Basic Screening Approach behind all DR Screening Applications................... 5-2

Figure 5-2 Example of California Rule 21 Screening Process ................................................. 5-3

Figure 5-3 Curves Identifying the System Impacts of DR Connecting to Various Pointson the Distribution System............................................................................................... 5-4

Figure 5-4 Key Elements of an Interconnection....................................................................... 5-6

Figure 5-5 Example of a Fuel Cell Interface at a Residential Location..................................... 5-7

Figure 5-6 Interconnection of a 250-kVA Synchronous Generator (Alternate Transformer

Shown Is for Three-Wire Ungrounded Feeders) .............................................................. 5-8Figure 5-7 Example of an Interconnection for a Large Three-Phase Inverter .......................... 5-9

Figure 5-8 Utility-Grade Relays (Photo Courtesy of GE) ........................................................5-12

Figure 5-9 Example of an Inverter Product Intended for Photovoltaic Applications ThatHas Internal Microprocessor-Based Protective Functions (Photo Courtesy ofXantrex)..........................................................................................................................5-13

Figure 5-10 When the Inverter Feeds a Bus at a Different Location Than the IntendedInterconnection Isolation Point, a Separate Control Package May Be Needed forThat Point.......................................................................................................................5-14

Figure 5-11 Two Methods of Relatively Fast-Acting Reverse Flow Protection........................5-18

Figure 5-12 Example of Transfer Trip Used to Ensure that the DR Is No LongerOperating .......................................................................................................................5-20

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LIST OF TABLES

Table 2-1 Impact of Distributed Resource Application and Ownership on theDetermination of Interconnection Requirements by the Distribution Company................. 2-8

Table 4-1 Grounding Recommendations for Distributed Resources (DR)...............................4-27

Table 4-2 Recommended Transformer Configurations for Three-Phase DistributedResource Installations ....................................................................................................4-42

Table 4-3 Harmonic Distortion Standards From IEEE 519-1992 ............................................4-64

Table 5-1 Comparison of Typical Interconnection Equipment Used in DR Applications..........5-10

Table 5-2 Protection Functions Commonly Employed On Larger Generators ........................5-15Table 5-3 Recommended Voltage Operating Limits for Small Distributed Resources (Ro)

Zero sequence reactance is less than three times the positive sequence reactance (Xo


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The Impacts of Distributed Resources on Distribution Systems

operating voltage when one of its phases become faulted. The purpose of this is to limit seriousovervoltages that may damage loads and equipment during faults.

The concept of effective grounding and use of sequence components is complicated for personsunfamiliar with sequence component analysis and so aslightly incorrectbut simplified way to

explain it is shown graphically in Figure 4-13. This approach is easier to understand and providesthe essence of the issue.

Figure 4-13Example of Effective Grounding

Figure 4-13 shows a three-phase power system that is grounded at the substation. Before theconductor drops to the earth and creates a fault, the voltage vectors between phases and earth areall essentially the same in magnitude and displaced by 120o(see pre-fault vectors). The earthpotential at point (N) on the diagram with respect to the substation ground point is essentially0 volts before the fault.

During the fault, the conductor of phase C touches the earth and current flows through the earthimpedance back to the substation ground. Voltage drop along the earths impedance (the ground-

path-return impedance) causes a shift in voltage at the earth point (N). This increases the voltagemagnitude on the two, unfaulted phases at this location. The larger the return path impedance,the greater the voltage rise between phase and earth on the unfaulted phases. Proper control ofthe ratio of the outbound impedance path relative to the ground return path can help limit thevoltage rise.

The Figure 4-13 example was greatly simplified but provides an easy-to-understand explanationas to why voltage between phase and neutral/earth goes up on unfaulted phases when a single,

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line-to-ground fault occurs. Note that on a four-wire system, there is a neutral in addition to theearth path that helps share the ground return current and thereby limit the return-path impedance.The four-wire, multi-grounded neutral system has a lot of advantages in cost, safety, andperformance over three-wire systems, but it does have the drawback that equipment isphase-to-neutral connected and therefore may be more susceptible to the voltage rise that occurs

during faults.

Power system engineers carefully design the distribution system (if it is four-wire,multi-grounded, neutral-type system) to limit the voltage rise on the unfaulted phases byemploying effective grounding in the design of the system. Effective grounding ensures that theground return path impedance is not particularly large relative to the outbound impedance of thedistribution system. This is done by using sufficiently large neutral conductors and a sufficientnumber of grounds as well as the correct type of transformer grounding at the substation.

The system, looking out towards all points from the substation, is designed to act as aneffectively grounded source, no matter where the fault is on the distribution system primary.

Note that this design practice assumes that the substation or alternate feeds from other stations inemergencies are the only sources feeding into the distribution systemthe design has notaccounted for DR sources feeding in from customer sites.

Effective grounding means that faults to the neutral will not cause a large shift in the neutral wirepotential near the fault point. This is important for four-wire designs where many transformersand other equipment are phase-to-neutral connected and damage may occur if the voltage risestoo much. With effective grounding designs, the voltage on unfaulted phases with respect toearth or the neutral does not rise more than approximately 25 percent greater than the nominalsystem voltage level during faults. DR connecting to the system must also be designed with thiseffective grounding approach in mind so that it does not cause a voltage rise more than 25

percent greater than nominal on any unfaulted phases. This is easily done if the appropriategrounding and transformer type are used.

Three-wire distribution systems are either ungrounded or high-impedance grounded and operateextremely differently than the four-wire system just discussed. On a three-wire, ungrounded orhigh-impedance, grounded system, there is no neutral return conductor and all loads get theirpower from phase-to-phase connected distribution transformers. The idea of effective groundingis not employed or even desired on this type of system.

A fault to earth of a single phase raises the potential of the earth to that of the phase it is incontact with, so that the phase-to-earth voltage on the remaining two phases rises by a factor of1.73 compared to the prefault conditions (see example shown in Figure 3-14). This soundsnegative but it doesnt matter because loads are connected to phase-to-phase and the phase-to-phase voltage does not change during the fault.

In the vector diagram of Figure 4-14, note that before the fault, the phase-to-earth voltage on anyphase, is approximately 7967 volts and the phase-to-phase voltage is 13,800 volts. During thefault, the voltage on phases A and B relative to earth becomes 13,800 volts because the earthpotential shifts to that of phase C. The phase-to-phase voltages are unaffected.

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Because transformers for this system type of system are phase-to-phase connected, the customerloads will not see the rise and will not be in danger. On three-wire, ungrounded systems, utilityequipment that is phase-to-earth connected (such as lightning arresters) is already specified tohandle any neutral shifts that occur and so is rated to withstand full, phase-to-phase voltage. ForDR connected on such three-wire systems, it is desirable to limit any fault currents to earth so

DR should not be effectively grounded and in fact should have no grounding or a highimpedance ground with respect to the power system primary.

Some form of ground fault detection to trip the unit is also desired. This case is just the oppositeof what is desired for a four-wire system where we want good grounding of the DR! This is anexcellent example of why it is important to know the type of distribution system to which theunit is being connected.

Figure 4-14Example of a Three-Wire, 13.8-kV Ungrounded System During a Fault to Earth

Ground Fault Overvoltage on a Four-Wire System

If ungrounded generator sources or generator sources that dont meet effective groundingcharacteristics feed power into four-wire, multi-grounded-neutral distribution systems, then thereis a danger that an overvoltage will occur between phase and neutral on any unfaulted phases

during a line-to-ground fault. This occurs because of neutral shift as discussed in the previoussection.

In Figure 4-15, a case is shown where a four-wire system experiences a faultthe phase-Cconductor has fallen on the neutral of the power system. In this case, the substation circuitbreaker quickly detects the fault and trips open. Once the breaker trips open, the DR that isconnected with an ungrounded, delta-transformer winding will no longer have the substationgrounding as a limiterto hold the neutral shift to a minimum amount. Instead, the neutral shifts

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to the same potential as the phase-C voltage. We could say that when the substation breaker tripsopen, the system changes from a four-wire, multi-grounded neutral type to a three-wire,ungrounded design fed by just the DR.

This is just like the case of Figure 4-14, but now transformers are serving various customer loads

that are phase-to-neutral connected. These customer loads will suddenly experience phase-to-phase voltage that is 173 percent higher than the pre-fault phase to neutral voltage. Damage willoccur and a potential safety hazard also exists. Utility equipment such a lightning arresters willalso likely be damaged. For such a large voltage rise, it takes only a few cycles of overvoltage topotentially damage customer loads and utility system equipment.

Some utilities have taken the approach of Figure 4-16that is to allow ungrounded generators toconnect, but to do so they must have a fast-acting, fault-detection scheme like that shown thattrips the unit offline as soon as a ground fault is detected. The problem with this scheme is that itis extremely sensitive to routine feeder disturbances and will nuisance trip periodically. To makeit less sensitive to disturbances requires that some time delay be added that could allow

overvoltages to persist for many cycles and this could result in equipment damage. The onlyway to really avoid serious overvoltages is to design the DR system as an effectively groundedsource.

Figure 4-15Example of a Four-Wire System Experiencing a Fault The Overvoltage on the DistributionCircuit Is Fed by an Ungrounded Generator (With Respect to Utility Primary) During aGround Fault. Note That the Generator Ground Connection on the Wye Side of theTransformer Does Not Make the Delta on the High-Voltage Primary Side Appear to BeGrounded.

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Figure 4-16Use of a Ground-Fault-Overvoltage Detection Scheme to Trip an Ungrounded Generatorand Limit the Duration of Overvoltages

Small Generators and Ground Fault Overvoltages

This discussion of grounding so far has not dealt with the size of the generator in terms of itsability to cause a serious ground fault overvoltage. Certainly, a large, poorly grounded generator

such as 5 MW or larger poses a large risk to the system compared to a small generator of 100 kWor less. Whereas a large, 5-MW, ungrounded generator could create an overvoltage over a wideareaperhaps the whole feeder, a smaller, 100-kW generator could not create a sustained,serious overvoltage on a large portion of the system no matter how poorly it was groundedbecause there is too much load for it to drivein that scenario.

On the other hand, because the potential operation of switches and interrupting devices couldisolate a smaller generator with only a small portion of the feeder load that it could sustain, theneven a small unit could still pose a threat to a small part of the system. Also, the aggregateimpact of several small generators that are poorly grounded can pose the same threat as a single,large generator.

These factors mean that regardless of size, generators should still be grounded properly withrespect to the power system. Also note that the secondary system can experience some of thesame type of overvoltage problems as the primary, if the grounding of the DR is not propersoproper grounding can help prevent overvoltages and damage right at the DR facility!

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Transformers and Grounding

As was stated previously, the type of transformer employed has an impact on the groundingperceived by the utility primary system. For the generator to appear as a grounded source to theutility primary distribution system, the transformer must be able to pass a ground path from the

low-voltage to the high-voltage side. (This is called a zero-sequence path in power engineeringterminology.)

Figure 4-17 shows four, commonly employed arrangements for transformer windings. Only thetop two arrangements shown can provide a grounding path to the primary. Furthermore, for thetransformer with grounded wye to grounded wye, the generator neutral must be grounded tomake the source appear as grounded. The top two arrangements are preferred for four-wire,multi-grounded neutral systems.

The bottom two arrangements shown act as ungrounded sources and are best used on three-wire,ungrounded distribution systems. An important point is that a DR site can be configured to act as

a well-grounded source on the low-voltage side of the transformer, but the system may stillappear to the utility primary to be ungrounded on the high side. Delta connection on the high sideand grounded-wye connection on the low side can achieve this effect (see the third configurationshown in Figure 4-17).

Figure 4-17Four Commonly Used Transformer Arrangements and the Way They Appear From aGrounding Perspective to the Primary Utility Distribution System

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Use of Existing, Three-Phase Transformer

In cases where an existing three-phase customer plans to install a DR, a desire often exists toconnect the DR to the facilitys low voltage bus and use the existing distribution transformer asthe interface to the primary distribution system. This saves the cost of a new transformer and

much other equipment. In most situations this is fine, however, at some customers the existingtransformer does not provide the necessary grounding path and the source wont appear aseffectively grounded to the distribution system primary. A good example of this situation is adistribution transformer (with delta connection on the high side and grounded-wye connection onthe low side) serving an existing commercial customer.

In this case, the transformer provides excellent grounding for power flowing from the primary tothe secondary, but if we reverse the situation and try to have power flow from secondary back tothe primary, then it provides no grounding at all! This is an excellent example of the existingdistribution system equipment not being designed for the flow of power from loads out to thesystem. Protection to prevent export of DR power to the primary system can prevent a steady

state flow of power, but during transient fault conditions, the grounding problem still exists andis still an issueDR must be grounded properly whether they are designed for export or not!

Transformers for Single-Phase Distributed Resources

Single-phase DR, such as residential, photovoltaic systems or fuel cell systems, are normallyconnected to existing, single-phase distribution transformers that would have the propergrounding connections, and so it is highly unlikely, compared to a three-phase installation, thatthe wrong type of transformer would be present.

The only possible exceptions to this could be cases where the single-phase distributed

transformer was phase-to-phase connected on a four-wire, multi-grounded, neutral-type systemor where a single-phase DR is used on a three-phase transformer that is not configured to providea grounding path to the primary. Situations where these two possibilities become an issue areexpected to be rare. Nonetheless, DR system integrators should be aware of the possibility. Atypical, small inverter installation with proper grounding is shown in Figure 4-18.

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Figure 4-18A Typical, Small (


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currents occur because the zero-sequence voltage induced on each leg of the delta winding is allin phase.

Because the delta is a closed loop, these voltages will create circulating currents in the loop.Typically, a three-phase distribution transformer with grounded-wye and delta connections may

have 3 percent impedance to zero sequence currents, and it is not uncommon that a 2 percentcomponent of zero-sequence voltage on the primary exists.

This would create a circulating current equivalent to 2/3 or 66 percent of the transformerscurrent rating! This would leave only 33 percent of the rating for power flow. To solve thisproblem, a grounding impedance can be inserted in the neutral connection of the transformer tolimit zero sequence circulating currentsthis is the common practice that works successfully formany DR sites. The grounding impedance also helps limits certain fault modes and reduces theimpact of the DR site on utility protectionso it has many benefits.

Figure 4-19Circulating Current in Delta Winding Because of Zero-Sequence Voltage

Impact of Grounded, Distributed Resource on Feeder Fault SensingWhile it is appropriate and desirable to have grounded DR to avoid overvoltages, some

grounding arrangements can contribute to and interfere with the flow patterns of ground returncurrents that should normally flow back to the substation. A transformers with grounded-wyeconnection on the high side and delta connection on the low side, is an excellent example of atransformer arrangement that can cause this type of interference.

The impact can be to make it difficult for relays at the substation to detect ground faults out onthe distribution system. It also can interfere with fuse-breaker coordination and other protective

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devices. Utility distribution engineers are careful as to how these transformers are connected tothe system to avoid these problems.

To understand how a transformer can interfere with ground fault return currents involves adiscussion of the sequence current components. As was discussed in the last section, any

significant zero sequence voltage imposed on the transformer grounded-wye side will result incirculating current flow in the delta winding. During a nearby line-to-ground fault azero-sequence voltage is developed.

This results in a circulating current in the transformer delta windingthis current is in a waydiverted from the substation path and is never seen by the substation protection relays. This hasthe effect of desensitizing the utility relaying to ground faults relative to the actual currentsoccurring out at the fault location.

It is important to recognize that this effect occurs as a result of the transformer with grounded-wye and delta connections and is essentially independent of the DR connected to that

transformer. A partial solution to the problem is the neutral grounding impedance. Use of aneutral grounding impedance in the ground path can limit the zero-sequence contributions (seeFigure 4-20) and reduce this impact. The ground impedance needs to be sized so that it is largeenough to reduce contributions but still small enough that effective grounding of the source canbe maintained. This is only a partial solution because currents can only be limited so much,before the machine loses it effective grounding.

Figure 4-20Neutral Grounding Impedance Used to Limit Circulating Current and Ground FaultDesensitization and to Reduce Ground Fault Contributions From the DR Itself

Do all DR need neutral grounding impedance? A single, small (e.g., 30-kW) DR will notsignificantly impact feeder protection because its zero-sequence impedance will be extremelylarge compared to the distribution system zero sequence impedance. In such an example, most of

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the fault current (>99 percent) would still flow back to the substation and be measured by therelays.

However, if the zero-sequence impedance of the DR source (or aggregate grounding sources)begins to approach the substation, zero-sequence impedance, by simple current divider laws, the

ground fault current at the fault location will begin to be significantly different than the currentmeasured by relays at the substation.

As a rule of thumb, when the DR grounding source, zero-sequence impedance becomes less than10-20 times the substation zero-sequence impedance, then this begins to cause significantimpacts on protection (meaning a 5-10 percent difference in the measured current at thesubstation versus actual fault current at the fault). Larger DR installations are most likely tocause problems. Of course, a large aggregate number of small DR sources could also lead to thisproblem.

Use of a grounding-impedance in the neutral connection of the transformer can reduce this

impact to more manageable levels but an overall upper limit still exists on the aggregate capacityof DR that could be interfaced without causing difficulties. To solve any difficulties, it couldrequire changes in relay settings and additional protective devices and modified protectionschemes (by both utility system and DR).

The neutral grounding reactance may be on the high-voltage or low-voltage secondary side of thepower system, depending on the types of transformers used. A common transformerarrangement found at many DR sites uses two transformersto get from the generator to theutility primary; an interface transformer between the DR and the facility bus and then theexisting utility distribution transformer (see Figure 4-21.) For that arrangement, the groundingreactor is installed on the 480-volt side of the system as shown.

Figure 4-21A Common Transformer Arrangement Found at Many Commercial or Industrial DistributedResource Sites

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Another grounded DR installation is the installation with grounded-wye and grounded-wyeconnections (see Figure 4-22). This too can interfere with ground faults and a grounding reactorcan help. In this case, the neutral grounding impedance will be located at the generator itself.Most rotating DR can be damaged by the severe, ground-fault current levels that occur duringfaults, so use of a grounding reactor or resistor on the generator is often needed anyway to

prevent damage to the generator.

Figure 4-22

Grounding Impedance at the Neutral Terminal for the Rotating Generator

Single-Phasing of Transformer Banks with Grounded-Wye and Delta ConnectionsWith the transformer arrangement using grounded-wye and delta connections, if one or twophases of the high-voltage-side become disconnected, as shown in Figure 4-23, then the delta

winding can magnetically couple power onto the de-energized phases. This could happen when afuse operates upstream, a wire is broken or a switch is opened on only one or two phases. Underthis condition, the transformer will attempt to supply the load on the de-energized phases byusing power from the energized phase.

This poses a threat because the voltage levels and phase relationships created by this mode ofoperation are improper and could damage loads downstream of the site. Furthermore, the loadseen by the transformer in this mode of operation would be quite large compared to the rating ofthe transformer and could cause thermal damage.

It is important to recognize that the energy that is causing the overload is not coming from the

DR, rather it is coming from the one remaining energized phase and being fed back around intothe other phases by magnetic coupling in the DR transformer. So tripping the DR on thelow-voltage side of the transformer does nothing to stop the problem.

The transformer itself needs to be tripped off line on the high side to stop the overload. The fusesoften used on transformers would not necessarily melt for this type of overload and so otherprotection may be required to prevent thermal meltdown. This is why many larger DR employ

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three-pole switching devices to isolate the high-voltage side of the transformer when the DR tripsoffline.

This problem can occur at any site that has a grounded-wye connection on the high side and adelta connection on the low side and it is not limited to just DR installations. In fact, most of the

documented cases are at regular customer sites where this type of transformer has been used andthere is not any DR installed. In the case of DR, though, it becomes an important issue becauseone of the most commonly recommended transformer configurations for DR grounding purposesis the grounded-wye to delta.

So if DR becomes extremely popular, there could be many more of these units out on the system.A solution to the problem is that a three-pole circuit breaker or other suitable switching deviceshould be employed to fully de-energize all phases of the transformer if a loss or severeunbalance of voltage is detected on any phase. It should be noted that this type of switchgear is arequirement of the National Electrical Code (see Article 705-21) for such generator installationsanyway, and so, if it is not present, it is a violation of that code.

Figure 4-23A Delta Winding on the Low Side Can Result (1) in the Distributed Resource Unit Back-Feed of Two De-Energized Phases, (2) in the Transformer Overloading, and (3) in

Improper/Unsafe Voltage Conditions and Phase Relationships on the Feeder

Transformer and Grounding Issues that Impact the Distributed Resource Itself

The discussion of transformer interface and DR grounding has focused on the utility systemimpact issues. However, it is important to recognize that many of these issues are critical to theprotection of the DR itself. Selection of an inappropriatetransformer or grounding scheme for aDR can lead to overheating of the generator and damage to the generator during some types of

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fault conditions. There also can be damaging overvoltages to the loads at the DR site if it isincorrectly grounded. Careful attention to the proper design details of grounding, protection andtransformer interface not only help the utility company avoid problems but also avoid damageand dangerous conditions at the DR site.

Having stated the above, this is not to say that there arent some design needs of the utilitysystem and DR that are in opposition. One example is the issue of grounding of the DR sourcewith respect to the utility system primary. Most DR designers, if they were given a choice, wouldrather have an ungrounded or high-impedance grounded interface with respect to the utilityprimary distribution system.

This can help reduce the impact of ground faults on the generator and eliminates the circulatingcurrents that can occur in some types of transformer configurations. Fortunately, there are designapproaches that can generally satisfy the grounding needs of the utility and also meet the DRneeds. While these may not be the ideal arrangement for either party alone, they serve as atechnical compromise that will satisfy safety and operating requirements. General

recommendations are discussed in the next section.

Overall Conclusions on Transformers and Grounding

The issues discussed in the preceding sections show that there are many factors that must beconsidered in the selection of appropriate transformers and grounding for DR. While there is stillnot 100 percent technical agreement in the industry as to the best transformer arrangements, ageneral technical consensus exists that effectively grounded configurations should be used tointerface DR with four-wire, multi-grounded neutral systems.

Both the transformer with grounded-wye connection on the high side and delta connection on the

low side and the transformer with grounded-wye and grounded-wye connections can be suitableto provide an effectively grounded interface (note that in the case of the grounded-wye togrounded-wye connections, the generator neutral must not be grounded for this to be true).

However, these configurations should usually be properly equipped with neutral groundingimpedances to avoid the issues that have been discussed in earlier sections. For three-wire,ungrounded distribution systems, the DR should not provide a ground path for current flow toground or at a minimum should have a high impedance path that can be quickly tripped off line.An ungrounded transformer interface (such as a delta to delta) or a delta connection on the highside to a grounded-wye connection on the low side can satisfy this objective.

If a grounded-wye transformer is to be used on the primary side of the three-wire system, itshould only be used if it is grounded through an extremely high impedance. In all cases, the DRshould be equipped with ground fault detection that trips the unit off line upon occurrence of aground fault. For ungrounded installations, this could be the broken delta PT method shownearlier in Figure 4-15. For grounded systems, standard current sensing methods could be used.

Table 4-2 summarizes the transformer and grounding recommendations. Because of variations inthe distribution system design and protection practices amongst the many different utilities in the

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country, be advised that Table 4-2 is only a guide for most utilities and that some utilities mayneed different arrangements to ensure safety and reliability of their system.

Also, in some instances, several transformers may likely exist between the DR and utilitysystemall transformers cascaded in series should provide the appropriate grounding

connections with respect to the part of the system to which they are connected, as well as thefinal interface to the primary. As a public policy matter, it is possible to standardize transformerselection for most smaller DR applied at residential sites or small commercial sites on feeders,where total penetration of DR is low. However, at larger industrial and commercial sites, acertain amount of custom engineering will be needed to get around problems that can arise.

Table 4-2Recommended Transformer Configurations for Three-Phase Distributed ResourceInstallations

Winding ConfigurationEmployed for Interface Betweenthe Generator and Utility System

UtilityPrimary Side

Generator Side(Low voltage

side)

Is it a Grounded

GenerationSource withRespect to

Utility SystemPrimary?

Type of Distribution System to Whichthis Transformer Should Normally Be

Applied

Yes

Suitable for four-wire, multi-groundedneutral systems. It may need a neutralgrounding impedance and three-poleswitchgear on the primary of thetransformer

Only if thegenerator neutral

is grounded

Suitable for most four-wire, multi-grounded neutral systems but thegenerator must be grounded. May exposethe generator to severe fault forcesneutral grounding impedance may beneeded.

No

Not usually recommended for four-wire,multi-grounded systems. A good choicefor three-wire, ungrounded distributionsystems.

No

Not usually recommended for four-wire,

multi-grounded neutral systems. Apossible choice for three-wire,ungrounded distribution systems.

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Service ReliabilityUtilities generally measure the reliability of power delivered to their distribution systemcustomers by tracking service interruptions that impact their customers. Two types of serviceinterruptions on the distribution system that utilities are particularly interested in tracking are

sustained interruptions and momentary interruptions. Generally, sustained interruptions aredefined as those lasting 5 minutes or longer. Momentary interruptions are those lasting less than5 minutes (often these may be just a few seconds). Depending on the type of distribution systemand the way it is protected, customers will experience various combinations of these two types ofservice interruptions.

Minimizing the number of momentary and sustained interruptions experienced by variouscustomers is extremnely dependent upon the proper functioning of the grid protection equipmentduring fault conditions. DR can negatively affect service reliability because, as has beendiscussed in earlier sections, it can confuse the operation of grid protection equipment includingfuses, reclosers, circuit breakers and other devices. If the equipment does not function properly,

utility customers can experience longer and more frequent outages.

Islanding of Distributed Resources on Radial Systems

Islanding is the situation in which a DR installation and a portion of the utility system havebecome isolated and the DR continues to operate and serve loads on the circuit. Islanding can beintentional or it can be unintentional depending on the objectives and controls employed.Unintentional islanding into any part of the utility system can compromise safety and can harmcustomer loads and distribution system equipment. Some key dangers of islanding include:

Island will drift out-of-phase with respect to the utility system and then equipment may be

damaged during utility company reclosing.

Incidents of energized, downed conductors may increasecausing more public danger.

Service restoration by utility crews may be delayed and made more dangerous.

Islands may not maintain proper voltage or frequency for connected loads this can threatencustomer loads and utility equipment.

Ferro-resonance or incompatible grounding practices of some DR that dont show up duringnormal system operation may lead to damaging voltages during the island existence.

A variety of island scenarios may occur depending on the size of the DR, configuration of the

power system and load that exists on the system. A large DR, such as a 5-MW unit, has enoughpower output capability that it could potentially island an entire distribution feeder, whereas, asmall DR, such as a 10-kW PV system, could island only a group of houses at most. Onerequirement for islanding is that the DR device must be capable of self-excitation, which is truefor synchronous generators and force-commutated inverters.

Generators that normally are not self excited, such as induction generators or line-commutatedinverters are generally not able to island. However, they can island under some conditions.

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Figure 4-24 shows an example of a large island that might be formed if a 3-MW synchronousgenerator is isolated with a major portion of the distribution feeder. Figure 4-25 shows apotential, small island on a secondary serving just a few customers.

Figure 4-24Example of a Large Island That Might Be Created if a Large Distributed Resource (e.g., 3MW) Is Isolated With a Major Portion of a Distribution Feeder

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Figure 4-25Example of a Small, Unintentional Island on the Secondary System if the Fuse ShouldOperate or Be Removed and the Anti-Islanding Protection in the Local Generators DoesNot Work Properly

Once an island forms with DR, the utility system no longer controls frequency or voltage in thatsection. It is the DR that is controlling the voltage and frequency and it would not ordinarily beequipped to handle that function over a large area. Customers may be subjected to voltages and

frequency that damage equipment or imperil human safety. Islanding may also damage utilityequipment and cause service restoration delays because, once established, an island will typicallybe out of phase with the utility voltage.

To reestablish normal operating conditions and rejoin the islanded section of line to the maincircuit, the two must be in phase and this coordination takes time. Rejoining the island in phaseis imperative, as an out-of-phase connection could damage the DR or utility equipment, which isnot rated for that capability. Utility personnel who are working near equipment that fails becauseof out-of-phase reclosing could be seriously injured. The effects of islanding may also pose apublic safety risk because there could be an increased hazard of downed conductors that can betouched by the general public and the protection system is less likely to successfully de-energize

lines that have fallen onto automobiles, energized other public services, and perform otherprotective activities (see Figure 4-26).

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Figure 4-26A Distributed Resource With Improper or Ineffective Anti-Island Protection Could Pose a

Threat to the Public and Utility Workers by Back-Feeding Downed Conductors

Fortunately, most of the potential cases of islanding can be prevented if DR use appropriateanti-islanding protection. The most common means of preventing islanding is what is often

referred to as the passive, anti-island protection technique. This approach uses a voltage andfrequency relay set to trip the DR whenever either parameter migrates outside an acceptablewindow. Relays would typically be set to a tight frequency range on the order of 0.5 to 1.0 Hzaround the nominal frequency of 60 Hz in the United States.

The range of allowed voltages are a bit wider, typically 5 to 10 percent, to allow for normalvariations. Undervoltage, overvoltage, and frequency protection equipment prevents islandingbecause in most cases when a section of the distribution system and DR unit separate, the outputof the DR unit will not match the power demand within the separated area. For synchronous orinduction generators, this will result in a change in voltage and frequency that causes the relaysto trip in an extremely short time frame.

An IEEE standard under development (Std. P1547) is currently recommending that DR ceaseexport of power within 10 cycles for a severe, abnormal, low-voltage conditions (less than50 percent). These would be indicative of an open switching device upstream or nearby fault.Because the utility company circuit breaker may attempt to reclose within anywhere from 12cycles up to more than 90 seconds, the recommended anti-island practice uses 10 cycles becauseno standard equipment exists that can reclose faster.

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Figure 4-27 shows the concept in action. It should be noted that another key part of anti-islanding protection is the blocking of reconnectionto the utility system. This means that oncethe relays trip the DR off line, the control logic is programmed to prevent any attempt toreconnect into an out-of-range utility system voltage or frequency condition. Only after voltageconditions have been restored to the normal range is DR allowed to reconnect. Note that some

utilities use this blocking approach on their circuit breakers in substations if there is concern thatDR may be islanding on the power system.

Figure 4-27

Illustration of the Concept Used in IEEE Standard P1547

In situations where the load on the island is nearly balanced with the generation on the island, thepassive technique may not be adequate because there may not be sufficient voltage or frequencychange to cause the unit to trip. This is particularly true for inverter-based technologies that canrapidly respond to changes in load and have extremely stable frequency output. To overcome thisproblem, more robust, active, anti-islanding techniques have been developed for many inverters.These approaches employ a combination of active and passive techniques including:

Overvoltage and undervoltage detection, based on the assumption of a mismatch betweenreactive sources and loads in island

Overfrequency, underfrequency, and rate-of-change of frequency detection, based on theassumption of a mismatch between active sources and loads in island

Harmonic content detection, based on higher relative harmonic levels for islanded systemscontaining high percentages of inverter sources

Comparison of the response of the DR unit to changes in power set point (response will befaster when grid connected)

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Active frequency shift, based on intentional frequency shift of inverters away from normalfrequency using positive feedback

Active voltage shift, based on positive feedback of voltage changes

Active power shift, based on detection of current and/or frequency changes during intentional

power modulation System faultlevel monitoring, based on measurement of the power systems source

impedance close to the interconnection point

Widely used active techniques are the voltage- and frequency-shift techniques. In those cases assoon as the island forms, the DR does not remain stable, and its frequency or voltage begins toshift until eventually it shifts outside of the acceptable window of its passive voltage andfrequency protection relays.

To be highly effective, this sort of shift must occur rapidly once the unit becomes islanded butthe unit must be stable enough to remain locked to the utility system voltage and frequency while

the reference utility voltage is present. A typical requirement for this protection is that it shouldoperate within a few seconds following the isolation of DR from the grid for a balanced loadisland scenario or a minor voltage or frequency excursion outside the limits.

For more severe situations, such as a deep voltage sag, it should operate within 10 cycles or less.Simulations and tests of passive and active techniques with different load types revealed thatsome active technique detection times could be longer than the requirement if multiple invertersare connected and the load type meets certain criteria.

Further study is needed to evaluate cases in which islanded systems are formed to comprisemixed forms of generation including synchronous sources. So far though, with inverters, tests

confirm that frequency- and voltage-shift techniques both generally provide rapid detection whenused even with worst-case loads. IEEE Standard 929 and UL Standard 1741 define anti-islandingtest procedures that represent some of the worst-case scenarios that are expected to occur inpractical situations.

Many DR operators desire to operate their units in an islanded mode as a source of standbypower during a utility interruptionsupporting only their own load (see Figure 4-28). Utilitycompanies have no issue with this approach as long as the units are not islanded with any portionof the utility system and have a proper means of being resynchronized and connected in phasewith the utility system once power is restored.

DR equipment exists that has been developed to provide anti-island protection for the utilitysystem connection, but can continue to operate as a tiny island supporting only site load for theDR customer. It also is possible to have interlocks that bypass the anti-island relays on a DR onlyafter a utility disconnect switch has been opened. This allows the DR operator to pull the switchopen, isolating the DR from the utility system, and then restart their DR to serve only the DR siteload.

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Figure 4-28Anti-Island Protection Can Be Arranged as Shown Here to Isolate the Distributed ResourceFrom the Utility System But Continue to Operate a Local Customer Facility

Intentional Islanding

While we have discussed the dangers of islanding of DR on the utility system, it is important torecognize that islanding may improve reliability if it is done as part of a carefully plannedprogram with the proper controls and equipment. When done in this manner, it is calledintentional islanding. This is an option that many utilities are considering but it has not seenmuch deployment yet.

It must be implemented properly and with great care to avoid causing the safety and operationalconcerns that we have already discussed. An example of intentional islanding is shown in Figure4-29 where a DR has been strategically placed downstream of a recloser. During an upstreamfault, it could improve service reliability for the customers served on the tail end of the circuit byislanding and continuing to support those customers (the recloser would open to provideisolation of the island).

To be successful, the DR must be able to support the islanded load, maintain adequate voltageand frequency, and handle any transient-starting inrush required to restart the island (should theisland be dropped by the DR). This all needs to be accomplished while ensuring that the properprotection and communication is provided to control the recloser and coordinate the operation of

the DR.

The recloser should be blocked from reconnecting to the utility system until the utility system isre-energized at the proper voltage and frequency and is in-phase with the island. This schemecould greatly benefit rural systems by providing an alternative source in areas that have no suchoption. It is not likely to be done with customer-owned DR but rather would be part of a strategicuse of utility-owned or energy service company DR to improve system performance.

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Figure 4-29An Example of Intentional Islanding Where a DR Has Been Strategically PlacedDownstream of a Recloser

Avoiding Islanding on Network Systems and Interactions with Network Protectors

Secondary network distribution systems function quite differently from radial distributionsystems and have correspondingly different complications with the interconnection of DR. Onecomplication arises from the use of network protectors and the potential that an island willdevelop on a low-voltage network. To understand this danger, lets first discuss the operation ofnetwork protectors.

The purpose of network protectors is to prevent reverse power flow from the low-voltagenetwork into a faulted network transformer or primary feeder cable (see Chapter 3 for details onthis function). These devices have sensitive, reverse-power relays that will trip on a tiny amountof reverse power flow (much less than 1 percent of the normal forward flow).

If care is not exercised in the application of DR on the low-voltage network, then DR can tripsuch protectors and island the low-voltage network from the main utility system. This isparticularly dangerous and should be prevented by limiting the amount of DR on the networkand/or making appropriate adjustments to the network and DR protection equipment so that thiswill not occur.

Figures 4-30 to 4-32 depict the connection of a secondary, spot network to several primaryfeeders and show the operation of the protectors under normal conditions, faulted conditions, andwith a large DR connected. In Figure 4-30, the network is fed by three feeders that , undernormal operating conditions, feed a nominally equal level of power into the network. The

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resulting redundancy in power supply lends networked systems their reliability, but also makesthem more complicated to protect.

When a fault occurs on one of these feeders, as shown in Figure 4-31, power feeds into thefaulted feeder from both the substation side and the low-voltage network side (by way of the

network transformer). To de-energize the fault requires that the substation breaker and thenetwork protector both trip. Power feeding from the low-voltage side will be in the reversedirection and the network protector is set to trip on an extremely low value of reverse power (lessthan 1 percent of the normal forward rating). Because of the redundancy of the network systemdesign, with the faulted feeder removed from the system, the remaining two feeders haveadequate capacity to supply the load on the network.

Figure 4-30Low-Voltage, Spot Network Under Normal Operating Conditions

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Figure 4-31Low-Voltage Spot Network With One of the Primary Feeder Cables Faulted

As is shown in Figure 4-32, placement of a distributed resource with a capacity large enough toexceed the network load could cause enough backfeed to the system such that all of the network

protectors connecting the feeders to the network would open. At this point, the network wouldbe energized only by the distributed resource and the generator-fed network system would beseparated from the feeder system. Several problems exist with this scenario, ranging from poorpower quality to nuisance tripping of protectors to equipment failure and major hazards.

One of the most critical hazards is that the network island will not stay at the same exactfrequency as the utility systemthe difference in frequency between the utility system and theisland is referred to as aslip frequency. While this slippage is occurring the utility system andnetwork-island periodically drift into and fully out of phase.

During a moment when they are in phase, it is possible for the network relay to be fooled into

believing that conditions are appropriate to reconnect. However, by the time the reconnectcommand is completed, the network-island and utility system will again have drifted out ofphaseso the network protector will actually close into an out-of-phase system. This willusually damage the network protector as well as the DR equipment and loads on the island.

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Figure 4-32Example of Distributed Resource With a Capacity Large Enough to Exceed the NetworkLoad

As an example of this problem, suppose that a large urban hotel with a spot network hasdetermined that a co-generating distributed resource would be cost effective. They proceed tointerconnect a cogeneration unit with a capacity slightly larger than their minimum load to thespot network. On a lightly loaded day, the hotels load drops below the output of the distributedresource, and power begins to back-feed through all three of the network feeders. The networkprotectors trip, disconnecting the hotels spot network from the spot network bus, and causingthe distributed resource to island with the load. After these systems become separated, they willdrift out of phase and become unsynchronized.

Eventually, the phases of the network bus and the DR-island will come close enough together toinitiate the reclosing of the network protectors. However, by the time the protectors are closed,the island may have swung out of phase again because it takes approximately second to fullyinitiate the command. The relays that control the automatic reclosing of network protectors werenever intended to act as synchronizing relays for interconnecting two, non-synchronized systems.

Also, the network protectors themselves are not tested or rated for this type of interruption dutyand it is still being evaluated whether this type of duty could pose a threat to most protectors.Some extremely serious incidents have existed where network protectors have burned up whenapparently trying to interrupt the electric power system from a DR island.

Technical solutions exist to this problem. Most obvious is that the DR power output could belimited to a capacity smaller than the buildings minimum load. This is not as easy as it may

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seem. First of all, it is extremely difficult to decide the minimum load level that should bechosen. Is it the minimum load that occurs on a daily basis, the minimum that occurs weekly, orthe annual minimum load? What is the annual minimum loadis it even known? What if a faultor overload in the building trips several circuit breakersshutting off most of the load in thebuilding and creating a lower than expected minimum load?

Clearly, to be safe, one would need to size the generator to consider the likelihood of all thesescenarios and have operating procedures that would shut down the DR unit before tripping anysignificant loads in the building. Even if the generator could always be operated at less thanminimum load under steady state conditions, this does not prevent transient reverse powermomentarily flowing into the protectors if a voltage sag should occur because of a fault on theutility system. For example, if a voltage sag occurs on the utility system because of an upstreamfault at the substation bus, the DR could momentarily cause reverse flow into all of the networkprotectors serving the spot network and thereby trip them. This, of course, would island thenetwork.

One way to be reasonably confident that the islanding problem can be avoided is toconservatively limit the size of the DR to a small value compared to the minimum load on thenetworkperhaps only 10 percent of the worst-case, minimum load. Even better, if the DR islimited to the size of the reverse power trip threshold of the most-sensitive network protector,then this will solve the problem altogether. Of course, with either of these approaches, thegenerator would end up being extremely small compared to the building loadin many cases,too small to meet the objectives of the building owner that installed it in the first place. In caseswhere a larger generator is to be applied, then modifications to the network protection arerequired.

These changes include using time-delayed relaying instead of the normal, instantaneous, reverse

power relaying on the network protectors coupled with an instantaneous, reverse-power relaythat trips the DR when reverse power is detected. Time delays are necessary because the normalinstantaneous trip on the network protector is so fast it will trip because of reverse current beforemost DR could be tripped off line. With a time delay on the network protectors, the DR can beset to trip off line before any network protector trips.

While making these relaying changes may be one possible solution, they cost money and, moreimportantly, could cause other problems for the utility system. For example, the long time delayson tripping of faults would increase the amount of damage caused by faults and also degradepower quality. Also quite a bit of controversy still exists regarding the ability of networkprotectors to serve as an interrupting device between a DR island and the utility system. So, theIEEE P1547, Draft 7, standard does not currently recommend that they be used for such duty,unless rated for it.

New technology is being considered to help resolve this issue. One proposed future approach isto use special electronic controls and communication paths to allow any network island that doesform to stay in phase with the utility system. This would eliminate the danger of islands andallow the network protectors to function as they are now without any changes. This technology isnot available yet but is under consideration by EPRI for future development. Manufacturers of

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network protectors are also developing new products that can address the needs of DR on thesystem.

Voltage and Frequency Control

Maintaining adequate operating voltage at all customer delivery points is critical to propersystem operation. As has been discussed earlier, the range of acceptable customer service voltageis normally classified as 5 percent on the nominal level, with +6% or -8% acceptable foroccasional and short-term events. These levels are described in ANSI standard C84.1a nationalstandard that all utilities must consider. It should be noted, however, that a few utilities haveeven tighter standards that supersede the ANSI C84.1 limitsstate regulatory commissionsimpose these.

For example, some utilities are required to maintain voltage within a +3% to 5% band.Frequency is also maintained within extremely tight tolerances to ensure proper operation ofconnected equipment. On a large, interconnected power system, small deviations in the 60-Hz

system frequency of as little as tens of millihertz, represent large imbalances between load andgeneration, so the frequency does not normally change that much. In reality, this tight frequencycontrol is more an artifact of the large size of the national electric grid and physical needs incontrolling it, as opposed to concerns over damage to connected loads, which can tolerate muchlarger variations.

In considering the impact of DR on the power system voltage and frequency, it should berecognized that DR has a greater impact on the system voltage than it does the frequency(at current, low-penetration levels for DR). This is because it can locally change the voltagewhere it is applied without having to change the voltage across the entirepower system.Whereas, to change the system frequency requires a system-wide impact and so the capacity of

the DR needs to be significant relative to the total system capacity. The largest individual DRunits (10-50 MW) are still less than 0.01 percent of eastern or western U.S. area generation, andso any single DR does not significantly impact frequency.

If the output of all DR units currently connected on the system were coordinated to raise or lowerthe system frequency, then the impact could be noticeable, but even here it would still not be thatgreat because aggregate DR penetration on these systems is under 5 percent. In the future, if DRpenetration were to increase to 10 percent or beyond, then frequency impacts could become anissue and utility companies will need to carefully model the impacts of DR generation on thesystem frequency. Some of the safeguards currently employed to protect the distribution system(anti-island controls) may actually destabilize system frequency once the DR reaches a

significant penetration level. While, this is not an issue now except for smaller power systems, in10 years it could become an issue.

On smaller bulk systems, such as geographically islanded power systems and other isolatedlocations, DR aggregate capacity with respect to system generation has in some cases alreadybecome large enough to significantly impact frequency, and problems have occurred on suchsystems. Fluctuating outputs from wind generation plants and other sources can push thefrequency outside of appropriate limits unless the proper feedback control from generation is

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used to stabilize the frequency. Studies are performed to assess the worst-case conditions offrequency change and implement the appropriate DR limits and/or system upgrades to preventproblems.

The condition where DR has the greatest influence on frequency is where it is operating as an

island in itself. It then has complete control over the system frequency. If DR is to operate as anisland, then it must be able to maintain relatively stable frequency. The frequency conditionsneeded for proper operation of loads would vary depending on the type of loads and applications.However, it does not need to be as tightly controlled as the bulk power system and frequencywithin 2 percent of nominal frequency should ordinarily be adequate for islanded DRoperation.

Many loads are capable of operating with even broader frequency excursions. Directmanipulation of the synchronous generator inputsmechanical torque and field current appliedto the rotoris the primary method of controlling

Integrating Distributed Resource

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