IEEE Application Guide

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Generation Interconnection

The NRECA Guide to IEEE 1547

Resource Dynamics Corporation

September 2001

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Introduction... 1

Section 1: Cooperative Distribution System Circuits ... 3

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

Voltage Regulation ... 6

P1547 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

Background... 11

Impact of DR ... 12

Synchronization ... 16

Background... 16

Impact of DR ... 16

Inadvertent Energizing of Area EPS... 23

Background... 23

Impact of DR ... 23

Monitoring ... 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

Background... 42

Impact of DR ... 43

Loss of Synchronism... 45

Background... 45

Impact of DR ... 45

Feeder Reclosing Coordination... 47

Background... 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

Background... 54

Impact of DR ... 56

Harmonics ... 60

Background... 60

Impact of DR ... 61

Immunity Protection ... 66

Background... 66

Impact of DR ... 66

Surge Capability... 68

P1547 Requirement Section 4.3.5) ... 68

Background... 68

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Tips, Techniques and Rules of Thumb ... 69 Islanding... 71 P1547 Requirement (Section 4.4) ... 71 Application Guidance ... 71 Background... 71 Impact of DR ... 71

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 ... 94

A.5.2 Non-islanding Test Procedure... 95

Appendix F ... 97

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Application Guide for Distributed Generation Interconnection

The 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 1 MVA. 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 in

Appendix 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

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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 distribution system 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 computers and other electronic appliances.

Distribution Secondary Systems

The secondary system is that portion of the distribution system between the primary feeders and the customer’s 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 a residential 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.

1_{Banking means paralleling on the secondary side a number of distribution transformers which are}

connected to the same primary. Banked transformers are still a form of radial distribution, because they are connected to one primary feeder. This configuration should not be confused with a secondary

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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 and

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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 that affect 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 radial distribution 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_.

2_{A feeder-voltage regulator can be either single-phase or 3-phase construction. The single-phase}

regulator is available in sizes ranging from 25-400kVA and the 3-phase regulator is available in sizes ranging from 500-2000kVA. Today's voltage regulators are all the step-voltage type. A step voltage regulator is basically an autotransformer which has numerous taps in series with the windings. These taps are changed automatically under a load by a voltage-sensing, switching mechanism. The taps are switched 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 factor to about 100%. Then automatically switched shunt capacitor banks are added to achieve the economic full-load power factor, which is typically 95% to 100%.

4_{Voltage Ratings of 60 Hz Electric Power Systems, ANSI C84.1-1995, Published by the National Electrical}

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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 current offset.

• The line voltage drop from the DR to the load center still reflects heavy loading, but the regulator output 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. Under certain conditions with a DR unit installed, other customers on the feeder may see higher than normal service 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 transformer with several other residences.

2. The distribution transformer serving these customers is located at a point on the feeder where the primary 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 even

raising 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 ANSI upper 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 (<10kW). This may not be the case, however, when a number of small units or a single larger unit have been installed in the same feeder. In this case, voltage regulation studies may be needed to insure that the feeder voltage will be maintained within appropriate limits.5

5_{To determine if the DR will cause a significant impact on the feeder voltage, the size and location of the}

DR, the voltage regulator settings, and impedance characteristics of the line must be considered. If line drop compensation is used by the regulator, then DR units interconnected within the regulator’s zone and downstream of the constant voltage point (CVP) will support (increase) the feeder voltage below the CVP. Those above the CVP will lower the voltage below the CVP. If voltage support is the key reason for using DR, then DR placement downstream of the CVP is crucial to meeting this objective (the farther

downstream of the CVP, the greater the support). The values of line-drop-compensation utilized will determine the CVP location on the feeder. Note that when no line-drop-compensation is used, the CVP is at the regulator device itself.

The installation of reverse power relay(s) by the DR owner may be required to maintain voltage regulation under these conditions.

The aggregate DR capacity threshold for which studies become appropriate depends on many factors. However, a reasonable rule-of-thumb is that a study is not required if:

• The injected current (measured at the primary level) is less than 5% of the feeder loading at the

interconnection point; and,

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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 excitation in 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 of an 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 customer owned. 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 line’s thermal limit without causing a voltage problem on the feeder. The power flow analysis should “flag” the locations where capacity constraints will be an issue from a thermal as well as a voltage perspective. In general, a DR at a location that is thermally limited is not connected at the optimal point from a “power loss” perspective.

6_{For shared secondaries, with DR even a small generator that injects less than 5% at the primary level}

could pose a voltage regulation risk to customers sharing the secondary. Thus, analysis of voltage conditions will almost always need to consider impacts on the secondary where the DR is located.

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Integration with Area Electric Power System Grounding

P1547 Requirement (Section 4.1.2)

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, 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 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-multi-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 same primary 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 steel}

poles 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 steel}

poles 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 commercial}

and industrial facilities is a Y-Y connected transformer. In these cases consideration has to be given to the grounding 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 the}

equipment and customer loads connected to the Area EPS feeder.

12_{For DR technologies that have time-variant fault contribution characteristics, the characteristic}

producing 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-multi-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 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.

Application Guidance

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 commercial}

and industrial facilities is a Y-Y connected transformer. In these cases consideration has to be given to the grounding of the generator if the secondary service is a 4-wire service.

14_{For DR technologies that have time-variant fault contribution characteristics, the characteristic}

producing 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-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 as discussed below. Customer's water pipe grounds Single phase secondary Station transformer Customer's water pipes

Primary phase wires Multigrounded neutral 1 φ transf S. A. Neutral Common Multigrounded

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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 type of 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-three-phase distribution transformers are connected three- 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 surge arrester 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 not be so large that it significantly dilutes the fault current contribution from the utility’s source substation and thereby degrades the ground fault detection sensitivity.

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

16_{In 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 and secondary 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 gap or arrester. Surge arresters on multigrounded neutral systems are connected directly to earth, and their grounding 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 –}

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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).

TIPS, TECHNIQUES AND RULES OF THUMB

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 be damaged.

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 conductor which 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 is quite 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 is the difference between its speed and the synchronous speed, divided by the synchronous speed. Slip is usually expressed as a percentage. It may be computed from the measured speed of the machine and the synchronous speed, but direct methods are more accurate.

Synchronization

P1547 Requirement (Section 4.1.3)

The DR unit shall synchronize with the Area EPS without causing a voltage fluctuation at the PCC greater than ± 5% of operating voltage.

Application Guidance

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 (∆ø, °) 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 the PCC, 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. If the 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.

TIPS, TECHNIQUES AND RULES OF THUMB

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 generator equipment 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 Meters Phase Angle

Meters Sync Scopes

>10 kW-500 kW 2 2 1 0

>500 kW-10 MW 2 2 1 1

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Synch-Check Relays

Synch-check relays are used to ensure that before a machine can be paralleled, the voltages on both sides of the circuit breaker are nearly in synchronism. That is, that the angle between the voltages and the frequencies are sufficiently close together that the circuit breaker can be closed successfully. If the limits are exceeded, the synchro-check relay will prevent closure of the circuit 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 o’clock 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 the distributed 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 Synch-check the electric power system voltage and the distributed generator voltages, close a contact when the two voltages are within certain limits for certain length of time. The synch-check relays are the least costly and simplest to operate. The synch-check relays may 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 combination packages are available with adjustable ranges to monitor and control the synchronism, frequency, phase or power factor and the voltage levels of the distributed generator. Dead bus relays can also be included in the combination packages to allow connecting to a dead bus (used in black plant applications) when the synchronizing relay itself would not provide a signal to close the circuit breaker at point of common coupling.

18_{Synchronizing lights serve as a backup to the synchroscope, or can substitute for the synchroscope.}

They are connected across the point of common coupling contacts and go dark at synchronism.

Table 2. Synchronizing Requirements for Paralleled DG Units without Islanding Capability DR Size Volt Meters

Voltage Differential

Meters

Freq Meters Phase Angle Meters Sync Scopes ≤10 kW 2 0 0 0 0 >10 kW-500 kW 2 1 0 0 0 >500 kW-10 MW 2 1 1 1 0 >10 MW 2 1 1 1 0

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Power Conversion Technology

Electric energy generated by a DR may be directly connected to an EPS, or indirectly connected through a static power converter. Directly connected synchronous generators must run at a synchronous shaft speed so that the power output is electrically in synchronism with the EPS. Directly connected induction generators are asychronous (not in synchronism). They operate at a rotational speed that varies with the prime mover and is slightly higher than that required by a synchronous generator. Indirect connection through a static power converter allows the electric energy source to operate independently of the EPS voltage and frequency. The method chosen to interconnect any of these energy sources to the EPS is dependent on the type of generation, its characteristics, its capacity, and the type of EPS service available at the site.

Induction

An induction generator is an asynchronous machine that requires an external source to provide the magnetizing (reactive) current necessary to establish the magnetic field across the air gap between the generator rotor and stator. Without such a source, an induction generator cannot supply electric power but must always operate in parallel with an EPS, a synchronous machine, or a capacitor that can supply the reactive requirements of the induction generator.

In certain instances, an induction generator may continue to generate electric power after the EPS source is removed. This phenomenon, known as self–excitation, can occur whenever there is sufficient

capacitance in parallel with the induction generator to provide the necessary excitation and when the connected load has certain resistive characteristics. This external capacitance may be part of the DR system or may consist of power factor correction capacitors located on the EPS circuit to which the DR is directly connected.

Induction generators operate at a rotational speed that is determined by the prime mover and is slightly higher than that required for exact synchronism. Below synchronous speed, these machines operate as induction motors and thus become a load on the EPS.

Some advantages of the induction generator are as follows:

• Needs only a very basic control system, since its operation is relatively simple.

• Does not require special procedures to synchronize with the electric EPS, since this occurs essentially automatically.

• Will normally cease to operate when an EPS outage occurs.

Induction machines must utilize speed matching within 5% of the synchronous speed prior to connecting. Synchronous machines must use synchronization relays or equipment to achieve an angular displacement between the machine output voltage and utility system voltage of 12 electrical degrees or less prior to connecting. Larger rotating equipment in this class will benefit from negative sequence detection (phase unbalance) should single phasing occur, and it good practice to include it for generators over 10 kW.

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Line Commutated vs. Self Commutated Inverters

Inverters may be line commutated or self commutated. Sychronizing of a line commutated unit requires only voltage magnitude matching because frequency and phase angle are established during connection. Synchronization of a self commutated inverter requires matching of voltage magnitude, frequency, and phase angle similar to any synchronous source. A self commutating inverter can operate independent from the electric power system as long as it has an internal frequency reference. A line commutated unit may not be able to make a black start, but may be able to continue to operate following separation from the electric power system. If line commutated unit has an internal frequency reference, it can continue to operate. Without a reference, the line commutated inverter will allow frequency to drift until it goes beyond the window of acceptable operating limits.

A disadvantage of an induction generator is its response when some types are connected to the area EPS at speeds significantly below synchronous speed. In this case, potentially damaging inrush currents and associated torques can result.

An induction generator, regardless of load, draws reactive power from the EPS and may adversely affect the voltage regulation on the circuit to which it is connected. The induction generator is then “sucking vars” from the system; it is important to consider the addition of capacitors to improve power factor and reduce reactive power draw.19

Synchronous

Most generators in service today are synchronous generators. A synchronous generator is an ac machine in which the rotational speed of normal operation is constant and in synchronism with the frequency of the EPS to which it is connected. Synchronous generators have their DR field excitation supplied either by a separate motor-generator set, a directly coupled self-excited dc generator, or a brushless exciter that does not require an outside electrical source; therefore, this type of generator can run either stand alone or interconnected with the EPS. When interconnected, the generator output is exactly in step with the EPS voltage and frequency. Note that separately excited synchronous generators can supply sustained fault current under nearly all operating conditions.

A synchronous generator requires more complex control than an induction generator, both to synchronize it with the EPS, and to control its field excitation. It also requires special protective equipment to isolate it from the EPS under fault conditions. Significant advantages include the fact that this type of machine can provide power during EPS outages and it also permits the DR owner to control the power factor at his facility by adjusting the dc field current.

Static Power Converter

Some DR installations produce electric power having voltages not in synchronism with those of the electric utility network to which they are to be connected. The purpose of an electric power converter is to provide an interface between the

nonsynchronous DR output and the utility so that the two may be properly

interconnected. Two categories of

nonsynchronous DR output voltages are as follows:

(1) Direct current voltages generated by dc generators, by fuel cells, by photovoltaic devices, by storage batteries, or by an ac generator through a rectifier.

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(2) Alternating current voltages generated by a synchronous generator running at nonsynchronous speed, or by an asynchronous generator.

As a consequence of these two broad categories of nonsynchronous DR output voltages, two broad categories of electric power converters can be used to connect the DR to the utility network:

(1) dc-to-ac power converter. In this case, the input voltage to the device is generally a nonregulated dc voltage. The output of the device is at the appropriate frequency and voltage magnitude as specified by the local utility. This is the dominant means of small and renewable DR

interconnection.

(2) ac-to-dc electric power converter. In this case, the input frequency and voltage magnitude to the device, or both, are not at levels that meet Area EPS requirements. The output of the converter device is at the appropriate frequency and voltage magnitude as specified by the Area EPS in cases where dc power can be utilized. This approach is not widely used.

The profusion of data centers and other customers using essentially dc power supplies (such as the power supplied by electronic ballasts) has opened the door to either a direct dc or dc-to-ac converter designed to deliver the dc output of small DR units directly to the application.

Static power converters are built using diodes, transistors, and thyristors, with ratings compatible with

DR applications. These solid-state devices are configured into rectifiers (to convert an ac voltage into a dc voltage), or into inverters (to convert a dc voltage into an ac voltage), or into cyclo-converters (to convert ac voltage at one frequency into ac voltage at another frequency). Some types require the utility source to operate while others may continue to function normally after a utility failure. The major advantages of solid-state converters are their higher efficiency and their potentially higher reliability as compared with rotating machinery converters. Additionally, this technology offers increased flexibility with the incorporation of protective relaying, coordination and communications options.

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Inadvertent Energizing of Area EPS

P1547 Requirement (Section 4.1.5)

Inadvertent Energization

The DR shall not energize the PCC when the Area EPS has been de-energized for any reason. Reconnection after Area EPS Outage

No reconnection shall take place until the Area EPS voltage and frequency are within the operating voltage range of 106V – 132V, and frequency range of 59.3Hz – 60.5Hz, respectively. The DR shall include an adjustable delay (or a fixed delay of five minutes) that can delay reconnection for up to five minutes20_{after Area EPS restoration of continuous normal voltage and frequency.}

Application Guidance

BACKGROUND

To ensure personnel safety during line maintenance or activities relating to service restoration, it is critical that inadvertent energizing of utility circuits be prevented when the EPS is de-energized. Accordingly, the DR shall not transfer power to the EPS side of the PCC when the EPS has been de-energized for any reason. Additionally, when the voltage or frequency of the Area EPS is outside of acceptable limits, unless islanding is permitted, power transfer from the distributed resource to the Area EPS must cease beyond the point of common coupling. In the case of a system fault, this will allow the Area EPS to step through its relaying and reclosing schemes in an effort to clear the fault, without interference from the DR.

IMPACT OF DR

Following an out-of-bounds event which has caused the DR to cease to energize the Area EPS line, the line shall remain disabled until continuous normal voltage and frequency have been maintained by the Area EPS for a minimum of five minutes. At this time, the DR is allowed to automatically reconnect to the Area EPS, if the Area EPS has authorized automatic reconnection.

20_{To prevent possible voltage collapse, staggered or random return time capability of DR units (such as}

induction generators) after the delay may be required.

It is expected that DR parallel operation will not be permitted when the density of the distributed resources of a particular portion of the aggregate system exceeds the capacity of that portion of the Area EPS beyond the PCC.

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TIPS, TECHNIQUES AND RULES OF THUMB

There is a range of incidents in which deenergization is required and inadvertent reenergization should be prevented. There are a number of different options for accomplishing this:

• manual disconnect switch; • direct transfer trip;

• automatic bus transfer switch; and, • non-islanding inverter.

Each of these options is discussed below. Manual Disconnect Switch21

A manual disconnect switch that can be locked can be used to separate the distributed resource from the Area EPS beyond the PCC. This provides Area EPS workers with an effective means to ensure that the system beyond the PCC cannot be inadvertently re-energized by the DR while maintenance is performed on the system22_.

Direct Transfer Trip

A direct transfer trip can serve to provide a remote signal activating the DR’s disconnecting device. As this can be activated remotely, it has the advantage of being capable of shutting down or disconnecting (depending upon the configuration) many sources at one time. Inadvertent re-energization of multiple units serving the same feeder can be controlled from a single source.

Transfer trip relaying is a method of protection whereby a tripping signal is transmitted to a remote line terminal, causing it to trip when a fault is detected in the protected line section. A transfer-trip relaying system is identified as an overreaching or an underreaching system, depending on the setting of the directional distance relay that keys the frequency shift tone or carrier transmitter at each terminal. If it has a setting that causes it to respond to faults on the protected line and, additionally to faults beyond the end of the protected line, it overreaches and the system is identified as an overreaching transfer trip system.

Permissive overreaching transfer trip systems

Permissive overreaching systems make use of a continuous pilot (guard) signal, and no tripping will occur while the guard tone is being received. A fault in the line section will cause the pilot frequency to shift to the trip frequency. At the same time, the fault detectors at both ends of the line will operate, and trip

21_{See subsequent section on Isolation Device for additional requirements on the use of disconnect}

switches.

22_{The disconnect switch does not, however, provide a sufficient means of ceasing and restoring power}

transfer to the system beyond the PCC when the change in state is required to occur quickly or automatically. Additionally, as distributed resources become more prevalent, it becomes more

cumbersome to manually switch and lock the disconnect switches. Disconnect switches may be required for other reasons as well (commercial, utility union work practices, etc.).

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signals will be transmitted to each line terminal, so that tripping will result to clear the line section. Tripping occurs when the distance relay operates at each terminal and a trip signal is received at that terminal. The distance relays at the two ends of the line cooperate to clearly identify a fault as being “internal” to the protected line or “external.”

Underreaching transfer trip systems

Underreaching systems may be either direct or permissive; they also make use of pilot signals. In direct systems, the fault detectors are set to overlap in the protected line section23_{, but not to respond to external}

faults. For internal faults, trip signals are transmitted from each end of the line to the opposite end, causing the circuit breakers to operate and clear the fault. In the direct underreaching system, receiving the channel trip causes tripping of the terminal breaker(s). No local fault-detector relay operation is required. Permissive underreach systems include a local directional distance relay which supervises tripping.

Overreaching transfer trip systems require that a signal be received by the channel equipment in order for tripping to take place. These systems are usually committed to channels that are not dependent on the integrity of the protected power line itself such as pilot wires and microwave.

Automatic Bus Transfer Switch

An automatic bus transfer switch can be applied to detect a loss of power beyond the PCC and subsequently change state to prevent transferring power to the Area EPS beyond the PCC.

Typically, the bus transfer switches are set so that they will not close on a dead bus thereby

preventing inadvertent re-energization. Non-Islanding Inverter

The non-islanding inverter can provide another means for preventing inadvertent re-energization. This is a relatively new product, although a track record of reliability is beginning to be established. Much work has been, and continues to be

performed to develop inverters that can ensure that the energy producing facility will not be able to generate electrical energy in the absence of the

EPS electrical source. Some of these inverters have been tested to appropriate standards on which the “non-islanding” function is based24_{. In these cases, some utilities have allowed the use of such devices}

and have modified their work practices accordingly.

23_{The directional distance relays are typically set to respond to faults within approximately 80 percent of}

the protected line length.

24_{UL 1741 is one example of a standard for inverters used on photovoltaic systems.}

CAN A SELF-COMMUTATED INVERTER BE NON-ISLANDING?

Self-commutated inverters can be designed as either voltage or current sources. Most EPS-interconnected self-commutated inverters are designed as current sources. The inverter uses the utility voltage as a reference, then provides the current available from the DR unit at the voltage and frequency the utility has presented to it. If the utility signal is not there as a reference, the inverter is designed to cease to energize the EPS across the PCC.

The high-frequency switching and digital control used by these inverters allows manufacturers to employ a variety of schemes to avoid islanding. One of these techniques, recently developed by a consortium of photovoltaic inverter manufacturers and Sandia National Laboratories, uses positive feedback from voltage and frequency to accelerate the drift of voltage and/or frequency outside of the normal trip limits when the EPS is not available to control these parameters.

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Monitoring

P1547 Requirement (Section 4.1.6)

Each DR unit of 250 kVA or more, or DR aggregate of 250 kVA or more at a single PCC shall have provisions for monitoring its availability, connection status, real power output and imaginary power output at the point of DR connection

Application Guidance

BACKGROUND

The need to monitor DR unit status is typically driven by Area EPS personnel safety and operating concerns. When there is no power export, and when reverse power relaying and/or power inverter logic prevents power export25_{, monitoring is usually not required. From a safety perspective, however,}

monitoring is still considered in some cases. When the DR is exporting power to the Area EPS, monitoring is essential.

Larger capacity DR installations may be located at a site with a relatively high electrical load. If the size of the DR is less than the size of the load, but is significant compared to the capability of the EPS serving the site, an operational basis may exist for monitoring.

This discussion of monitoring does not take into account the application of revenue metering. IEEE 1547 only addresses the technical requirements of interconnection; revenue metering is a business and

contractual issue and is not covered here.

IMPACT OF DR

In those cases where the DR has the capability to export power and/or energy into the EPS, the EPS operator is naturally concerned about the impact on distribution system operations. In these cases, and to ensure the safety of Area EPS operations personnel and of the general public, the interconnecting Area EPS generally requires real-time status information from the DR.

The 1547 Standard, as noted above, does not require this type of monitoring; this is typically included in the contract or tariff that describes the business terms of DR interconnection and EPS interaction. IEEE 1547 only requires that the DR unit include provisions for monitoring selected operating parameters at

the point of DR connection. The details of the monitoring requirements must be spelled out in the

agreement with the DR owner. However, to present a complete picture of the package of monitoring

25_{In this case, the Area EPS is assured that during an outage of a circuit or during unusual switching}

operations, the DR is unable to inject power and energy into the EPS. This operating restriction placed on the DR addresses the primary safety concerns associated with DR operation.