Interconnection Guidelines for Distributed...

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Interconnection Guidelines for Distributed Generation

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Roger Dugan

Robert Zavadil

David Van Holde, Project Director

August 2002

E SOURCE & Electrotek Concepts

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TABLE OF CONTENTS Acknowledgments i

About the Authors ii

Executive Summary 1

1. Introduction 3

2. Utility Distribution System Design 5

2.1 Steady-State Operation/Voltage Regulation 5

2.2 Overcurrent Protection 7

2.3 Planning and Economics 12

3. DR Interconnection Technologies 20

3.1 DG Models for Power System Studies 20

3.2 Characteristics of DG Interface Technologies: Rotating Machines 21

3.3 Characteristics of DG Interface Technologies: Static Power Converters 30

4. Interconnection Requirements 37

4.1 General Protection Requirements 37

4.2 Protection of the DR/EPS Interface 42

4.3 Effect on Transformer Connections 48

5. Power Quality and Reliability 56

5.1 Voltage Regulation Issues 56

5.2 Impact on Utility Overcurrent Protection 61

5.3 Improving Reliability with DR 67

5.4 Adverse Impacts of DR on Utility Reliability 76

5.5 Harmonics from DR 79

6. Application Problems 82

6.1 Voltage Change upon Interconnection or Reclose After a Fault 82

6.2 Harmonic Surprise with Rotation Machines 84

6.3 Desensitizing Utility Relays 86

6.4 Coordinating with Reclosing 89

6.5 Ferroresonance 90

6.6 Capacitor Switching 94

7. Engineering Analysis of DR Interconnection 97

7.1 Basic Power Flow 97

7.2 Fault Studies 110

7.3 Dynamics 116

7.4 Electromagnetic Transients 122

Notes 125

INTERCONNECTION GUIDELINES FOR DISTRIBUTED GENERATION

Distribution outside sponsoring organization prohibited. ii

Acknowledgments

We would like to thank the following people who provided advice, reviewed the

material, and made other contributions to this study:

Bryan Gernet Arizona Public Service

Ronald Onate Arizona Public Service

Mike Doyle Oncor

Scott Castelaz Encorp


Distribution outside sponsoring organization prohibited. ii

About the Authors David Van Holde, PE, is director of the E SOURCE Distributed Energy Service. Formerly a Senior Energy Analyst for Seattle City Light, David managed the utility’s commercial and industrial multiresource audit program. He also led the provider’s Distributed Generation Task Force, investigating trends, testing technologies, and making policy recommendations to utility management on DG. Task Force achievements included development and implementation of City Light’s Net Metering Program, participation in a fuel cell pilot, and installation of a microturbine, as well as evaluation of several large photovoltaic installations proposed in Seattle. In addition, David managed utility sponsorship of a major retrofit of Seattle Public Schools’ lighting and fan systems that resulted in savings of more than 17 million kilowatt-hours per year. He has had extensive experience with industrial and commercial energy analysis and engineering, training, and report preparation. David holds a BEME from Pratt Institute and an MS in mechanical engineering from Oregon State University, both with emphasis in energy engineering; his master’s thesis focused on institutional cogeneration.

Roger C. Dugan is a senior consultant for Electrotek Concepts Inc., Knoxville, Tennessee. He has more than 30 years’ experience in the power industry, much of which has been devoted to distribution system analysis. He has been working on issues related to distributed resources (DR) interconnection with utility distribution systems for more than 20 years. In recent years, he has been developing software and training materials for helping utility distribution engineers include DR in the planning process. He is the coauthor of Electric Power Systems Quality (McGraw-Hill) and is a Fellow of the IEEE.

Robert Zavadil is marketing manager and senior consultant for Electrotek Concepts Inc. He has more than 20 years of experience in the power industry, including 13 years with Electrotek and 7 years with Nebraska Public Power District. At Electrotek, he has consulted for a variety of clients in electric power quality, distributed photovoltaic applications, wind energy, and other forms of distributed generation. At Nebraska Public Power District he was a staff engineer in the Protection and Control and Substation Engineering departments and performed technical studies related to transmission and distribution system protection, power quality, and grounding. He is a member of the IEEE.

Editorial services: Gail Reitenbach


Distribution outside sponsoring organization prohibited. 1

Executive Summary

Most electric distribution systems are designed and operated on the premise of there

being a single source of electrical potential on each distribution feeder at any given

time. Distributed resources (DR) violate this basic assumption. Although most

experts agree that distribution systems can safely accommodate a few modestly sized

DR units, the possible effects of connecting large amounts is a source of major

concern to utility engineers, and many question the value of DR to the utility.

Unfortunately, until this guidebook’s publication, there is a dearth of practical

information for utility engineers to help them understand and deal with DR as it

becomes more common. This guidebook compiles current engineering practice for

assessing and mitigating DR impacts on electrical distribution systems and overviews

some methods used to assess the costs and benefits of interconnection.

A review of the pertinent elements of utility system design, focused on protection,

and distribution planning and economics applied to the costs and benefits of DR in a

distribution system provides background to the rest of this guide. An electrical

engineering overview of the dominant DR technologies as they affect the electrical

power system is provided, followed by common DR interconnection technologies

and interconnection requirements. These are directly related to the Institute of

Electrical and Electronics Engineers Draft Standard for Interconnecting Distributed

Resources with Electric Power Systems (IEEE P1547). These requirements are

explained and expanded with examples of simple and complex DR interface

protection schemes. Effects of various interconnection transformers on the protection

and performance of both the DR and the utility distribution systems are reviewed in

detail.

Power quality and reliability impacts of DR are considered generally and via specific

application examples, with mitigation strategies where DR may negatively impact the

distribution system, as well as applications where DR will support customers or

utilities.

An engineering analysis of DR interconnection completes the guidebook, offering

utility distribution engineers an understanding both of how DR elements can be

incorporated into their common systems analysis toolbox and also when and how

more sophisticated dynamic and transient analysis may be needed.



1. Introduction

As is frequently pointed out, distributed generation (DG) is not a new idea. The

earliest electric generation equipment was distributed, that is, located very close to

the electric loads designated to use the power they generated. This situation,

however, was of necessity rather than choice, because there was no electric utility

distribution infrastructure to interconnect with. Rapid acceptance of electric energy

begat a booming industry, and the race to build ever-larger generating units and

higher-voltage transmission networks dominated the business of the electric utility

industry for the better part of the 20th century.

As the great leaps in central generating unit size and efficiency began to get smaller

and the oil shocks of the 1970s increased attention on and scrutiny of the electric

energy infrastructure, interest in distributed generation was renewed. This time,

however, it was apparent that the preferred mode of operation for small, modular

electric power sources would be in parallel with the existing electric distribution

system. In this “best of both worlds” scenario, the unique values of DG technology—

such as environmental friendliness, fuel price stability, and transmission and

distribution savings—could be realized without sacrificing the stability and security

of the normal utility supply.

More than two decades of serious research and investigation have gone into

identifying and understanding the myriad technical issues associated with

nonnegligible amounts of generation connected to utility distribution systems. Much

light has been shed on the potential technical impacts that distributed generation can

have on distribution system design, operation, and protection. At the same time, DG

technology has become more sophisticated and capable, giving hope for the eventual

resolution of some of the more difficult integration aspects. At the core, however, the

fundamental technical problem remains the same: A vast proportion of the installed

electrical distribution plant in the U.S. was designed and is operated on the

presumption of a single source of electric potential at any instant in time. Distributed

generation obviously violates that premise and, at some capacity level, will

influence—degrade under many circumstances—the reliability, performance, and

possibly safety of any utility distribution feeder.

The popularity of the concept of using distributed generation for electric power

systems of the future increased substantially in the latter part of the 1990s. Growing

awareness at the public policy level has become a major driver. This most recent

groundswell is leading to mandates for streamlining the evaluation process for

approval to interconnect distributed generation with the utility distribution system.

Such policy shifts are happening in spite of the fact that much of what has been



learned technically about DG’s effects on the distribution system has not been

validated with field experience and has yet to make its way into conventional

distribution system engineering practice.

Work to establish a common technical understanding between utility engineers, DG

equipment vendors, and users has been under way. The most notable of these efforts

is the standards development initiative within the IEEE Power Engineering Society.

IEEE P1547 is a standards working group charged with the development of an

interconnect guideline for distributed generation. Although it was not approved at

the writing of this guide, prospective IEEE Standard 1547 is expected to establish

important benchmarks for the performance of DG equipment. For utility engineers

and equipment designers alike, it promises to increase their understanding of the

operational and behavioral characteristics necessary for the successful integration of

distributed generation with distribution system operations.

IEEE Standard 1547 will be a good and necessary first step. Almost by its own

admission, however, it is just that, a first step. Distribution system design is too

diverse, distribution company practices and policies too varied, and the range of

scenarios for distributed generation too broad to be covered comprehensively by a

single guideline. For distributed generation to become widespread, distribution

engineering practice itself must evolve so that system performance, reliability, and

safety can be maintained in the face of the technical challenges posed by distributed

generation.

This guide is intended to be an engineering manual to complement the technical

issues covered in the prospective IEEE Standard 1547. It is aimed at practicing

distribution system engineers and is intended to provide guidance and direction on

how to conduct important distribution engineering analyses with distributed

generation in the picture. For reasons previously mentioned, there is no single

“answer” as to how much distributed generation can be accommodated without

compromising performance, reliability, or safety. The real answer is specific to the

location of distributed resources within the utility’s power system and is the result of

appropriate engineering analysis. In this guide, these analyses are illustrated with

examples and case studies, with the intent of providing readers with the appropriate

technical understanding and perspective to better understand their own specific

problems.

In the PDF file of this report that is posted on the study Web site, the figures printed

here in grayscale appear in color, which will facilitate interpretation of the more

detailed graphics.



2. Utility Distribution System Design

This chapter provides important background to the basic design philosophies for

common distribution system assets and covers these critical areas:

■ Steady-state operation and voltage regulation,

■ Overcurrent and overvoltage protection, and

■ Planning and economics.

Because the effects of distributed generation (DG) on these aspects of system design

and performance are covered in the following chapters, only the fundamentals of DG

impacts are covered here.

The design of utility distribution systems is a compromise between cost and

reliability that’s intended to achieve the maximum possible reliability at an acceptable

cost. The design is also based on delivering power from the transmission grid to the

end user by “wires” (lines, transformers, and so on) that do not have moving parts.

2.1 Steady-State Operation/Voltage Regulation

During normal steady-state operation of the utility system, the primary emphasis is

on delivering power to the end user continuously at a satisfactory voltage magnitude.

This is typically within the range of ±5 percent of nominal rated voltage on the

distribution system.

The voltage is also expected to be relatively free of distortion. A total harmonic

distortion of 5 percent is typically the maximum allowed, with no single harmonic

exceeding 3 percent.1

Utilities employ several kinds of devices to help regulate voltage. Several of these are

shown in Figure 1 and are described here:

■ Substation load-tap changer (or on-load tap changer, LTC). Nearly all substation transformers have taps in the windings to adjust the voltage. Some have only no-load tap changers (NLTC), which requires the transformer to be de-energized or unloaded to change the tap. However, most have LTCs that can change tap under load to adjust the voltage. The typical tap range is ±10 percent, although wider ranges are available.

■ Line regulator (also called a “step voltage regulator” or “booster”). This is a tap-changing autotransformer with local control intelligence. Regulators are added to longer feeders when it is no longer possible to maintain acceptable voltages by means of substation LTC and switched capacitors.



■ Switched shunt capacitors. As the load grows on a feeder, the voltage profile along the feeder begins to sag. Capacitors are generally the first type of device a utility will add to the feeder to correct for this. They are usually the least expensive of the options for correcting for the effects of load current and have the added benefit of reducing the losses and freeing up line capacity. Though line regulators can boost the voltage, they do not significantly alter the loading.

Substation LTCs and line regulators behave similarly. They most commonly have 16

steps of raise (boost) taps and 16 steps of lower (buck) taps of 5/8 percent each.

Thus, they are frequently called “32-step” regulators. Modern controls are

microprocessor-based and have a wide variety of control options. In a typical

application, when the voltage goes out of band for a predetermined time delay

ranging from 15 to 45 seconds, the tap will change at a rate of about one tap every 2

seconds until the voltage is satisfactorily back within band. This is sufficiently fast for

the vast majority of load cycles experienced on a distribution feeder, although rapidly

changing loads may call for additional measures. Given the normal variation of load

on a feeder, a maximum of a dozen or so tap changes per day are expected. Excessive

numbers of tap changes can dramatically reduce the life of the LTC or regulator.

Figure 1: Voltage regulation system on a radial distribution feeder

In the U.S., LTCs are three-phase tap changers with one control for all three phases,

whereas line regulators are usually single-phase autotransformers with individual

controls for each phase. Regulators are normally installed in three-phase banks, but

they may also be installed in other connections, such as open-delta, which requires

only two regulators for a three-phase load. Regulators are also applied on longer

PRIMARYDISTRIBUTION

FEEDERS

SUBSTATIONLTC

TRANSMISSIONSYSTEM

FEEDER BREAKEROR RECLOSER

LINE REGULATOR

SWITCHED SHUNTCAPACITORS



single-phase laterals. Some models allow all three phases to be ganged so that the

three phases operate together from one control.

Although it may seem that having three independently controlled autotransformers

would contribute to voltage unbalance, it often accomplishes better phase balance.

Distribution lines are typically constructed in an unbalanced configuration, and there

are many single-phase loads. This naturally leads to unbalance in the system. Single-

phase voltage regulators can actually compensate for some of the unbalance in the

voltage.

Some regulator controls can bypass the initial time delay if the voltage goes

sufficiently far out of band. Then the device proceeds directly into the 2-second tap

change sequence.

Typically, capacitor banks are sized in increments of 300 kilovolt amperes reactive

(kVAR) with typically no more than 2,400 kVAR in one location unless there is a

large load. An average size would be between 600 and 1,200 kVAR. Switching in a

capacitor bank would typically boost the voltage by 2 to 3 percent. Capacitors are

switched only once or twice per day. Controls usually rely on local measurements of

voltage, current, or volt amperes reactive (VAR). Many capacitors are simply

controlled by a time clock and switch at the same time each day.

It is important to have a basic understanding of how utility voltage regulation is

accomplished, because there are possible interactions between these devices and

distributed generation. Conflicts can arise when the generation either attempts to

regulate the voltage in opposition to the utility devices or the generation changes too

rapidly for the standard voltage regulation equipment to respond.

2.2 Overcurrent Protection

The structure of utility transmission and distribution systems is strongly influenced

by the needs of overcurrent protection. Faults (short circuits) are inevitable. Any

given system can be expected to suffer several faults each year. The number will

depend on exposure to lightning and trees as well as the age of the system’s

components. There is a wide range in this number. Some feeders will average less

than 1 interruption per year, while others might have more than 25.

When the short circuit occurs, the fault current must be interrupted quickly to

minimize damage so that electricity service can be promptly restored.

The number of breakers, or other fault interrupters, that must operate to clear the

fault depends on the design of the system. Transmission systems generally consist of

a highly meshed network of lines that interconnect numerous sources of power.



Transmission lines usually have fault interrupters at both ends. When a fault occurs

in a line, both interrupters must operate as shown in Figure 2, because the fault

current could be supplied from either end.

One advantage of transmission system protection is that it readily accepts new

generation. Also, generation directly connected to the transmission system tends to

be large, which makes interconnection cost less of an issue. An excellent protection

system represents only a minor portion of the entire generator system cost. In

contrast, this document concentrates on smaller generation connected to distribution

systems where interconnection cost is a significant portion of the total installation

cost.

In contrast with transmission systems, most distribution systems have been designed

with the assumption that the fault current contribution can come from only one

direction. There are two basic designs of distribution systems: radial systems and low-

voltage secondary networks. The design of each of these has been strongly influenced

by economics and simplicity of operation. There are many more distribution circuits

than transmission circuits, and the cost of protection is an extremely important factor

in distribution planning. Each feeder consists of numerous sections, and it is not

economically feasible to place fault interrupters at both ends of each section to better

accommodate distributed resources (DR). Therefore, DR installations must adapt to

the behavior of existing protection systems.

Figure 2: Clearing a fault on the transmission system

Radial System Protection

Radial systems usually cost the least to build. Their protection consists of a number

of overcurrent devices in series. Ideally, only one of these devices has to operate to

clear a fault—the nearest upline device. Customers on unaffected sections of the

Both Breakers

Must Operate

Fault



feeder remain in service. Although this is the basic way the system operates, utilities

have added some relatively complex behaviors to some of the protective elements to

improve reliability.

The fundamental element is the fuse, which is the last element in the series of

overcurrent devices. Typical feeders have a breaker or recloser at the head followed by

a main three-phase feeder section (Figure 3). There may be one or more line reclosers

on the feeder if the main breaker cannot sense a fault all the way to the end of the

feeder. Fuses are the last line of defense. Many of the lateral taps off the main feeder

will be fused to minimize the impact of faults on those taps. Otherwise, the main

feeder must be interrupted to clear the fault. These lateral tap fuses are a source of

conflict with DR interconnected to the distribution system. It is generally bad

practice to have single-phase fault interrupters between three-phase generators and

the nearest upline three-phase fault interrupter. Such practice results in too many

opportunities to single-phase the generator. Thus, fuses and single-phase reclosers are

not recommended upline from a three-phase generator.

The mechanical fault interrupters (breakers and reclosers) are designed to coordinate

with the fuse and have a time-current characteristic (TCC) of approximately the

same shape. To achieve coordination for permanent faults, the devices nominally

operate slower as one progresses upline toward the substation. However, readers

should be aware that there are notable exceptions to this rule, as utilities have applied

numerous techniques for improving the performance of radial distribution feeders

over the years.

Figure 3: Radial distribution feeder overcurrent protection scheme

There is also another class of mechanical device found on many feeders: the

sectionalizer. Sectionalizers do not have a TCC curve and do not interrupt fault

PRIMARYDISTRIBUTION

FEEDERS

SUBSTATION

TRANSMISSIONSYSTEM

BREAKER ORRECLOSER

LINE RECLOSER

SECTIONALIZER

FUSED LATERAL



current. Instead, they have built-in intelligence to observe the behavior of the upline

recloser and isolate the faulted section after the interruption has occurred. They can

be either three-phase or single-phase. As with fuses, it is generally undesirable to have

single-phase sectionalizers upline from three-phase generators because of the single-

phasing issue.

The current must be interrupted to clear the fault. The radial system protection

expects fault current from only one direction and assumes the current can be

interrupted by operating one device. Therefore, any distributed resource on a radial

feeder must disconnect to permit the feeder protective devices to go through their

normal fault-clearing sequence.

Many faults on the system are temporary. Therefore, automatic reclosing of breakers

and reclosers is a nearly universal utility practice. Breakers and reclosers typically

make two to four attempts to clear the fault. Because most faults are temporary,

many breakers and reclosers are set to operate once or twice very quickly in an

attempt to save the lateral fuses so that a line crew does not have to be dispatched to

restore service.

Some of the conflicts with distributed resources that one might expect in the

protection scheme shown in Figure 3 include these:

■ DR infeed into the fault prevents the fault from clearing in the expected time.

■ DR infeed desensitizes the overcurrent devices so that they no longer detect all the faults as promptly as they would otherwise.

■ DR infeed may prevent the possibility of saving lateral fuses on temporary faults.

■ Fuses and single-phase reclosers and sectionalizers may have to be removed or replaced with three-phase switchgear.

■ Reclose intervals may have to be extended to ensure that the distributed resource has properly disconnected.

Each of these conflicts yields either higher interconnection costs or results in some

reduction in distribution system reliability.

Secondary Network Protection

The other major class of distribution design is depicted in Figure 4. Typically, there

are a number of feeders from the same substation supplying power to a low-voltage

secondary network in a downtown area or in an office complex. Single-facility

networks are commonly known as “spot networks.” The purpose of this design is to



achieve very high reliability, and it is more expensive to build than the simple radial

system. The system is designed to take at least one fault on any of the primary feeders

without interrupting power to any of the customers served from the low-voltage

network. Interruptions are expected only when there is a major transmission failure.

Some network systems are designed to sustain two failures on the primary

distribution feeders.

Figure 4: Protection for a low-voltage secondary network system

SUBSTATION

TRANSMISSIONSYSTEM

FEEDER BREAKEROR RECLOSER

THESE DEVICESMUST OPERATE

FAULT

LOW-VOLTAGE NETWORK

NETWORKPROTECTOR

PRIMARY FEEDERS

In the design depicted in Figure 4, there are four primary voltage feeders serving the

network. Network transformers are spaced periodically along these feeders,

transferring power from the primary feeders to the low-voltage network. Each

network transformer is paired with a special fault interrupter called a “network

protector.” The network is an extensively meshed system of wires interconnecting the

loads. Ideally, each load point would have at least two network lines feeding it so that

service would continue if one failed.

In the U.S. there are two popular voltages for secondary networks: 480 volt (V) and

120/208 V.

The secondary network interconnects all the feeders. Therefore, when a fault occurs

on one feeder, current will be fed back through the network from the other feeders,

as shown in Figure 4. Not only must the feeder breaker operate, but all the network

protectors connected to the faulted feeder must open to interrupt all contributions to

the fault.



To accomplish this automatically, network protectors are relayed to trip on reverse

power on the presumption that the only time power would flow opposite the normal

direction is when there is a fault on the primary distribution feeder. To prevent

energizing the network transformer from the secondary, these relays may be set to be

very sensitive, and it takes very little reverse power to trip the network protector. This

is the source of the chief difficulty in applying distributed resources on secondary

networks and limits the maximum DR capacity to a fraction of the minimum load. If

there is a net export of power from the network, even for an instant, all of the

network protectors can be tripped, which defeats the main purpose for having such a

network.

Some networks must be arranged so that the load is distributed among the primary

feeders to achieve a satisfactory voltage balance between the feeders. Otherwise, some

network protectors would trip during normal operation or minor system

disturbances. The introduction of distributed resources into the network could

change the load profile within the network such that the voltage balance between the

feeders is adversely affected. This would increase the number of inadvertent network

protector operations.

2.3 Planning and Economics

Much of the economic benefit of distributed resources is realized when the DR is

installed for end-use applications. Factories with high-value products will find

backup power attractive, and it may be possible to economically interconnect that

generation for the mutual benefit of the utility and the end user. Backup generation

might be operated at peak demand times to help utilities cover contingencies until

such time as the utility makes an investment in additional wire capacity. If the

arrangement has sufficient economic merit and the generation proves reliable, the

utility may defer transmission and distribution (T&D) expenditures indefinitely.

Another area in which there are quite favorable economics on the end-use side is

combined heat and power (CHP). Many commercial and industrial sites have

thermal loads as well as electrical loads and are consuming natural gas or some other

fuel to supply their thermal needs. These facilities can benefit economically from

CHP applications that use waste heat from the electricity generation process to satisfy

the thermal demand, with resultant high net efficiency. CHP applications are often

interconnected with the utility system at least part of the day.

Where is the potential benefit of DR to utilities? How can planning engineers

determine if and when DR might be an economical solution to a planning problem?

This issue is one on which an entire book can be written. Here we will make some

basic suggestions for how to go about making the evaluation. Figure 5 shows a



multilevel screening process for evaluating a DR application for utility distribution

planning.2

Figure 5: Four-step progressive screen for planning with distributed resources

The first level is strictly performed using economics. The marginal cost of

implementing T&D upgrade (“wires”) solutions is compared against the marginal

cost of DR technologies. This screens out many possibilities quickly. Besides

investment costs, value-of-service indicators can be used as well as measures of costs

associated with wholesale power price volatility. As we move down the process, the

analysis gets increasingly specific. The second level is a more detailed economic

screen that includes some simulations of the electrical system in moderate detail. This

takes a closer look at how proposed DR solutions might yield economic benefit.

From the utility perspective, often only the lowest-cost technologies—diesel gensets

or combustion turbines—are attractive after passing through these two screens.

Higher-cost technologies may still be attractive to an end user, and the utility may

choose to partially subsidize particular applications that provide benefit. However,

the utility must be careful not to pay more than the marginal costs identified in these

two screens for lower-cost alternatives. The third level takes a look at the DR

candidates that survive the previous screens and ranks them from the engineering

perspective. At the bottom level, a candidate DR solution has been selected and

requirements for interconnection and operation are determined. This is the only step

in the process familiar to many utility distribution engineers. However, several

interesting things occur before deciding to install DR.

One process that can include DR and that is effective for the middle two screening

levels is depicted in Figure 6. The cycle begins with a system model that is built from

the data describing the impedances, loads, and so on. The system is simulated with

T&D Marginal Cost Screen

High-Level Feasibility Screen

Engineering Screen

Implementation Studies

T&D Marginal Cost Screen

High-Level Feasibility Screen

Engineering Screen

Implementation Studies



various issues contributing to the development of cost functions. Simulations are

carried out over several years with assumed load growth characteristics.

The basic idea is to start with the so-called “do nothing” case. Any proposed solution

that is an economic improvement to operation of the present system should have a

lower cost than the do nothing case. This is one way to screen out plans that are too

costly. The planner selects options from the menu shown and adjusts the system

model to reflect those changes.

Figure 6: Planning cycle for including DR in distribution planning

System ModelOperatingSimulations

Costing

SystemData T&D Expansion

Investment Plans

DecisionInformation

Start with Do-Nothing Case

EnergyLossesDG Energy, HoursEnergy above capacityPQ Indicesetc.

$$

Options:SubstationsFeedersDGDSMDA

Load,GrowthCharac-teristics

CostData

DR is simply another item on the menu that includes the traditional solutions of

new substations and feeders. Demand-side management (DSM) and distribution

automation (DA) can be treated similarly as long as their impact on the system

model can be represented. Simulations and costs are repeated for each proposed

solution. Theoretically, this process will expose the most economical plan to solve the

capacity problem and also indicate when it would be best to make the proposed

investment(s).

One of the key problems hampering planners with respect to DR is a lack of

planning experience. Most utilities have decades of experience with substations and

feeder expansions. Rules have been established, either formally or informally, that

generally come close to delivering the best solution considering these options. But

how does one make rules without the experience? The main idea is to come up with

better simulations that more accurately represent the costs involved.

Figure 7 illustrates, in a very simplified way, how to use cost functions generated

from simulations to make investment decisions. Operating costs are computed for

each year considering the issues of interest (such as losses and reliability costs). When



the present value of the operating cost crosses the present value cost of an investment

option, it should be economical to invest in that option at that time. In the context

of distributed resources, Option 1 is usually an expensive “wires” solution consisting

of a new substation or feeders. Option 2 is an incremental solution such as DR that

costs less, at least initially. Displaying the cost functions in this manner gives a better

idea of when it might be more economical to invest in the incremental solution than

the large-capacity solution.

Figure 7: Cost functions can indicate when an investment should be made

Year

Pre

sent

Val

ue, $

High Growth Scenario

Low-Growth Scenario

Investment Option 1

Investment Option 2

Capacity Exceeded

Peak Planning

Assumed Cost

Traditional distribution planning methods have considered only peak power

capacity. When that capacity is exceeded, the cost function implicitly turns upward

sharply, justifying investment in either of the two options in that year. However, this

approach does not give any indication of when an incremental solution might be

better than the traditional wires solution. Growth must be considered to make this

distinction.

The planner should consider a set of three to five growth scenarios. This set typically

would consist of the expected growth rate and one or two reasonable scenarios on

either side of the expected rate. Generally, the higher the growth rate, the more likely

the wires solution will appear favorable. If the growth rate is relatively low, or the

constraint is only for a small portion of the load, the incremental solution is favored.

The incremental solution is also favored when growth is uncertain. For example,

utilities commonly lease gensets to cover contingency conditions until load growth is

more certain.

One issue that arises is how to measure reliability and apply a cost to it. There are

probably as many ways to do this as there are planners doing it. Electrotek Concepts

has settled on a method that incorporates ideas used by distribution planners for

more traditional peak capacity planning and for measuring reliability by computing

the expected unserved energy (EUE). Once an EUE number has been derived, a cost

can be applied based on the value of electricity to end users when it is unavailable.



Figure 8 illustrates some of the basic concepts. Two limits are established for line and

transformer loading as well as for voltage limits: the normal limit and the maximum,

or emergency, limit. This is similar to what many planners do for power flow studies.

Then the energy served in excess of these limits is accumulated as the daily and

annual load cycles are simulated. The energy exceeding the maximum limit

represents the amount of load that must be curtailed to keep the system viable and is

termed the “unserved” energy.

The normal limit may be used for a variety of purposes in the planning process.

Many planners simply use this limit to trigger planning studies, knowing there is still

excess capacity left in the system. For DR studies, the normal limit is often set to

represent the maximum amount of power that can be backed up to an alternate feed

in case of a contingency. Thus, the energy exceeding the normal limit represents the

load that is at risk of being unserved if there is a contingency. This is a particularly

useful value when evaluating the use of peaking and backup DR to cover

contingencies.

The normal limit can also be used as a measure of the capacity remaining in the

system. It can be used to help differentiate between proposed sites for distributed

generation in which the impact on lightly loaded lines is ignored. One would set the

limit at a value that is frequently exceeded during annual operation so that some

reasonable resolution can be achieved to compare different alternatives. For example,

one could set the normal rating at 50 percent of the maximum. Then only the lines

that are loaded in excess of 50 percent would have an impact on the decision. All

other lines are ignored. One computes the energy exceeding this limit for each

competing alternative. The one with the lowest value is likely to be the site giving the

most long-term benefit to the utility for the given circuit configuration. The absolute

value of the result is not necessarily useful by itself, but the value relative to that of

other options is useful. If one attempted to use the maximum limit for this analysis,

there would be less resolution in the comparative results because the maximum limit

would seldom, if ever, be exceeded for some of the options.



Figure 8: Basic concept for establishing limits for computing costs related to system capacity limits

One useful way to display the energy values computed in this method is shown in

Figure 9, which shows the shape of the overloads over a year. It is also the shape of

the DR dispatch required, if needed, to maintain capacity margins so that load would

not have to be curtailed. This figure shows a typical summer peaking system that

suffers its main capacity constraints during afternoons in July. There are also smaller

periods of overload in June and August. This particular constraint can be met with a

base of at least 500 kilowatts (kW) of DR and can be completely covered with 2,500

kW. This suggests DR solutions such as

■ Leasing up to 2,500 kW of portable generators for the summer months.

■ Offering capacity credits to customers to make their backup generation available to the utility by either transferring load or interconnecting with the distribution system.

■ Stepping up DSM efforts to reduce the summer peak.

PO

WE

R

Maximum Limit

Normal Limit

Energy at risk ofbeing unserved

Unserved Energy



Figure 9: Plot of load exceeding limits (also shape required from DR to maintain margins)

1

5

9

13

17

21

Jan Apr Ju

l

Oct

0

10000

20000

30000

40000

50000

60000

70000

80000

kWh

Hour

Month

The typical outcomes of a planning study involving DR for use to support the utility

distribution system are shown in Figure 10. This chart compares the present value

(PV) cost for various investment scenarios. The top part of the chart shows the

timing of the proposed capital investment in substations and feeders. The bottom

half of the chart shows the cost functions for three load growth scenarios: high,

expected, and low. The investment was originally planned for implementation as

soon as the load exceeded the peak capacity. Usually, this means that the system

cannot be expected to supply the load for the expected worst-case contingency. For

the expected growth scenario, the investment may be deferred from its original date

for a period of time by using distributed generation to cover the contingency. The

period of deferral depends on actual growth rates but is commonly two to three

years. This results in substantial savings, indicated by the shorter bar for deferred

cost.

If the load growth is higher than expected, the DR plan is more costly, and deferral

of the T&D investment is not economical. However, if the actual growth rate turns

out to be much lower than expected, distributed resources may be used to cover the

overloads indefinitely, eliminating the need for the T&D investment for the



planning period. This is one illustration of the value of using DR as a hedge against

uncertainty in cases where T&D investment is marginally economic.

Figure 10: Present value (PV) cost comparison for various investment scenarios (capital investment deferred by distributed generation is dependent on load growth)

PVCOST

TIME

T&D Capital Investment Timing

PVCOST

TIME

DG HighGrowth

DG ExpectedGrowth

DG LowGrowth

Annualized Costof Alternatives

T&D Plan

No DGDeferred by DG(expected growth)



3. DR Interconnection Technologies

The range and diversity of distributed generation (DG) technologies is large relative

to the much more familiar technology of central station electric generation plants. A

variety of fuels and prime movers are used—from the radiant energy of the sun with

photovoltaic modules, to chemical reactions in fuel cells, to conventional diesel or

natural gas–engines and gas turbines. For purposes of this guide, however, the energy

conversion process is not of primary importance to evaluations of how DG

installations affect the performance of distribution systems to which they are

connected.

Despite the wide range of technologies and energy-conversion processes found in DG

technology, as pertains to the interface with the external electric power system,

distributed resources (DR) come in two major types: rotating electric machines and

static electrical power inverters. For purposes of electric power system analyses, it is

the behavior of this last stage of the conversion process—from whatever form to AC

electric energy compatible in voltage, frequency, and phase angle with the external

electric power system—that is of primary importance.

Engineering evaluations of the “impacts” of an element that is to be connected to the

power system employ a range of analytical techniques; these techniques form the

basis for computer simulation or calculation routines that have become standard

practice for power system designers. The studies in which these tools are used allow

the engineer to “see the system” as it will behave or operate before the element is

actually installed. This is especially true for evaluations of DG interconnections,

because they would normally be conducted prior to actual installation or

commissioning of the unit in question.

As such, the ability to represent, or model, the distributed generator is a critical part

of the engineering evaluation process that has been successfully used for more than a

century to manage one of the most complex machines ever created—the

interconnected electric power system. In contrast with more conventional electric

generation equipment, DG technologies are generally not as well known or

understood, and many times they incorporate equipment or controls that are

unfamiliar to the utility engineering community. This section provides an overview

of the common interfaces for DG systems and discusses approaches for considering

such devices and equipment in analytical procedures.

3.1 DG Models for Power System Studies

The appropriate representation of an electric power system element is greatly

dependent on the purpose and objective of the analytical procedure. Representations



of the same element will vary depending on the type of analysis to be performed. In

evaluating the possible impacts of DG installations on distribution system

performance, the most common analyses consist of two general types of idealized

system models typically used in distribution system evaluation: power flow

calculations and short-circuit calculations.

Results of these basic analyses are used to evaluate a number of fundamental

distribution system performance aspects, including voltage regulation, thermal

capabilities/loading, protection system behavior, and delivery losses. Less frequently,

other studies may be necessary to evaluate technical issues such as harmonics, voltage

flicker, or dynamic response to disturbances on the power system.

3.2 Characteristics of DG Interface Technologies: Rotating Machines

Synchronous Generators

Synchronous generators are by far the most common device for converting kinetic

energy in a rotating shaft to electric energy. Electrically, synchronous machines

consist of a three-phase stationary winding (stator) connected to the three phases of

the power supply system and a winding on the rotor to which a source of DC

excitation is applied.

Volumes of technical papers and textbooks have been written on the principles of

synchronous generator control. There are two primary control mechanisms: the

speed governor on the prime mover driving the machine and the excitation control

system, which supplies DC potential to field winding and regulates field current.

Power control in a synchronous generator is the responsibility of the governor on the

prime mover. By changing the mechanical torque applied to the rotating system (for

example, by increasing steam flow to turbine blades), the speed of the system will

either increase or decrease, depending on the algebraic sign of the change. As it does,

the rotor of the synchronous generator either moves forward or backward relative to

the synchronously rotating stator field in the machine, which is fixed by the

frequency of the power system. The angle of synchronous generator rotor with

respect to the synchronously rotating stator field is called the “torque angle,” and for

a constant terminal voltage directly determines the real power flowing into or out of

the terminals. Because the generator must run in precise synchronicity with the

electric grid, changes in grid frequency will result in changes in real power output of

the distributed generator.

Reactive power output of a synchronous generator can be controlled by adjusting the

DC voltage applied to the field winding to affect a change in the field current.



To ensure system security and reliability in interconnected bulk power networks,

control mechanisms of individual large generators must be coordinated. Frequency-

sensitive governors with coordinated droop settings are used to assist with system

frequency regulation and to apportion incremental changes in load among various

generating units. Excitation control systems are tuned to ensure proper steady-state

voltage regulation and provide dynamic voltage support during disturbances for

system recovery. In smaller installations, as would be the case for distributed

generators, a wider variation in the control mechanisms and parameters is found,

because their individual impact on the grid would be small. Governors may be set to

regulate real power generation independent of system frequency variations, and

excitation controllers may utilize a constant power factor or reactive power reference

instead of bus voltage signal to control reactive power.

Modeling synchronous generators and the various auxiliary control equipment for

power system studies is a fairly well-developed art. In utility short-circuit

calculations, simplified generator models consisting of an internal voltage source in

series with an equivalent reactance are usually employed (Figure 11).

Figure 11: Simple synchronous machine model for steady-state (left) and short-circuit calculations (right)

In short-circuit calculations, the classical equivalent circuit consisting of an

equivalent voltage source behind internal reactance is typically used. The internal

machine voltage can be found by adding the voltage drop across the internal

synchronous reactance to the terminal voltage. For short-circuit calculations from

“flat” system conditions, however, this voltage is assumed to be 1.0 per unit. The

subtransient reactance Xd" replaces the synchronous reactance.

The simple synchronous generator model used in most utility short-circuit studies

leaves out some of the more intricate details of the terminal current under fault

conditions. The model is still appropriate for most studies, because transmission

system short circuits are fairly distant electrically from the terminals of any individual

Eg

Xd’’

I

Vt

+

-

Eg

Xs

I

Vt

+

-P, Q



generator. This may not be the case on distribution systems with distributed

generators, however.

Figure 12 illustrates some details of the contributions from an asynchronous

(induction) generator to a three-phase fault at its terminals. Immediately following

inception of the short-circuit, the current is characterized by a symmetrical value

related to the subtransient reactance Xd" plus a DC component, which is a function

of the precise point on the voltage wave where the fault begins (the DC offset will

vary by phase for a fault initiated simultaneously on all three phases). As the fault

progresses, the DC component decays and then vanishes. The symmetrical

component also decays, to the point where the magnitude now becomes a function

of the transient reactance of the generator, Xd’. The respective short-circuit time

constants Td" and Td’ govern the rates of decay for the symmetrical components,

while decay of the DC component is a function of the machine’s X/R ratio.

For faults not at the terminals, the time constants and effective impedances will be

modified by the characteristics of the equivalent electric circuit between the generator

and the fault.

Precise computation of short-circuit currents from synchronous generators is

complex and involved, especially in systems with multiple machines. Time-domain

computer simulation is the most straightforward method, but it requires a substantial

amount of data, and there are practical limits on the size of the system that can be

represented at this level of detail. Reasonable approximations of the symmetrical

contribution of synchronous generators to distribution system faults can usually be

obtained with the simple model.

Figure 12: Synchronous generator contribution to a three-phase short circuit at machine terminals

Detailed models (Figure 13) are routinely employed for transient and dynamic

stability simulations of large power systems with a variety of digital computer

12.5 MVA Synchronous Generator

Time (sec)

Contribution to Fault at Terminals

5.75 5.9 6.05 6.2 6.35 6.5

kA

-8

-6

-4

-2

+0

+2

+4

+6

+8SG Current

Contribution with Xd’

Contribution with Xd’’

dc component



programs. In these models, the generator, governor, excitation control, and

sometimes the prime mover (such as steam or gas turbine, boiler, or hydraulic

system) are represented by differential equations that are solved at successive

increments of time, along with the power flow equations for electric network to

which they are connected. It is not yet clear to what extent stability studies and

dynamic simulations will become necessary for distribution systems with distributed

generation.

Synchronous generators are normally considered to be linear devices, that is, the

voltages and currents generated are perfectly sinusoidal. This assumption is less

accurate for smaller machines for reasons associated with the distribution of the

individual windings in the slots of the machine stator. Under certain situations,

harmonics can be an issue with small rotating machines, although the degree of

distortion is much less than that associated with familiar nonlinear loads. Section 5

contains a description of some harmonic issues related to small rotating machinery.

Typical parameters for synchronous machines used in models like that shown in

Figure 13 are found in Table 1.



Figure 13: Detailed PSCAD/EMTDC synchronous machine model used for dynamic studies showing representation of mechanical system, excitation controller, and governor along with synchronous machine

Te

std

yC

V_I

NP

Wm

Tmech

VTIT 3

IfEfEf0

Vref

Exciter_(AC1A)

Tm

2

( Syn

cM/c

)M

ultim

ass

Te

Wra

dT

mT

mi

Tei

w

Wre

f

Cv

Ste

am G

ov

1

DG1

Ef0 Ef If VTIT

3

Tm0Tmw

w

Te

Tm

A

B

C

Exciter w/ voltage orpower factor feedback

Governor

rotating Mechanical Systemw/ prime mover energy input

Synchronous Generatorw/ stator, field, anddamper windings



Table 1: Typical equivalent circuit parameters for small synchronous generators (impedances in per unit)

.BDIJOF

7BMVF " # $ %

kVA 69 156 781 1044

kW 55 125 625 835

V 480 480 480 480

pf .80 .80 .80 .80

n(r/min) 1,800 1,800 1,800 1,800

H .329 .205 .500 .535

Xd 2.02 6.16 2.43 2.38

Xd’ .171 .347 .254 .264

Xd" .087 .291 .207 .201

Xq 1.06 2.49 1.12 1.10

Xq" .163 .503 .351 .376

τdo’ (s) .950 1.87 1.90 2.47

τdo" (s) .078 .013 .024 .018

τqo" (s) .045 .020 .016 .009

ra .011 .034 .017 .013

τa (s) .014 .022 .038 .032

X0 .038 .054 .051 .074

X2 .125 .375 .279 .260

IFD base (A) 9.5 5.6 16.75 16.2

SG (1.0) .46 .207 .164 .099

SG (1.2) 1.45 1.00 .625 .569

Induction Generators

Induction generators are essentially induction motors that are driven at speeds above

their nameplate synchronous speed by some prime mover. The machine consists of a



three-phase stationary winding connected to the three phases of the power supply—

much like that found in a synchronous machine—and a second assemblage of real or

virtual windings on the rotor. Wound-rotor induction machines have a three-phase

winding on the rotor structure that’s accessible externally via slip-ring connections.

In squirrel cage induction machines, by far the most common type, the rotor

windings are actually constituted by “bars” connected between two conductive rings,

one at each end of the rotor. The bars are physically embedded into the rotor

structure, resulting in a degree of robustness and reliability not found in other

electrical machines.

Because an induction machine has no field winding, the excitation necessary for

torque production and power flow must be drawn from the power supply system.

The electric current necessary for magnetizing the iron core is responsible for much

of the reactive power required by an induction machine.

Currents flowing in the rotor circuits are the other part of the torque-production

equation. Setting up these currents requires that a voltage be induced into the rotor

circuit. Relative motion—that is, a speed difference—between the rotor circuits and

the revolving magnetic field established by the stator windings, is the source of this

induced voltage. At synchronous speed, the relative motion between the rotor circuits

and the stator field is zero, and no voltage is induced in the rotor circuits. However,

if the rotor circuits move faster or slower than the synchronously rotating stator field,

voltages are induced that have a magnitude and frequency proportional to this speed

difference. Slip in an induction machine is a measure of this relative speed difference.

Under normal operating conditions, the slip varies in a nearly linear fashion with

load or generation. For example, in a machine rated for 2 percent slip at full load (or

generation), the slip value at 50 percent load (or generation) will be approximately 1

percent.

The variation of induction machine speed with torque provides for a much “softer”

coupling between the electric power system and the mechanical system driving the

machine. Induction generators also exhibit an inherent damping behavior for power

system disturbances. For example, if power system frequency increases—an

indication of generation in excess of load—this higher frequency actually reduces the

magnitude of slip in the induction generator, leading to a temporary reduction of

output—the exact remedy for high system frequency.

Reactive power is required by all induction machines and is normally drawn from the

supply system connected to the stator terminals. Even under no-load or no-

generation conditions, a substantial amount of reactive power is required by the



machine. Reactive power will then increase as the stator current increases (in either

generator or motor mode).

Shunt capacitor banks are typically used to improve the power factor of induction

motors and generators. Standard practice is to compensate for most or all of the no-

load reactive power with fixed capacitor banks (generally switched with large

induction machines and switched banks), which are staged on or off, depending on

the desired compensated power factor as the load or generation conditions in the

machine change.

When the source of excitation—the power supply system, in most cases—is removed

from an induction machine, the main flux field collapses and torque production or

power flow is no longer possible. It does take several cycles for this field to collapse,

however, during which time an induction machine will contribute current to a short

circuit on the power system. Also, if voltage is just reduced rather than removed

completely as the result of a downstream fault, the main flux will decay to some new

value but will provide necessary excitation for the machine to contribute to the fault.

Contributions from end-use induction motors are rarely considered in utility fault

studies, although they can be an important consideration for protective device

coordination and rating within some industrial facilities. The IEEE Brown Book

(Standard 399-1997) “IEEE Recommended Practice for Industrial and Commercial

Power Systems Analysis” details procedures for calculating induction motor and

generator contributions to short circuits within facilities. A similar approach can be

employed for DG installations employing induction generators, but the differences

between industrial protection equipment and those utilized for medium-voltage

utility feeders in terms of operating and clearing times and device coordination must

be taken into consideration.

The effect of a DG installation on distribution system fault currents is illustrated in

Figure 14. Here it is assumed that the fault location is downline from the point on

the radial feeder to which the distributed generator installation is connected. This

relatively large DG plant consists of ten 750-kW wind turbines that use line-

connected squirrel-cage induction generators. Initially, the short-circuit current

contributed by the induction generators is nearly a great as that from the feeder

source. It contains both a symmetrical and DC component. As the fault progresses,

the induction generator contribution decreases as the main flux in the machine

decays. By the time the fault is cleared, the contribution from the induction

generators has nearly vanished.

How induction generators in DG applications should be treated for short-circuit

calculations will depend on the relative size of the DG plants and the type of



equipment employed to protect the feeder. For larger induction machines, the time

constants for main flux decay will be longer, requiring them to be treated more like

conventional sources for short-circuit calculations. A simple model consisting of an

equivalent voltage source behind the leakage inductance of the machine (stator plus

rotor leakage inductance, Xs + Xr) would provide an adequate indication of the

impact on distribution system fault currents in the first several cycles. Typical

parameters for induction machines of various sizes are found in Table 2.

Figure 14: Induction generator contribution to three-phase fault on a distribution system

Table 2: Typical equivalent circuit parameters for induction machines

Time

Fault Currents (Phase A)

0.94 1.016 1.092 1.168 1.244 1.32 -4 -3 -2 -1 +0 +1 +2 +3 +4

Total Fault Current

System Contribution Induction Generator Contribution

Cur

rent

(kA

)

HPR1

(pu)R2

(pu)Xm (pu)

Xs (pu)

Xr (pu)

Xs + Xr (pu)

10 0.028 0.020 2.612 0.093 0.163 0.256

25 0.017 0.011 2.778 0.088 0.148 0.236

75 0.020 0.009 4.000 0.114 0.191 0.306

100 0.044 0.035 7.820 0.341 0.540 0.881

200 0.045 0.034 7.267 0.402 0.592 0.994

250 0.011 0.009 3.371 0.128 0.158 0.286

800 0.006 0.003 4.124 0.059 0.074 0.134

880 0.007 0.003 5.763 0.126 0.167 0.294

2400 0.005 0.000 6.728 0.124 0.178 0.302



3.3 Characteristics of DG Interface Technologies: Static Power Converters

Certain DG technologies produce electrical energy in a form not compatible with a

fixed-voltage, fixed-frequency AC power system. Static power converters are

increasingly employed to effect the required electrical conversion, either from DC or

variable voltage, variable-frequency alternating current. Somewhat of a novelty or

confined to a few niche applications only 25 years ago, power electronics technology

has advanced tremendously, with new semiconductor switching devices, control

techniques, and converter technologies now impacting nearly all aspects of electric

energy utilization.

From the power system perspective, there are two basic types of static power

converters: line-commutated and self-commutated. Only a decade ago, there might

have been some question regarding which basic type might be employed in a DG

application. However, today, the more advanced and capable self-commutated

equipment is used almost exclusively. For this reason, the focus of this section is on

these more advanced converters.

A modern static power converter utilizes power semiconductor devices (that is,

switches) that are capable of both controlled turn-on as well as turn-off. Further, the

device characteristics enable switch transitions to occur very rapidly relative to a

single cycle of 60-hertz (Hz) voltage—nominal switching frequencies of a couple to

several kilohertz (kHz) are typical. This rapid switching speed, in combination with

very powerful and inexpensive digital control, provides several advantages for DG

interface applications:

■ Low waveform distortion with little expensive passive filtering.

■ High-performance regulating capability.

■ High conversion efficiency.

■ Fast response to abnormal conditions, including disturbances such as short circuits on the power system.

■ Capability for reactive power control.

Some DG technologies, such as fuel cells and photovoltaic modules, use energy-

conversion processes that result in electric power in the form of direct current.

Microturbines and some types of variable-speed wind generation produce electric

power where both the voltage magnitude and frequency vary. Static power



conversion is used with all these technologies, with the specific configuration varying

somewhat according to the characteristics of the energy source (Figure 15).

In the case of DC sources, transformation to line-compatible electricity can be

accomplished with a single conversion stage, with a static power converter operating

in inverter mode (real power flow from DC to AC). When sources create something

other than DC electricity, additional stages can be used to first transform that supply

to DC.

Figure 15: Static power converter configurations used in DG technologies

The importance of this concept for interconnection considerations is that the static

power conversion stage that connects to the AC power system is quite similar,

regardless of the characteristics of the original source of electric energy in the DG

technology.

A common topology for DC/AC static power converters used in DG applications is

shown in Figure 16. The three-phase version of the system consists of six power

semiconductor switches, usually insulated-gate bipolar transistors (IGBTs) with an

integrated, reverse-paralleled diode. A capacitor on the DC link provides a small

amount of storage and serves as a filter to assist in smoothing the DC voltage. On the

AC side, inductors/reactors connect the three AC terminals of the switch matrix to

the power system. Small capacitive filters (not shown) are sometimes found on the

line side of the line interface reactors to remove noise generated by IGBT operation.

ac

dcac

dcPowerSystem

DGEnergySource

ac

dc

PowerSystem

DGEnergySource



Because a capacitor is used as the filtering element on the DC side, the arrangement

is commonly referred to as a voltage-source converter.

When the filtering element on the DC bus is a series inductor, the device is often

referred to as a current-source converter because of the propensity of the series

inductance for smoothing current. Current-source topologies were very common

with older thyristor-based conversion technology but are much less common today.

Because the effective switching speed of the power semiconductor switches is quite

fast relative to the 60-Hz power system frequency, it is possible to synthesize voltage

and current waveforms with very little lower-order harmonic distortion. Limits on

these harmonics found in the IEEE 519 standard are easily met with most modern

converter equipment.

The operating characteristics of a static power converter are not bound by well-

known physical principles, as is the case for rotating machinery; rather, how a

converter behaves under steady-state conditions and in response to events on the

power system is mostly a function of the various internal control systems and circuits.

This is usually not a problem for simpler studies like power flow analysis, where the

system would be represented as a negative load or a source with a defined real and

reactive power injection. Operation under other conditions, however, cannot be

ascertained from the basic structure or topology. Manufacturer’s specifications are

the only recourse.

Figure 16: Topology for DC/AC conversion stage for a voltage-source static power converter in a DG application

Figure 17 depicts a simplified control schematic for a static power converter in grid-

tied operation. Because the distributed generator is likely small relative to the short-

circuit capability of the supply system, the voltage magnitude at the interconnect

point cannot be influenced to a great degree by the distributed generator. The

control scheme, therefore, is designed to directly regulate the currents to be injected

into this “stiff” voltage source.

I1

I1



Figure 17: Simple output current control stage for a static power converter in a grid-tied DG application

The AC line voltages, DC link voltage, and two of the three AC line currents (for a

three-wire connection) are measured and provided to the main controller. The AC

voltage and line currents are measured at a high resolution relative to 60 Hz, so that

the controller is working with effectively instantaneous values. By comparing the

measured DC voltage to the desired value, the controller determines if the real power

delivered to the AC system should be increased, decreased, or held at the present

value. Such a simple regulation scheme works because there is no electric energy

storage in the converter (except for that in the DC filter capacitor), so the energy

flowing into the DC side of the converter must be matched at all times to that

injected into the AC line. If these quantities do not match, the DC link voltage will

either rise or fall, depending on the algebraic sign of the mismatch.

The error in the DC voltage is fed into a proportional-integral (PI) regulator to

generate a value representing the desired root mean square (RMS) magnitude of the

AC line currents. Another section of the control is processing the instantaneous value

of the AC line voltage to serve as a reference or “template” for the currents to be

produced by the converter. The desired instantaneous value of the line current is

computed by multiplying the desired RMS current magnitude by the present value

from the template waveform. In the next stage of the control, often called the

“modulator” section, the desired instantaneous value of line current is compared with

the measured value (in each phase). The modulator then determines the desired state

of the six switches in the matrix based on the instantaneous current error in each

phase of the line currents. The states are transmitted to the IGBT gate drivers, which

then implement the state of each IGBT in the matrix as commanded by the

controller. The process is then repeated at the next digital sampling interval of the

overall control.

This process is repeated thousands of times per single cycle of 60-Hz voltage. By

using the line voltage as a template for the shape of the currents to be synthesized,

synchronism is ensured. Additionally, if there is no intentional phase shift introduced

in the control calculations, the currents will be almost precisely—save for small

ComputeDesiredCurrents

ComputeSwitchStates

S1S2S3S4S5S6

Line Voltage

dc Voltage

Desireddc Voltage

MeasuredLine Currents



delays introduced by the control itself—in phase with the line voltages for unity

power factor operation.

A static power conversion device of the topology shown in Figure 16 that is

controlled in the way described in the preceding paragraphs is known as a “current-

regulated voltage-source converter.” Even though the physical configuration is of the

voltage-source type due to the DC filter capacitor, the scheme for directly regulating

output currents with the fast-acting modulator makes it appear more like a current

source.

Figure 18 depicts the output of a current-regulation scheme like the one described in

a three-phase 20-kilowatt (kW) converter. Here, the modulator will only change the

state of the switches if the absolute value of the difference between the desired and

actual line currents exceeds a certain value. The small errors that are continually

corrected by the action of the converter control are clearly visible. Because of the high

switching speed, however, the distortion of the current waveform is very low, well

within IEEE 519 limits.

Figure 18: Static power converter output current showing reference (desired) current and actual current

The significance of the previous discussion from the interconnection perspective is

that, unlike rotating machinery, whose behavior is bound by fairly well-known

physical principles, the response of static power–converter equipment in DG

installations to events on the power system is entirely dictated by the embedded

control algorithms. How a static power converter contributes to short circuits, for

example, cannot be deduced from the topology or values of passive elements such as

-0.1

-0.06

-0.02

+0.02

+0.06

+0.1

Desired Current(smooth line)

Actual Current



ties, inductors, or DC link capacitors. Figure 19 illustrates how the simple control of

the previous example would behave during a fault on the supply system. Because the

simple control in this example makes an implicit assumption about nominal voltage

and then utilizes a proportional-integral controller to determine the magnitude of the

line current necessary to provide for real power balance between AC and DC

terminals, the line current changes very little during the fault. In this example, the

converter shuts down after approximately three cycles, because the

overvoltage/undervoltage protection circuitry determines that the line voltage is

outside the operating threshold.

Figure 19: Output current of static power converter during supply system fault (converter shuts down three cycles after fault inception)

System studies that consider static power converters must rely on the manufacturers’

characterizations of how their products will perform under the range of power system

conditions that need to be evaluated in an interconnection study. Standards efforts

like that of IEEE P1547 are important for establishing the type of information that

should be provided to support technical evaluations of interconnection performance.

One final DG interface technology that should be noted is actually a hybrid of

conventional rotating machinery and static power conversion. Figure 20 illustrates a

doubly fed induction machine found in certain commercial wind turbines that uses a

bidirectional converter (real power can flow from supply to converter or from

converter to supply) to control currents in the rotor circuits of a wound-rotor

induction generator. Because the stator winding of the induction generator is directly

connected to the line, the terminal characteristics of this type of interface are a

combination of the respective characteristics of the machine and the static power

converter. For example, reactive power necessary for exciting the induction machine

may be drawn from the supply, although it is also possible to provide it from the

converter via the rotor circuits, in which case the system will operate at unity power

factor. Contributions to short circuits may be substantial for the first several cycles of

Time (sec) 0.1 0.14 0.18 0.22 0.26 0.3

kA

-0.15

-0.1

-0.05

+0

+0.05

+0.1

+0.15Actual Current



the fault—as would be the case for a large induction machine—unless the converter

control of the rotor circuit currents is fast enough. As with static power converters in

general, the manufacturers’ specifications must be consulted to determine the

characteristics appropriate for technical studies.

Figure 20: Hybrid interface technology, with stator of induction machine connected directly to line and rotor circuit supplied by four-quadrant power converter

PowerConverter(line side)

PowerConverter

(machine side)

Pg

en ,Q

gen

P, Q (stator)

P (rotor/converter)

SwitchControl

TorqueComputation

Rotor CurrentComputation

Gearbox

750 kW wound-rotor induction

generator

i*abc(rotor)

iabc(rotor)

Lookup Table(T vs. Z)

Shaft Speed Z Blades

T*

Z



4. Interconnection Requirements

This section focuses on interconnection requirements, including those detailed in the

draft of IEEE Standard P1547. The goal of this material is to provide additional

engineering background to allow for a better interpretation of the brief summaries of

requirements that appear in the standard. More detail is provided on such subjects as

islanding, detection of utility-side faults, and coordination with utility fault-clearing

and reclosing schemes. Additional information on protection of the distributed

resources (DR)/utility system interface is also provided.

4.1 General Protection Requirements

Because the distribution system was not designed for multiple sources of power, all

distributed resources must disconnect to allow the system fault-clearing process to

proceed. In most cases, the correct decisions about relaying for the DR breakers must

be made with only information available locally. This leads to questions such as

“How can DR relaying detect utility-side faults?” and “How should the relaying

coordinate with utility-side equipment?”

If the relaying does not properly detect disturbances on the utility side, the

distributed resources could end up isolated on a portion of the feeder load for times

ranging from a few cycles to several seconds. In some cases, the generation may

continue to feed the isolated section indefinitely. Regardless of time, this is referred

to as “islanding,” because it forms an electrical island that operates without

connection to the grid. Although there are some research efforts under way to

determine how to safely operate islands, or microgrids, most utilities currently forbid

the formation of inadvertent islands because of liability concerns. Therefore, another

important aspect of the protection issue that we address here is the detection of

islands.

There are at least three undesirable consequences of DR remaining connected for too

long after the utility breaker or line recloser has opened:

■ The fault fails to clear before the reclose operation. Arc products from temporary faults take several cycles to dissipate—time that is dependent on voltage level and climate. If the distributed resource continues to operate and feed the fault too long, there will be insufficient time to clear the fault, and the arc will restrike upon reclosing of the utility breaker. This will cause an unnecessary second operation of the breaker that can extend the scope of the interruption to more customers and subject utility transformers and lines to additional short-circuit currents.

■ The distributed resource is still connected when the utility breaker recloses. This can be devastating to some types of DR, particularly rotating machines. There is



no guarantee that the reclosure will be in synchronism with the machine. The result can be very high winding forces and shaft torques due to out-of-phase energization. There might also be excessive breaker contact currents.

■ Frequency and voltage excursions can cause damage to load equipment.

We now examine the requirements related to these issues.

Detecting Utility-Side Faults

Ideally, DR relaying should detect a utility-side fault before the utility-side protective

equipment can operate, although this is not always possible. This is when it is easiest

to detect, because the voltages are likely to be abnormal while the fault is still present.

The primary means of fault detection will be abnormal voltages. The basic

functionality is to simply check the voltage magnitudes. The faulted phase would be

expected to be low due to the short circuit. Unfaulted phases may actually be higher

than normal.

The ability to recognize the voltage waveforms as being abnormal depends on the

transformer connection. Transformers with delta or ungrounded-wye primaries may

make it difficult to sense certain types of faults by voltage magnitude only from the

transformer secondary side. Negative-sequence voltage relaying can make the fault

detection more sensitive for these cases. Time delays on such relays should be at least

as long as for the voltage relays to avoid unnecessary generator trips for faults on

other feeders or for transient switching events (such as power factor correction

capacitors) that yield momentary imbalances.

Another problem is differentiating between faults on the feeder serving the DR and

faults on adjacent feeders or on the transmission system. Setting the DR relays too

sensitive will result in unnecessary tripping of the generation. One solution is to arm

the relay to trip when unusual voltages are detected but to delay tripping until utility

breakers would have normally had time to trip and clear the fault.

Transmission system breakers are fairly consistent in clearing faults in five to six

cycles. Clearing times of fault interrupters on distribution systems have much more

variation. Fuses can blow in as little as one-half cycle or take several seconds,

depending on the fault current magnitude. Mechanical interrupters such as breakers

or reclosers can operate in as short as 1.5 cycles but can also take a few seconds to

relay out on low-current faults. Once the trip signal occurs, the interruption would

be expected to take fewer than five cycles.



Different delay times should be applied to different levels of over- or undervoltages

to reduce chances that the distributed resource is not disconnected inadvertently.

IEEE P1547 suggests two levels:

■ 0.16 seconds (s) (10 cycles) for voltages less than 50 percent. Very low voltages suggest that the fault is likely on the generator’s feeder or that the utility’s breaker has already opened, so the time delay can be short. However, it is also possible that there has been a major transmission fault or the fault is close to the substation bus on another feeder. The 10-cycle time delay is longer than the typical time for breakers to clear transmission and close-in faults (6 cycles) to prevent nuisance tripping, yet it is short enough to get the distributed resource off line early in the first reclose interval.

■ 2 s (120 cycles) for voltages between 50 percent and 88 percent. This condition would suggest that the fault is not close to the generator site and may be on an adjacent feeder or past a downstream line recloser or fuse. This delay gives the other fault interrupters an opportunity to clear the fault without tripping the generator off line.

For overvoltage relays, IEEE P1547 also recommends two levels:

■ 1.0 s for voltages between 110 percent and 120 percent.

■ 0.16 s for voltages greater than 120 percent.

Reverse power relaying would be applicable in DR installations where no net export

of power is expected (where customer load is always expected to be greater than the

generation). When a utility-side fault occurs, there may be a surge in power from the

generator back into the system that can be detected. Reverse power relays are

particularly useful for detecting islanding after the utility breaker opens.

Impedance relays may also be used to accomplish the same function as the reverse

power. These can be used to gain better detection of faults or detect the existence of

an island even when exported power is expected.

Overfrequency and underfrequency relays are not intended to be used for detecting

utility-side faults before the utility breaker opens. They are largely used for island

detection. However, field experience has indicated that generators are being

inadvertently tripped when utility-side faults occur by the frequency relays. The

reason claimed by relay manufacturers is that the relays are set to trip

instantaneously. Therefore, the voltage waveform disturbance that occurs upon fault

initiation is interpreted as a frequency change. Manufacturers suggest using at least a

six-cycle (0.1 s) time delay, which presumably gives the frequency detection

algorithm more time to compute the correct frequency.



Coordinating with Utility Fault Clearing

Coordination is mainly a timing issue. The basic requirement for coordination with

utility fault-clearing practices is for the distributed resource to disconnect at the same

time the utility breaker operates or very soon thereafter. The generator is to be

disconnected from the system to allow the fault to clear, if possible, and to avoid

potential damage from reclosing out of phase.

The distributed resource must remain disconnected until system integrity has been

restored. IEEE P1547 requires the DR to remain off line until the voltage has

returned to normal for delays of up to 5 minutes, if the DR reconnection delay is

adjustable, or a fixed period of 5 minutes if fixed. Delays under 5 minutes will

typically require negotiation between the DR owner and the serving utility.

The tripping intelligence can come from either the utility-side fault-detection scheme

or the islanding-detection scheme. When local intelligence is insufficient, it will be

necessary to install direct transfer trip so that the interconnection breaker is operated

in concert with the main utility fault-interrupting device.

Islanding Detection

If the DR relaying has not detected a fault by the time the utility breaker opens, the

distributed resource is in an islanding condition, isolated on some or all of the feeder

load. Islanding detection must then pick up the fact that an island has occurred and

disconnect the DR before the utility system recloses. Islands may also occur without

faults when breakers are opened by operator error, equipment malfunction, or for

performing maintenance. There may be no danger of being exposed to a reclose in

that instance, but the islanding-detection scheme would be responsible for separating

the generator from the electric power system as promptly as possible.

Direct transfer trip is one sure way to coordinate the operation of the utility breaker

and the generator breaker. However, this is too costly for most DR systems

interconnected at the distribution level. The island must be detected by local

intelligence in these cases.

Basic island-detection functionality is provided by a combination of

overvoltage/undervoltage and overfrequency/underfrequency detection. If there is a

reactive power mismatch upon separation, the voltage excursion would generally be

quite noticeable. If the DR is producing more volt-amperes reactive (VARs) than the

system demands, the voltage will quickly rise to a new value, and vice-versa. Some

DR technologies do not produce reactive power while they are interconnected. If

there is no other source of reactive power, the system voltage will quickly collapse.

However, there are capacitors on most utility distribution feeders to help supply the



reactive power. One strategy to prevent islands is to switch in a large reactive element

when the utility breaker opens to purposely create a large VAR mismatch. This

causes the voltage to immediately deviate from normal, and the island is detected by

the voltage relays on the distributed resource.

The island frequency would vary when there is a power mismatch. If there is too

much load, a rotating machine generator will slow down; too little, and the generator

speeds up, resulting in a corresponding frequency change. Inverters designed

according to IEEE Standard 929 introduce an intentional frequency error, or

periodically perturb their output current, in a manner that will tend to cause the

inverter output to quickly drift when they become islanded while controlled in grid-

connected mode.

The voltage relays will be set primarily to detect utility-side faults, with trip points as

described above.

Frequency relays should be set just outside the limits normally expected for utility

system frequency deviation and can be a very sensitive means of detecting an

inadvertent island. For DR less than 30 kilowatts (kW), IEEE P1547 recommends

setting the trip points at 59.3 hertz (Hz) for underfrequency and at 60.5 Hz for

overfrequency trip. Larger generation is permitted to stay on longer (unspecified time

delay) until the frequency drops below 57.0 Hz. The logic behind this standard is

that the larger generation might help prevent system collapse in an emergency. In any

case, whenever the frequency measured by the DR relay is outside the band allowed

for the utility, it is likely running islanded.

Some time delay should be used in the relay to ensure that an accurate measurement

of frequency is made. Otherwise, the overfrequency/underfrequency relaying can act

as a very sensitive fault detector and give false trips on common utility system

disturbances that temporarily alter the voltage waveshape. Manufacturers recommend

at least 0.1 s (six cycles). The IEEE P1547 document suggests 10 cycles, or 0.16 s.

It is generally expected that nearly all islands will be quickly detected by voltage and

frequency relays. In Electrotek’s own studies of this issue, less than 1 percent of

thousands of randomly generated cases of synchronous generator DR and load would

stay within both ±2 Hz and ±10 percent voltage for more than 1.0 s after a simple

opening of the utility feeder breaker. It was assumed that there was no fault on the

feeder and that the breaker opened while the system was normal. When a fault is

present before the opening, it is more likely the island will be detected early.

The problematic cases were where the DR output was slightly greater than the feeder

load. In cases where it is deemed more likely that the DR can sustain an island for at



least the reclose period, basic protection can be supplemented by other islanding-

detection schemes:

■ Reverse power relaying is an obvious choice in systems that are not permitted to export power.

■ Impedance relays can be used for a similar function when export is permitted. The apparent impedance of the system will change, especially if the fault remains.

■ Instantaneous overvoltage detects conditions that result in distorted voltages, such as ferroresonant conditions that come about due to interaction between the distributed resource and capacitors on the system when the island forms.

Other, more exotic, schemes include these:

■ Harmonic voltage change. Harmonic currents normally flow through the utility source, causing minor voltage distortion. When the island forms, the short-circuit current increases considerably, causing the harmonic voltage distortion to increase.

■ Rate of change of power. This operates on the assumption that the distributed resource will suddenly attempt to export more power to match the load (this is dependent on generator and control technology).

One requirement consistent with IEEE P1547 is that interconnected distributed

resources should not attempt to regulate voltage but should control only power and

power factor. They should stay in this mode as long as the interconnection breaker is

closed. This significantly reduces the chances of forming a sustained island by

making it necessary to perfectly match active and reactive power of the entire system

to form an inadvertent island. In contrast, while running as a backup, stand-alone

power source, the generator must regulate voltage and frequency. It is much more

likely to sustain an island in that mode. This creates special multimode control

requirements for generators that operate in both grid-parallel and stand-alone modes.

4.2 Protection of the DR/EPS Interface

The specifications described here pertain only to protection of the DR/electrical

power system (EPS) interface and not necessarily to protection of the DR

technology. For example, synchronous generators are assumed to have the necessary

synchronizing relays and associated controls.



Disconnect Switches

In addition to the protective relaying functions describe in subsequent sections, it is

nearly a universal requirement that DR installations of all sizes have disconnect

switches that can be locked out from areas that are accessible by utility personnel.

This is to prevent interconnection of the generator to the utility system during

certain maintenance operations or when system conditions do not permit

interconnection. An example of the latter would be when the DR site is being served

by an alternate feed that does not have the appropriate protection to accommodate

the generator.

Additional lock-out requirements could include in-facility transfer trip between all

breakers that can disconnect the distributed resource. This helps prevent conditions

in which the distributed resource might form an island inside the end-user facility

and accidentally reconnect out of synchronism.

In many cases, the disconnect switches will be required to have a visible open and

have load-break capability.

Simple Interconnection

The protection scheme shown in Figure 21 applies to small systems that are not

expected to be able to support islands. There is no consensus on what constitutes

“small” DR systems. The IEEE P1547/D08 document does not have a clear-cut

definition of size delineation, although that was attempted earlier in the standards

process. From Sections 4.2.1 and 4.2.2, one can infer that “small” would refer to DR

smaller than approximately 30 kW. Other utility interconnection standards might

restrict this to 10 kW or may allow this kind of interface protection up to 100 kW or

more.

DR of this size would commonly be connected to the load bus at secondary voltage

levels. Overcurrent protection is provided by molded case circuit breakers. The main

DR interface protection functions are overvoltage/undervoltage (27/59 relay) and

overfrequency/underfrequency (81 O/U relay).

These relays trip either the generator breaker or the main service breaker, depending

on the desired mode of operation. Tripping only the generator leaves the load

connected. If the DR is to be used as a backup power resource, the main service

breaker is tripped so that the generation can continue to supply the load. It should be

noted that special controls (not shown) may be required for this transfer to occur

seamlessly.



Figure 21: Interface protection for a small system

The overvoltage/undervoltage relay is primarily responsible for detecting utility-side

disturbances. There should be no frequency deviation until the utility fault

interrupter opens. If the fault is very close to the generator interconnection and the

voltage sag is deep, the overcurrent breakers may also see the fault. However, the

molded case breakers are primarily for protecting the distributed resource in case of a

fault within it.

Once the utility supply becomes disconnected from the distribution feeder, the

voltage and frequency relays work in concert to detect the island. For small DR, one

would normally expect the voltage to collapse very quickly and to be detected by the

undervoltage relay. If this does not occur, the frequency would be expected to deviate

quickly outside the band expected for normal utility operation, and the frequency

relay would detect the island and trip the unit off. Sometimes the frequency relay can

interpret the voltage transient at the beginning of the fault as frequency deviation.

This is beneficial if the goal is to detect faults as quickly as possible. However, this is

also a source of nuisance tripping, and one must be careful not to set the frequency

relaying too sensitive.

IEEE P1547/D08 recommends two voltage levels and time delays for both

undervoltage and overvoltage. If, for some reason, only one setting is possible for

overvoltage/undervoltage, the shortest time delay should be used. This will likely

result in unnecessary tripping, and the DR owner may then decide to add sufficient

relaying to accommodate the two-step approach. There is one setting each for the

underfrequency and overfrequency relay function.

DR

LOAD

SERVICETRANSFORMER

81 O/U27/59DR

LOAD

SERVICETRANSFORMER

81 O/U27/59



Complex Interconnection

Most generators larger than 1 megawatt (MW) would usually be protected by a full

range of relays similar to those for the interconnection of utility central station

generators. Figure 22 shows one example of such a system for a large synchronous

generator. It shows the relays necessary for interface protection as well as some of the

relays necessary for generator protection. Not all the functions that might be

necessary for proper control of the generator, interlocking of breakers, and so on are

shown in this diagram. This installation comprises several generators connected

identically.

In this example, there is a primary side utility breaker. This is commonly a three-

phase recloser, which is a convenient switchgear package for utilities to install. The

recloser comes with overcurrent relaying (not shown), and a separate DR relay

package has been added that operates off a separate potential transformer. This is the

main breaker used to achieve or ensure separation of the generator(s).

The relaying elements in the system and their function are as follows.

Primary Side

■ 27/59: Standard undervoltage/overvoltage relay. This serves as the primary means of fault detection and island detection. It can be used to block closing of the breaker until there is voltage present on the utility system, or there may be a separate relay function for that purpose.

■ 81 O/U: Standard overfrequency/underfrequency relay. This is for islanding detection.

■ 47: Negative sequence voltage relay (optional). This is a backup means for detecting utility-side faults that can be more sensitive than voltage magnitudes in some cases. It also helps prevent generator damage due to unbalance.

■ 59I: Instantaneous (peak) overvoltage. This is a supplemental islanding-detection function that would be employed when ferroresonance or other resonance phenomena are likely (typically when utility-side capacitors interact with the generator reactance).

■ 59N: Ground overvoltage. This relay is installed in the corner of a broken delta connection on the potential transformer. It is a supplemental fault-detection and islanding-detection relay function that measures the zero-sequence voltage. It would detect conditions in which the generator is islanded on a single line-to-ground fault. It is needed more when the primary connection of the transformer is delta or ungrounded-wye.



Figure 22: Relatively complex scheme for protection of a large synchronous generator

These relaying functions may be moved to the secondary side of the service

transformer if there is no high-side breaker. The relays would trip the main breaker

on the secondary side in that case.

Large systems are also more likely than smaller ones to be able to afford direct

transfer trip, which can be accomplished via wireless technologies. Either the recloser

or the main generator breaker would be tied into the next upline fault interrupter so

that the DR is separated automatically each time the interrupter is tripped. The other

relaying functions can be retained, but with a somewhat longer time delay to give

precedence to the direct transfer trip.

Generator Side

■ 50/51: Overcurrent relay. This is responsible for tripping the main breaker for faults within the generator system.

DG

ANOTHERGENERATOR

GENERATORTRANSFORMER 81 O/U 47 59 I

25

50/51V46

50/51464032R

(GENERATOR PROTECTION)

51G

87G

UTILITYBREAKER OR

RECLOSER

59 N27/59



■ 46 relay at transformer: Negative sequence current. Used particularly in open-phase conditions and trips the main breaker. (Generators have a separate 46 relay.)

■ 25: Synchronizing relay. This controls closing of the main breaker when the generator(s) are being interconnected to the utility. (This scheme would also require synch check relays on the individual generators if they are to be interconnected separately.)

Generator Protection

■ 87G: Differential ground relay. Used for fast detection of ground faults within the generator.

■ 51G: Ground overcurrent. Trips the generator for high neutral currents indicative of a ground fault on the secondary system.

■ 32R: Reverse power relay. This relay detects power going into the generator, which would indicate a fault.

■ 40: Loss of field relay. Detects loss of field excitation.

■ 46: Negative sequence current. Protects the machine against excessive unbalanced currents, which may or may not result from a fault.

■ 50/51: Overcurrent relays. Protect the generator against excessive loads and faults on either side of the generator breaker.

This example demonstrates the majority of relaying functions that would be used to

interconnect distributed resources to the utility distribution system. Many of these

functions can be obtained from special DR interface relay packages that can be

conveniently installed. The package that controls the interface breakers is generally

required to be “utility grade.” Generator protection relays typically are supplied with

the generator.

Other Interconnection Schemes

The protection schemes presented represent just two of the many possible

arrangements. In fact, documents as large as this guide have been written on this

subject alone. These two schemes were presented to show the range of protective

relaying requirements for interconnecting DR to the utility system. The schemes

presented here also focus on the interface protection. In any given DR system, there

may be many other relays and interlocks associated with the control of the system.

C.J. Mozina3 gives several other examples. Also, there are extensive documents

available on the Web sites of the major vendors of generation protection relays.4



Dedicated Feeders

For generators that are particularly large relative to the capacity of the feeders,

utilities will often require a dedicated feeder for the customer with the generation.

4.3 Effect of Transformer Connections

Grounded-Wye/Wye

This is a common connection applied in North America for three-phase loads. It is

applied because of its reduced susceptibility to ferroresonance on cable-fed loads and

fewer operating restrictions for being switched for maintenance. It is also generally

well-behaved with respect to DR applications, although it will pass triplen harmonics

on to the power system.

The interconnection diagram shown in Figure 23 shows a typical installation. The

transformer is solidly grounded on both sides. It may be advisable to have a reactor in

the neutral of wye-connected machines for the reasons stated below. The fuses

indicated on the diagram are transformer fuses rather than line fuses. In general, fuses

between the generator and utility substation can subject the generator to single-

phasing, which is undesirable. However, these fuses are expected to blow only when

there is a fault inside the transformer or the secondary breakers fail to clear a low-side

fault.

Figure 23: Grounded-wye/wye interconnection transformer

TRANSFORMERFUSES

OPTIONALNEUTRAL

REACTOR ANDBYPASSSWITCH

WYE-WYETRANSFORMER

Advantages of grounded-wye/wye connections include these:

■ No phase shifting of utility-side voltages. This makes detection of utility faults by DR protection relays more certain.



■ Less concern for ferroresonance (but some core designs can still yield ferroresonance if there is sufficient capacitance).

Disadvantages include these:

■ Allows DR to feed all types of faults on the utility system.

■ Does not inhibit the flow of zero-sequence harmonic currents that might be produced from certain kinds of generators.

Because of these two concerns, it may be difficult to parallel some generators using

this transformer connection. If the distributed resource is a synchronous machine, it

may produce a small amount of third-harmonic voltage distortion, depending on the

winding pitch of the machine. If a synchronous generator does not have a two-thirds

winding pitch, paralleling it to the utility system provides a very low impedance path

for the third harmonic, and the resulting neutral currents may damage generator

equipment or add unwanted harmonic currents to the utility system. A neutral

reactor may be necessary for some wye-connected machines while they are paralleled

to the utility system to limit the flow of zero-sequence harmonics (principally the

third) and limit the contribution of the generator to ground faults.

The reactor would be shorted when operating the generator in stand-alone mode to

provide emergency backup power so that a stable neutral is presented to the load.

Delta/Grounded-Wye

This is another common connection for three-phase loads in North America and the

most common in Europe. It would probably be favored for serving loads in most

cases if it were not for the susceptibility of the connection to ferroresonance in cable-

fed systems.

Advantages of delta/grounded-wye connections include these:

■ Does not feed into utility-side ground faults.

■ Third harmonics from the DR do not reach the utility system.

■ Provides some alleviation of voltage sags due to utility-side single-line-to-ground (SLG) faults.


■ Difficult to detect some SLG faults from the secondary side by voltage relaying alone.

■ Susceptible to ferroresonance in cable-fed installations.



■ Third harmonics in the DR may cause excessive current in the secondary-side neutral.

■ If islanded on SLG fault, it can subject utility arresters to overvoltages (see Figure 26).

■ If islanded on SLG fault and little load, it can result in resonant overvoltages.

The last two items are common to all transformers with an ungrounded primary

connection.

Note that, although this connection prevents third harmonics from the generator

from reaching the utility system, it does not prevent their flow on the low-voltage

(LV) side (DR side). As with the grounded-wye/wye connection, it is generally not

advisable to directly connect synchronous alternators that are not two-thirds pitch

without inserting an impedance in the neutral to limit the third-harmonic current

flow. Thus, an optional reactor and bypass switch are shown in Figure 24.

Figure 24: Delta/grounded-wye connection�

Though the phase shift can be beneficial to the load in reducing the impact of

voltage sags due to SLG faults, it also makes some SLG faults on the utility system

more difficult to detect. This increases the chances of islanding, because it delays

fault detection until the utility breaker operates. As with all ungrounded primary

OPTIONALNEUTRAL

REACTOR ANDBYPASSSWITCH

DELTA / WYETRANSFORMER

PTs (3-phase) for59N relay

59N (or 59G)



connections, there is a danger in being islanded on an SLG fault with very light load

even briefly, because this can result in a resonant condition.

Therefore, it is common to add other relaying functions to aid in the early detection

of utility-side faults. A negative sequence relay can make the detection more reliable.

Though the voltage magnitudes seen on the secondary may not change sufficiently,

they will become unbalanced, resulting in detectable negative sequence voltages and

currents.

A common approach is to add relaying on the primary side of the transformer, such

as a ground overvoltage (59N or 59G in Figure 24) relay that can detect the presence

of the SLG fault. This is implemented by installing potential transformers on the

primary system and then placing a voltage relay in the corner of the delta winding on

the instrumentation transformer.

Grounded-Wye/Delta

Some utility engineers claim that grounded-wye/delta is the best connection for DR.

In fact, it is the most common connection used for most utility central station

generation and large merchant plants directly connected to the transmission system.

Advantages of grounded-wye/delta connections include these:

■ Protection schemes are well understood by both vendors of larger DR equipment and utility protection engineers.

■ Third-harmonic currents that might be produced by the generator cannot flow on the generator side and are, therefore, not passed on to the power system. Thus, economies in generator design might be realizable, and no neutral reactor is necessary to limit the current.

■ On the distribution system, utility-side faults make themselves known on the DR side quite readily, because the transformer itself actually participates in all ground faults. (This connection is also known as a “grounding transformer” or a “ground source.”)

Unfortunately, this behavior of participating in all ground faults is undesirable on

many distribution systems, and few utilities will allow this connection on the

distribution system without special study. Accepting this connection often means

making changes to the feeder overcurrent protection scheme that are either costly in

terms of replacing equipment or that inconvenience other customers on the feeder.



Figure 25 shows how the connection contributes to a single-line-to-ground fault on a

four-wire, multigrounded neutral distribution system, the most common in the U.S.

The thick arrows show the normal contribution expected from the main utility

source. Only one phase is involved on the distribution side, and the fault appears

line-to-line from the transmission side. The thin arrows show the paths of the current

from the grounded-wye/delta DR interconnection transformer. The currents flow

back through the substation and contribute additional current to the fault. The

amount contributed would depend on the size and impedance of the transformer.

For clarity, the DR contribution is not shown in the diagram. This contribution will

depend on the capability of the DR to feed the fault. In many cases, the contribution

due to the transformer alone will be larger.

This behavior has a number of possible adverse side effects when it is present on the

distribution system:

■ Increased fault current means increased damage at the fault site.

■ The connection contributes to sympathetic tripping of the feeder breaker for faults on other feeders. The transformer supplies current to other feeders connected to the same substation bus. Ground trip pickup levels must be increased to maintain coordination, which results in less-sensitive fault protection.

■ If saving of lateral fuses is being attempted, the fault infeed, which is likely to be larger than that from the DR itself, makes this much more difficult to achieve.

■ For larger transformers, the additional fault contribution can increase the fault current beyond the interrupting ratings of fused cutouts and line reclosers. This is less of a problem with more modern equipment, but most utility systems are populated with many pieces of older equipment.

■ The transformer itself is subject to short-circuit failure when the fault occurs. This is particularly true for smaller transformer banks with impedances of less than 4 to 5 percent. A special transformer must generally be ordered.

■ The transformer is also subject to failure thermally, because the feeder load is not balanced. Thus, the transformer acts as a sink for zero-sequence load currents.



Figure 25: Grounded-wye/delta transformers for DR interconnection can feed ground faults on four-wire multigrounded neutral systems, introducing additional fault stresses and interfering with utility-side protective relaying

MAIN FAULTCONTRIBUTION

FROM EPSCONTRIBUTION

FROM DRTRANSFORMER

(MULTI-GROUNDED NEUTRAL)

FAULT

DG

If this connection is to be used on a typical distribution system, some of the options

for better accommodating it are these:

■ Ground the transformer through a neutral reactance of sufficient size to limit the fault current contribution and the amount of unbalanced load current the transformer would have to absorb.

■ Increase ground trip pickup settings on feeder breakers and line reclosers.

■ Abandon lateral fuse saving (fast tripping); it will probably be unsuccessful anyway.

Individual installations can be successfully engineered so that they will work

acceptably. However, large numbers of such installations should be avoided.

Fault detection and islanding detection from the generator side of the transformer are

generally somewhat more straightforward than with other connections. There are

fewer situations than can escape detection.

Wye/Delta or Delta/Delta

Though not in the majority, these connections are still common for commercial and

industrial loads. Both have similar behavior with respect to serving DR. Neither

would be the preferred connection for serving most new DR installations, but they

could be encountered in legacy systems where a customer wishes to operate DR

parallel with the grid.



Some inverter-based systems (such as fuel cells, photovoltaics, and microturbines)

require an ungrounded connection on the DR side, because the DC side of the

inverter is grounded. This is often accomplished with a separate isolation transformer

rather than the main service transformer. However, either of these connections would

also suffice.

The delta secondary is sometimes a “four-wire” connection with one of the delta legs

center tapped and grounded to serve single-phase 120-volt (V) loads. This is

common in smaller commercial facilities that have three-phase HVAC equipment

along with typical office load. If this is the case, no part of the DR can be grounded

while operating parallel with the grid.

Advantages of wye/delta or delta/delta connections include these:

■ More economical transformer installation for smaller three-phase service with some single-phase loads.

■ Load is isolated from ground faults on the utility side.

■ DR would not typically feed utility-side ground faults (except when resonance occurs).

■ Can provide ungrounded interconnection for inverter-based systems requiring it.


■ Utility-side SLG faults are more difficult to detect.

■ Utility arresters are subjected to high steady-state overvoltages if the arrestors are islanded on an SLG fault (Figure 26). This is true for delta/grounded-wye connections as well.

■ Highly susceptible to ferroresonance in cable-fed installations.

■ More restrictions on switching for utility maintenance. Three-phase switchgear may be required on the primary, because there are several problems that can occur if one attempts to perform single-phase switching. This will increase the cost of the interconnection.

The prompt detection of SLG utility faults using voltage relaying is a problem with

these connections. This will delay fault detection until after the utility breaker has

opened, resulting in at least a brief island. This can result in overvoltages and a

resonant condition common to all ungrounded primary connections. Supplementing



voltage relaying with negative sequence current or voltage relaying can make the

detection more certain.

Figure 26: Transformers with ungrounded primary connections can subject utility-side arresters to overvoltage

ARRESTERSSUBJECTED TO LINE-TO-LINE VOLTAGES

PERMANENT LINE-TO-GROUND FAULT

UTILITYINTERRUPTINGDEVICE OPEN

UNGROUNDEDTRANSFORMERCONNECTION

G



5. Power Quality and Reliability

Distributed generation (DG) can both improve and degrade power quality. In fact,

there are often both good and bad attributes to a distributed resource (DR)

application, depending on one’s viewpoint. In this section, we discuss the impact of

DR (for better or worse) on the quality of power delivered to the customer.

5.1 Voltage Regulation Issues

Voltage regulation issues often impose the most limiting constraints on the amount

of DR that can be accommodated on a utility distribution system.

Figure 27 illustrates one voltage regulation problem that can arise when the total DR

capacity on a feeder becomes significant. This problem is a consequence of the

requirement to disconnect all DR when a fault occurs.

Figure 27: Voltage drop when DR is forced off by utility-side fault

Voltage drop/rise upon sudden disconnection/connection

The “before fault” portion of Figure 27 shows the voltage profile along the feeder

prior to the fault occurring. The intent of the voltage regulation scheme is to keep

VOLTAGE PROFILE

BEFORE FAULT

VOLTAGE PROFILE

AFTER RECLOSE



the voltage magnitude between the two limits shown. In this case, the DR helps keep

the voltage above the minimum and, in fact, is large enough to give it a slight voltage

rise toward the end of the feeders.

When the fault occurs, the DR disconnects and, according to the requirements of

IEEE P1547/D08, may remain disconnected for up to 5 minutes. Then the breaker

recloses, resulting in the condition shown in the second part of Figure 27. The load

is too great for the feeder and the current settings of the voltage regulation devices—

load tap changers (LTCs), regulators, and switched capacitors. Therefore, the voltage

toward the end of the feeder sags below the minimum. The voltage will remain low

until voltage regulation equipment can react. This can be the better part of 1 minute

or more, which can increase the risk of damage to load equipment due to excessively

low voltages.

Of course, this assumes that the voltage regulation devices are not already at

maximum tap. Utility planners will often point out that this is one of the dangers of

relying on DR to meet capacity. It masks the true load growth on the system, and

there is insufficient base capacity in the wires to deliver the power.

This issue can be one of the more limiting with respect to how much DR can be

accommodated on a feeder. It is particularly an issue for lengthy feeders on which the

DR is located some considerable distance from the substation. This may be an

attractive application of DR, because it defers the construction of major wires

facilities to serve the remote area. However, this solution may include the cost of

having to modify long-established operating practices and sacrificing some system

reliability.

Solutions include these:

■ The DR is likely to be customer-owned. If the entire customer load is also required to disconnect when the DR is forced off, the net change in feeder loading should be negligible.

■ Install another line regulator bank with a control that can bypass the normal time delay when the voltage goes far out of bounds. This allows the low voltage to be corrected in a few seconds in most cases. Of course, this is an added cost to the interconnection.

■ Limit the amount of DR on the feeder to limit the change in voltage to an amount that can be accepted with the existing voltage regulation scheme.

■ Many DR techonologies can be restarted more quickly than the delay recommended by IEEE P1547. However, it is not advisable to do this without communicating with the utility.



■ Stagger the reenergization of feeder sections so that the DR is reconnected before all the load is reconnected. This will reduce reliability for some customers and will require extensive communication and control systems, which are costly.

Interference with Voltage Regulators

Figure 28 shows one common case of interference with the voltage regulator controls.

Many regulators make use of a control feature that automatically switches the

direction the regulator attempts to regulate when the net power through the

regulator reverses. The purpose of this feature is to change regulator direction when

the feeder is being supplied by its alternate source.

Figure 28: Reverse power from DR can fool the direction sensor on a regulator control

When a permanent fault occurs on a feeder, the faulted section is isolated. While

repair is proceeding, part of the feeder may be switched to another circuit. Any

voltage regulators on the affected feeder must switch direction so that the regulated

bus is opposite the source. The decision to switch is made locally by the control using

the direction of active power. Although reactive power can normally flow in either

direction, reverse active power should only occur when fed from the alternate feed.

The control will have a setting for the magnitude of reverse power to trigger the

direction change and a time delay.

When there is more DR capacity than the minimum load, the net power sensed by

the regulator can reverse, as shown in Figure 28. This puts the regulator in precisely

the condition that the automatic reverse power feature is designed to avoid: It is

attempting to regulate the utility source. Because the utility source is much more

powerful than the DR source, this attempt will be unsuccessful, and the tap will

usually go to a limiting position in the wrong direction.

DR

Regulator SwitchesDirection to Try toControl This Way

Net Power



The regulator should stay in the normal forward control mode in this condition.

Solutions to this problem include these:

■ Some microprocessor-based regulator controls have a “cogeneration” mode that prevents reversing when the generator is interconnected. Reverse power may alter the control strategy but does not change the direction. For DR that is operating most of the time, the control can simply be left in this mode. For intermittent generation, operation would be improved if there were communications circuits available to coordinate the actions of the DR and the control.

■ Set the control to go to neutral tap on reverse power. This can minimize the impacts of incorrect voltage regulator action, although it will not provide good voltage regulation when the feeder is actually being fed from the alternate circuit.

■ Replace older-generation, simpler regulator controls with those that have cogeneration and communications features.

■ Move the regulator back toward the substation so that there is more load on the DR side of the regulator.

■ Limit the DR output.

Varying Generation

Varying generation can also cause problems for utility voltage regulation equipment.

Much of the DR for which interconnection is contemplated will not be varying.

When the energy source is fossil fuel, the DR will typically be operated at full output

all the time it is connected. Variable sources are largely renewable sources such as

solar and wind generation. Wind generation is typically the more difficult to deal

with, because it can vary greatly in a matter of seconds—much faster than standard

utility voltage regulation equipment can respond.

A proposed wind farm installation is shown in Figure 29. An 8,000-kilowatt (kW)

wind farm was to be located nearly 7.5 miles from the substation on a 12.47-kilovolt

(kV) feeder. This is a very large flow for this class of feeder. The conductor in the

main three-phase feeder was 336 MCM ACSR constructed on a typical 8-foot

horizontal crossarm and was not transposed over its entire length. The voltage- and

volt-ampere reactive (VAR)-control devices consisted of two 600-kVAR switch

capacitor banks and a line regulator positioned as shown in Figure 29. The capacitor

switches were controlled by current magnitude. The voltage regulator was set for 122

volts (V) and a bandwidth of 3 V.



Figure 29: One-line diagram of service to a wind farm

SWITCHED CAPACITORBANKS

32-STEP VOLTAGEREGULATOR

UNTRANSPOSED OVERHEADFEEDER, HORIZONTAL

CROSSARM CONSTRUCTION

Figure 30 shows the three-phase voltages computed just downline from the regulator

over a 40-minute period for one circuit-loading condition. This illustrates the

difficulty that a varying generator of this type can present. The main problem at this

loading was that the capacitor controls switched frequently. In two instances, they

switched on and then off a short time later. This is too much duty for the switches,

which are expected to switch only once or twice per day.

The regulators in this case operated only twice. In other loading conditions and

capacitor control settings, the regulators had many more tap operations. In one case,

there were 17 tap changes in 40 minutes. Utilities expect only a few tap changes in

an entire day. Due to the unbalanced line design, the regulators on the outside two

phases generally work harder than the one on the middle phase.

Though the varying voltage characteristic does not look very attractive, it falls within

service standards. The unbalanced line configuration contributes to phase imlance,

but the single-phase regulators do a good job of compensating. The negative

sequence voltage does not exceed 0.5 percent. The voltage magnitude varies

approximately 3 percent over this time period but stays well within the normal range.

The change occurs so slowly that it does not exceed flicker standards. When profiles

of voltage vs. time were fed into a computer program that computes the IEC flicker

short-term flicker measure, PST,5 the value typically came out approximately 0.2. The

upper limit is 1.0. The main issue with this and similar large wind farm installations

is overtaxing of the conventional voltage regulation equipment.



Figure 30: Voltages computed for mid-feeder location for a simulated wind farm showing response of voltage regulators and capacitors (total time duration: 40 minutes)


■ Change capacitor control settings. In this case, capacitor switching can be reduced by using voltage control and a wider band, although this forces the regulators to do more work.

■ Extend the regulator bandwidth to reduce the number of tap changes. Also, transposing the line would help balance out the number of operations between the phases.

■ Limit the size of the wind farm. The location is not generally a variable and is likely to be rural, in a weak part of the system.

■ Build an express feeder for the wind farm. This is the ultimate solution for many wind farms but is comparatively costly. Thus, many wind farms today are constructed in much larger sizes and connected directly to the transmission grid via distribution feeders serving only the wind turbines.

5.2 Impact on Utility Overcurrent Protection

One of the keys to high electrical utility reliability is a well-coordinated overcurrent

protection system. This section describes situations in which DR can have a negative

impact on existing utility systems. Changes to accommodate DR can be as simple as

changing a relay setting or as costly as adding additional breakers or reclosers.

Regulator Tap

Changes

Capacitor

Switching



Reduction of Reach (Desensitizing Relays)

Figure 31 illustrates one situation that is of concern to many electrical system

protection engineers. When the total DR capacity increases to a certain amount, the

infeed into faults can desensitize the relays and leave remote sections of the feeder

unprotected.

Each overcurrent relay device has an assigned zone of protection that is determined

primarily by its minimum pickup value. This is the minimum current that will cause

the relay to operate and trip the breaker. Some refer to size of the zone of protection

as the “reach” of the relay. DR infeed will reduce the current that the relay senses,

thereby shortening its reach. A low-current (high-impedance) fault near the end of

the feeder is more likely to go undetected until it does sufficient damage to develop

into a major fault.

Figure 31: Generator infeed to a fault can limit the distance a utility overcurrent relay can sense down the feeder

This can be a particular problem for peaking generation located near the end of the

feeder. Such generation is on at peak load level where the overcurrent relaying would

normally be very sensitive to a high-impedance fault. The DR infeed has the

potential to mask many faults that would normally be detected.


■ Decrease the relay pickup current. This may not be practical for ground relays that are already set very sensitive.

■ Add a line recloser to create another protection zone that extends far past the end of the feeder.

■ Use a transformer connection that minimizes DR contribution to ground faults, because high-impedance faults are likely to be ground faults.

FAULTREDUCED SOURCE

CURRENTCONTRIBUTION GENERATOR

INFEED

UTILITY BREAKER

NORMAL ZONE OFPROTECTION

REDUCED ZONEOF PROTECTION



Interfering with Fuse Saving

Fuse saving is commonly practiced in utility overcurrent protection schemes,

particularly in more rural regions. The time-current characteristic (TCC) curves for a

typical recloser-fuse coordination that employs fuse saving is shown in Figure 32 for

the situation depicted in Figure 33. The recloser is set to operate on a 1A, 3D

sequence. That is, it will operate once on its fast (A) curve and then up to three times

on its delayed (D) curve as long as the fault is still present. The desired sequence for

the situation depicted in Figure 33 is for the recloser to operate on its A curve faster

than the fuse melt curve for all fault currents up to the maximum fault current

available at the fuse location (Ifault). The D curve is slower, allowing the fuse to blow

when the fault is permanent. If the fault is temporary, the arc will extinguish, and

service will be restored upon the subsequent reclose, which normally takes place in 1

or 2 seconds. This saves the cost of sending a line crew to change the fuse and

improves the reliability of customers served on the fused lateral.

Figure 32: Typical time-current characteristic for recloser-fuse coordination with fuse saving

This fuse-saving action is a horse race. In the best of circumstances, it is a challenge

for the mechanical recloser to detect the fault and operate fast enough to prevent

damage to the fuse element. DR infeed adds to the current in the fuse without

adding to the current in the recloser. This speeds the fuse melting up while slowing

the recloser response slightly. For some amount of DR, both the recloser and fuse

operate simultaneously, defeating the intended coordination.

For the specific situation shown in Figure 33 with a 280A recloser and a 40 T fuse,

fuse-saving coordination fails when the total capacity of synchronous machine

generators reaches about 900 kilovolt-ampere (kVA).6 The machines were assumed to

Ifault

D Curve

A Curve

40T Fuse Melt Curve

Tim

e

Current Ifault

D Curve

A Curve

40T Fuse Melt Curve

Tim

e

Current



be interconnected through typical grounded-wye/wye transformers and are thus able

to feed SLG faults on fused laterals.

Solutions include the following:

■ Increase the size of the lateral fuse. The largest size that will coordinate with this recloser setting is a 65T, which would allow up to approximately 1,500 kVA of DR without affecting fuse saving. Of course, all fused cutouts in the zone will have to be changed, which is quite expensive.

■ Many utilities would choose to simply abandon fuse saving, particularly if the DR is only connected intermittently.

■ Require the DR to have transformer connections that do not feed SLG faults to allow more DR to be served with respect to this issue.

Failure to Clear Faults

Another event that can negatively affect reliability is that the temporary fault can fail

to clear because the DR infeed continues to support the fault arc. A breaker or

recloser operates to shut off current to the fault so that the arc can disperse. However,

if the DG does not also disconnect quickly, it can sustain the fault until the reclose

operation occurs. Fault arc products need several cycles to disperse while the current

is interrupted. Utilities usually allow at least 12 cycles (0.2 s) for this to occur.

The DR need not feed the fault continuously. The island need only be sustained long

enough to prevent the arc from dispersing before the reclose. This is a particular

problem when either the DR relaying has difficulty detecting the fault until the

utility breaker opens or the DR interconnection breaker operates too slowly.

A rule of thumb is that 5 amperes (A) of fault current can sustain a fault. Of course,

this is greatly dependent on many environmental factors, and one cannot assume that

if the fault current is less than this, the arc will always go out on its own. Therefore,

the arc might be maintained by relatively small generation.

In the fuse-saving case illustrated in Figure 33, the recloser may interrupt quickly

enough to save the fuse. However, if the DR maintains the fault, the fuse will blow

upon reclose, because the recloser is on its “D” delayed timing curve. Customers on

the fused lateral will suffer an unnecessary outage.



Figure 33: Generator infeed into the fault can blow the fuse before the recloser can protect it


■ More sensitive DR relaying. The key to prompt DR separation is being able to detect the fault before the utility breaker operates and then institute tripping at about the same time.

■ Extend the reclose intervals to gain greater assurance that the fault will clear (see next section). It will not be possible to detect all faults before the island occurs, so allow sufficient time for the DR to disconnect.

Reclosing

Because most faults are temporary, reclosing is an almost universal practice

throughout North America. Figure 34 shows three common reclosing sequences. The

top two represent recloser sequences, and the bottom one represents a substation

breaker sequence.

R

FAULT

40T FUSE

280Amps1A, 3D

DG

UTILITYSOURCE

LINE RECLOSER



Figure 34: Some typical reclosing sequences employed by utilities

Because breaker and recloser technologies evolved separately, the philosophies of

operation differ. The intervals between operations tend to be more uniform for

reclosers, although modern controls allow considerable flexibility. The reclose times

for breakers are counted from the first trip operation. The common 0-15-45 reclose

sequence means that the first reclose occurs as fast as possible (also called

“instantaneous reclose”), the second reclose occurs a little less than 15 seconds later,

and the final one occurs approximately 30 seconds after the second.

Regardless of the sequence, the main idea is for temporary faults to clear during the

interval between reclose operations. This is commonly referred to as the “reclose

interval” between “shots.”

DR must disconnect early in the first reclose interval to allow the normal fault-

clearing sequence to proceed successfully. There are two generally bad consequences

if this fails to happen:

■ The fault fails to clear, resulting in at least one more operation of the fault interrupter. This increases the chance of damage to utility facilities and may subject customers to unnecessary outages.

DR must disconnect by this time

DR must disconnect by this time



■ The DR is still connected when the reclose occurs, resulting in damage to the distributed resource. This is less of a concern with inverter-based distributed resources, which have little inertia. However, it is an important concern for rotating machines, which can suffer winding and shaft damage due to out-of-phase switching forces.


■ Extend the first reclose interval. This is particularly important if the utility is accustomed to using instantaneous reclose. This greatly increases the chances of reclosing with DR still connected. Extending the interval to 1 second (s)or more will help ensure that the DR is off line. A few utilities require 5 s for the first reclose interval on any feeder containing DR. IEEE P1547 recommends a 10-cycle (0.16-s) delay on tripping to avoid nuisance tripping. This takes up a significant portion of an instantaneous reclose interval, which ranges from 0.2 to 0.5 s. Instantaneous reclose and DR are fundamentally incompatible.

■ Employ more-sensitive fault detection. A key to disconnecting the DR soon after the utility breaker operates is to anticipate the operation. This means detecting the fault at nearly the same time as the utility breaker detects it. One difficulty will be that the voltages seen by the DR relaying will frequently not be low enough during the fault. Negative sequence and reverse power (for non-exporting facilities) relaying can increase sensitivity.

5.3 Improving Reliability with DR

One does not have to look far into the DR literature to find statements claiming that

one advantage of distributed generation is improved reliability. As we shall see, the

validity of that claim depends on one’s viewpoint and how one defines reliability.

In this section, we look at some applications where there is an improvement in

reliability. Then in the subsequent section we evaluate applications that degraded

reliability.

Whose Reliability?

One of the first questions we must deal with is to clarify whose reliability is being

improved. This document is intended primarily for a utility audience, but it is not

always clear that the utility will realize a reliability benefit from DR. Most of the gain

in reliability goes to individual customers who have invested in DR that can also

serve as backup generation when the utility system is down.

When a utility looks at reliability, it is generally in terms of the standard reliability

indices that measure the average rates of quantities relevant to the sustained

interruptions of power in the system. For example, one standard measure of the



performance of utility systems is the System Average Interruption Frequency Index

(SAIFI), often written as

This index is a measure of how often the average customer in the system is

interrupted each year. The value is highly dependent on how one defines “system.”

Typically, utilities will report these values’ average over most, if not all, of their

service territory. A typical target for SAIFI ranges from 0.5 to 1.0. For a large system

with thousands of customers, the reliability improvement achieved for one customer

with backup generation is barely noticeable.

With the advent of better power quality–monitoring equipment and databases, some

utilities are able to scale the indices down to individual feeders or even sections of

feeders. Even from this perspective, the impact of DR on reliability is small. To see a

noticeable improvement in these indices, one would have to be able to restore service

to many customers by forming an independent island served by backup generation.

This is done by some utilities when serving remote areas by a single feed, but it is not

common. Most prefer to build alternate feeds by wire where that is economically

practical. For liability reasons, there is almost universal opposition to employing

customer-owned generation to form such islands.

If we scale this analysis down to a single customer, the perspective changes radically.

Although the average customer may experience only one interruption per year, some

may experience considerably more. Customers in rural areas where there are trees

along the feeders may experience four or more interruptions of three hours each. If

the value of the load justifies backup generation, customers—commercial and

industrial customers in particular—can expect a tremendous improvement in

electricity reliability by installing distributed generation.

Next, we examine three DR applications that can result in reliability benefits to the

utility system as a whole. Then we examine the use of DG for backup purposes by

customers seeking to improve reliability—by, essentially, the formation of single-

customer islands.

Siting for Transmission Support

Support for the transmission grid can be accomplished with DR connected to either

the transmission or the distribution system. It is common for utilities to install

peaking generation in their substations. This is convenient to the utility, because it

SAIFI(No. Customers Interrupted)(No. of Interruptions)

Total No Customers=

.



has control over the property, and substations also are likely to have connections to

utility energy management systems. This enables the utility to ensure that the

generation will be deployed as necessary to support the system.

Generation installed on the distribution system is likely to be customer controlled.

However, its use may benefit portions of the transmission system. In fact, there is

sometimes a bonus ranging from 5 percent to 20 percent with respect to transmission

relief, depending on where the generation is located on the feeder and how heavily

the feeder is loaded. The generator will reduce the losses and the reactive power

required to serve the load. For example, a 1-megawatt (MW) generator may reduce

the total demand on the transmission grid by 1.1 MW. On some severely

constrained systems, this can have a ripple effect back through the system, allowing

considerably more than 1 MW of additional load to be served.

The amount of capacity relief that DR brings to the transmission system depends on

a number of factors. Location is very important, and not every substation is in a good

position to offer relief. Others are in severely constrained areas where a little load

relief allows the transmission grid to serve several times that amount of load. If the

issue is simply the supply of electricity, and there are no grid constraints, then the

generation may be located on any substation in the service territory. However, DR

located in some areas will have a greater benefit than in other areas.

The value of DR in a particular location is determined by power flow studies. Figure

35 shows the results of determining the value based on loss reduction for a

transmission grid. Each filled circle represents a bus. The numbered buses indicate

the top six locations for 5-MW units for a particular contingency condition. A

different contingency may yield a completely different solution. Also, assuming a

different unit size would shift the distribution of generators slightly. One result of

this analysis that’s of interest to utility engineers is knowing where distributed

generation might be helpful. If this is the limiting contingency, some special effort

can be made to acquire generation on the substations at the buses shown.

The criteria for selecting the “optimal” site also have a great influence on the result.

Although losses are a good metric to use in general, because the results tend to

naturally alleviate congestion, there are other methods. For example, losses may be

weighted by the degree of line overloads. This will result in DR sites that reduce the

flows in the most heavily loaded lines that have a significant amount of losses.



Figure 35: The numbered locations indicate the top six locations for 5-MW generators on a transmission system based on loss reduction for a given contingency condition

Siting for Distribution Feeder Reliability Improvement

To provide support for distribution feeders, the DR must be sited out on the feeder,

away from the substation. This generally means the generation is customer-owned.

Generation located in the substation will be beneficial only when there is a constraint

in the substation transformer or the transmission system supplying the substation.

Where should the generation be located? The optimal DR siting problem is similar

to the optimal siting problem for shunt capacitor banks. Many similar algorithms can

be used. Some of the same rules of thumb also apply. For example, if the load is

uniformly distributed along the feeder, the optimal point for loss reduction and

capacity relief is approximately two-thirds of the way down the main feeder. When

there are more generators to consider, the problem requires computer programs for

analysis.



The utility does not generally have a choice in the location of feeder-connected DR.

When the DR is owned by the customer, the location is given and the problem is to

determine if the location has any capacity-related value to the utility. Optimal siting

algorithms can be employed to evaluate the relative value of alternative sites.

As in transmission grid capacity relief, location is very important. Due to the simple,

radial structure of most feeders, there is generally no constraint so severe that a DR

application will allow the serving of additional load several times greater than the size

of the generator. However, there can be a multiplying effect, as shown in Figure 36.

This figure shows that if we were to place 1 MW of generation in the substation, we

would not be able to serve any additional load on the feeder, because no feeder relief

is achieved. It would support the transmission system, but not the distribution

system. However, if there is a good site on the feeder, the total feeder load,

distributed as previously assumed, can grow by as much as 1.4 MW. This is one way

to measure the benefit of DR with respect to reliability and capacity issues.

Figure 36: Capacity provided by feeder-connected DR is dependent on location

0=∆∆

GEN

LOAD

P

P

4.1=∆∆

GEN

LOAD

P

P

0=∆∆

GEN

LOAD

P

P

4.1=∆∆

GEN

LOAD

P

P

This type of application is further illustrated in Figure 37. The feeder load has grown

to where it exceeds a limit on the feeder. This limit could be imposed by either

current ratings on lines or switchgear or bus voltage limits. There is DR on the feeder

at a location where it can actually relieve the constraint, and it is dispatched near the

daily peak to help serve the load. The straightforward message of the figure is the

load that would have to be curtailed can now be served. Therefore, reliability has

been improved.

This application is becoming more common as a means of deferring expansion of the

“wires” infrastructure. The generation might be leased for a peak load period.



However, it is more common to offer customers capacity credits to use the

generation for the benefit of the utility system.

Figure 37: Siting DR to provide feeder capacity relief

Daily Load Profile

Feeder Limit DG Dispatched ON

DG Sited to Provide Feeder Relief

Daily Load Profile

Feeder Limit DG Dispatched ON

DG Sited to Provide Feeder Relief

There is by no means universal agreement that this is a viable solution to the

reliability problem. When utility planners are shown this figure, most will concede

the obvious, but they won’t necessarily agree that this situation represents an

improvement in reliability. Three of the more powerful arguments against it are

these:

■ If the feeder goes out, only the customer with the DR sees an improvement in reliability. There is no noticeable change in the service reliability indices.

■ Customer generation cannot be relied upon to start when needed. Thus, reliability cannot be expected to improve.

■ Using customer-owned generation in this fashion masks the true load growth. Investment in wires facilities lags behind demand, increasing the risk that the distribution system will not be able to serve the load.

Support for Feeder Restoration

The use of DR to cover contingencies is becoming more common. Traditionally,

utilities have built sufficient wires capacity to serve the peak load, assuming one

major failure (the so-called “N-1 contingency” design criterion). At the distribution

feeder level, this involves adding sufficient ties to other feeders so that the load can be

conveniently switched to an alternate feeder when a failure occurs. There must also

be sufficient substation capacity to serve the normal load and the additional load

expected to be switched over during a failure. This results in substantial overcapacity

when the system is in its normal state with no failures.



One potentially economic application of DR is to provide support for feeders when

it is necessary to switch them to an alternate source while repairs are made. This may

be substantially less costly than building a new feeder or upgrading a substation to

cover this contingency.

Figure 38 depicts the use of DR located on the feeder for this purpose. The DR is

located near the tie points between two feeders. It is not used for feeder support

during normal conditions. When a failure occurs on either side of the diagram, the

open tie switch is closed to pick up load from the opposite side. The DR is

dispatched to relieve capacity constraints on the backup feeder. Locating the DR in

this manner gives the utility some flexibility and more reconfiguration options.

Figure 38: Using DR located near a feeder tie to help support contingencies

Of course, DR in this location is likely to be owned by the customer, and many

utility engineers will be reluctant to depend on it. Often only one of the alternate

feed options has significant constraints. For example, the constraint may occur only

when one attempts to pick up an entire feeder from an alternate source. For that, the

situation depicted in Figure 39 may be more palatable to utility engineers. The DR

would be located in the substation, where it would be under utility control. Basically,

the contingency being covered here is the loss of major substation components or a

transmission feed. A wires solution to solve this same problem will generally involve

the purchase of another transformer or the upgrading of transmission facilities. Either

can cost several million dollars. Thus, DR can offer an economically attractive way to

cover this contingency, particularly if the DR can be leased for only a few months

each year.



Figure 39: DR located in a substation can help support an alternate feed

Customer Islands

A great improvement in reliability may be achieved if islands can be formed. The

improvement is from the perspective of customers able to participate in the island.

Technically, when a customer uses backup generation, a one-customer island is

formed. Utilities are reluctant to permit the formation of islands consisting of several

customers. The liability for damage to load equipment and for the safety of the

public is too great. However, many utilities are faced with situations analogous to

that shown in Figure 40.

In this situation, there is a resort located 8 miles from the nearest substation, and

there is no alternate feed. The line to the resort passes through a heavily treed area

subject to many weather-related faults. High winds blow trees across the lines, which

requires several hours each time to restore power. For the sake of an example, let’s

assume that storms cause four outages each year totaling 20 hours of outage.

Figure 40: DR applied to support a customer island

8 mi

RESORTLOAD

B B

Generator

TREES

There are two options we might want to consider regarding application of the

generation. The generator could be employed strictly as backup or could be

implemented as cogeneration. Backup generation would be more common.

Cogeneration would be an appropriate consideration if there were sufficient thermal

load at the resort in addition to the electrical load.



With backup generation, the customer still sees four interruptions. However, their

duration is greatly reduced. Backup diesel gensets can start and be fully loaded in a

few seconds. That may or may not be appropriate behavior for the generation. In

cases where the load is not so critical, the end user may want to wait to see if the

utility is successful in clearing the fault. It may take, perhaps, 1 minute for the utility

breaker to complete its cycle. Thus, the average outage time is cut from 1,200

minutes to no more than 4 minutes.

Cogeneration, which would run continuously, is appropriate if there is sufficient

thermal load to utilize the waste heat from the generator. Gas turbines, natural gas

reciprocating engines, and microturbines are common technology that can provide

valuable waste heat. Diesel engines can also be used in such applications, especially if

emissions are not an issue. If we assume that once the utility tie breaker opens and

load transfers seamlessly to the generator, the expected customer outage minutes for

this load approach zero. The reliability is at least one order of magnitude better.

It should be noted that it is often difficult to make a smooth transition from

cogeneration to backup mode. The mismatch in active and reactive powers can cause

control swings that knock the generator off line. So there may still be a brief outage

while the generator is restarted or reconfigured to operate in standby mode.

The DR technology employed in this application must obviously be capable of

operating in stand-alone mode. Induction generators and some inverter technologies

require the utility system to be present to operate. Also, to provide satisfactory power

quality, the installed generator kVA capacity may have to be substantially larger than

the load. As a first guess, the generator size should be larger than the total load and at

least twice the size of the amount of motor load that will be started simultaneously.

This may be necessary to provide capacity to start large motor loads such as those

found in industrial processes, air handlers, and elevators. Harmonic-producing loads

such as adjustable-speed motor drives and large amounts of switch-mode power

supply load also require higher generator capacities to reduce bus voltage distortion

to a tolerable level.

The results illustrated for this resort example can be extrapolated to any customer

situations where the reliability is poor relative to the needs of the load. Such

customers can benefit greatly from some form of DR that can operate in backup

mode, and it can be more economical to solve the problem with DR than with wire-

based solutions.



5.4 Adverse Impacts of DR on Utility Reliability

In this section we explore several situations in which DR is detrimental to the

reliability of the electric power system. The issues raised form the core of the

reasoning behind the interconnection requirements found in the IEEE P1547

document.

Interference with Utility Fault-Clearing Process

The root cause of most interconnection conflicts for distributed resources that are

interconnected with utility distribution systems has to do with the actions that must

be taken to clear primary-side faults. Several examples have been discussed in great

detail in the first part of this section.

When faults fail to clear, some reliability effects are immediate, while others may take

years to surface. In many cases, the failed fault clearing will simply appear to result in

only a second, unnecessary breaker operation. This subjects line equipment to

additional short-circuit stresses. Substation transformers can fail due to through-fault

forces. Not only is this costly to the utility, but customer loads are also frequently

curtailed until a spare transformer can be moved in.

In other cases, failure to clear a fault means a fuse blows that otherwise would have

been saved. Customers on the affected lateral will suffer an outage typically ranging

in duration from 30 minutes to 3 hours.

Some utilities make only one attempt to clear faults. Therefore, failure to clear a

temporary fault results in a breaker lockout and an outage for all the load on the

feeder.

Extending reclose intervals also has a reliability impact. Utilities that use

instantaneous reclosing have done so because a significant number of customers

benefit by being able to ride through the very short interruption. Increasing the

interval time will cause many to shut down. For some processes, a momentary

interruption of 1 second is the same as a 4-hour sustained interruption for other

customers.

Masking of True Load Growth

This issue is one of the main reasons why many distribution planners will not give

credit for DR in capacity planning studies. If interconnected DR usage becomes

prevalent, the loading signals normally apparent in the substation are masked. Unless

special effort is made to keep track of all the DR installations, the planner is not

certain what the true capacity margin is.



There are at least two conditions in which this presents an operational issue that can

result in reduced system reliability:

■ All DR is required to disconnect to allow for clearing of faults. If the base capacity in the circuit isn’t there, the reclose operation will result in low voltages and overloaded feeders when a fault occurs at peak loading. Load will have to be curtailed unless many of the DR sites also disconnect the load with the generation.

■ The DR is not available at peak loading. This can happen for a variety of reasons, including equipment failure. However, there is also concern that the DR owner will be out of business or be otherwise financially unable to run the DR.

Therefore, utility planners often insist on building sufficient capacity to serve all the

load and will consider DR only as a temporary bridge to cover capacity shortages

while new base wires capacity is being built. As time passes and nothing is done to

improve base capacity, the view of the planner is that the loading eventually reaches a

point where the reliability is compromised.

Insufficient Amount of DR

Not only can there be so much DR that the load growth is masked, but having too

little can also impact reliability. It almost always takes a certain minimum amount of

DR before there is sufficient capacity to allow additional load to be served, either in

normal or contingency configurations.

Utilities are often faced with distribution capacity shortfalls of a few megawatts. To

solve this problem, they may develop a program to encourage the use of small,

energy-efficient DR by customers. However, it may take years to get enough capacity

in place to create a positive effect on reliability. This is the main reason why many

utilities choose to lease gensets in sufficient quantity rather than relying on customer-

side generation.

This issue highlights one of the key conflicts between utility planning and the use of

DR to support the system. Many of the advantages of DR come through the

application of energy-efficient systems on the customer side. In some cases, these

units may be best applied in sizes of a few kilowatts to a few hundred kilowatts,

whereas it generally requires a few megawatts of DR to defer distribution expansion

plans. Utility planners address their most pressing constraints first, which typically

require investment within one to three years. This is too short a time frame to set up

a program to get customers to install DR capacity in sufficient quantity because of

the high initial investment hurdle. DR is not like demand-side managment programs

that replace relatively low-cost items such as light bulbs, refrigerators, and air



conditioners. The only options left at this point are either to build new wires capacity

or lease larger-sized gensets. It would be better if smaller DR were targeted to

distribution planning areas that are growing but are several years from reaching a

constraint. This could slow growth sufficiently to eventually allow a significant

deferral.

When the system has evolved to the point where there are many sites of smaller-sized

DR owned by end users, how much capacity credit should be given for planning?

This is a question that can only be answered with time and experience. Assuming the

DR technologies have firm capacities and are not renewables without storage, there

appears to be gathering consensus for discounting the capacity by 30 to 50 percent.

This accounts for units that do not start when called upon for any reason. The units

could be down for maintenance or be prohibited from running because of emissions

limits or workplace rules.

Renewables would be discounted much more, depending on how well the output

coincides with the loading. In certain residential areas, solar photovoltaic (PV) array

output coincides well with the loading peak, and the discounting will be small.

However, in other areas, PV output will miss the 7:00 p.m. dinner-time peak and

must be discounted substantially. There is not a great amount of wind generation

connected to distribution systems, but the output of the existing generation is so

unpredictable that only 5 to 15 percent capacity credit can be given.

Inadvertent Islanding

Perhaps the greatest fear of the utility protection engineer is that DR will fail to

detect the fact that the utility breaker has opened and will continue to energize a

portion of the feeder. Therefore, much attention has been paid to detecting islands or

forcing islands to go unstable so they can be detected (IEEE Standard 929). The

reliability concern is that other customers will be subjected to such poor quality

voltage that equipment damage will be sustained. There is also the safety concern of a

generator accidentally energizing a line that was expected to be dead.

Relaying is one way to address the issue. Another is having requirements for the

operating mode while the DR is interconnected that significantly reduce the chances

that the generation will match the load when an inadvertent island forms:

■ Inverters operating in parallel are less likely to form an island if they are in current-source mode. This requires another source to provide a voltage for the current-source inverter to follow. Of course, this source could be provided by another synchronous generator that remains on the island.



■ All DR should operate in constant power factor or constant reactive power mode. For many devices, this will be unity power factor, producing watts only. Automatic voltage control (AVC) should be avoided while DR is interconnected unless the generator is directly connected to a control center to receive dispatching signals. Without the ability to regulate voltage, the load-generator match would have to be almost perfect to escape detection by the relaying schemes described in this document.

5.5 Harmonics from DR

Modern Inverter Harmonic Characteristics

All DG technologies that generate either DC or non-power-frequency AC must use

an electronic power inverter to interface with the electric power system. The use of

inverters has in the past resulted in greater harmonic distortion than one might get

from alternators. There are many who still associate DR with bad experiences with

harmonics from electronic power converters. If thyristor-based, line-commutated

inverters were still the norm, this would continue to be a large problem. Fortunately,

inverter manufacturers have adopted switching inverter technologies for the most

part, which has eliminated the bulk of the harmonics problems from inverters.

The early thyristor-based, line-commutated inverters quickly developed a reputation

for being undesirable on the power system. These inverters produced harmonic

currents in similar proportion to loads. Besides contributing to the distortion on the

feeders, one fear was that this type of DG would produce a significant amount of

power at the harmonic frequencies. Such power does little more than contribute to

losses in lines and transformers.

To achieve better control and to avoid harmonics problems, inverter technology has

changed to switched, pulse-width modulated (PWM) technologies, resulting in a

more friendly interface to the electric power system.

Figure 41 shows the basic components of a utility interactive inverter that meets the

requirements of IEEE Standard 929-2000.7 Direct current is supplied on the left

side of the diagram either from a conversion technology that produces DC directly or

from the rectification of AC generator output. Variations of this type of inverter are

commonly employed on fuel cells, microturbines, photovoltaic solar, and some wind

turbines.

The DC voltage is switched at a very high rate with an insulated gate bipolar

transistor (IGBT) switch to create a sinusoidal voltage or current of power frequency.

The switching frequency is typically on the order of 50 to 100 times the power

frequency. The filter on the output attenuates these high-frequency components to



such a degree that they are usually negligible. The largest low-order harmonic

(usually the fifth) is generally less than 3 percent, and the others are often negligible.

The total harmonic distortion (THD) limit is 5 percent, based on the requirements

of IEEE Standard 519-1992. Occasionally, there will be reports of inverters

exceeding these limits under specific conditions, but the harmonic issue with

inverters is certainly much less of a concern than with the older technologies.

Figure 41: Modern pulse-width modulator switching inverter schematic

SWITCHINGCONTROL

VOLTAGE

CURRENT

FILTERAC SWITCHDC

While interconnected to the utility, commonly applied inverters basically attempt to

generate a sine wave current that follows the voltage waveform. Thus, it would

produce power at unity power factor. It is possible to program other strategies into

the switching control, but the unity power factor strategy is the simplest and most

common. If the inverter has standalone capability, the control objective would

change to producing a sinusoidal voltage waveform at power frequency, and the

current would follow the load.

One problem, which occurs infrequently, arises when a switching inverter is installed

in a system that is resonant at frequencies produced by the switching process. The

symptom is usually high-frequency “hash” appearing on the voltage waveform. The

usual power quality complaint, if any, is that clocks supplied by this voltage run fast

at times. The typical circuit condition that yields this resonance will usually involve a

cable run and no power factor correction capacitor bank. The cable adds enough

capacitance to bring the system resonance into the 35th to 50th harmonic range.

This problem is generally solved by adding a capacitor to the bus that is of sufficient

size to shunt off the high-frequency components. Of course, one must be careful

when sizing the capacitor to avoid causing other resonances that might be harmful.



Machine Harmonics, Winding Pitch, and the “Harmonic Surprise”

Harmonics from rotating machines are not always negligible, particularly, in grid-

parallel operation. The utility power system acts as a short circuit to zero-sequence

triplen harmonics in the voltage, which can result in surprisingly high currents. For

service transformers connected grounded-wye/wye or delta/wye, only synchronous

machines with two-thirds pitch can be paralleled without special provisions to limit

neutral current. For service transformer connections with a delta-connected winding

on the DG side, nearly any type of three-phase alternator can be paralleled without

this harmonic problem. Refer to the “Harmonic Surprise” section in Section 6 for

additional details.



6. Application Problems

This section presents a series of mini case studies through which common issues and

problems related to distributed resources (DR) on the distribution system are

illustrated with quantitative examples. The goal is to illustrate problem analysis and

resolution that uses the information and approaches described in previous chapters.

6.1 Voltage Change upon Interconnection or Reclose After a Fault

One of the major limitations on the amount of DR than can be accommodated on a

distribution system without costly changes is how much the system voltage changes

for DR interconnection or disconnection. This is often the principal limitation when

the DR is located a considerable distance from the substation.

There are two conditions of concern: when DR is connected and ramped up to full

power and when DR is forced off to clear faults on the utility system.

The former condition may only be significant when there is a single, large DR

installation. When there are widely distributed DR locations, each making its own

decision about when to connect, the interconnection voltage swing might occur

slowly. This will allow standard utility voltage regulation equipment to keep up with

the voltage change.

Regarding the latter condition, it is a universal requirement for DR to disconnect for

faults on the utility system and remain disconnected for up to 5 minutes (per IEEE

1547). Thus, all the DR will be suddenly removed from the feeder. The voltage

change that occurs when the utility breaker recloses without the DR is often a good

measure of the feeder’s degree of dependence on DR for capacity. If the change is too

great, however that is defined, then changes will have to be made to the system.

One approach to studying this issue is to compute the voltages immediately before

and after the connection to DR is energized. Figure 42 shows the results of one such

study on a 25-kilovolt (kV)–class feeder. This represents the result of thousands of

cases in which the DR was randomly placed along the feeder in random sizes and for

random loadings. The voltage rise when the DR was interconnected was plotted for

each case, and contours of constant voltage change were developed as shown. The

dark heavy lines are a linear approximation to three of the contours: 1.0, 1.05, and

1.10 per unit (pu) voltage. That is, voltage rises of 0, 5 percent, and 10 percent,

respectively.

The contours are plotted as constant voltage for distance from the substation and

excess generation over load. Excess generation is defined as the total DR power

minus the total load power. Though a similar plot could be made using generation



megawatts (MW) alone for the horizontal axis, the correlation is stronger for the

excess generation quantity.

Figure 42: Contours of voltage rise when interconnecting DR randomly in distance along the feeder and in feeder loading

-10 -5 0 5 10 15 200

5

10

15

20

25

30

35

40

1.0

1.05

1.1

1.15

Distance from Sub, km

Excess Generation, MW

-10 -5 0 5 10 15 200

5

10

15

20

25

30

35

40

1.0

1.05

1.1

1.15

Distance from Sub, km

Excess Generation, MW

Values for this plot can be computed from relatively simple power flow analyses.

However, the program must be capable of properly representing the behavior of load

tap changers (LTC), regulator, and capacitor controls.

To use this data, which applies to a specific feeder, let’s assume we want to install a

generator 20 kilometers from the substation and restrict the maximum voltage

change to 5 percent. The 105 percent contour indicates that the excess generation

would be zero in this case. In other words, the generation should not exceed the

minimum load. At this distance from the substation, the chart suggests that there is

approximately a 1 percent change in voltage per MW of generation. Naturally, this

general result is dependent on feeder topology, load distribution, and line

impedances.

The closer the DR is placed to the substation, the greater the amount of DR that can

be accommodated according to this criterion.



Symptoms

The symptoms or DR impacts on feeder voltage stability are large voltage changes

that may coincide with other major events such as faults. If there is too much DR on

the feeder with respect to the constraints of excess generation and distance of that

generation from the substation, the voltage will be noticeably low immediately

following a utility breaker operation to clear a fault. This may gradually correct itself

over the next minute or so, depending on the settings on the voltage regulation

equipment.

A rise can also occur if large amounts of DR are energized and ramped up to power

quickly. This might be a large genset used for peaking or a large cogeneration facility

coming on line. It can also happen for numerous small distributed resources after

they are forced off for fault clearing. If they follow the P1547 document, they will

reconnect after a time delay of 5 minutes or some other time specified by the utility.

Solutions

One solution is to require the customer with DR to remove the load as well as the

DR when the DR is forced off. Another is to restore the feeder in stages. Both

solutions may result in poorer reliability for some customers.

The voltage change will be greater when the DR technology produces or consumes

more reactive power. Therefore, another solution is to require the DR to operate near

unity power factor. A voltage change will still occur, but it will be less severe. Unity

power factor is normal for many inverter-connected DR technologies. The reactive

power for induction machines cannot generally be controlled, and external capacitors

must be used to compensate for reactive power consumption. This solution is

acceptable as long as harmonic resonances are avoided and capacitor switching

transients are tolerable.

Another strategy is to stagger the reconnect delay when there are numerous DR

devices so that they don’t all come back on at the same time after fault clearing.

6.2 Harmonic Surprise with Rotating Machines

A commonly held misconception is that standby generation can simply be intertied

parallel with the utility to export power from the generator onto the grid.

Unfortunately, many machines do not have the proper design to accomplish this.

They produce too much third harmonic voltage as a result of their designed winding

pitch. Machines that do not have a two-third pitch winding may generate 5 percent

third harmonic voltage, or more.



This does not sound like much and is not a problem when the DR is operating as

backup generation, because the load impedes the flow of third harmonic current.

Harmonic currents from the load are often much larger. However, the impedance of

the utility system is so low that it appears almost like a short circuit to any harmonic

voltages the generator might produce. This results in what we call “the harmonic

surprise” when the paralleling breaker is closed.

Figure 43 illustrates one case in point. The facility was fed by a standard delta/wye

transformer serving the plant at 480 volts (V) (277 V line-to-neutral). The standby

generator was the same kilovolt-ampere (kVA) rating as the transformer and was also

wye-connected and solidly grounded. When paralleled, the installers were surprised

by the large amount of current measured in the neutral conductor: more than 25

percent of the full rated current.

Figure 43: Genset owners are sometimes surprised by high circulating third harmonic currents when paralleling DR with the utility distribution system

If we assume that the generator produces 5 percent third harmonic voltage, the

mystery is quickly solved. The current is limited only by the third harmonic

impedance of the machine and the transformer. The generator impedance seen by

harmonic frequencies is the subtransient reactance, Xd" (14 percent in this case).

From the wye side, the transformer offers only its short-circuit (leakage) reactance of

5 percent, because the delta winding essentially short circuits the third harmonic

current, which is a zero-sequence harmonic (all three phases are in phase with each

other rather than separated by 120 degrees). Multiplying the reactances by 3 to

account for the higher frequency results in 8.8 percent third harmonic current in

each phase. The currents add together at the neutral points, yielding 26 percent in

the neutral paths.

DELTA / WYETRANSFORMER

Z=5%

277/480V

Xd"=14%8.8% ThirdHarmonic

3 x 8.8% = 26%Third Harmonic



This current simply circulates, causing losses and phase voltage imbalance, which

limits the output of the generator and may interfere with its control. It could also

place excessive duty on neutral conductors, depending on their size.

Symptoms

■ The generator trips out on ground overcurrent or by thermal protection. It is not possible to produce full power from the generator.

■ High neutral currents and unbalanced phase voltages are measured. A power quality monitor would indicate high third harmonic currents and voltages.

■ An infrared scan shows heating at neutral conductor junctions.

Solutions

■ Vendors of engine gensets will generally insist on a two-thirds pitch machine for applications where a backup generator may be connected grid-parallel at some time. If it is not possible to change the machine, a reactor may be inserted in the neutral of the generator to limit the current while the DR is operating in parallel with the grid. When operating in stand-alone backup mode, the reactor may be shorted out with a bypass switch.

■ A different transformer with a delta-connected secondary will prevent the flow of third harmonics. Likewise, a delta-connected alternator will cancel out the third harmonic.

6.3 Desensitizing Utility Relays

Overcurrent relays on the utility system are set to detect a range of fault currents.

The minimum pickup value is selected so that the relay can sense specified high-

resistance faults at a certain location on the feeder. This defines the zone of

protection. This zone should overlap the next series overcurrent device downstream.

If it is the last device, the zone must extend comfortably past the end of the feeder.

Relay settings are established assuming current contributions from only one source.

Some computer programs for computing short circuits consider load effects, while

others ignore it. Normally, it is a minor issue, but when there is considerable

impedance in the circuit and the fault, small changes can make the difference

between detecting a fault and not.

This example describes an analysis to determine the potential impact of DR in the

rural part of a feeder (Figure 44). The feeder is lengthy and consists of an urban

section and a rural section. A Cooper Power Systems VWE line recloser is installed

near the urban/rural boundary. The recloser pickup current was 280 amperes (A),

and its operating sequence was 1A3D.



Figure 44: One-line diagram of a feeder

The proposal was to use customer-owned DR (gensets) positioned along the rural

part of the feeder to help support the feeder during peak load. One concern was the

impact of the DR on the ability of the recloser to see faults at the end of single-phase

laterals. Fault simulations were conducted over a range of fault resistances and total

DR sizes. A chart of the results is shown in Figure 45.

At peak load, there is already considerable current flowing in the recloser. Therefore,

it does not take much additional current to trip the recloser, and the recloser is

actually able to detect a 50-ohm fault at the end of the lateral. This is quite sensitive.

Analysis of the fault currents at no load suggests that the protection engineers

originally designed the system to detect a 20-ohm fault at the end of the single-phase

lateral. As the amount of DR increases, the recloser sees less of the fault current,

because the DR is closer to it. Approximately 600 kVA of DR contributes sufficient

fault current that a 20-ohm fault is required at peak load to trip the recloser.

Obviously, if there were more than 600 kVA, the protective zone would be reduced

below the original design sensitivity.

This result will vary somewhat with the assumed locations of the DR, but the trend

would be about the same.

VWERECLOSER,280A, 1A3D

HIGHIMPEDANCE

FAULT

1-PHASELATERAL

DR

LOADS



Figure 45: Current seen through recloser for various fault resistances and size of DG

Reduction of Reach of Recloser(at peak load)

0

100

200

300

400

500

600

700

0 10 20 30 40 50 60

Fault Resistance, Ohms

Cu

rren

t T

hro

ug

h R

eclo

ser

No DG100 kVA200 kVA400 kVA600 kVAMin Pickup

Symptoms

One of the chief sources of high-impedance faults is vegetation contacting overhead

lines. Therefore, one symptom would be evidence of faults burning for extended

periods. This evidence can come from customer reports or by observing arc damage

on lines, pole hardware, and trees. Of course, this happens without DR being

present. The impact of DR would be to increase the risk of extended arcing times.

Another symptom would be blown lateral fuses. The recloser sequence is designed to

save the lateral fuses. During a fault with DR still feeding the line, the fuse sees the

full fault current, although the current in the recloser is reduced. This can easily

result in fuse-saving failure. In fact, in this case it was found that the fuse-saving

failures would be expected to begin occurring when the total DR capacity increases

to approximately 300 kVA.

Solutions

If the DR is to be used only for intermittent peaking purposes, no action may be

necessary, because this represents a small window of opportunity for a high-

impedance fault event. If action is to be taken, the first consideration is to lower the

minimum pickup on the recloser to make it more sensitive.

In this case, the recloser is already nearly too sensitive for the peak load current. It

would not be wise to reduce the pickup level, because it would result in nuisance



trips. The best option is to install another recloser farther downline. Depending on

the topology, the least-cost solution may be to use a few single-phase reclosers on the

longer single-phase laterals.

Relay desensitizing is not generally an issue for high-current faults unless the DR

capacity approaches the basic feeder capacity (for example, a large cogeneration plant

on the feeder).

6.4 Coordinating with Reclosing

As pointed out in previous sections, most utilities in North America practice

reclosing for faults on overhead lines. This creates two conflicts with DR

applications:

■ The line must be dead for a certain period of time (typically 6 to 12 cycles, depending on weather conditions) to ensure that the fault arc has dissipated sufficiently to withstand system voltage. DR must separate from the utility system early in the reclose interval to allow sufficient time for the fault arc to extinguish. Otherwise, the fault will re-ignite when the utility breaker recloses, and a second operation of the breaker will occur, probably causing some customers to experience a sustained interruption unnecessarily.

■ If the reclose occurs while the DR is still interconnected, there is a good chance of damaging the DR, particularly if it is a rotating machine.

Concerning the latter situation, Electrotek has seen evidence from three cases of out-

of-phase reclosing on DR. Two were created on purpose as part of a laboratory test.

The breaker was timed to reclose nearly 180 degrees out of phase on both a 1-MW

synchronous machine and an inverter that was intentionally kept operating

(normally, it would be expected to halt switching). The inverter resynchronized

quickly with no noticeable adverse impacts. However, the generator expelled pieces

of insulation. Although it did not fail electrically, one must assume some permanent

damage was done that will shorten the machine’s life.

The third case involved a low-head hydro generator. It had suffered a failure in either

the shaft coupler or the shaft itself that was attributed to line recloser operation. A

dynamics simulation clearly showed that excessive stresses to the generator would

result from reconnecting it to the utility out of phase.

This evidence supports Electrotek’s long-held contention that instantaneous

reclosing and interconnected DR are incompatible, particularly for rotating machine

generation. Sooner or later, a reclose operation is going to catch a unit still on line

and cause damage to it.



Symptoms

The key symptoms when the reclosing interval is too short for DR are these:

■ Breakers and reclosers frequently go through two shots to clear the fault.

■ Fuse saving is failing.

■ DR owners complain about equipment damage after being “surged by the utility,” or words to that effect.

Solutions

The first low-cost solution to consider is to extend the reclose time. This is

particularly true if instantaneous reclose is being used. It may not be technically

possible for the DR to always disconnect before the reclose. Extending to 1 or 2

seconds (s) is often sufficient, although some utilities use 5 s on feeders with DR.

When the cost is warranted, direct transfer trip and reclose block are possible

solutions. Transfer trip ties the operation of the DR interconnection breaker to the

utility breaker. Reclose block generally involves adding a three-phase potential

transformer bank on the load side of the recloser to sense the presence of voltage. If

voltage above a certain magnitude is present on any of the phases, the close operation

is blocked. Modern microprocessor-based recloser controls generally come with this

feature built in.

6.5 Ferroresonance

Ferroresonance is a special kind of resonance in which the inductive element is the

nonlinear characteristic of an iron core device, such as a power transformer. The

most common occurrence of ferroresonance occurs when the magnetizing reactance

of a transformer inadvertently is in series with cable or power factor capacitance.

However, it also occurs with rotating machines and is one possible problem that

arises from the interconnection of generators with the utility system.

One interesting case that is not necessarily unique to distributed generation occurs

for DR units served by cable-fed transformers. Many of the larger installations are

required to have their own transformer. The DR is also required to disconnect at the

first sign of trouble on the utility system. This combination of requirements can lead

to a common ferroresonant condition, as illustrated in Figure 46. Underground cable

runs are normally fused at the point where they are tapped off the overhead feeder

line. This is variously called the riser pole or dip pole. Should something happen that

causes one or two phase fuses to blow, the relaying on the DR will detect an

unbalanced condition and trip the generator relay. This leaves the transformer

isolated on the cable with no load and is a prime condition for ferroresonance,



because the cable capacitance in an open phase, or phases, now appears in series with

the transformer’s magnetizing impedance (Figure 47).

Although this normally is a reliable installation that may last for years in service

without any problems, there are several reasons why the fuses may blow or become

open. Normally, they are designed to blow for faults in the cable, but there are other

reasons. Animals such as squirrels or snakes may climb the pole and get across the

line. Fuse elements may also fatigue due to frequent inrush currents or lightning

surge currents. Fused cutouts may open due to corrosion or improper installation.

Finally, they may be operated by the line crew for maintenance purposes.

Figure 46: Typical cable-fed service transformer configuration

Figure 47: Schematic showing how the magnetizing impedance of a delta-connected transformer appears to be in series with the cable capacitance when one fused cutout is open

PADMOUNTEDSERVICE

TRANSFORMERGENERATOR

BREAKER

PRIMARYDISTRIBUTION

CABLE

FUSED CUTOUTS

RISER POLE



Whether this fuse blowing results in damage depends on many variables and the

specific design of the equipment. A number of ferroresonance modes are possible,

depending on the connection of the transformer, its size, and the length of cable. The

most susceptible transformer connections are the ungrounded ones: delta and

ungrounded-wye. The delta configuration with one phase open is shown in Figure

47. The overvoltages for this condition that can occur can easily reach three to four

per unit. Figure 48 shows the voltages computed for a 300-kVA delta-connected

transformer fed by cable that has 30 nanofarads (nf) of capacitance. This figure

models a case in which there is no load on the transformer and no arresters. Arresters

would clamp the voltage to a lower value unless they thermally failed from prolonged

exposure to this waveform. The high voltages and the chaotic waveshape are due to

the transformer slamming in and out of saturation. The magnetic forces associated

with this change cause the core to emit very loud noises that are sometimes described

as something loose inside the transformer or a chorus of hammers on anvils.

Figure 48: Typical voltage waveforms for the condition in Figure 47 with no load or arresters (scale is 1.0 per unit per vertical division; from Electrotek’s FerroView™ program)

This can cause failures of both the arresters protecting the transformers and the

transformers themselves. Arresters fail thermally, leaving the transformers

unprotected. Then the transformers may fail either from thermal effects or from

dielectric failure.

At one time it was believed that grounded-wye connections were impervious to

ferroresonance. However, this was shown to be false in a landmark paper.8 Although

grounded-wye transformers made up of three single-phase transformers, or a three-

phase shell core design, are immune to this type of ferroresonance, the majority of

pad-mounted transformers used in commercial installation are of three-legged or

five-legged core design. Both are susceptible to ferroresonance due to phase coupling

through the magnetic core. Although not immune to ferroresonance, the

overvoltages are lower than with ungrounded connections, typically ranging from



120 percent to 200 percent. Sometimes, the voltages are not high enough to cause

immediate failure of the transformer, although the transformer may be making

considerable noise. However, some load equipment with a low tolerance for

overvoltages will be subject to failure. It is common for low-voltage arresters and

transient voltage surge suppressors to suffer failures during this type of

ferroresonance. The utility line crew responding to a trouble call may discover that

the transformer is making a lot of noise but is still functional. In other cases, there is

no detectable damage. In yet other cases, there may be a burned spot on the paint on

the top of the tank where high fluxes in the core have caused heating in the tank.

Primary arresters should be tested and the secondary inspected for failed equipment

before re-energizing.

As stated above, this problem is not necessarily unique to DR installations. Many

modern commercial facilities also have cable-fed service transformers and also

disconnect the mains when there is a problem on the utility system. The purpose

here is to switch to uninterruptible power supply systems or backup generation.

Unfortunately, doing so leaves the transformer isolated on the load with little or no

load.

Symptoms

For the DR installation with a separate service transformer, ferroresonance is usually

first noticed by the noise emitted by the transformer after the generator disconnects.

There may also be a transformer failure, which will trip a relay. If there is any small

load, such as lighting and generator control power that are still connected to the

service transformer, lamps may be flickering randomly and controls may exhibit

unexplainable behavior.

Solutions

There is a general rule when interconnecting three-phase DR to a distribution feeder

that there be no line fuses or single-phase reclosers between the generator and the

utility substation. This is to prevent single-phasing the generator, which can not only

result in ferroresonance but can also thermally damage rotating machines. This rule is

particularly appropriate for DR with cable-fed service transformers. The riser pole

fuses may be replaced with solid blades (no fuses) or three-phase switchgear such as a

recloser or sectionalizer. Replacing the fuses with solid blades will reduce the

reliability of the feeder section somewhat. Each time there is a fault on the cable

system, the entire feeder or feeder section will be out of service. If the cable is short

and dig-ins unlikely, this may very well be the lowest-cost option. If protection is

required, the three-phase switchgear option is recommended.



The type of ferroresonance shown in Figure 48 is very sensitive to load. If the system

can be designed so that there is always a relatively small resistive load attached to the

secondary bus, the resonance can be damped out. Figure 49 shows what happens to

the voltages when a 2 percent load (6 kilowatts) is attached to the transformer. The

open phase voltage quickly declines to approximately 25 percent, which is not a

concern. Not just any load will do: the load must appear resistive. Inductive loads

may not be satisfactory.

Some utilities will use a portable load bank when performing manual switching

operations on unloaded transformers susceptible to ferroresonance. The load bank is

removed when all three cutouts are completely open or closed. This is a very effective

means of limiting the chances of damaging ferroresonance.

For transformers serving loads, it is often possible to find a small amount of lighting

load or other resistive load to leave connected to the mains when the bulk of the load

is transferred to backup generation. The problem with many DR sites is that there is

no tie between the load bus and the generator bus. Sometimes, DR sites will use a

resistive load bank for testing the generator. One strategy to prevent ferroresonance

in susceptible installations is to switch in a small load bank on the transformer bus

whenever the generator is tripped off by a relay that has detected a utility-side

disturbance. Because this is done on the secondary, the cost is likely to be lower than

the primary-side options.

Figure 49: Voltage waveform for the condition in Figure 48 with 2 percent load (scale is 0.5 per unit per vertical division)

6.6 Capacitor Switching

Utilities use switched capacitors to help support the voltage during high load periods.

These banks are mostly controlled by local intelligence and are switched at

predetermined times or loading level as measured by either voltage, current, or

kilovolt ampere reactive (kVAR). Some types of DR can also produce reactive power

(VARs), and this can create control hunting (oscillating around a desired control



valve) and other difficulties. Here, we describe one common interaction that can

cause synchronous machine gensets to trip off.

There can be several capacitor banks on the feeder, as illustrated in Figure 50. The

capacitors switch independently of the generator control unless special

communications and control have been added to coordinate their dispatch. A 2 to 3

percent increase in voltage is common when a typical capacitor bank is switched on.

The preferred mode of operation for the generator in parallel operation is generally to

maintain a constant power and power factor. The reactive power of the machine is

controlled by the exciter field, which has minimum and maximum limits. The

generator control attempts to maintain a constant reactive power output until it

bumps up against one of these limits. There can be conditions in which the total

reactive power output of the generator and all the capacitors is too great, resulting in

high voltages. This is particularly likely when capacitors are switched by time clock or

by current magnitude (without voltage override).

Figure 50: Utilities commonly employ numerous switched capacitor banks on distribution feeders, which may not coordinate well with generator field controls, causing nuisance generator tripping

At least three things can happen at this point to trip the generator:

■ The generator control senses overvoltage at its terminals and attempts to back down the field to compensate. However, the utility system overpowers the generator, and the field reduces to a level deemed to be too low for safe operation of the machine.

■ When the generator reaches its voltage limit, reactive power flows back into the machine. When it reaches a certain level, the generator protection interprets this as a malfunction.



■ DR technologies not capable of producing reactive power (some inverter interfaces) trip on overvoltage.

Symptoms

The chief symptom will be that the DR trips off line frequently—perhaps as often as

once a day. Tripping may also occur at the same time each day, which is a clear

indication of a miscoordination between the DR and a time-controlled capacitor

bank. Tripping may occur only on weekends, when the load is low and system

voltages tend to run high.

Solutions

■ One solution is to change the tap on the service transformer to reduce the voltage at the generator terminals.

■ It may be possible with appropriate communications and control to inhibit the switching of certain capacitors when a generator is running. The utility may also choose to simply remove a capacitor from service and rely on the DR to produce the reactive power. The DR technology would have to be appropriate for the application and must be likely to be on line when needed.

■ Problematic machines may be replaced with less-susceptible ones. There is variability in the excitation capabilities of synchronous machines, and some are more tolerant of operating at low field levels or at negative power factor.



7. Engineering Analysis of DR Interconnection

In this section we describe various analytical tools used in distribution system

engineering. We evaluate the capabilities of common software tools for analyzing

systems with distributed generation and suggest approaches for incorporating DR

models.

7.1 Basic Power Flow

Power flow analysis is the chief tool used by distribution planners to evaluate capacity

and operational issues on distribution systems. Distribution engineers have been

traditionally most interested in what happens at peak loading. Therefore, most of the

distribution analysis tools that have been designed for feeder analysis were originally

designed to handle the peak loading case. Many programs analyze only one feeder at

a time and assume a simple equivalent for the transmission system.

The proper analysis of DR will require more extensive simulations in many cases.

Although there are things that can be learned by studying the peak load situation

only, there are often cases that require looking at daily load cycles and other off-peak

conditions.

Common Distribution Power Flow Solutions Techniques

The most popular technique for computing radial system distribution power flow is

the so-called forward-backward sweep. There are numerous variations on this

technique to handle the diversity of odd situations that arise, but the basic

methodology is illustrated in Figures 51 and 52. Note that some analysts in this area

will define forward and backward opposite from what is shown here.

Figure 51: Backward sweep: Compute shunt element (such as load), currents, and currents in branches, summing back to the source

I = f(V)

Loads Capacitors

I = f(V)

Loads Capacitors



Figure 52: Forward sweep: Compute voltage drop in each segment along the feeder, starting with the source

I = f(V)

Loads Capacitors

Normally, one starts with a good guess at the voltages throughout the system. One

way to get this start is to do the forward sweep (Figure 52) assuming no current is

flowing. This gives a “flat” starting voltage that automatically takes into account such

things as regulator taps and off-nominal tap substation transformers.

Next, the algorithm starts at the ends for the feeder and works its way back toward

the source. This is the backward sweep (Figure 51). Given the guess at the bus

voltages, estimates of the current in all the loads, capacitors, and any other shunt

elements are computed. Because there is only one path to the source, the line

currents are computed simply by summing all the downline currents. Software

developers have come up with very ingenious techniques for making this process fast

by determining the order in which the branches are accessed.

After all the branch currents have been computed, the forward sweep begins. Starting

at the infinite bus (source equivalent), the voltage drops are computed in each branch

segment. The sequence of accessing the segments is usually the reverse of the

backward sweep. The shunt elements are not of concern in this sweep; only the series

elements or power delivery elements are considered, including lines, transformers,

switches, and regulators.

The algorithm repeats the backward and forward sweep until the solution converges.

For most distribution systems, the number of iterations will typically be three to five.

When the system is more heavily loaded, the number of iterations typically will

increase to 10 or 15. Convergence may be decided by voltage magnitude, power, or

current. Voltage convergence is probably most common with a typical convergence

tolerance being 0.0001.

This methodology differs considerably from the traditional Gauss-Seidel or Newton-

Raphson algorithms. There are no big matrices to handle. Problems are typically

worked in actual ohms and volts rather than per unit. The method is favored,

because it offers several advantages, including these:



■ Speed is probably the greatest advantage to developers of distribution analysis software. This method is much faster than power flow methods designed for large meshed networks. Speed is nearly linearly proportional to problem size, allowing very large radial systems to be solved in seconds.

■ Sequencing of the voltage regulation devices (regulators) and capacitors falls out naturally from the sweep algorithm.

■ A wide range of load models and models of other shunt elements is easily handled. These elements are basically treated as current injection sources into the power delivery network.

This method falls into the general class of point-Jacobi methods for solving nonlinear

equations. As such, there are some limitations to the range of values for which the

solution will converge. To summarize briefly, the limitations basically boil down to

meaning that the apparent impedance of all the shunt-connected elements must

always be greater than the impedance of all the series elements. Quite a strain is put

on the convergence of this method when the voltage drops below 80 percent. The

lower limit is generally around 70 percent. This is not a concern for power flow

calculations where we expect the voltages to be greater than 90 percent. However, it

means that this method of solution is restricted to power flows and cannot be used

for short-circuit calculations or harmonics analysis.

Developers have been quite creative in working around these limitations. Some

models will automatically change to a linear element during the solution process so

that convergence can be achieved at low voltages.

This method does not apply directly to network circuits. However, many

distribution systems have spot networks or other weakly meshed systems. When there

are not many loops in the system, these can be analyzed with radial system

algorithms by using a few tricks.9 One simple one is shown in Figure 53. The

network is broken in a selected location and the loop tie replaced with equal and

opposite current injection sources. The system topology reverts to radial, allowing

the radial solution algorithm process to be used. The iteration process is modified to

enforce the Kirchoff constraints at the break point as closely as possible.



Figure 53: Handling weakly meshed networks in radial power flow algorithms

LOOP BREAK THE LOOP AND REPLACE WITH EQUAL AND OPPOSITE CURRENT INJECTIONS

Balanced versus Unbalanced Three-Phase Modeling

Distribution systems have many unbalanced elements. Figure 54 shows some of the

situations that can occur:

■ Single-phase loads. Connected either line-to-neutral or line-to-line.

■ Capacitor banks with blown fuses. This is a common occurrence and sometime affects DR.

■ Open-delta regulators. Sometimes used on rural three-phase feeders feeding resort areas where wind generation, small hydro, or even diesel generators might be located.

■ Untransposed distribution lines. Few are balanced.

■ Neutral impedances in transformers and capacitors.

Other common imbalances not shown include

■ Single-phase or two-phase laterals.

■ Overbuilt double-circuit lines sharing a common neutral.

■ Three-phase transformer banks made up of transformers of unequal sizes.

■ Odd transformer connections: open-wye, open-delta, scott-T, or four-wire delta.

■ The usual 240/120-V center-tapped single-phase service transformer.

These present quite a modeling challenge for power flow programs. In fact, the open

delta regulator bank is one of the benchmark cases for testing a distribution analysis

program. If it can model that, it can model almost anything. Is it necessary to model



these for DR analysis? There is no definite answer to this question. Sometimes it is

necessary, but there are also cases where a simplified balanced model will suffice.

Figure 54: Example showing some of the extreme types of imbalances that can occur in distribution systems

Although traditional power system (that is, transmission system) load flow programs

are balanced solutions, many distribution power flow packages can model

unbalanced systems. The default mode may be unbalanced systems. Given the

current interest in this subject—much of it driven by DR—nearly all distribution

analysis packages in the near future will have unbalanced, three-phase solution

capability with few modeling limitations. However, the simplified balanced

equivalent will generally solve faster and still has a place.

Balanced, positive-sequence models are adequate for the following analyses related to

applying DR:

■ Capacity studies where three-phase lines, capacitor banks, and the like are the only options being considered for solutions. One generally does not plan for imbalance. One leaves some engineering margin in the design to allow for the effects of imbalances in the actual system.

■ Siting and sizing of three-phase DR based on losses or released capacity.

■ Loss-reduction studies. Though 30 to 40 percent of the losses on a feeder may be on the single-phase laterals, if the only solution being considered is three-phase DR, it is necessary to model on the three-phase portion of the system.

■ Some short-circuit studies. The three-phase fault is often either the worst case or a sufficient case for determining the response of the DR.

Blown Capacitor Fuse

Neutral ReactorSingle-phase Loads

Open-Delta Regulator Bank

Blown Capacitor Fuse

Neutral ReactorSingle-phase Loads

Open-Delta Regulator Bank



■ Some islanding studies. Normally, this is done by opening a three-phase switch or breaker and determining how quickly the voltage and frequency deviate from normal. If this shows a high potential for islanding, it might be worthwhile to then build an unbalanced model and add single-phase loads. Some DR will have difficulty serving an unbalanced load, and that would not show up in a balanced dynamics analysis.

■ Some reliability studies.

Unbalanced models are necessary for the following:

■ Designing or operating close to the feeder current and voltage limits. Imbalances can create significant difference between the phases.

■ Modeling long single-phase or two-phase laterals.

■ Studying high penetrations of single-phase DR.

■ Detailed short studies to determine what the DR protective relaying will see for unbalanced utility-side faults.

■ Determining dynamic or other response of DR to unbalanced utility faults (80 to 90 percent will be single-line-to-ground faults).

■ Voltage fluctuation studies for wind generation fed from long, untransposed feeders with single-phase regulators.

■ Other voltage regulator studies (voltage regulators are usually operated as independent, single-phase devices).

■ Accurate and realistic harmonics studies.

■ Switching transients, ferroresonance, and other resonance studies.

■ Accurate reliability studies.

Modeling DR for Distribution Power Flow Analysis

In the forward/backward sweep method, DR is typically treated as another current

injection source. That is, it behaves like a negative load. This is exactly the way most

DR will behave when interconnected. Generally, the exciter controls on synchronous

machines are set to hold constant reactive power or power factor. Inverters are often

factory set to produce only unity power factor while they are in utility-interactive

mode. Therefore, this model will suffice for most DR analysis.



Because most distribution power flow methods were designed for systems with only

one source, the modeling of DR that actively regulates the bus voltage is more

difficult. The methods do not naturally accept the so-called “P-V” bus model, where

power and voltage magnitude are the given quantities. However, a few commercial

packages have implemented modifications to their algorithms to accomplish this, and

it is expected that more will be able to model such DR soon.

This issue would apply to large generation that actually has the capacity to control

the utility bus voltage. There are a few instances where the utility may prefer this

type of operation. One example is a generator located several miles from the

substation where the system is weak and the load is not constant. The generator may

be able to do a better job of regulating the voltage than other options. However, this

ability comes with a price. While operating in automatic voltage regulation (AVR)

mode, the generator is much more likely to sustain an island. Therefore, the anti-

islanding detection is more expensive.

Determining DR Capacity Impacts

The potential benefits of DR are very time- and location-specific. That is, the value

varies according to where the DR is located and when it is operating. If the utility is

considering offering capacity credits, it is important to determine if the subject DR

has any real value to the system. For some applications, this is difficult to judge from

just a snapshot power flow solution of a peak load condition. The solution must be

performed over a period of time to determine such things as the number of hours the

generator is likely to run and the cumulative benefit to the system.

The ability to follow a daily load profile such as the one shown in Figure 55 has not

been a traditional part of power flow packages for either transmission or distribution

systems. There is quite a lot of variation in the ability of the different commercial

packages to accommodate this. However, it is often very important for analysis of

both peaking DR and base-load cogeneration. For example, the voltage regulators

and capacitors are designed to operate in a particular sequence, and the best way to

simulate that is to perform power flow solutions following the daily load curve. It is

difficult to get the correct answer with a single snapshot.

The other issue is finding a location where DR is beneficial and measuring the

benefit. Figure 56 illustrates one situation. Here the benefit is measured in terms of

the additional amount of load that can be served by a feeder relative to the size of the

DR added. This measure is popular in some transmission planning studies. In this

case the constraint is assumed to be in the feeder. This would typically be either low

voltage toward the ends of the feeder or excessive current in some line or transformer.

DR is of no value unless it can relieve that constraint. Therefore, if the DR is located



in the substation where the utility might find it attractive, it offers no value by this

measure, because there is no means to deliver the power. If it is located in a good

spot on the feeder, it is generally possible to serve a greater amount of load than the

DR output before the constraint is reached again. The amount of increased load

support generally gets no higher than 140 percent, as shown, but that is fairly easy to

achieve for DR technologies that produce reactive power.

Figure 55: Example peak day load profile

Peak Day Load Profile

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hour

Lo

ad M

ult

iplie

r

Figure 56: When feeder capacity is constrained, the location of DR is very important to its benefit

0=∆∆

GEN

LOAD

P

P

4.1=∆∆

GEN

LOAD

P

P

0=∆∆

GEN

LOAD

P

P

4.1=∆∆

GEN

LOAD

P

P

In this example, the search algorithm would find the place where the most additional

load can be supported. Other objective functions for optimizing the location are loss



improvement and some measure of capacity relief. The search techniques are similar

to those for finding optimal locations for capacitors. The primary difference is that

the solution being considered produces watts as well as VARs.

Loss improvement is a simple metric that is relatively easy to implement in most

power flow programs. One simply tries different locations and ranks the candidate

sites according to the impact of losses. At its simplest, this is done only at peak

loading. To obtain a more accurate assessment, a daily load variation can be

simulated. This might be important if the DR technology is base-load technology

such as cogeneration or fuel cells. The losses during minimum load periods might

yield surprising results. For large DR, there might be no net savings over the year

because of line losses realized in shipping power back to the source. This would not

be apparent from a single snapshot at peak load. Peaking generation can generally be

assessed by analyzing the peak load.

There are a variety of ways one might measure capacity relief. ABB recently proposed

some relatively simple formulae at the 2001 IEEE PES T&D Conference.10 These

formulae can be computed from peak loading calculations alone and would be useful

for evaluating peaking generation. The formulae follow:

Where,

CM = Capacity margin of the proposed option

PI = Performance Index of the proposed option

Cost = Cost of the proposed option

Pk,rated = Rated power flow in branch k

Pk,new = New power flow in branch k

Pk,org = Original power flow in branch k

n = Tuning parameter (1.2)

nk

origknewk

Cost

PPCM

∑ −=

,,

CostP

P

P

P

PI k ratedk

orgk

k ratedk

newk ∑∑ −=

22

,

,

,

,



Equation (1) is basically the arithmetic sum of the unused branch capacity in the

system for the proposed DR option. Equation (2) is an index reflecting the amount

of power over capacity in all the branches in the system. Both are normalized to the

cost of implementing the option. These factors were designed primarily for

transmission or subtransmission system expansion but may also be used to rank DR

alternatives on distribution systems.

Figure 8 in Section 2 illustrates another approach that has a more general application

and can be applied to more types of DR than peaking generation applications.

Capacity is measured by computing the amount of energy served above system limits.

In any given system more than one constraint could be violated. One has the option

of computing just the energy in the shaded areas as shown or counting the entire

energy under the curve once the limit is exceeded. The latter might be appropriate

for conditions that exceed the maximum limit in which the entire load is de-

energized. The former is more appropriate for estimating the amount of DR needed

to keep within capacity limits.

There is an art to setting the limits. Maximum limits are usually set to the maximum

continuous rating of the various circuit elements. The normal rating is up to

engineering judgment and may be used for a variety of purposes. For example,

setting the normal rating to about 50 percent of the maximum rating can yield

energy exceeding normal values that are useful for determining the value of proposed

DR sites. This would place emphasis on locations that alleviate loading on the more

heavily loaded lines. Lines with less than 50 percent loading do not influence the

evaluation as they would by using loss evaluation.

Annual Simulations

There are a number of uses for annual simulations of power delivery systems for DR

application. The 3-D plot of the annual losses in Figure 57 illustrates one. This figure

clearly defines the shape and duration of congestion on the system. Plotting the losses

accentuates the effects of congestion so that they can be clearly seen. Because the

congested time is brief and only in the summer, leased peaking units might be a

reasonable DR option. On peak days, peaking DR may be called upon to operate

most of the daylight hours, which might make day-long operation infeasible. With

the low losses during the bulk of the year, base-load cogeneration will have little net

value to the power delivery system, although the combined heat and power benefits

to the end user may be substantial.



Figure 57: Annual distribution system loss characteristics

1

5

9

13

17

21

Jan Apr Ju

l

Oct

0

5000

10000

15000

20000

25000

kWh

Hour

Month

One strategy for performing annual load simulations is to simply compute 8,760

hourly power flow solutions sequentially. This is accurate but can be time-consuming

for larger circuits. Figure 58 shows a typical characteristic for the peak load of each

day of the year. This was extracted from an 8,760-hour data stream recorded for the

actual load. Modern metering equipment is making this data relatively easy to

obtain.

The 8,760-hour data may be easily distilled into a load-duration curve by sorting the

hourly data in order (Figure 59). This is almost always a smooth curve that can be

fitted accurately with a few straight lines. Therefore, an annual simulation of energy

quantities can be determined quickly by only a few power flow solutions. This is

generally used only for gross estimates of annual performance but does have several

uses for DR analysis. Combining the load-duration curve with the daily load shape

can improve accuracy, especially for the simulation of peaking generation, in which it

is important to properly sequence the regulators and capacitors. A useful annual

simulation may be obtained from approximately 150 power flow solutions.



Figure 58: Peak load for each day of the year

Figure 59: Typical annual load-duration curve for a distribution planning area

Yearly Load-Duration Curve

00.10.20.30.40.50.60.70.80.9

1

A further enhancement is to use monthly load-duration curves and different daily

shapes for each month. This yields greater accuracy, and the results lend themselves

to being used in the 3-D plots. A typical 3-D plot like that shown in Figure 57

requires 1,440 separate power flow solutions.

Finally, one may simulate annual loading characteristics by Monte Carlo methods.

Load is represented by applying statistics to 8,760-hour load data. A typical daytime

load shape for a U.S. utility has a mean value of 65 percent of the annual peak with a

standard deviation of 9 percent. Running 500 to 1,000 power flow solutions while

randomly varying the loading assuming a normal distribution will generally result in

Daily Peak Values for 1 Year

0.000

0.200

0.400

0.600

0.800

1.000

1.200

Day

Lo

ad M

ult

iplie

r



a sampling of most interesting load conditions. This may be sufficient for the

simulation of some annual energy issues. Unfortunately, it suffers the same difficulty

as the single, peak snapshot power flow, because there is no guarantee that the

voltage regulating devices will be properly sequenced.

Some of the DR installed on the distribution system will be aggregated into installed

capacity markets so that it can be bid into the local power markets. Therefore, its

dispatch will depend more on market price than load shape. Prices generally peak in

the same season as the load, but not necessarily at the same time. Prices tend to be

much more spiky than the load (Figure 60). This introduces an additional complexity

into annual loading simulations. One can no longer assume that the generation will

be on when the local load peaks. This need to perform simulations based on price

dispatch of DR will become more important as local power markets develop and

more distributed resources are aggregated to become players in these markets.

Figure 60: Annual local marginal price curve

0

200

400

600

800

1000

1200

$/M

WH

Rapidly Varying Load (Wind Farms and the Like)

We have pointed out repeatedly in this guide that voltage regulation is frequently the

most limiting issue with respect to how much DR can be accommodated without

making changes to existing distribution operating practices. Modeling regulator and

capacitor switching is important. One type of DR that can be particularly taxing to

these devices is wind generation. Wind system simulation often requires a series of

power flow solutions in steps of approximately 1.0 s. Figure 61 shows the results of a

40-minute simulation (2,400 sequential power flow solutions).

It is critical to have a realistic model of the regulator and capacitor control as well as

the unbalanced impedances of the lines for this analysis. The example in Figure 61

employed a three-phase regulator (LTC or ganged line regulators) on a line with

typical horizontal phase construction. As the power increases, the outside phases tend

to separate from the middle phase by a greater degree, creating more imbalance.



Actually, three single-phase regulators do a better job of controlling the imbalance.

However, the outside two phases see increased numbers of operations and are subject

to premature failure. The capability to perform this kind of simulation is not

common in distribution system analysis programs at present.

Figure 61: Results of a wind farm simulation using 1-second intervals

6000

6500

7000

7500

8000

8500

1

187

373

559

745

931

1117

1303

1489

1675

1861

2047

2233

Time, s

Vo

ltag

e (L

-N)

A-Phase

B-Phase

C-Phase

7.2 Fault Studies

Another important tool for the distribution engineer is the short-circuit analysis.

This is used to determine fuse sizes and the settings for relays and reclosers to protect

the power delivery system from damage during inevitable short circuits.

The more traditional computer programs for distribution system short-circuit

analysis do not include infeed from sources other than the bulk power system. They

simply sum the positive and zero-sequence impedances from the substation to the

site of the fault (see Figure 62) and compute the short-circuit currents by applying

the common formulae found in reference books (for example, Cooper Power

Systems’ distribution system protection manual11). The voltages appearing

throughout the circuit and on the secondary side have generally not been of interest.

Therefore, only the currents seen by the relays, reclosers, and fuses are reported.



Figure 62: Radial distribution feeder short-circuit analysis simply sums impedance from substation to the fault

RFault

Model

One-Line

Fault

Sum Z1, Z0 to Fault RFault

Model

One-Line

Fault

Sum Z1, Z0 to Fault

This is changing with the interest in modeling DR on the distribution feeder. There

can be contributions from more than one source, and the voltages seen on the DR

side of the service transformer during the fault are of interest. The disturbance in the

voltage is one of the key quantities by which the DR is able to detect something

wrong on the utility system.

It is not difficult to modify the algorithms to compute the DR contribution, and

many distribution analysis software vendors have responded to customer demands

and have begun to add the appropriate capabilities. It is not known how rigorous

each implementation might be or how many have completed implementation. It

appears to be safe to assume that nearly all vendors will have an offering with suitable

capabilities in the near future, if they don’t already. The capabilities for programs

developed by individual utilities is not known.

Short-circuit software developed for transmission network analysis will generally have

the appropriate models for computing DR contributions to the fault, at least for

synchronous machine DR. Distribution engineers may find these tools to be

unfamiliar, but they will generally suffice in the absence of tools designed specifically

for distribution systems.

There are two common techniques for including the generator contribution: (1)

apply the principle of superposition, and (2) perform a complete network solution

(as in transmission network programs).

For superposition, each source is considered separately while all other voltage and

current sources are set to zero. This is not always as simple as it sounds, because it

will often be necessary to construct a meshed network model of the system. While



considering the contribution from the generator, the utility source is considered

shorted, which requires modeling of the impedances back to the source. The

resulting system will not be radial.

Some analysts simply compute the DR contribution to a short circuit near the point

of common coupling and add that to the utility source contribution. This is not

quite accurate, but it is conservative in most cases. This would be a quick method for

estimating the maximum possible short-circuit current and might be useful for

evaluating such things as fuse-saving coordination.

To get a more accurate value, a more detailed model of the system is required. This is

particularly important for evaluating relay desensitization issues where DR might

prevent overcurrent relays from seeing certain faults. Rather than the maximum fault

current, the fault current for high-resistance faults is of interest. This takes a more

detailed model to determine accurately. Figure 63 illustrates the situation.

Figure 63: DR infeed into fault reduces current seen by feeder breaker

RFault

(Model)

Loads

ZSource

ZGen

ZShared

DR InfeedLoad Current + Source Contribution to Fault

Fault Current

RFault

(Model)

Loads

ZSource

ZGen

ZShared

DR InfeedLoad Current + Source Contribution to Fault

Fault Current

The utility contribution and the infeed current from the DR share a common path

through line impedances and the fault resistance. For high-resistance faults at the end

of the feeder, this can cause a significant reduction in the fault current seen by the

breaker responsible for protecting the end of the feeder (this could also be a line

recloser). Both contributions to the fault must be considered to obtain an accurate

answer.

Complicating the analysis is the load current. Though much short-circuit analysis

ignores load current, it can be a significant factor for minimum fault current analysis.

Load current can actually make the relays a little more sensitive, extending the reach

to see higher-resistance faults than the design value. That is, it takes somewhat less

fault current to trip the relay at full load than at minimum load. The protection

design usually assumes no load contribution. Load counters the desensitizing effect of

the DR infeed. However, DR of sufficient size in the proper location with respect to



the fault can prevent the relays from seeing the fault properly, and a better analysis is

obtained when both load and DR are considered.

Because fault studies generally use constant-impedance modeling techniques, loads

are commonly included as an equivalent impedance at their rated voltage value. As

the voltage deviates more from normal, constant-impedence modeling becomes less

accurate. However, for minimum fault current magnitudes, the voltage over much of

the feeder is near normal, so this is often an acceptable assumption. Some short-

circuit analysis techniques will use an iterative approach that treats loads at buses

with near-normal voltage as a power flow analysis would. Thus, the effect of

induction motor loads drawing more current as the voltage collapses is better

represented in the analysis. This will only work for a relatively narrow range of bus

voltage, because power flow solutions will generally not converge for voltages less

than 70 to 80 percent, depending on the methods. Therefore, sophisticated

techniques for deciding which loads to model with constant impedance or constant

power must be employed.

DR Models in Fault Analysis

Synchronous machine contribution to a fault is typically calculated using a Thevinen

equivalent of the machine (Figure 64). The Thevinen equivalent impedance is most

commonly transient reactance (Xd’) but can also be subtransient reactance (Xd"). Ed’

and Ed" refer to the voltage behind the corresponding reactance. Methods for

determining the voltage behind the impedance vary. Some assume 1.0 per unit

voltage, while others compute the voltage from a previous power flow solution.

Figure 64: Equivalent one-line model of synchronous machines for fault studies

Xd’ or Xd"

Ed’ or Ed"

INTERCONNECTIONTRANSFORMER

FAULT ON POWERSYSTEM

Traditionally, Xd’ is used for fault studies, because this is often the current that is

present after the first one or two cycles up until the time the breaker is called upon to

operate. This is commonly five to six cycles for transmission system breakers. With

distribution systems, there will be some need to consider the subtransient values

(Xd") for some studies. Many fuse operations take place in less than one cycle,

although some may take several seconds. Recloser “fast” operations can be completed



in 1.5 cycles, although the rating may be 3 to 5 cycles. Using Xd" would give a more

accurate picture of the fault current and unfaulted phase voltages during those

conditions.

Induction machines introduce a need for engineering judgment. The textbook

picture of an induction machine subjected to a fault is that the fault current

contribution dies out very quickly in 1.5 cycles. The assumption is that the machine

was subjected to a three-phase fault at its terminals, causing the voltage to collapse.

This seldom happens in actual practice. Eighty to 90 percent of faults will be single-

phase faults for which the faulted phase voltage may exceed 0.5 per unit. The

excitation of the induction machine is only slightly diminished. The conservative

approach is to treat the induction machine as a synchronous machine for faults that

yield a high unfaulted phase voltage. The simple rule of thumb taught at the

University of Wisconsin-Madison Short Course on Interconnecting Distributed

Generation to the Distribution System is that the induction machine is treated as a

synchronous machine as long as the voltage exceeds 60 percent. If it is important to

get a precise number for the contribution, electromagnetic transients programs may

be used to model the induction machine in great detail.

IGBT inverters have limited capability to supply fault currents. When the controls

detect something wrong, they shut off immediately. One rule of thumb frequently

used by power systems analysts is to assume the inverter fault current contribution is

limited to 2.0 times normal rated current. Some utility engineers use 3.0 to be

conservative, but this is probably not warranted, because the contribution will

generally not be much greater than rated current. This can be a challenge to model in

short-circuit programs, because they usually do not have the capability to model what

are essentially current sources. These programs are generally based on Thevinen

equivalent impedance models. Fortunately, if the inverter is assumed to be limited to

2.0 times rated current, this is often an insignificant contribution and can be

neglected.

Modeling Protective Device Behavior

With respect to DR application, fault studies should evaluate two important issues:

the interaction of DR with the utility fault-clearing process and the ability of the DR

to detect faults on the utility system and disconnect in adequate time.

Evaluating these issues is sometimes difficult. Utility distribution engineers are

accustomed to performing static short-circuit analysis and comparing the

coordination of overcurrent protection devices by plotting the results against relay

and fuse time-current characteristic (TCC) curves. However, the operation of utility

fault-clearing devices on the distribution system can be complicated due to multiple



breaker operations and certain sequences that must be followed. When the DR fault

contribution erodes protective device coordination margins, simple TCC curve

evaluation is often inadequate. It is often necessary to perform several snapshot short-

circuit analyses to estimate the response of the system in each of the states that can

exist.

The key operation to model is the clearing of the fault up through the first reclose

interval to evaluate the following two questions:

■ Can the utility device properly sense the fault without loss of coordination?

■ Can the DR detect the presence of the fault and disconnect before the first reclose?

The first question can be answered by computing the fault currents over a range of

fault conditions. The second requires the voltages at the DR interface as well as the

currents. Interconnection transformers will greatly influence these results and must

be properly modeled. The connection of the potential transformers for the relaying is

also important. Full three-phase modeling is generally required for this analysis,

because the most common faults are single-line-to-ground.

The following is an example procedure for determining the impact of DR infeed on

fuse coordination:

1. Model the system for the fault under consideration and determine the time for the utility device to operate.

2. Determine if the DR interconnection relays are able to detect if anything is amiss at this point and determine the relay operation times.

3. Model the system just after the utility breaker opens. Compute the continuing infeed into the fault from the DR, if any. If the infeed exceeds fuse-melting levels, determine the melting timing for the fuses involved. This should be done based on cumulative I2t, including the amount from prior to the breaker opening. I2t melting curves are generally provided for current-limiting fuses. For expulsion fuses, it is often adequate to assume that I2t is constant.

4. Determine the voltage and current values seen by the DR interconnection relays and their operation time for the DR isolated on the fault. Because this a static analysis, frequency variation is not evaluated.

5. Evaluate the DR relaying time and the clearing time of the interconnection breaker against the melting time of the fuse and the reclose time of the breaker. To preserve the coordination prior to adding the DR, the DR should relay and clear before either the melting of the fuse or reclosing of the breaker.



If there is not sufficient engineering margin by this analysis, dynamic analysis is

generally required to determine if the frequency deviation will provide adequate

margin.

Combining short-circuit analysis with dynamics analysis (see the next section) can

contribute greatly to the understanding of how DR will interact with the utility

protection system. The time-dependent behavior of the protective devices would be

represented along with the dynamic characteristics of the machines and inverters. At

the present, such tools are not readily available without resorting to an

electromagnetic transients computer program. This is one area for continuing

research in the development of DR-related engineering tools for utility distribution

engineers.

Once combined with dynamics, this analysis can also be enhanced by employing

Monte Carlo techniques to look at a wide range of faults and fault locations. The

simulation is repeated for each random case generated. This gives a clearer picture of

the behavior of the system with interconnected DR and could be especially

important for analyzing large penetrations of small DR.

7.3 Dynamics

Islanding is usually foremost on the list of utility distribution engineers’ concerns. A

principle concern is that the resulting voltages and frequencies will do damage to

other utility customers for which the utility will be held responsible. Islanding often

occurs for a brief period following the opening of a utility breaker to clear a fault.

There will be a few cycles on an island while the DR interconnection relaying detects

the problem and clears. The existence of a fault at least gives the DR relaying advance

warning that the utility breaker is about to open. Of perhaps greater concern is the

case when there is an inadvertent trip of the utility breaker without a fault. The

question is, Will the resulting voltage and frequency deviate fast enough to detect the

island promptly? Simulation of the system dynamics is required to provide the

answer. If the answer is no, other means of dealing with the inadvertent island must

be implemented.

Dynamic behavior may be analyzed by an electromagnetic transients program but is

also commonly done in the sinusoidal steady state. Dynamics analysis falls into the

same class of analysis as transient stability analysis for transmission systems. The

electrical system is modeled as constant impedances at nominal frequency. It is

assumed that the frequency change of interest during the simulation will be small.

Given that we generally trip the DR off line for less than 1-Hz change, this

assumption is good. If the frequency deviates more than this, the solution accuracy is

probably not of much concern.



The dynamic portion of the simulation involves the modeling of rotating machines

and other devices with time-varying characteristics. The analysis is performed in the

sinusoidal steady state, but the machine speed, torque, and intertial properties are

represented by differential equations. The first derivative of the speed is given by the

familiar machine equation:

( )eTmTHt

−=∂∂

21ω

Where,

ω = Angular speed

H = Intertial constant

Tm = Mechanical torque

Te = Electrical torque

The control response of exciters, governors, and inverter switching controls may also

be represented. These equations and control system models may also be nonlinear.

Therefore, the modeling expertise required for these studies is a step above that

required for static power flow and short-circuit studies. However, it is not quite as

difficult as the modeling for electromagnetic transients studies.

The two most common dynamics studies performed for DR interconnected with the

distribution system are islanding analysis (voltage and frequency deviation) for the

inadvertent breaker opening case and stability analysis for fault events that DR would

be expected to ride through.

Because the worst stability case is often a three-phase fault, both of these analyses for

three-phase DR can be performed with positive-sequence models. Nearly all

dynamics programs would be capable of performing this analysis. A few can handle

arbitrary unbalanced conditions. If unbalanced conditions must be studied, a more

capable program must be employed. Electromagnetic transients programs are often

used for this task.

Dynamics simulation is costly and time-consuming. The first stage of islanding

studies should be a screening by simple static power flow and short-circuit analyses.

If the power flow solution will not converge, it is unlikely that the prospective island

will be sustained. On most distribution systems, it is beneficial to perform this with

unbalanced three-phase analysis if the feeder has many single-phase loads. The

generator or service transformer connection may not allow the successful energization

of the island with many single-phase loads.



When cases are identified where the potential behavior of the system is questionable,

the engineer must employ a dynamics tool or an electromagnetic transients tool. On

distribution systems, the problem is generally modeling one or more DR installations

against the power system, which is modeled as an infinite bus (Figure 65).

Figure 65 shows the model for a synchronous machine DR study. The bulk power

system is modeled as a short-circuit equivalent. Impedances of the feeder are

represented as well as the loads. It is important to model the loads for islanding

studies. Some models allow easy representation of the dynamics of load models,

although this data may be difficult to obtain. The generator and prime mover are

represented by their mass and the exciter and governor control elements shown. The

switches indicate the types of switching operations normally simulated. One

represents the feeder breaker, and the other represents faults that are applied and

cleared.

Figure 65: Elements of a typical distribution-connected DR dynamics study

Inf. BusExciter

Faults

GPrime Mover

Loads

V, I

Governor

ω, TP

Inf. BusExciter

Faults

GPrime Mover

Loads

V, I

Governor

ω, TP

Figure 66 shows one interesting result from an islanding analysis using a similar

model. In the case modeled, an actual feeder was modeled for a loading condition

close to the output of the generator. The feeder voltage at the point of common

coupling was barely above the minimum permitted of 95 percent. It was assumed

that the generator shaft power did not change and the field did not change for the

period of interest. The feeder breaker is opened at 0.3 s into the simulation. There is

a reactive power deficit, and the voltage sags immediately below 90 percent but does

not go below 88 percent, where P1547 recommends setting the first level of

undervoltage relaying. Thus, it is assumed that the undervoltage relay would not

detect this island. Meanwhile, the machine begins to gain speed, because it is

producing more power than is needed. The voltage increases from the increased

induction and the impact of the slightly higher frequency on the system.



Figure 66: Example results of an islanding study performed with a dynamics program

0.90

0.95

pu

Vo

ltag

e

-59.5

60

60.5

61

61.5

62

62.5

63

Fre

qu

ency

, Hz

0.2 s

Voltage

Frequency

1.5 s

Island Detected

0.90

0.95

pu

Vo

ltag

e

-59.5

60

60.5

61

61.5

62

62.5

63

Fre

qu

ency

, Hz

0.2 s

Voltage

Frequency

1.5 s

Island Detected

A commonly recommended setting of the overfrequency relay is 60.5 Hz with a 10-

cycle delay. In this case, the relay would detect the island in about 0.2 s. Because the

machine continues to speed up, the trip signal will be sent to the break at about

0.366 s after the opening. It may take another six cycles (0.1 s) for the breaker to

clear, resulting in a total tripping time of 0.466 s. Though this is reasonably fast, this

scheme would not work reliably if the utility employs instantaneous reclosing.

Therefore, we recommend at least 1.0 s for the first reclose interval and prefer 2.0 s

to obtain adequate margin.

A recent example of a stability analysis that gives many of the typical details of the

models may be found in a paper by Miao, et al.12 It shows results of a generator in

which the exciter and governor were assumed to respond and there were oscillations

after a 0.4-second fault. This analysis used the popular Matlab/Simulink with the

Power System Blockset.13

The automatic voltage regulator for synchronous machines connected to the

distribution system is generally controlled differently than for machines connected at

transmission levels or operating as backup generators. Many utilities forbid

generators from attempting to regulate the feeder voltage and require a constant

power factor or reactive power control mode. A fixed field like that used on some

synchronous motors may also satisfy this requirement. For power factor control, the

exciter control takes both terminal voltage and current to compute the reactive power

and adjust the field current. This model may not be one of the default models



available to the user of a program designed for transmission-connected DR, making

the modeling process more difficult.

While interconnected, the governor control tries to maintain a particular output

power. It can get its power signal from the terminal voltage and current or the shaft

speed and torque. For many DR technologies, the power is controlled simply by

opening the throttle wide open, where it remains for short-term transient events.

Obtaining satisfactory data for accurate dynamics analysis of distribution systems can

be frustrating. One may encounter used machinery that has been recycled from other

facilities and whose original manufacturer is no longer in business. Typical values of

machine impedances and inertias may be assumed. Even with new equipment for

which the machine parameters are known, it may not be possible to obtain all the

parameters of the exciter and governor controls. One may be forced to assume some

generic control or assume that the field and power do not change for the period of

interest. The latter is sufficient for many cases where the period of interest is less than

0.5 s, although it is generally somewhat optimistic toward islanding detection. That

is, by not representing control actions that tend to bring voltage and frequency back

into specifications, simulation results might indicate that detection of an island is

more likely than it actually is.

Inverters

Inverters are commonly assumed to have no inertia and will shut off shortly after

trouble is detected. This can be represented in dynamics studies by switching off the

inverter shortly after initiation of the disturbing event. This will at least demonstrate

the behavior of the system with only rotating machines.

In practice, inverters will continue to supply the system with power if the terminal

voltages remain near normal. A variety of system conditions that can cause this.

IGBT inverter controls are often designed to inject current in phase with the voltage

to produce a particular power level. A simple model would be to assume a constant

power injection source, or a negative load (active power only), depending on the

capabilities of the computer program. If the switching control block diagram can be

obtained, it may be possible to represent some aspects of the control using existing

model templates.

If it is necessary to model precise inverter dynamic behavior, an electromagnetic

transient program should be used.



Data Requirements for Dynamics Analysis

For all generators

■ MVA or kVA rating

■ Maximum power output

■ Rated power factor

■ Power factor operation range (leading/lagging limits)

■ Inertia of generator and prime mover, including gearcase, if any (typically

supplied in MW-sec)

For synchronous generators (typical values, see also Table 1)

■ Direct axis subtransient reactance, Xd" (0.17 pu)

■ Quadrature axis subtransient reactance, Xq" (0.20 pu)

■ Direct axis transient reactance, Xd’ (0.26 pu)

■ Quadrature axis transient reactance, Xq’ (0.26 pu)

■ Direct axis synchronous (nonsaturated) reactance, Xd (2.0 pu)

■ Quadrature axis synchronous reactance (nonsaturated), Xq (1.15 pu)

■ Direct axis subtransient open-circuit time constant, T’DO (0.035 s)

■ Quadrature axis subtransient open-circuit time constant, T’QO (0.020 s)

■ Direct axis transient open-circuit time constant, T’DO (5.6 s)

■ Quadrature axis transient open-circuit time constant, T’QO (5.6 s)

■ Armature constant, TA (0.16 s)

■ Armature resistance, RA (0.015 pu)

■ Stator leakage reactance, XL (0.14 pu)

■ Saturation at typically 100 percent and 120 percent terminal voltage

■ Block diagram of exciter and values for all variables and constants



■ Block diagram of governor control and values for all variables and constants

For induction generators

Impedance data may be similar to that for synchronous machines or derived from the

following data, which may be more available:

■ Slip (speed) at full load.

■ Locked rotor current at 100 percent voltage.

■ Full load current.

■ Electrical torque-speed curve.

■ A block diagram of prime mover governor control and values for all variables and constants.

■ Normally, exciter data would not apply except in the case of doubly fed wound

rotor designs commonly used in wind turbines. This requires a special model.

7.4 Electromagnetic Transients

An electromagnetic transients program is the ultimate simulation tool for difficult

cases. It dispenses with the simplifications necessary for steady-state analysis in power

flow and dynamics tools and recreates the waveforms point-by-point. All of the

nonlinearities in the problem can be handled explicitly and as accurately as the

known data will allow. This additional capability comes at the expense of more

complicated problem setups and longer simulation times. The expertise required for

proper problem descriptions can also be substantially greater than for other tools,

although dynamics tools can also demand special skills.

Because of time requirements and the special nature of the dynamics tools, it is

expected that they will be used sparingly, if at all, by utility distribution engineers on

a regular basis. These tools will be most commonly applied by those performing

research projects, failure analyses, and designing DR equipment. Users would

typically be specialists in power system simulation.

Figure 67 illustrates the type of model used in electromagnetic transients simulation

for studying DR interconnections. The utility equivalent source is to the far right,

and the wye-connected generator is on the far left side of the diagram. The generator

is connected through a delta/wye-grounded transformer to the distribution system,

which is somewhat unusual. The fault block (center, bottom) applies various types of

faults to the distribution feeder. The distribution substation transformer is a three-



winding transformer connected wye-wye with a delta tertiary. The distribution feeder

is modeled as a coupled three-phase line.

Figure 67: Example schematic for a simple DG islanding study performed using the PSCAD/EMTDC� electromagnetic transients program

A

B

C

A

B

C

A B C

100.0 [MVA]

24.94 13.8 [kV] 60.0

#1 #3

Vta

100.

0

100.

0

100.

0

Ia

Ib

Ic

A

B

C

A

B

C

10.0 [MVA]

12.47 24.94

#1 #2

COUPLED

SECTION

A

B

C

A

B

C

PIVpa

RRL

RRL

RRL

A

B

C

RL

A

B

CFAULTS

ABC->G

TimedFaultLogic

DG1

Ef0 Ef If VTIT

3

Tm0Tmw

Te

Tm

A

B

C

One type of analysis performed for this model is to see if the generator can ride

through a typical six-cycle voltage sag caused by a worst-case three-phase fault. The

voltage at the point of common coupling to the distribution feeder is forced to zero

for six cycles, after which the fault is assumed to have been cleared. Ideally, the

generator would ride through this without undo transients of either the voltage or

speed.

Figure 68 shows typical results of simulating the application of a three-phase fault.

The chart shows the generator power and reactive power (top), generator terminal

voltages (middle), and terminal currents (bottom). The currents display the typical

synchronous machine response of about one cycle of very high current that

corresponds to the contribution from the subtransient reactance (Xd") followed by a

more steady, lower current that corresponds to the contribution from the transient

reactance (Xd’). In this particular case, the machine accelerates a little, and there is

some swing when the fault clears. However, the machine stays stable. This might not

be the case for a generator with less inertia. The attractiveness of a transients

simulation is the ability to see the cycle-by-cycle behavior in detail.

The data required to build this model is very similar to that needed for a dynamics

simulation. Depending on the specific type of modeling required, some additional

data might include the following:

■ For transients, a complete three-phase model would be required, but the more readily available dynamics model may be only a positive-sequence equivalent.



■ Lines may be entered as unbalanced impedance matrices.

■ Saturation characteristics of transformers.

■ Inverter switching model details. Inverters are modeled explicitly in the time domain.

Figure 68: Typical results from an electromagnetic transients simulation of a fault applied to a three-phase synchronous machine



Notes

1 IEEE Standard 519-1992, IEEE Recommended Practice and Requirements for

Harmonic Control in Electric Power Systems (1992).

2 Distribution Planning with Distributed Generation Workshop, Electrotek Concepts

Inc., Knoxville, TN, and Energy and Environmental Economics Inc., San Francisco,

CA (2000–2002).

3 C.J. Mozina, “Interconnect Protection of Dispersed Generations,” IEEE PES

Transmission and Distribution Conference, Atlanta, Georgia (November 2001).

4 Generator Protection Application Guide, Basler Electric (June 2001), from

www.basler.com and M-3520 Intertie Protection, Beckwith Electric Co. Inc., from

www.beckwithelectric.com.

5 IEC 61000-4-15, Flickermeter-Functional and Design Specifications (1997).

6 R.C. Dugan, T.E. McDermott, D.T. Rizy, and S. Steffel, “Interconnecting Single-

Phase Backup Generation to the Utility Distribution System,” IEEE PES 2001

Transmission and Distribution Conference Proceedings, Atlanta, Georgia (November

2001).

7 IEEE Standard 929-2000, Recommended Practice for Utility Interface of Photovoltaic

Systems.

8 D.R. Smith, S.R. Swanson, and J.D. Borst, “Overvoltages with Remotely Switched

Cable-Fed Grounded Wye-Wye Transformers,” IEEE Transactions on Power

Apparatus and Systems, v. PAS-94, no. 5 (September/October 1975), pp. 1843–

1853.

9 C.S. Cheng and D. Shirmohammadi, “A Three-Phase Power Flow Method for Real-

Time Distribution System Analysis,” IEEE Transactions on Power Systems, v. 10, no.

2 (May 1995), p. 671.

10 R.E. Brown, J. Pan, X. Feng, and K. Koutlev, “Siting Distributed Generation to

Defer T&D Expansion,” IEEE 2001 PES Transmission and Distribution Conference

Proceedings, Atlanta, Georgia (November 2001).

11 Electrical Distribution System Protection, Cooper Power Systems, Waukesha, WI

(1990).



12 Z.Miao, M.A. Choudhry, and R. L. Klein, “Dynamic Simulation and Stability

Control of Three-Phase Distribution Systems with Distributed Generation,” IEEE

PES Winter Meeting, New York (January 2002).

13 Power System Blockset for Use with Simulink, Hydro Quebec TEQSOM

International, from www.mathworks.com.

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