IEEE Application Guide

Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

Resource Dynamics Corporation September 2001

Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

September 2001

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 P1547 Requirement (Section 4.1.2) ........................................................................................................ 10 Application Guidance ............................................................................................................................. 11 Background......................................................................................................................................... 11 Impact of DR ...................................................................................................................................... 12 Tips, Techniques and Rules of Thumb ............................................................................................... 14 Synchronization .......................................................................................................................................... 16 P1547 Requirement (Section 4.1.3) ........................................................................................................ 16 Application Guidance ............................................................................................................................. 16 Background......................................................................................................................................... 16 Impact of DR ...................................................................................................................................... 16 Tips, Techniques and Rules of Thumb ............................................................................................... 18 Inadvertent Energizing of Area EPS........................................................................................................... 23 P1547 Requirement (Section 4.1.5) ........................................................................................................ 23 Application Guidance ............................................................................................................................. 23 Background......................................................................................................................................... 23 Impact of DR ...................................................................................................................................... 23 Tips, Techniques and Rules of Thumb ............................................................................................... 24 Monitoring .................................................................................................................................................. 26 P1547 Requirement (Section 4.1.6) ........................................................................................................ 26 Application Guidance ............................................................................................................................. 26 Background......................................................................................................................................... 26 Impact of DR ...................................................................................................................................... 26 Tips, Techniques and Rules of Thumb ............................................................................................... 27 Isolation Device .......................................................................................................................................... 30 P1547 Requirement (Section 4.1.7) ........................................................................................................ 30 Application Guidance ............................................................................................................................. 30 Background......................................................................................................................................... 30 Impact of DR ...................................................................................................................................... 31 Tips, Techniques and Rules of Thumb ............................................................................................... 31 Voltage Disturbances .................................................................................................................................. 33 P1547 Requirement (Section 4.2.1) ........................................................................................................ 33 Application Guidance ............................................................................................................................. 33 Background......................................................................................................................................... 33 Impact of DR ...................................................................................................................................... 34 Tips, Techniques and Rules of Thumb ............................................................................................... 35 Frequency Disturbances.............................................................................................................................. 39 P1547 Requirement (Section 4.2.2) ........................................................................................................ 39 Application Guidance ............................................................................................................................. 39

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Background......................................................................................................................................... 39 Impact of DR ...................................................................................................................................... 39 Tips, Techniques and Rules of Thumb ............................................................................................... 40 Disconnection for Faults ............................................................................................................................. 42 P1547 Requirement................................................................................................................................. 42 Application Guidance ............................................................................................................................. 42 Background......................................................................................................................................... 42 Impact of DR ...................................................................................................................................... 43 Tips, Techniques and Rules of Thumb ............................................................................................... 43 Loss of Synchronism................................................................................................................................... 45 P1547 Requirement (Section 4.2.4) ........................................................................................................ 45 Application Guidance ............................................................................................................................. 45 Background......................................................................................................................................... 45 Impact of DR ...................................................................................................................................... 45 Tips, Techniques and Rules of Thumb ............................................................................................... 45 Feeder Reclosing Coordination................................................................................................................... 47 P1547 Requirement (Section 4.2.5) ........................................................................................................ 47 Application Guidance ............................................................................................................................. 47 Background......................................................................................................................................... 47 Impact of DR ...................................................................................................................................... 47 Tips, Techniques and Rules of Thumb ............................................................................................... 49 Limitation of DC Injection.......................................................................................................................... 51 P1547 Requirement (Section 4.3.1) ........................................................................................................ 51 Application Guidance ............................................................................................................................. 51 Background......................................................................................................................................... 51 Impact of DR ...................................................................................................................................... 51 Tips, Techniques and Rules of Thumb ............................................................................................... 52 Limitation of Voltage Flicker Induced by the DR ...................................................................................... 54 P1547 Requirement................................................................................................................................. 54 Application Guidance ............................................................................................................................. 54 Background......................................................................................................................................... 54 Impact of DR ...................................................................................................................................... 56 Tips, Techniques and Rules of Thumb ............................................................................................... 57 Harmonics ................................................................................................................................................... 60 P1547 Requirement (Section 4.3.3) ........................................................................................................ 60 Application Guidance ............................................................................................................................. 60 Background......................................................................................................................................... 60 Impact of DR ...................................................................................................................................... 61 Tips, Techniques and Rules of Thumb ............................................................................................... 62 Immunity Protection ................................................................................................................................... 66 P1547 Requirement (Section 4.3.4) ........................................................................................................ 66 Application Guidance ............................................................................................................................. 66 Background......................................................................................................................................... 66 Impact of DR ...................................................................................................................................... 66 Tips, Techniques and Rules of Thumb ............................................................................................... 66 Surge Capability.......................................................................................................................................... 68 P1547 Requirement Section 4.3.5) ......................................................................................................... 68 Application Guidance ............................................................................................................................. 68 Background......................................................................................................................................... 68 Impact of DR ...................................................................................................................................... 68 3

Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

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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 Tips, 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 ........................................................................... 94 A.5.2 Non-islanding Test Procedure................................................................................................ 95 Appendix F ................................................................................................................................................. 97 References................................................................................................................................................... 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 Mike Smith, Singing River EPA, MS

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547 • •

September 2001

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 network 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 and secondary 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 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-tapchanging 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.

Switched shunt capacitor banks are often used on distribution systems as part of the overall voltageregulation 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%.

3

4

Voltage Ratings of 60 Hz Electric Power Systems, ANSI C84.1-1995, Published by the National Electrical Manufacturer’s 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 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 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. reduce losses. These conditions typically occur during off-peak periods.

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

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 (10 kW-500 kW 2 2 1 1 >500 kW-10 MW 2 2 1 1 >10 MW 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,

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Table 2. Synchronizing Requirements for Paralleled DG Units without Islanding Capability Voltage Phase Angle Sync DR Size Volt Meters Differential Freq Meters Meters Scopes Meters 2 0 0 0 0 ≤10 kW 2 1 0 0 0 >10 kW-500 kW 2 1 1 1 0 >500 kW-10 MW 2 1 1 1 0 >10 MW 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. Synchcheck relays, which are designed to 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.

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.

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.

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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.

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.

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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.

19

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.

See Appendix B for a discussion of power factor.

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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. 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.

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.

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

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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.

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.). 22

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

September 2001

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

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

The non-islanding inverter can provide another by these inverters allows manufacturers to employ a means for preventing inadvertent re-energization. variety of schemes to avoid islanding. One of these techniques, recently developed by a consortium of This is a relatively new product, although a track photovoltaic inverter manufacturers and Sandia record of reliability is beginning to be established. National Laboratories, uses positive feedback from Much work has been, and continues to be voltage and frequency to accelerate the drift of voltage performed to develop inverters that can ensure and/or frequency outside of the normal trip limits when the EPS is not available to control these parameters. 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.

The directional distance relays are typically set to respond to faults within approximately 80 percent of the protected line length. 23

24

UL 1741 is one example of a standard for inverters used on photovoltaic systems.

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

September 2001

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

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.

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547 requirements that may comprise the business arrangement, this section summarizes the fundamental monitoring provisions. The Area EPS is mostly concerned with DR system status and loading during times of unusual system operating states, such as an outage of a circuit or emergency switching operations. At these times, the EPS operator is reluctant to depend on automatic devices to remove the DR from the system. If the size of the DR is very small compared to the EPS serving the site, the interconnecting Area EPS generally will not require monitoring26.

September 2001

Establishing the DR Monitoring Threshold The suggested threshold for monitoring in IEEE 1547 is 250 kVa, or approximately 200 kW. During deliberations in development of this requirement, 100 kW was originally proposed as a lower break point. The 100 kW break point was sized for the 400-ampere electrical service entrances being used in many new upscale homes. The original intent was to exempt residential installations from the monitoring requirements. In addition, it was noted that many entities (such as RTO control centers) providing real time control of the Area EPS transmission system would only need to see the power flow from any aggregate installations totaling 1 MW or larger.

When monitoring is required, most Area EPS SCADA systems have the ability to monitor relay contact operations, and this capability can be used to provide core information about system status to the Area EPS operator. Most modern DR units today are equipped with multi-function microprocessor-based control systems. These systems generally have the capability for detailed data logging around fault conditions, with data storage in a non-volatile format. Accordingly, this information should be readily available to service personnel investigating fault conditions. If more detailed real time monitoring is desired, the area EPS operator may be able to use established systems to integrate the DR status outputs into their overall system monitoring. When the DR feeder penetration ratio exceeds 25 percent, based on the known minimum feeder section load with which the DR can be isolated, monitoring shall be required, regardless of the size of the DR unit.

TIPS, TECHNIQUES AND RULES OF THUMB In cases where the DR has the capability to export capacity and energy to the Area EPS, installation of metering for monitoring and control purposes is recommended, in accordance with the following guidelines: Aggregate DR Size Requirement 1 MW...................................................Monitoring required27

26

An example of this last case is a 20 kW windmill on a residential property with a peak load of 5 kW served by a rural distribution line with a capability of 6 MW.

27

Situations may arise when the EPS operator may be willing to waive this requirement based on the capability of the DR interconnection package, or the experience of the DR operator.

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

September 2001

Monitoring arrangements typically include: • • • • • •

Remote Terminal Unit (RTU) for performing Supervisory Control and Data Acquisition (SCADA) functions; communications equipment; telephone circuit protection equipment; transducers; potential transformers; and, current transformers.

The Area EPS operator is typically provided with local indication and discrete signals for remote monitoring of the Local EPS, including: • • •

Isolation device status (open or closed); Local EPS operating at normal voltage and frequency; and, Local EPS locked out (i.e., unable to be automatically connected to the Area EPS).

In addition, the monitoring arrangement should include electrical energy and demand information, reactive power information, voltage information, and alarms28. IEEE 1547 requires a design verification to ensure that the provisions for monitoring are in accordance with the technical requirements. Potential free contacts and analog values, originally included in the IEEE 1547 requirement but subsequently dropped, represent specific technologies that may be applicable for some systems, but are inappropriate for others. For example, a common photovoltaic (PV) application is to use multiple smaller inverters (often 1-2 kW) to make an aggregate system rated at over 50 kW. Typically, all of these inverters communicate via a communication link to a central computer that can display all of the required data (and more). Another popular approach is communication over a TCP/IP protocol through an Ethernet connection.

The monitoring arrangement should be capable of displaying 2 seconds of data gathered before and after any fault condition, and should retain data for the 10 most recent fault conditions. It is usually good practice to collect RMS amps, RMS volts, and frequency. Data should be recorded on a cycle-by-cycle basis at the point of common coupling, including a time stamp.

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

September 2001

EXAMPLE OF UTILITY-SPECIFIC REQUIREMENTS FOR DR MONITORING The DR will provide a terminal strip suitable for connecting 18 to 14 gauge wires via ring or spade terminations. On this terminal strip the following signals will be terminated. Analog Unidirectional Signals (signals will be 0 -1.0 milliamperes) • Instantaneous voltage (1 phase minimum) • Instantaneous current (1 phase minimum) Bi-directional Signals (signals will be -1.0 to 0 to + 1.0 milliamperes) • Instantaneous kW (1 phase minimum) • Instantaneous KVAR (1 phase minimum) Digital (all digital contacts will be form C contacts) • • •

Facility status (on line/off line, synchronizing breaker open/closed); Hourly generation (kWh pulses); and, Equipment alarms indicating functional status of protection system (for example, dead man timer, failed power supply, or other system failure alarm).

Note: Monitoring is technically involved. While this information is not prescriptive, it is intended to be useful for the cooperative member or DR developer to have available this typical list of monitoring and control needs. It should be noted that kW and KVAR metering is not included; this is likely to require revenue grade metering, not within the scope of IEEE 1547 but which will need to be addressed by the contractual arrangement with the DR owner.

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

September 2001

Isolation Device P1547 Requirement (Section 4.1.7) Where required by the Area EPS operating practices, a readily accessible, lockable, visible-break isolation device shall be located between the Area EPS and the DR unit.

Application Guidance BACKGROUND This requirement from IEEE 1547 differs from the earlier requirement, Inadvertent Energizing of the Area EPS. While the two requirements are clearly related, the earlier requirement focuses on preventing the DR energization of the PCC when the Area EPS has been de-energized for any reason. The intent of this requirement for an isolation device is primarily driven by personnel safety concerns during routine line maintenance or other service activities, not necessarily when the Area EPS is out of service. Strategically located disconnect switches are an integral part of any electrical power system. These switches provide visible isolation points to allow for A NEW NATIONAL ELECTRICAL CODE safe work practices. The National Electrical Code29 REQUIREMENT (NEC) dictates the requirements for disconnect devices, which allow for safe operation and maintenance of the Added as a new requirement in the 1999 NEC, Section 445-10 requires that generators be electrical power systems within public or private equipped with disconnect switches. The text of buildings and structures. This requirement deals this new code requirement reads as follows: specifically with disconnect switches required to ensure safe work practices taking place on the Area EPS and NEC 445-10. Disconnecting Means Required for not addressed by the National Electrical Code. Generators. Generators shall be equipped with a disconnect by means of which the generator and all protective devices and control apparatus are Similar to the National Electrical Code, all electric able to be disconnected entirely from the circuits utilities have established practices and procedures supplied by the generator except where: which ensure safe operation of the electrical power system under both normal and abnormal conditions. • The driving means for the generator can be readily shut down; and Several of these procedures identify methods that • The generator is not arranged to operate in ensure that the electrical system has been properly parallel with another generator or other configured to provide safe working conditions for Area source of voltage. EPS line and service personnel. Although these procedures may vary somewhat between utilities, the underlying intent of the procedures is to establish “safe work area clearances” to allow Area EPS line and service personnel to operate safely in proximity to the electrical power system. To achieve this result, electric utilities have developed procedures that require visible isolation, protective grounding and

National Electrical Code, NEC 1999, NFPA 70, published by the National Fire Protection Association, One Batterymarch Park, Quincy, Mass.

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September 2001

jurisdictional tagging of the portion of the electrical power system where clearance is to be gained. These procedures, in unison with other safety procedures and sound judgement based upon knowledge and experience, have resulted in an essentially hazard free work environment for Area EPS personnel.

IMPACT OF DR In a DR installation, some equipment and fuses or breakers may be energized from two or more directions. Thus, disconnect switches should be strategically installed to permit disconnection from all sources. Typically, the load-side contacts (switch blades) of a disconnect switch are de-energized when the switch is open. However, this is not necessarily the case when a DR is connected to the Area EPS system, so a safety label should be placed on the switch, warning that the load-side contacts may still be energized when the switch is in the open position. Also, a means should be provided for fuse replacement (in fused switches) without exposing the worker to energized parts.

TIPS, TECHNIQUES AND RULES OF THUMB To facilitate the utility safety procedures described above, it is a general practice that a visible break isolating device be provided for each source of electrical energy which is electrically connected to the utility electrical system. These isolation devices, typically electrical disconnect switches, are used to provide visible isolation of the electrical power source from the utility’s electrical system when clearance is to be gained.30 Installation of a disconnect switch allows utility workers to isolate the DR from the EPS and prevent inadvertent energization of circuits on which they are working. When a disconnect switch is provided, the following requirements should be met: 1. The energy producing source must be capable of being isolated from the Area EPS by means of an external, visible, gang-operated disconnecting switch. The switch should be externally operable without exposing the operator to contact with live parts and, if power operable, of a type that can be opened by hand in the event of a power supply failure. This disconnecting switch is to be installed, owned and maintained by the owner of the distributed resource facility. 2.

The disconnect switch shall be located within 10 feet of the point of common coupling. If this is not practical, the disconnecting switch should be located between the DR and the point of common coupling and a laminated weather-proof map showing the location of the DR disconnecting switch shall be permanently mounted adjacent to the PCC.

3. The disconnect switch must be rated for the voltage and current requirements of the installation. 4. Disconnect switches shall meet applicable UL, ANSI and IEEE standards, and shall be installed to meet all applicable local, state and federal codes. 5. The disconnect switch shall be readily accessible for operation and locking by the Area EPS personnel at all times. Operation of this switch by the serving utility is at the discretion of the utility with appropriate notice to the DR. See the related discussion of disconnect switches as included in the earlier section on Inadvertent Energization of Area EPS.

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6. The disconnect switch shall be clearly marked, “DR Disconnect Switch,” with permanent 3/8 inch letters or larger. 7. For disconnect switches energized from both sides, a marking shall be provided to indicate that all contacts of the switch may be energized. DR isolation requires all ungrounded conductors and equipment, such as inverters, transformers, and other associated devices to be disconnected from all sources of supply. The DR operator should install an isolation device to permit safe access to the wiring system.

CAUTION IN THE USE OF DISCONNECT SWITCHES A manual disconnect switch capable of being locked can be used to separate the distributed resource from the electric power system beyond the PCC. This provides utility workers with an effective means to ensure that the system beyond the PCC cannot be inadvertently reenergized by the DR as maintenance is performed on the system. 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.).

Effectively, each generator must be disconnected from every other source of electric power without jeopardizing either the equipment, operating personnel, the general public, or other sources that remain in operation. The isolation device should be operable without exposing the operator to contact with live parts, be capable of being locked in the open position, and be readily accessible. The rating of the switch should not be less than the load to be carried by the DR, and the open or closed position of the switch should be verifiable. Following the isolation of all electrical power sources, protective safety grounds are attached to the high voltage phase conductors and jurisdictional tags (tags specifying the individual person who can authorize operation of a particular electrical device, such as a disconnect switch) are placed to further safeguard utility personnel. These procedures ensure that safe work area clearances are established and maintained. Following the necessary maintenance work, the jurisdictional tags and the protective grounds are removed and the disconnect switches are closed to allow for re-energization of the electrical power system. As an option to the disconnect switch described above, much work has been, and continues to be performed to develop inverters which can ensure that the DR will not be able to generate electrical energy in the absence of the utility electrical source (the non-islanding inverter). Utilities may wish to modify their current work practices by waiving the requirement for an isolation device when such an inverter has been installed, and the inverters have been tested to appropriate standards on which the “non-islanding” function is based31. In most cases, the utility accessible and lockable visible-break, load break switch will be the option chosen to meet this requirement. It is suggested for DR projects less than 10 kW (e.g., small residential photovoltaic installations) that this requirement can be met by a plug or twist-lock plug, if it can be removed in a manner preventing it from being plugged back into the system. A pad-lockable cap that can be placed over the plug for which only utility personnel have the key is one such example. The testing provisions of IEEE 1547 include a demonstration of the operation of the utility disconnect switch or control being used to meet the isolation requirement.

31

UL 1741 is one example of a standard for inverters used on photovoltaic systems.

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Application Guide for Distributed Generation Interconnection The NRECA Guide to IEEE 1547

September 2001

Voltage Disturbances P1547 Requirement (Section 4.2.1) The protection functions of the interconnection system shall measure the effective (RMS) or fundamental frequency value of each phase-to-neutral or, alternatively, each phase-to-phase voltage. When any of the measured voltages is in any voltage range given below, the DR shall cease to energize the Area EPS within the clearing time as indicated. Clearing time is the time between the start of the abnormal condition and the DR ceasing to energize the Area EPS. For DR less than or equal to 30 kW in peak capacity, the voltage set points and clearing times shall be either fixed or field adjustable. For DR greater than 30 kW the voltage set points shall be field adjustable. 32 The voltages shall be measured at the point of DR connection when any of the following conditions exist: (a) the aggregate capacity of DR systems connected to a single PCC is less than or equal to 30 kW, (b) the interconnection equipment is certified to pass a non-islanding test33, (c) the aggregate DR capacity is less than 50% of the total Local EPS minimum electrical demand, and export of real or reactive power to the Area EPS is not permitted.

Interconnection System Response to Abnormal Voltages (on a 120 V, 60 Hz base)34 Voltage Range (Volts)

Clearing Time (sec.)*

V