ieee application guide

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Application Guide for Distributed

Generation Interconnection

The NRECA Guide to IEEE 1547

Resource Dynamics Corporation

September 2001


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Application Guide for Distributed Generation Interconnection

The NRECA Guide to IEEE 1547 September 2001

2

Introduction................................................................................................................................................... 1

Section 1: Cooperative Distribution System Circuits ................................................................................... 3

Section 2: Meeting IEEE 1547 Technical Requirements.............................................................................. 6

Voltage Regulation ....................................................................................................................................... 6P1547 Requirement (Section 4.1.1) .......................................................................................................... 6

Application Guidance ............................................................................................................................... 6

Background...........................................................................................................................................6

Impact of DR ........................................................................................................................................7

Tips, Techniques and Rules of Thumb ................................................................................................. 8

Integration with Area Electric Power System Grounding........................................................................... 10

P1547 Requirement (Section 4.1.2) ........................................................................................................ 10

Application Guidance ............................................................................................................................. 11

Background ......................................................................................................................................... 11

Impact of DR ......................................................................................................................................12

Tips, Techniques and Rules of Thumb ............................................................................................... 14

Synchronization .......................................................................................................................................... 16P1547 Requirement (Section 4.1.3) ........................................................................................................ 16


Background ......................................................................................................................................... 16

Impact of DR ......................................................................................................................................16


Inadvertent Energizing of Area EPS........................................................................................................... 23



Background ......................................................................................................................................... 23

Impact of DR ......................................................................................................................................23


Monitoring .................................................................................................................................................. 26P1547 Requirement (Section 4.1.6) ........................................................................................................ 26


Background ......................................................................................................................................... 26

Impact of DR ......................................................................................................................................26


Isolation Device .......................................................................................................................................... 30



Background ......................................................................................................................................... 30

Impact of DR ......................................................................................................................................31


Voltage Disturbances .................................................................................................................................. 33



Background ......................................................................................................................................... 33

Impact of DR ......................................................................................................................................34


Frequency Disturbances.............................................................................................................................. 39




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Background ......................................................................................................................................... 39

Impact of DR ......................................................................................................................................39


Disconnection for Faults ............................................................................................................................. 42

P1547 Requirement................................................................................................................................. 42

Application Guidance ............................................................................................................................. 42Background ......................................................................................................................................... 42

Impact of DR ...................................................................................................................................... 43


Loss of Synchronism................................................................................................................................... 45



Background ......................................................................................................................................... 45

Impact of DR ...................................................................................................................................... 45


Feeder Reclosing Coordination................................................................................................................... 47



Impact of DR ...................................................................................................................................... 47


Limitation of DC Injection.......................................................................................................................... 51



Background ......................................................................................................................................... 51

Impact of DR ......................................................................................................................................51


Limitation of Voltage Flicker Induced by the DR ...................................................................................... 54

P1547 Requirement................................................................................................................................. 54

Application Guidance ............................................................................................................................. 54Background ......................................................................................................................................... 54Impact of DR ......................................................................................................................................56


Harmonics ................................................................................................................................................... 60



Impact of DR ...................................................................................................................................... 61


Immunity Protection ................................................................................................................................... 66



Impact of DR ...................................................................................................................................... 66


Surge Capability.......................................................................................................................................... 68

P1547 Requirement Section 4.3.5) ......................................................................................................... 68


Background ......................................................................................................................................... 68

Impact of DR ...................................................................................................................................... 68


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Islanding...................................................................................................................................................... 71

P1547 Requirement (Section 4.4) ........................................................................................................... 71


Background ......................................................................................................................................... 71

Impact of DR ......................................................................................................................................71Tips, Techniques and Rules of Thumb ............................................................................................... 72

Appendix A................................................................................................................................................. 76

Glossary ...................................................................................................................................................... 76

Appendix B ................................................................................................................................................. 78

Discussion of Power Factor ........................................................................................................................ 78

Appendix C ................................................................................................................................................. 82

Grounding Fundamentals............................................................................................................................ 82

Appendix D - Example One Line Diagrams ............................................................................................... 90

Appendix E ................................................................................................................................................. 94

Example of Non-Islanding Test .................................................................................................................. 94

A.5 Interconnection Test to Verify Non-Islanding............................................................................94

A.5.1 Non-Islanding Test Procedure Background...........................................................................94A.5.2 Non-islanding Test Procedure................................................................................................ 95

Appendix F .................................................................................................................................................97

References................................................................................................................................................... 97


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Application Guide for Distributed Generation InterconnectionThe NRECA Guide to IEEE 1547

Introduction

This application guide is intended to supplement, expand and clarify the technical requirements of

IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems. While

the Standard includes distributed generation (DG) through 10 MVA, this guide addresses DG through 1MVA. Neither this guide nor the Standard covers revenue metering requirements. Tariff and contract

issues are also beyond the scope of this document. Because the Standard in not yet approved by the IEEE

Standards Board, Draft 07 has been used. It is assumed that the final version of the Standard will not

change significantly. When the final version of the Standard is published, changes will be made to this

guide to reflect actual wording of the Standard.

The subjects in part 2 of this guide closely parallel the Standard. For each topic the actual

Standard language is quoted followed by application guidance divided into three sections: 1) Background,

2) Impact of DR, and 3) Tips, Techniques and Rules of Thumb. A Discussion of Power Factor inAppendix B is not addressed in the Standard, but it an important topic to consider. Since grounding is

such an important topic and there are some non-standard grounding practices, Grounding Fundamentals

are discussed in Appendix C. This guide does not cover testing, but since the issue of islanding is so

important, Appendix E gives some examples of non-islanding tests.

While the Standard was designed to cover the bulk of DG installations, in some circumstances

additional technical specifications may be required. Especially in some remote areas, the addition of DG

may be a significant percentage of the circuit load. The Tips, Techniques and Rules of Thumb section

under each topic gives guidelines and thresholds where additional specifications may be required. In

addition, most installations over 1 MW will require a specific engineering study to determine any

additional requirements.

The National Rural Electric Cooperative Association wishes to give special thanks to N. Richard

Friedman of the Resource Dynamics Corporation for the compilation of this guide. Jay Morrison of the

NRECA Energy Policy Department contributed to this document. Appreciation is also noted to the

members of the NRECA T&D Engineering System Planning Subcommittee for their input, review and

suggestions.

The current members of the System Planning Subcommittee are:

Ronnie Frizzell, Arkansas Electric Cooperative Corp., AK (Chairman)

Brian Tomlinson, Coserv Electric, TX (Vice Chair)

Mark Evans, Volunteer Electric Co-op, TN (Recorder)

Robin W. Blanton, Piedmont EMC, NC Robert Dew, United Utility Supply, KY

David E. Garrison, Allgeier Martin & Associates, MO

H. Wayne Henson, East Mississippi EPA, MS

Bill Koch, Rural Electric Magazine, WA

Joe Perry, Patterson & Dewar Engineers, GA

Georg Schulz, RUS, DC

Mike Smith, Singing River EPA, MS


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Chris Tuttle, RUS, DC

Kenneth Winder, Moon Lake Electric Assn., UT (Former Chairman)

This is a working document. Any comments or suggestions are welcome. Please address all

comments to:

Bob Saint, Principal, T&D Engineering

National Rural Electric Cooperative Association

4301 Wilson Blvd.

Arlington, VA 22203

Phone: (703) 907-5863

Email: [email protected]
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Section 1: Cooperative Distribution System Circuits

Nearly half of the distribution circuits in the United States are owned by cooperatives. As energy markets

are restructured, more pressure will be felt by cooperatives to control costs, increase operating flexibility,and maintain system and supply source reliability. Distributed generation (DG) offers new options for

cooperatives and their customers. Understanding how DG systems are designed, interconnected and

operated is key to understanding the impact of DG on cooperative distribution systems.

The Electric Power System

An electric power system generally consists of generation, transmission, subtransmission, and

distribution. Most electric power is generated by central station generating units. Generator step-up

transformers at the generation plant substation raise the voltage to high levels for moving the power on

transmission lines to bulk power transmission substations. The purpose of high voltage transmission lines

is to lower the current, reduce voltage drop and reduce the real power loss (l2R). Real power is the

product of voltage, current and the power factor (the angle between the voltage and the current phasors).As the voltage is increased for a fixed amount of power, the current decreases proportionately. The

power transmitted remains constant, but the decrease in current results in reduced losses.

Transmission lines are usually 138 kV and above. Transmission substations reduce the voltage to

subtransmission levels, usually between 44 kV and 138 kV. Subtransmission lines are those lines where

the voltage is stepped directly to the customer utilization voltage. Interconnections to other electric utility

transmission and subtransmission systems form the power grid.

The system voltage is stepped down beyond the transmission system to lower the cost of equipment

serving loads from the subtransmission and distribution segments of the power system.

The transmission and subtransmission systems are generally networked. In contrast, the distributionsystem consists of radial distribution circuits fed from single substation sources. The distribution system

includes distribution substations, the primary voltage circuits supplied by these substations, distribution

transformers, secondary circuits including services to customers premises and circuit protective, voltage

regulating and control devices.

The Distribution System

The distribution system typically consists of three phase, four wire Y grounded and single phase, two

wire grounded circuits. Distribution circuits have voltages ranging from 19.9/34.5 kV to 7.2/12.5 kV

(phase-to-ground voltage/phase-to-phase voltage), although there are some lower voltage 4 kV three

wire ungrounded systems still in existence. These lines are typically referred to as primary circuits

and their nominal voltage may be referred to as the primary voltage.

Transformers on the distribution system step the voltage from the distribution line voltage to the

customers utilization voltage commonly referred to as the secondary voltage. The secondary system

serves most customer loads at 120/240 volts, single phase, three wire; 208Y/120 volts three phase four

wire; or 480Y/277 volts three phase four wire. A complete list of preferred voltage levels is tabulated in

American National Standards Institute (ANSI) C84.1.
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Residential, small commercial, and rural loads are served by overhead distribution feeders and lateral

circuits, or by underground distribution circuits. Most residential loads are served by three phase, four

wire primary feeders with single phase lateral circuits, although some three phase laterals serve small

industrial and large commercial loads. Most rural loads are served with single phase primary and

typically have one customer per distribution transformer.

Distribution Primary Circuits

A typical radial 12.5 kV distribution circuit would be served from a distribution substation transformer

fed from one subtransmission line. If loads are large enough or of a critical nature, a second

subtrasmission feed and transformer will be installed. Most existing primary distribution circuits are

overhead construction, but much new construction is underground, especially in residential and

commercial areas. Most primary distribution circuits are a radial design with one source per circuit.

The trend to higher distribution voltages means more load may be served from each distribution circuit.

This would normally imply reduced reliability, because more load is affected by clearing faults on the

distribution circuit. However, automatic switching and protective relaying devices mitigate this effect.

Also, customers are demanding a higher level of reliability due to the increased use of home computersand other electronic appliances.

Distribution Secondary Systems

The secondary system is that portion of the distribution system between the primary feeders and the

customers premises. The secondary system is composed of distribution transformers, secondary circuits,

customer services, and revenue (billing) meters to measure the energy (kWh) usage. In some cases the

demand (kW) and power factor are also measured.

The secondary circuits connect the customer service to the low voltage side of the distribution

transformer. Although secondary systems are predominantly single phase, three wire, three phase

secondaries are used where a combination of large commercial and small industrial loads are located in aresidential area.

There are three different secondary system configurations:

radial secondary;

solid banked secondary; and,

loose banked secondary.

The radial secondary system is the most common configuration for serving cooperative rural areas, as

well as residential and light commercial loads. Secondary banking1 is used in areas where the loads are

close together and there is a need to reduce voltage flicker due to motor starting.

1Banking means paralleling on the secondary side a number of distribution transformers which areconnected to the same primary. Banked transformers are still a form of radial distribution, because theyare connected to one primary feeder. This configuration should not be confused with a secondarynetwork configuration where the distribution transformers are connected to two or more primary feeders.
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Banked secondary systems for residential or rural (if practical) are single phase, but three-phase banking

is also used for commercial applications. The advantages of banking distribution transformers are as

follows: (1) reduces voltage drop during motor starting by 50 to 70%, (2) improves the overall voltage

profile, (3) provides clearing of secondary faults, (4) reduces the size of secondary conductors, (5)

reduces the size of the distribution transformer (due to load sharing) by as much as 20-30%, (6) improves

reliability of service, and (7) new load may be added without changing out the transformers andsecondary conductors.
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Section 2: Meeting IEEE 1547 Technical Requirements

Voltage Regulation

P1547 Requirement (Section 4.1.1)

DR shall not degrade the voltage provided to the customers of the Area EPS to service voltages outside

the limits of ANSI C84.1, Range A.

Apart from the effect on the voltage of the Area EPS due to the real power generation of the DR, the DR

shall not attempt to oppose or regulate changes in the prevailing voltage level of the Area EPS at the PCC,

except that DR generators shall be permitted to use automatic voltage regulation when such regulation

can be accomplished without detriment to either the Area EPS or Local EPS.

Application Guidance

BACKGROUND

Voltage regulation is the term used to describe the process and equipment used by an electric power

system (EPS) operator to maintain approximately constant voltage to users despite the normal variations

in voltage caused by changing loads. Voltage regulation and voltage stability are important factors thataffect the operation of a power distribution system. If a system is not well regulated or stable, machines

receiving power from the system will not operate efficiently. Voltage regulation is considered in every

step of design and when sizing conductors.

Several different methods can be used to regulate voltage in a power distribution system. Typical radialdistribution systems are regulated at substations using feeder-voltage regulators2 or automatic load-tap-

changing transformers. Switched shunt capacitor banks3 may also be used at the substation for part of the

system voltage control. On distribution feeders, both line regulators and switched capacitors are used.

Rural areas served by cooperatives typically include long stretches of power lines with single-phase

automatic step regulators for supplementary voltage regulation. These step regulators are smaller in rating

than the feeder regulators and are often pole mounted. Ideally, utilities aim to keep the service voltage at

all customers within Range A as specified in ANSI Standard C84.14.

2A feeder-voltage regulator can be either single-phase or 3-phase construction. The single-phaseregulator is available in sizes ranging from 25-400kVA and the 3-phase regulator is available in sizesranging from 500-2000kVA. Today's voltage regulators are all the step-voltage type. A step voltageregulator is basically an autotransformer which has numerous taps in series with the windings. Thesetaps are changed automatically under a load by a voltage-sensing, switching mechanism. The taps areswitched in order to maintain a voltage as close to the predetermined level as possible.

3 Switched shunt capacitor banks are often used on distribution systems as part of the overall voltage-regulation scheme. Unswitched shunt capacitors are typically applied to bring the light-load power factorto about 100%. Then automatically switched shunt capacitor banks are added to achieve the economicfull-load power factor, which is typically 95% to 100%.

4Voltage Ratings of 60 Hz Electric Power Systems, ANSI C84.1-1995, Published by the National ElectricalManufacturers Association, 1995.
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IMPACT OF DR

Voltage regulation practice is based on radial power flows from the substation to the loads. DR

introduces meshed power flows that may interfere with the effectiveness of standard voltage regulation

practice. The effect of DR on EPS voltage regulation can cause changes in power system voltage by

1) the generator offsetting the load current, and 2) the DR attempting to regulate voltage. Most types of

DR generators and utility-interactive inverters should strive to maintain an approximately constant power

factor at any voltage within their rating; accordingly, the primary impact of DR on voltage regulation is

the result of the DR offsetting the load current. This is especially important in ensuring that a DR

installation will meet the intent of this P1547 requirement requiring the DR not to attempt to oppose or

regulate changes in the prevailing voltage level of the Area EPS.

The operation of DR on utility circuits basing voltage regulation on radial power flows can result in both

high and low service voltage unless precautions are taken. Examples of each of these situations are

discussed below.

Low Voltage

Most feeder regulators are equipped with line drop compensation (LDC) that raises the target regulator

output voltage in proportion to the load. This feature helps to maintain constant voltage at a point further

downstream by raising the regulator output voltage to compensate for line voltage drop between the

regulator and the load center. A DR located immediately downstream of a feeder voltage regulator may

interfere with the proper operation of the regulator, if the generation output is a significant fraction of the

normal regulator load. When the DR offsets 15 percent or more of the load current, this causes the

regulator to set a voltage lower than required to maintain adequate service levels at the end of the feeder.

The impact on feeder voltage regulation is as follows:

The feeder may be heavily loaded, but the regulator sees relatively low load due to the DR currentoffset.

The line voltage drop from the DR to the load center still reflects heavy loading, but the regulatoroutput voltage is not increased because of the low loading seen by the regulator.

As a result, low voltage conditions occur at the load center.

It should be noted that some cooperatives operate at lower voltage during lightly-loaded conditions to

reduce losses. These conditions typically occur during off-peak periods.

Compromises in the regulator settings, additional regulator controls or relocation of the regulator

to a point downstream of the DR interconnection point (or interconnection of the DR unit upstream

of the regulator) may be necessary to maintain adequate voltage at the load center.
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High Voltage

During normal radial feeder operation, there is a voltage drop across the distribution transformer and the

secondary conductors, and voltage at the customer service entrance is less than at the primary. Undercertain conditions with a DR unit installed, other customers on the feeder may see higher than normalservice voltage with associated unintended consequences. This situation can occur when:

1. A DR unit (such as in a small residential DR system) shares a common distribution transformerwith several other residences.

2. The distribution transformer serving these customers is located at a point on the feeder where theprimary voltage is near or above the ANSI C84.1 upper limit (126+ volts on a 120 volt base).

3. The DR introduces reverse power flow that counteracts the normal voltage drop, perhaps evenraising voltage somewhat.

With these conditions, the service voltage to the other customers may actually be higher at the customer

service entrance than on the primary side of the distribution transformer; it may even exceed the ANSIupper limit.

TIPS, TECHNIQUES AND RULES OF THUMB

In most cases, the impact on the feeder primary will be negligible for any individual residential scale DR

unit (


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In this case (see box above), a voltage problem on the primary is unlikely. When the injected current is

much above 5%, there is more reason to worry about potential impacts.6

Synchronous Generator DR and Voltage Regulation

Synchronous generators equipped with voltage-regulator controls deliberately vary their field excitationin response to voltage changes, in an attempt to maintain constant voltage. When interconnected with a

large EPS, changes in field excitation cause reactive power exchange with the EPS.

The effect of constant-voltage regulated distributed generators on EPS voltage is a function of the short

circuit ratio of the distributed generator to the power system. If the short circuit ratio is small, the

distributed generator will have little actual effect on power system voltage, but the generator power factor

may become abnormally low under high or low voltage conditions on the EPS. Such a condition can limit

the real power capability of the generator and contributes to inefficient operation of the EPS.

A power factor controller can be used, instead of a voltage-regulator controller, to stabilize the excitation

system of synchronous rotating generators. The VAr/power factor controller can be used to maintain a

constant power factor or VAr output, making the synchronous machine voltage response resemble that ofan induction generator or utility-interactive inverter.

Siting DR to Reduce Distribution System Losses

Distributed generation will also impact losses on distribution systems. DR units can be placed at optimal

locations where they provide the best reduction in feeder losses. Siting of DR units to minimize losses is

like siting capacitor banks for loss reduction. The only difference is that the DR units will impact both the

real and reactive power flow. Capacitors only impact the reactive power flow. Most generators will be

operated between 0.85 lagging and 1.0 power factor, but some inverter technologies can provide reactive

compensation (leading current). A good load flow analysis software should be able to model the effects

on system losses. On feeders where losses are high, a small amount of strategically placed DR with an

output of just 10-20% of the feeder demand can have a significant loss reduction benefit for the system.Unfortunately, most utilities do not have control over the siting locations, since DR is usually customerowned. Nonetheless, for utilities that are moving forward with their own DR programs, optimal siting of

units can increase the performance of the system.

Siting DR and Consideration of Thermal Capacity Limits

Larger DR units must also be sited with consideration of feeder capacity limits. In some cases overhead

lines and cables may be thermally limited, meaning that the DR can inject power that exceeds the lines

thermal limit without causing a voltage problem on the feeder. The power flow analysis should flag the

locations where capacity constraints will be an issue from a thermal as well as a voltage perspective. In

general, a DR at a location that is thermally limited is not connected at the optimal point from a power

loss perspective.

6For shared secondaries, with DR even a small generator that injects less than 5% at the primary levelcould pose a voltage regulation risk to customers sharing the secondary. Thus, analysis of voltageconditions will almost always need to consider impacts on the secondary where the DR is located.
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Integration with Area Electric Power System Grounding


The interconnection of the DR with the Area EPS shall be coordinated with the neutral grounding

method7 in use on the Area EPS as follows.

Three-Wire Area EPS Systems. (Section 4.1.2.1)

DR interconnections to Area EPS primary feeders of three-wire grounded or ungrounded systems, or to

tap lines of such systems, shall not provide any metallic path to ground from the primary feeder except

through suitably-rated surge arresters, high-impedance devices used only for fault detection purposes, or

both. 8

1. DR interconnections to Area EPS primary feeders of three-wire grounded or ungrounded systems, orto tap lines of such systems, shall not provide any metallic path to ground from the primary feeder

except through suitably-rated surge arresters or high-impedance devices used only for fault detection

purposes, or both. 9

2. For DR interconnections, directly or through a transformer,10 to Area EPS primary feeders of multi-grounded or uni-grounded four-wire construction, or to tap lines of such systems, the maximum

unfaulted phase (line-to-ground) voltages on the Area EPS primary feeder, during single line-to

ground fault conditions with the Area EPS source disconnected, shall not exceed those voltages that

would occur during the fault with the Area EPS source connected and no DR generation. 11

3. The ground-fault current contribution of the DR, and its interconnection transformer, shall not be

greater than 100% of the fault current contribution of the DR to a three-phase fault at the sameprimary feeder fault location. An interconnection to a primary feeder of a three-wire grounded or

ungrounded system shall have zero ground fault current contribution.12 These ground fault current

limitations shall not apply to any DR interconnected to an Area EPS through the existing distribution

transformer provided that neutral grounding, if any, of the high voltage winding is not changed.

7 For definition of grounding methods consult IEEE 62.92.1.

8 For the purposes of this subclause, grounded metallic enclosures or support structures such as steelpoles or metallic conduit, are not considered to be metallic paths to ground from the primary feeder.

9 For the purposes of this subclause, grounded metallic enclosures or support structures such as steelpoles or metallic conduit, are not considered to be metallic paths to ground from the primary feeder.

10 In many existing 4-wire multi-grounded distribution circuits the existing transformer for commercialand industrial facilities is a Y-Y connected transformer. In these cases consideration has to be given to thegrounding of the generator if the secondary service is a 4-wire service.

11 Voltages exceeding this limit are acceptable if it can be shown that they will not be detrimental to theequipment and customer loads connected to the Area EPS feeder.

12For DR technologies that have time-variant fault contribution characteristics, the characteristicproducing the highest fundamental-frequency fault current from the DR shall be used in this calculation(i.e., for synchronous generators, the subtransient reactance shall be used).
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Four-Wire Area EPS Systems. (Section 4.1.2.2)

For DR interconnections, directly or through a transformer13, to Area EPS primary feeders of multi-

grounded or uni-grounded four-wire construction, or to tap lines of such systems, the maximum unfaultedphase (line-to-ground) voltages on the Area EPS primary feeder, during single line-to-ground fault

conditions with the Area EPS source disconnected, shall not exceed those voltages that would occur

during the fault with the same Area EPS source connected and no DR generation.

The ground-fault current contribution (3I0) of the DR, including the effect of any transformers between

the DR and the primary feeder, shall not be greater than 100% of the fault current contribution of the DR

to a three-phase fault at the same primary feeder fault location.14 This ground fault current limitation

shall not apply to any DR interconnected to an Area EPS through the existing distribution transformer

provided that neutral grounding, if any, of the high voltage winding is not changed.


BACKGROUND

A grounding system consists of all interconnected grounding connections in a specific power system and

is defined by its isolation or lack of isolation from adjacent grounding systems. The isolation is provided

by transformer primary and secondary windings that are coupled only by magnetic means.

System grounding, or the intentional connection of a phase or neutral conductor to earth, is for the

purpose of controlling the voltage to earth, or ground, within predictable limits. It also provides for a flow

of current that will allow detection of an unwanted connection between system conductors and ground.

When such a connection is detected, the grounding system may initiate operation of automatic devices to

remove the source of voltage from the conductors with undesired connections to ground.

The National Electric Code (IEEE/ANSI 70) prescribes certain system grounding connections that must

be made to be in compliance with the Code. The control of voltage to ground limits the voltage stress on

the insulation of conductors so that insulation performance can more readily be predicted. The control of

voltage also allows reduction of shock hazard to persons who might come in contact with live conductors.

Types of Distribution Feeders and Grounding Methods

13 In many existing 4-wire multi-grounded distribution circuits the existing transformer for commercialand industrial facilities is a Y-Y connected transformer. In these cases consideration has to be given to thegrounding of the generator if the secondary service is a 4-wire service.

14 For DR technologies that have time-variant fault contribution characteristics, the characteristicproducing the highest fundamental-frequency fault current from the DR shall be used in this calculation(i.e., for synchronous generators, the subtransient reactance shall be used).
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The grounding of utility distribution feeders is usually derived from a distribution substation transformer

with wye-connected secondary windings and with the neutral point of the windings solidly grounded or

connected to ground through a noninterrupting, current-limiting device such as a reactor. A grounding

transformer may also be used to establish a grounded system.The circuits associated with grounded

distribution systems generally have a neutral conductor connected to the supply grounding point. The

neutral conductor of the distribution circuits may be described as either multigrounded, unigrounded, or

ungrounded:

Multigrounded.....connected to earth at frequent intervals.

Unigrounded........fully insulated and have no other earth connection except at the source.

Ungrounded.........no intentional connection to earth.

U.S. utility distribution feeders are either: 1) four-wire-multigrounded or unigrounded systems, 2) three-

wire ungrounded systems, or 3) three-wire grounded systems. An example of the common neutral

method of distribution is shown in Figure 1.

IMPACT OF DR

DR interconnection to each type of distribution system can impact protection and coordination asdiscussed below.

Customer's water

pipe grounds

Single phase

secondary

Stationtransformer

Customer's water

pipes

Primary phase wires

Multigrounded neutral

1 transf

S. A.

NeutralCommon

Multigrounded

Figure 1. Common Neutral Method of Distribution
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Types of Distribution Systems

Three-Wire Ungrounded Systems

Three-wire ungrounded systems are clearly in the minority of U.S. distribution feeders. While this typeof system has no intentional connection to earth, connections to ground may occur through potential

indicating or measuring devices or other very high impedance devices.

Three-Wire Grounded Systems

In three-wire unigrounded systems, a neutral conductor is not run with each circuit, but the system is

grounded through the connections of the substation transformer or grounding transformer. On three-

phase three-wire primary distribution circuits, single-phase distribution transformers are connected phase-

to-phase. The connection of three single-phase distribution transformers or of three-phase distribution

transformers is usually delta-grounded wye or delta-delta. (The floating wye-delta or T-T connections

also can be used.) The grounded wye-delta connection is generally not used because it acts as a

grounding transformer. Surge arresters are generally connected phase-to-ground. However, the surgearrester rating is higher than those used on multigrounded neutral systems since the temporary 60 Hz

overvoltages expected under fault conditions are also higher.15

Four-Wire Multigrounded or Ungrounded Systems

Most U.S. utility distribution feeders are four-wire-multigrounded-neutral systems that are defined as

being effectively grounded with respect to the substation source. The neutral conductor associated with

the primary feeders of multigrounded neutral distribution systems is connected to earth at intervals

specified by national or local codes. It is also common practice to bond this neutral conductor to surge-

arrester ground leads and to all noncurrent-carrying parts, such as equipment tanks and guy wires, and to

interconnect it with the secondary neutral conductor or grounded conductor.16

For a single line to ground fault, this arrangement limits the voltage rise on unfaulted phases to about 125

to 135% of the prefault condition.17 Three-phase interconnections to multigrounded four-wire systems

must provide an adequate ground current source to control unfaulted-phase overvoltages for brief

islanding conditions during fault clearing, unless an interconnected DR is so small that it cannot support

any voltage on the system when isolated with load. However, the DR ground current source must also notbe so large that it significantly dilutes the fault current contribution from the utilitys source substation

and thereby degrades the ground fault detection sensitivity.

15IEEE Guide for the Application of Neutral Grounding in Power Systems, Part 4, IEEE Std. C62.92.4-1991.

16In some situations, the same neutral conductor is used for both the primary and secondary systems.There is some variation in this practice, however, and some utilities do not interconnect the primary andsecondary neutral conductors nor bond the neutral to the guy wire. If no direct interconnection is made,the secondary neutral conductor may be connected to the primary neutral conductor through a spark gapor arrester. Surge arresters on multigrounded neutral systems are connected directly to earth, and theirgrounding conductor may be interconnected directly to the primary neutral conductor and equipment tanks.They may also be interconnected with the secondary neutral at transformer installations.

17 IEEE Guide for the Application of Neutral Grounding in Power Systems, Parts 1-4, IEEE Std. C62.92 1991.
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Use of a DR source that does not appear as an effectively grounded source connected to such systems

may lead to overvoltages during line to ground faults on the utility system. This condition is especially

dangerous if a generation island develops and continues to serve a group of customers on a faulted

distribution system. Customers on the unfaulted phases could in the worst case see their voltage increase

to 173% of the prefault voltage level for an indefinite period. At this high level, utility and customer

equipment would almost certainly be damaged. Saturation of distribution transformers will help slightly

to limit this voltage rise. Nonetheless, the voltage can still become quite high (150% or higher).


Assuring DR Integration with the EPS Ground

Multigrounded Neutral Systems

To avoid problems, all DR sources on multigrounded neutral systems that are large enough to sustain an

island should present themselves to the utility system as an effectively grounded source. If they do not,

they should use appropriate protective relaying to detect primary side ground fault overvoltages and

quickly trip off-line (instantaneous trip). The former approach is preferred since it limits by design the

voltage swells that the system will see during a fault. The latter approach, while used successfully in

many installations, could subject the customer to many cycles of severe overvoltage prior to the DG unit

being cleared from the system. Additionally, if the DR is not cleared quickly enough, equipment could bedamaged.

Static Power Converters

Integration of the ground system of a static power converter based DR facility with the existing grounding

system requires an examination of the circuit isolations from ground that might occur across the

interconnection. When operating in parallel with the Area EPS, effective grounding must be assured.

When the DR must disconnect itself to permit fault clearing on the utility system, or operate in a

standalone mode, the same grounding effectiveness must be designed into both systems.

A converter based DR directly connected to a grounded ac system through its static power converter is a

grounded source as long as the interconnection is made. If the DR has a neutral or grounded conductorwhich is not switched upon disconnect and is solidly tied to the ac system neutral then even during

disconnect and possible standalone operation without the ac system the DR remains grounded and has the

protective features of grounding still in force.

If a directly connected static power converter based DR was not tied to a grounded conductor during

separation from the utility for standalone electricity supply, balanced grounded operation will be lost. In

the case of single-phase systems, inclusion of an isolation transformer can eliminate this particular

Distributed generation must be applied with a transformer configuration and grounding

arrangement compatible with the utility system to which it is to be connected. Otherwise,

voltage swells and overvoltages may be imposed on the utility system that can damage utility or

customer equipment.
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problem. Grounding is accomplished on both sides of the transformer and the grounded DR energy

source can operate fully grounded with or without connection to the grounded utility service.

DR systems with converters that use three phase isolation transformers to interface with the Area EPS

present a variety of issues, all dependent on the configuration of the windings on either side of the

transformer. It is generally advisable that a power source be grounded at only one point, and the NEC isquite specific on this point. If multiple ground connections are created in the integration of the DR facility

to the existing ground system, neutral currents could flow in the ground system and compromise the

integrity of the protective grounding system.

If the DR is served by a dedicated isolation transformer, this permits the energy source of the DR to be

directly grounded either solidly or through an impedance. Certain static power converter networks

operate with a midpoint neutral. Alternatively the energy source may be grounded directly through the

converter at its midpoint. The transformer typically steps up the DR converter voltage to the level

required to match the ac utility interconnect voltage. It is at the transformer in particular that the

grounding connections must be controlled.
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SLIP AND SYNCHRONIZATION

The slip of a rotating ac machine isthe difference between its speed andthe synchronous speed, divided bythe synchronous speed. Slip isusually expressed as a percentage.It may be computed from themeasured speed of the machine andthe synchronous speed, but directmethods are more accurate.

Synchronization


The DR unit shall synchronize with the Area EPS without causing a voltage fluctuation at the PCC

greater than 5% of operating voltage.


BACKGROUND

In order to synchronize the distributed generator with the electric power system, the output of the

distributed generator and the input of electric power system must have the same voltage magnitude,frequency, phase rotation, and phase angle. Synchronization

is the act of checking that the four variables mentioned above

are within an acceptable range (or acceptable ranges). For

synchronism to occur, the output variables of the distributed

generator must match the input variables of the electric

power system. With polyphase machines, the direction of

phase rotation must also be the same. This is typically

checked at time of installation, the phases being connected to

the switches such that the phase rotation will always be

correct. Phase rotation is not usually checked again unless

wiring changes have been made on either the generator or

inverter, or the electric power system.

IMPACT OF DR

The testing provisions of IEEE 1547 require the test to demonstrate that the interconnection system, at

each point where synchronization is required, shall not connect the associated DR unit (or aggregation of

DR units) to an Area EPS except when all of the appropriate conditions are satisfied. If these conditions

are met, the DR will synchronize with the Area EPS with any voltage fluctuation limited to 5% of

nominal voltage.

The conditions for three types of DR follows.

A. Synchronous Generator to an EPS, or an Energized Local EPS to an Energized Area EPS.

Connection will be prevented when the DR (or the energized Local EPS) is operating outside of the

following limits relative to the Local EPS (or Area EPS).
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Aggregate Rating of

DR Units

(kVA)

Frequency

Difference

(f, Hz)

Voltage

Difference

(V, %)

Phase Angle

Difference

(, )

0 - 500 0.3 10 20

500 1,500 0.2 5 15

1,500 - 10,000 0.1 3 10

The test performed by the DR for the EPS will demonstrate that at the moment of paralleling-device

closure, all three parameters in the table above are within the stated ranges. This test shall also

demonstrate that if any of the parameters are outside of the ranges stated in the table, paralleling-device

closure will not be permitted.

B. Asynchronous (Induction) Generator to an EPS

In the case where the induction motor is acting as a generator, and the voltage drop is less than 5% at thePCC, the requirement is met.

Where the resulting voltage drop is greater than 5%, the analysis will proceed to consider the benefit of

accelerating the generator to near synchronous speed before connecting. If this produces less than 5%

voltage drop, then no additional testing is required and the requirement is met.

When the resulting voltage drop is still found to be unacceptable, the analysis will proceed to consider the

use of a static soft start unit that will provide a controlled rate of change of current.

The results of the analysis will be recorded and made available to the Area EPS Operator.

C. Static Inverter

A non-interactive inverter shall be treated as a synchronous generator of comparable size. A line

interactive inverter will be tested to establish the current that would be delivered to an EPS of zero

impedance. This will demonstrate the current control capacity of the inverter regulator.

The zero impedance current will be calculated from the value measured at two different impedances. Ifthe current is less than 120% of rated, the inverter will be considered to be in compliance at any rate. The

impedance values used for the test shall be as follows.

Z1 = 0.02*V*V/P

Z2 = 0.05*V*V/P

Where Z = impedance value

V = the DR unit rated line-to-line voltage, and

P = the DR unit rated power output.

The test will be carried out with a calibrated oscilloscope connected to measure the current in each phase.

The root mean square (rms) current shall be calculated for the first half of the cycle. From these results

the rms current to be delivered at an impedance level of zero shall be calculated by extrapolation.
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The test shall be carried out 10 times at each impedance value and the results maximized over these tests

when extrapolating to zero impedance.


Out-of-Range Operation

Operation with phase angles out of phase between the distributed generator and the electric power system

may result in overheating of synchronous generator armature core ends with damage to the electric power

system and the distributed generator equipment.

When operating with a lower voltage magnitude, branch circuits may cause malfunctioning of motors and

controls. Semiconductors operation may also be impacted when voltage magnitude is allowed to slip

below desired levels. The semiconductors may malfunction and cause loss of control of distributed

generator devices. In addition, lower voltage may also extinguish mercury vapor type and fluorescent

lamps causing personnel safety to be compromised.

Operation at under frequency may result in synchronous generator hot spots and higher than normal

generator insulation temperatures.

Synchronization Techniques

Either manual or automatic synchronization devices may be used for synchronization of the distributed

generator with the electric power system. Considerations in the design and operation of both types are

discussed below.

Manual Synchronization

Manual synchronization equipment is normally used on smaller (less than 100 kW) distributed generatorequipment and as a backup to an automatic system on larger units. Manual synchronization equipment

varies with distributed generator size. The requirements for synchronization equipment for DGs

operating in parallel with the EPS and able to operate as an island are summarized in Table 1. For the

similar requirements for DGs with no ability to operate as an island, see Table 2.

For small single-phase systems (10 kW or less) which are electric power system connected only with no

islanding capabilities, only two volt meters are required.

For larger systems which are 10 kW and larger and have both electric power system operation and

islanding operation capabilities, the manual synchronization equipment will consist of two voltmeters,

Table 1. Synchronizing Requirements for Paralleled DG Units with Islanding

Capability

DR Size Volt Meters Freq MetersPhase Angle

MetersSync Scopes

>10 kW-500 kW 2 2 1 0

>500 kW-10 MW 2 2 1 1

>10 MW 2 2 1 1
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Synch-Check Relays

Synch-check relays are used to ensure thatbefore a machine can be paralleled, the voltageson both sides of the circuit breaker are nearly in

synchronism. That is, that the angle between thevoltages and the frequencies are sufficiently closetogether that the circuit breaker can be closedsuccessfully. If the limits are exceeded, thesynchro-check relay will prevent closure of thecircuit breaker.

two frequency meters, and a synchroscope.18 (See Table 1.) One voltmeter and one frequency meter

monitor the electric power system voltage and frequency. The other voltmeter and frequency meter

monitor the distributed generator voltage and frequency. A synchroscope pointer is used to indicate the

phase angle between the electric power system voltage and the distributed generator voltage. The straight

up or 12 oclock position indicates that the two voltages are in phase.

For a synchroscope, the connection between the electric power system and the distributed generator is

made when the synchroscope is rotating slowly in the clockwise direction and the pointer is about 11:30

position. When the pointer is rotating, it shows the frequencies of the electric power system and thedistributed generator are not exactly the same. Synchronization with the pointer rotating slowly clockwise

will ensure the connection between the two units is made along with a small outflow of power from the

distributed generator to prohibit the reverse power relay from tripping erroneously.

Automatic Synchronization

Many types of automatic synchronizers are

available to replace part or all of the manual

synchronizing functions mentioned above. Synch-

check relays, which are designed to check the

electric power system voltage and the distributed

generator voltages, close a contact when the twovoltages are within certain limits for certain length

of time. The synch-check relays are the least costly

and simplest to operate. The synch-check relaysmay also serve as signal devices for automatically

closing the breaker at the point of common

coupling.

Highly accurate and reliable automatic synchronizing relays and electronic transducer combinationpackages are avail

ieee application guide

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