Application Guide for Distributed Generation Interconnection: 2006 Update. The NRECA Guide to IEEE 1547

Transcription

1 Application Guide for Distributed Generation Interconnection: 2006 Update The NRECA Guide to IEEE 1547 Resource Dynamics Corporation March 2006

2 NOTICE While every effort was made to include information in this Guide that is as accurate as possible, neither the National Rural Electric Cooperative Association nor the Resource Dynamics Corporation guarantees the accuracy or completeness of or assumes any liability in connection with the information and opinions contained in this Guide. The National Rural Electric Cooperative Association and/or the Resource Dynamics Corporation shall in no event be liable for any personal injury, property damages, or other damages of any nature whatsoever, whether special, indirect, consequential, or compensatory, directly or indirectly resulting from the publication, use of, or reliance upon this Guide. This Guide is published with the understanding that National Rural Electric Cooperative Association and the Resource Dynamics Corporation are supplying information and opinion but are not attempting to render engineering or other professional services. If such services are required, the assistance of an appropriate professional should be sought. Copyright 2006 National Rural Electric Cooperative Association (NRECA). All rights reserved. No part of this document may be copied, reproduced, transcribed or utilized in any form or by any means, electronic or mechanical, including photocopying and recording, without prior written permission from the copyright owner. 2

3 FOREWORD 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. Robert Saint of the NRECA guided development of the document throughout the process and his insight and review was invaluable. 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: Joe Dorough, Jackson EMC, GA (Chairman) David E. Garrison, Allgeier Martin & Associates, MO (Recorder) Steve Atkinson, Northern Virginia EC, VA Mark Barbee, Kansas Electric Power Co-op, KS Robin W. Blanton, Piedmont EMC, NC Robert Dew, Hi-Line Engineering, GA Ronnie Frizzell, Arkansas Electric Cooperative Corp., AR Jon Joyce, Central REC, OK Donald Junta, RUS, DC Rollie Miller, Hill County EC, MT Joe Perry, Patterson & Dewar Engineers, GA Ryan Smoak, McCall-Thomas Engineering Co., SC Brian Tomlinson, Navarro County EC, TX Pat Williams, East Mississippi EPA, MS Kenneth Winder, Moon Lake Electric Assn., UT Any comments or suggestions regarding the content or use of this Guide are welcome. Please address all comments to: Bob Saint, Principal, T&D Engineering National Rural Electric Cooperative Association 4301 Wilson Blvd. Arlington, VA Phone: (703) National Rural Electric Cooperative Association March

4 INTRODUCTION Over the last 5 to 7 years, there has been a significant increase in the number of interconnected distributed generation (DG) units. The increasing penetration of DG was driven by improving cost and performance of both old-line and new technologies, and by customers and third parties seeking to reduce costs, increase local control of the energy resource, and increasing awareness of the important role of power system reliability. New guidelines and requirements for interconnection are being adopted by many states, and the impact of the IEEE 1547 interconnection standard, approved by the IEEE in 2003, is clearly being felt. While the technical requirements for interconnection continue to be the focus of this Application Guide, some business and tariff issues are having significant impacts on ultimate project feasibility. This Guide briefly examines the key business and tariff issues, referencing the NRECA Business and Contract Guide and other elements of the DG Toolkit. Business issues receiving a lot of attention include net metering and net billing, liability insurance and utility rights of termination and disconnection. When interconnecting DG to the electric utility system, the DG unit must meet a series of technical requirements designed to ensure the safety of personnel and the stability of the power system. To meet these technical requirements, the DER unit must include protection, control and communication components enabling safe operation and interaction with the utility system. If the DG manufacturer must meet differing technical requirements for each installation, then a customized protection, control and communication package must be designed and assembled for each unit. However, if the technical requirements for DG interconnection can be standardized, the DG unit will reflect lower costs due to the standard (rather than customized) protection, control and communication package offered with each unit. This is the intent of IEEE Standard IEEE P1547.2, Draft Application Guide for IEEE Std 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems was being developed when this update was published. Draft version 3.1 of the IEEE document was published in February, 2006, and this document draws heavily from that preliminary, unapproved version. Like with the IEEE document, use information contained herein AT YOUR OWN RISK. 4

5 FOREWORD...3 INTRODUCTION...4 Section 1: IEEE 1547 Background...7 Section 2: Cooperative Distribution System Circuits...11 Section 3: Business and Contract Issues...13 Section 4: Meeting IEEE 1547 Technical Requirements...16 Voltage Regulation...16 Application Guidance...16 Integration with Area Electric Power System Grounding...22 Application Guidance...22 Synchronization...25 Application Guidance...25 Distributed Resources on Secondary Grid and Spot Networks...32 Inadvertent Energizing of the Area EPS...34 Application Guidance...34 Background...34 Impact of DR...34 Tips, Techniques and Rules of Thumb...34 Monitoring Provisions...36 Application Guidance...36 Background...36 Impact of DR...36 Tips, Techniques and Rules of Thumb...37 Isolation Device...40 Application Guidance...40 Background...40 Impact of DR...41 Tips, Techniques and Rules of Thumb...41 Protection from Electromagnetic Interference...43 Application Guidance...43 Background...43 Impact of DR...44 Surge Withstand Performance...45 Application Guidance...45 Background...45 Impact of DR...45 Tips, Techniques and Rules of Thumb...46 Paralleling Devices...48 Application Guidance...48 Background...48 Impact of DR...48 Tips, Techniques and Rules of Thumb...49 Response to Area EPS Abnormal Conditions...50 Application Guidance...50 Application Guidance...51 Background...51 Impact of DR...53 Tips, Techniques and Rules of Thumb...54 Area EPS Reclosing Coordination...60 Application Guidance

6 Background...60 Impact of DR...61 Tips, Techniques and Rules of Thumb...63 Voltage...66 Application Guidance...66 Background...66 Impact of DR...67 Tips, Techniques and Rules of Thumb...68 Frequency...73 Application Guidance...73 Background...73 Impact of DR...73 Tips, Techniques and Rules of Thumb...74 Loss of Synchronism...76 Application Guidance...76 Background...76 Impact of DR...76 Tips, Techniques and Rules of Thumb...77 Reconnection To Area EPS...79 Application Guidance...79 Limitation of DC Injection...81 Application Guidance...81 Background...81 Impact of DR...81 Tips, Techniques and Rules of Thumb...82 Limitation of Flicker Induced by the DR...83 Application Guidance...83 Background...83 Impact of DR...85 Tips, Techniques and Rules of Thumb...86 Harmonics...88 Background...88 Impact of DR...89 Tips, Techniques and Rules of Thumb...91 Islanding...94 Background...94 Impact of DR...94 Tips, Techniques and Rules of Thumb...95 Intentional Islanding...98 Appendix A - Glossary Appendix B - Discussion of Power Factor Appendix C - Grounding Fundamentals Appendix D - Example One-Line Diagrams Appendix E - Interconnection Standards Appendix F - References

7 Section 1: IEEE 1547 Background IEEE 1547 Series of Standards IEEE 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems, is the first of a series of standards documents being developed by the Institute of Electrical and Electronic Engineers (IEEE) concerning distributed resources interconnection. A number of related standards projects are currently underway, including , P1547.2, P1547.3, P1547.4, P1547.5, and P IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems Scope. This standard establishes criteria and requirements for interconnection of DR with electric power systems (EPS). Purpose. This document provides a uniform standard for interconnection of distributed resources with electric power systems. It provides requirements relevant to the performance, operation, testing, safety considerations, and maintenance of the interconnection. IEEE P Draft Standard for Conformance Tests Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems Scope. This standard specifies the type, production, and commissioning tests that shall be performed to demonstrate that the interconnection functions and equipment of a DR conform to IEEE Standard P1547. Purpose. Interconnection equipment that connects DR to an electric power system (EPS) must meet the requirements specified in IEEE Standard P1547. Standardized test procedures are necessary to establish and verify compliance with those requirements. These test procedures must provide both repeatable results, independent of test location, and flexibility to accommodate a variety of DR technologies. IEEE P Draft Application Guide for IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems Scope. This guide provides technical background and application details to support the understanding of IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems. Purpose. This document facilitates the use of IEEE 1547 by characterizing the various forms of distributed resource technologies and the associated interconnection issues. Additionally, the background and rationale of the technical requirements are discussed in terms of the operation of the distributed resource interconnection with the electric power system. Presented in the document are technical descriptions and schematics, applications guidance, and interconnection examples to enhance the use of IEEE IEEE P Draft Guide For Monitoring, Information Exchange, and Control of Distributed Resources Interconnected with Electric Power Systems Scope. This document provides guidelines for monitoring, information exchange, and control for DR interconnected with EPS. Purpose. This document facilitates the interoperability of one or more distributed resources interconnected with electric power systems. It describes functionality, parameters and methodologies for monitoring, information exchange and control for the interconnected distributed resources with or associated with electric power systems. 7

8 Distributed resources include systems in the areas of fuel cells, photovoltaics, wind turbines, microturbines, other distributed generators, and distributed energy storage systems. IEEE P Draft Guide for Design, Operation, and Integration of Distributed Resource Island Systems with Electric Power Systems Scope. This document provides alternative approaches and good practices for the design, operation, and integration of DR island systems with EPS. This includes the ability to separate from and reconnect to part of the area EPS while providing power to the islanded local EPSs. This guide includes the distributed resources, interconnection systems, and participating electric power systems. Purpose. This guide is intended to be used by EPS designers, operators, system integrators, and equipment manufacturers. The document is intended to provide an introduction, overview and address engineering concerns of DR island systems. It is relevant to the design, operation, and integration of DR island systems. Implementation of this guide will expand the benefits of using DR by targeting improved electric power system reliability and build upon the interconnection requirements of IEEE IEEE P Draft Technical Guidelines for Interconnection of Electric Power Sources Greater than 10MVA to the Power Transmission Grid Scope. This document provides guidelines regarding the technical requirements, including design, construction, commissioning acceptance testing and maintenance/performance requirements, for interconnecting dispatchable electric power sources with a capacity of more than 10 MVA to a bulk power transmission grid. Purpose. The purpose of this project is to provide technical information and guidance to all parties involved in the interconnection of dispatchable electric power sources to a transmission grid about the various considerations needed to be evaluated for establishing acceptable parameters such that the interconnection is technically correct. IEEE P Draft Recommended Practice For Interconnecting Distributed Resources With Electric Power Systems Distribution Secondary Networks Scope. This standard builds upon IEEE Standard 1547 for the interconnection of DR to distribution secondary network systems. This standard establishes recommended criteria, requirements and tests, and provides guidance for interconnection of distribution secondary network system types of Area EPS with DR providing electric power generation in Local EPS. Purpose. This standard focuses on the technical issues associated with the interconnection of Area EPS distribution secondary networks with a Local EPS having DR generation. The standard provides recommendations relevant to the performance, operation, testing, safety considerations, and maintenance of the interconnection. In this standard consideration is given to the needs of the Local EPS to be able to provide enhanced service to the DR owner loads as well as to other loads served by the network. Equally, the standard addresses the technical concerns and issues of the Area EPS. Further, this standard identifies communication and control recommendations and provides guidance on considerations that will have to be addressed for such DR interconnections. Need for IEEE 1547 DR is increasingly being deployed commercially. DR is defined as small-scale electricity generation located close to the load being served. A lot of attention has been paid to DR over the last decade, and many new projects are being developed and proposed for end-use customers. Most of these projects will 8

9 need to be interconnected with the grid. Interconnection will require proper equipment that will allow the customer facility to interact with the grid and provide the customer with an alternative power supply source. The interconnection system is the equipment that makes up the physical link between the DR and the utility. The interconnection system is the means by which the DR unit electrically connects to the outside electrical power system and can also provide monitoring, control, metering, and dispatch of the DR unit. As recognized in IEEE 1547, there is a critical need for a single document of consensus standard technical requirements for DR interconnection rather than having to conform to numerous local practices and guidelines. IEEE 1547 provides uniform criteria and requirements relevant to the performance, operation, testing, safety considerations, and maintenance of the interconnection. Meeting IEEE 1547 Technical Requirements As stated in IEEE 1547: The requirements shall be met at the point of common coupling (PCC), although the devices used to meet these requirements can be located elsewhere. This standard applies to interconnection based on the aggregate rating of all the DR units that are within the Local EPS. The functions of the interconnection system hardware and software that affect the Area EPS are required to meet this standard regardless of their location on the EPS. The stated specifications and requirements, both technical and testing, are universally needed for interconnection of DR, including synchronous machines, induction machines, or power inverters/converters, and will be sufficient for most installations. In an effort to open the door for requirements not specifically included in IEEE 1547, the Standard adds a footnote to the Purpose that states additional technical requirements and/or tests may be necessary for some limited situations. While the impact of this footnote on the adoption and implementation of IEEE 1547 is not completely clear, it does allow state and local authorities having jurisdiction over the interconnection to impose additional requirements as appropriate. Throughout this Guide some of these additional requirements are noted. Limitations of IEEE 1547 IEEE 1547 is not all-encompassing in its coverage of DR interconnection. Examples of some of the limitations: Applies to DR installations with aggregate capacity of 10 MVA or less at the point of common coupling 1 (PCC); Main focus of IEEE 1547 is DR on radial primary and secondary distribution systems; Assumes that the DR is a 60 Hz source; Does not prescribe protection or operating requirements for DR units; Does not address planning, designing, operating, or maintaining the grid; Does not address business or tariff issues. 1 Defined in IEEE 1547 as the point where the customer s electric facility is connected to the utility distribution system (or the area electric power system). 9

10 Does not apply to automatic transfer schemes in which load is transferred between the DR and the utility grid in a momentary make-before-break operation provided the duration of paralleling the sources is less than 100 ms for DR interconnected to radial feeders. How to Use This Guide This document is an update of the NRECA Guide originally published in April This application guide is intended to supplement, expand and clarify the technical requirements of IEEE While the Standard includes DG through 10 MVA, this guide addresses DG through 3 MVA. Networks are a special case and are briefly addressed in IEEE 1547 and in more detail in However, networks are not discussed in this document as their use by cooperatives is limited. The Standard does not cover revenue metering requirements, or tariff and contract issues in detail. Section 2 of this document gives background information on cooperative distribution system circuits. This Guide briefly examines the key business and tariff issues in Section 3, referencing the NRECA Business and Contract Guide and other elements of the DG Toolkit. Business issues receiving a lot of attention currently include net metering and net billing, liability insurance and utility rights of termination and disconnection. The topics in Section 4 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. Appendix A is a glossary of terms. A discussion of power factor is provided in Appendix B. While this topic is not addressed in the Standard, it is important to consider. Since grounding is such an important topic and there are some non-standard grounding practices, Grounding Fundamentals are discussed in Appendix C. Appendix D shows example one line diagrams. Other interconnection standards are shown in Appendix E. 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, newly added DG may account for a significant percentage of the circuit load. The Tips, Techniques and Rules of Thumb section under each topic gives guidelines and thresholds where additional requirements may apply. In addition, most installations over 1 MW will require an engineering study to determine any additional requirements. In the Guide, the terms distributed generation (DG) and distributed resources (DR) are used interchangeably. 10

11 Section 2: 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. 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 (I 2 R). 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. 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. 11

12 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 subtransmission 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 banking 2 is used in areas where the loads are close together and there is a need to reduce voltage flicker due to motor starting. 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. 2 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. 12

13 Section 3: Business and Contract Issues Examination of the state and utility guidelines for DER interconnection provides some insight into the issues deemed most important at the implementation level. The following issues were addressed by a number of states, but some state guidelines were silent on a few key issues. Application Process. Every state and utility guideline included an application process. This process always incorporated the submission of plans and schematics to the utility for approval. Feasibility/Impact/Pre-Interconnection Studies. Almost all of the guidelines reviewed in Table 1 covered and allowed for up-front impact studies, typically completed in a short timeframe at little or low cost to the applicant. Facility/Detailed/Engineering Studies. These types of more detailed studies are closely tied to the feasibility/impact studies. Fewer sets of guidelines included these studies. Interconnection/Application Fees. While most state and utility interconnection requirements do include one or more fees as part of the application process, some of the baseline interconnection documents do not cover the details of these fees. In some case, the fees are spelled out in either the application form itself, of a related process flow document. Electric Supply/Purchase Agreement. This is an agreement signed between the utility and the customer covering the terms and conditions under which electrical power is supplied to, or purchased from the utility. As an example, Salt River Project (SRP) requires customers purchasing energy from SRP utilizing an interconnected DER system to enter into an agreement for backup, supplemental and maintenance power with an energy supplier (that may be a different entity than SRP). Insurance/Liability Requirements. This requirement is discussed in detail elsewhere in this report. While not spelled out in all the guidelines reviewed, most jurisdictions and utilities require the DER owner to be covered by a current liability insurance policy. Refund of Salvage Value. This requirement is only included in the California Rule 21 rules that read as follows When a Producer elects to abandon the Special Facilities for which it has either advanced the installed costs or constructed and transferred to [PG&E], the Producer shall, at a minimum, receive from [PG&E] a credit for the net salvage value of the Special Facilities. This issue is not addressed in the rules of any other states. Dispute Resolution. This topic is addressed only by a minority of the guidelines reviewed. However, it is becoming more important as the processes mature in each state, and especially since it was specifically covered in the FERC process currently underway. Minnesota has addressed the issue as follows: A) Each Party agrees to attempt to resolve all disputes arising hereunder promptly, equitably and in a good faith manner. B) In the event a dispute arises under this Agreement, and if it cannot be resolved by the Parties within thirty (30) days after written notice of the dispute to the other Party, the Parties agree to submit the dispute to mediation by a mutually acceptable mediator, in a mutually convenient location in the State of Minnesota. The Parties agree to participate in good faith in the mediation for a period of 90 days. If the parties are not successful in resolving their disputes through mediation, then the Parties may refer the dispute for resolution to the Minnesota Public Utilities Commission (MPUC), which shall maintain continuing jurisdiction over this Agreement. 13

14 Table 1 shows some state-level technical requirements and how they correspond with IEEE 1547 and with business and contract requirements. Table 1. Technical Interconnection Requirements AZ CA CT DE IL MA MI MN NJ NY REQUIREMENTS FOR INTERCONNECTING DISTRIBUTED GENERATORS TO AN ELECTRIC POWER SYSTEM State Guidelines (Draft) Salt River Project Guidelines California Interconnection Guidebook Rule 21 - SCE, SDG&E, PG&E CL&P/UIC Guidelines** Connectiv Power Guidelines ComEd: The DG Book - Guidelines Ameren Draft Guidelines State Guidelines (Draft)** WMEC Guidelines** MEC Guidelines Consumer Energy Guidelines Proposed State Guidelines** Connectiv Guidelines PSEG Guidelines State Guidelines ConEd Guidelines IEEE 1547 Technical Requirements 4.1 General Requirements Voltage regulation Y* Y* Y* Y* Y Y* Y* Y Y Y*** Y*** Y Y*** Y*** Y*** Y*** Integration with Area EPS grounding Y* Y Y Y* Y* Y* Y* Synchronization Y*** Y*** Y* Y* Y* Y*** Y Y Y*** Y*** Y Y*** Y*** Y*** Y*** Distributed resources Distribution secondary grid networks Distribution secondary spot networks Y* Inadvertant energization of the Area EPS Y Y Y Y Y Y* Y Y Y Y Y Monitoring provisions Y* Y* Y* Y* Y* Y* Y* Isolation device (disconnect switch) Y* Y* Y Y Y Y Y Y* Y Y Y* Y Y Y Y Y Y Interconnection integrity Protection from electromagnetic interference Y* Surge withstand performance Y* Y* Y Y Y* Paralleling device Y 4.2 Response to Area EPS abnormal conditions Area EPS faults Y* Y* Y* Y* Y* Y* Y Y Y* Y Y Y Area EPS reclosing coordination Y* Y* Y* Y* Y* Y* Y Y Y* Y* Y Y* Voltage Y* Y*** Y* Y* Y* Y Y Y* Y* Y Y* Y* Y* Y* Frequency Y* Y*** Y* Y* Y* Y Y Y* Y* Y Y* Y* Y* Y* Loss of synchronism (no flicker) Y* Y* Y Y Y* Y Y Y Y Y* Y Y* Y* Y* Y* Reconnection to Area EPS Y* Y* Y* Y* Y* Y Y Y Y Y Y* 4.3 Power Quality Limitation of DC injection Y Y Y Y Y Y Y Y* Y* Y* Limitation of flicker induced by the DR Y* Y* Y Y Y* Y Y Y Y Y* Y* Y Y Y Y Y* Harmonics Y* Y* Y* Y* Y* Y* Y Y Y Y* Y Y Y Y Y 4.4 Islanding Unintentional Islanding Y* Y* Y* Y* Y* Y* Y* Y Y Y* Y* Y Y Y Intentional Islanding Technical Requirements not covered in IEEE 1547 Customer responsible for protecting their equipment Y Y Y Y Y Y Y Y Y Y Dedicated transformers - special requirements Y Y Y Y Y Y Y Y Y Y Y Synchronous generators - special requirements Y Y Y Y Y Y Y Y Y Y Y Y Y Y Induction generators - special requirements Y Y Y Y Y Y Y Y Y Y Y Y Y Y Static inverters / inverter systems - special requirements Y Y Y Y Y Y Y Y Y Y Y Y Requirements for meters/metering Y Y Y Y Y Y Y Y Y Y Y Y Y Y Net metering Y Y Y Y Y Y Y Y Telemetering / Communication channels Y Y Y Y Y Y Y Y Y Y Y Y Momentary Paralleling allowed Y Y Y Y Y Y Y Y Y+ Y Equipment precertification/pre-approval Y Y Y Y Y Y Y Y Y IEEE 1547 Testing Requirements 5.1 Design tests (Type testing) Y* Y* Y* Y* Y* 5.2 Production tests Y* Y* 5.3 Interconnection installation evaluation Y* Y* Y* Y* Y* Y* Y* Y* 5.4 Commissioning tests Y* Y* Y* Y* Y* Y* Y* Y* Y Y Y* Y* Y* Y* Y* Y* 5.5 Periodic interconnection tests Y* Y* Y* Y* Y* Y* Y* Y* Y* Y* Y* Y* Y* Y* Y* Business/Contractual Requirements Application process - schematics, plans submitted Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Feasibility/Impact/Pre-Interconnection studies required Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Facility/Detailed/Engineering studies may be required Y Y Y Y Y Y Y Y Y Interconnection/Application fees required Y Y Y Y Y Y Y Y Y Y Electric supply/purchase agreement Y Y Insurance/liability requirements Y Y Y Y Y Y Y Y Utility refunds salvage value of special facilities if abandoned Y Dispute resolution process Y Y Y Y Y Termination rights Y Y Y Y *Requirement does not exactly match IEEE 1547, but has the same purpose - see state/utility guidelines for details **In the guidelines, it is specifically mentioned that all generators must comply with IEEE 1547 standards, in addition to their own requirements ***Requirement is mentioned or implied, but no specific parameters are given +Momentary paralleling allowed, but special relays are required in certain cases The NRECA DG Toolkit contains additional information and guidance on business and contract issues and includes a number of documents, which are described below. The Business and Contract Guide provides a ready-reference on how to deal with customer and thirdparty generators, from the initial information requirements needed to consider an application, to the detailed contract documents used to close the deal. Cooperative staff that may benefit from use of this Guide includes T&D engineers, DG lawyers and Distribution Managers. Attachments to the Guide include a Consumer Guideline for consumers expressing an interest in DG; a short form interconnection 14

15 contract for photovoltaic or other DG units less than 10 kw for installation in a home, residence, business; a long form interconnection contract for DG units that do not qualify for the short form; and an application form (in two parts) that must be completed by consumers seeking permission to interconnect. The Toolkit also contains a document titled Developing Rates for Distributed Generation. This document describes the numerous issues that must be addressed in setting policies, rates, and procedures for dealing with distributed generation, and give sample tariffs. The DG Toolkit also contains a White Paper on Distributed Generation which addresses many of current issues cooperatives are facing regarding distributed generation. 15

16 Section 4: Meeting IEEE 1547 Technical Requirements Voltage Regulation IEEE 1547 Requirement (Section 4.1.1) The DR shall not actively regulate the voltage at the PCC. The DR shall not cause the Area EPS service voltage at other Local EPSs to go outside the requirements of ANSI C84.1, Range A. Application Guidance BACKGROUND Voltage regulation is the term used to describe the process and equipment used by an Area Electric Power System (Area EPS) operator to maintain voltage within acceptable limits. The primary objective of voltage regulation is to provide each customer connected to the Area EPS with voltage that conforms to the design limitations of the customer s utilization equipment. Almost all utilization equipment is designed for use at a definite terminal voltage: the nameplate voltage rating. The voltage drop in each part of the electrical power system from the source to the utilization devices makes it economically impractical to provide all customers with a constant voltage corresponding to the nameplate voltage of utilization devices. Thus, a compromise is necessary between the allowable deviation from utilization equipment nameplate voltage supplied by the power system and the deviation above and below the nameplate voltage at which satisfactory equipment performance can still be obtained. The voltage limits at the Point of Common Coupling (PCC) where the Area EPS is connected to a Local EPS are specified in the American National Standards Institute (ANSI) Standard C84.1. Range A defined by ANSI C is the most stringent requirement meant to narrowly define normal operating conditions at the PCC. The Area EPS is to be designed and operated so that the service voltage at each PCC will be within the limits specified for Range A. However, this standard does allow infrequent voltage excursions outside of these limits. This standard also defines the Range A utilization voltage. Utilization equipment is to be designed and rated to give fully satisfactory performance when the voltage at its terminals is within Range A utilization voltage limits. Figure 1 shows the Range A service and utilization voltage limits on a 120-volt base. 3 3 To make it easier to compare the voltage ranges on an electrical power system, a 120-volt base is frequently used. The use of a 120-volt base cancels the transformation ratios between the various voltage levels in the power system so that the actual voltages vary solely on the basis of the voltage drops in the system. Any voltage may be converted to a 120-volt base by dividing the actual voltage by the ratio of transformation to the 120-volt base. For example, the ratio of transformation for a 480-volt level of the power system is 480/120 or 4, so 460 Volts measured on the 480-volt level of the system would be 460/4 or 115 Volts on a 120-volt base. 16

17 125 MAXIMUM VOLTAGE LIMIT RANGE A V 125 V VOLTAGE ON A 120 V BASE ALLOWABLE VOLTAGE DROP IN AREA EPS PRIMARY 1 ALLOWABLE VOLTAGE DROP IN TRANSFORMER AND SECONDARY 2 ALLOWABLE VOLTAGE DROP IN LOCAL EPS FOR OTHER THAN LIGHTING EQUIPMENT 117 V 114 V ALLOWABLE VOLTAGE DROP IN LOCAL EPS FOR LIGHTING EQUIPMENT SERVICE VOLTAGE LIMITS UTILIZATION VOLTAGE LIMITS FOR LIGHTING EQUIPMENT UTILIZATION VOLTAGE LIMITS FOR OTHER THAN LIGHTING EQUIPMENT 110 V 108 V 1 The portion of the Area EPS operating at a primary voltage level, typically 4, 12, 25 or 34.5 kv. 2 The portion of the Area EPS operating at a secondary voltage level, ranging from 120 to 600 Volts. Figure 1. ANSI C84.1 Range A Voltage Limits (120-Volt Base) The voltage supplied to each customer at the PCC is an important measure of service quality. Satisfactory voltage level is required to operate lights, equipment and appliances properly. In many states within the United States the voltage regulation to be maintained at the PCC by the Area EPS Operator under normal system conditions is specified by the state regulatory authority having jurisdiction. These state requirements may vary from state to state and may be different from those specified in ANSI C84.1. The maximum permissible deviation from nominal system voltage at the PCC is typically limited to 5% and agrees with the service voltage limits of ANSI C84.1. Due to the dynamic nature of most customer loads, the load current and power factor at any given point on the Area EPS is constantly changing. Accordingly the voltage at any given point away from a generator bus is subject to constant change due to the voltage drops in the impedances between that point and the generators. Voltage regulation is required to maintain voltage within acceptable limits. The distribution substation provides the connection between the transmission system, where most generation is currently interconnected, and the distribution system. The distribution system consists of distribution circuits 4 used to distribute power from the distribution substations to numerous transformers serving individual or small groups of customers. Most Area EPS s are radial and have only one source of power i.e. the distribution substation. The typical Area EPS is regulated at its source substation using voltage regulators 5, automatic load tap changing transformers 6 and capacitor banks. 4 Distribution circuits are synonymous with the term Area Electric Power System (Area EPS). The Area EPS consists of the facilities that deliver electric power to a load. 5 Voltage regulators can be either single phase or three phase construction. Today s voltage regulators are step voltage type. A step voltage regulator is an autotransformer with numerous taps in series with the windings. These taps are changed automatically under load by a voltage sensing, switching mechanism to maintain a voltage as close to predetermined level as possible. 6 Automatic load tap changing transformers operate similar to step voltage regulators except they are three phase devices. They have voltage sensing on only one phase and step all three phases in unison. 17

18 Shunt capacitor banks 7 and sometimes line regulators are used on the Area EPS as a component of the feeder voltage regulation scheme. Series capacitor banks, static VAR compensators and other devices installed on the Area EPS contribute to improved voltage regulation, but these types of devices are usually installed to address transient voltage disturbances. Another important aspect of voltage regulation is the maintenance of balanced three-phase voltage on the Area EPS s. Eighty percent or more of the customers on many Area EPS may be served from singlephase tap lines or single phase transformers connected to the main feeder of the Area EPS. These singlephase loads may create unbalanced voltage drops on the Area EPS resulting in unbalanced voltage being present at customer locations where there are three-phase utilization devices. The operation of three phase motors and some other types of three-phase utilization devices is adversely affected by unbalanced phase voltage. If the voltage unbalance is significant, i.e. 2.5 to 3% or greater, the motor or device may overheat or become inoperative. Some utilization equipment, such as a large chiller compressor, is even more sensitive to voltage unbalance. Factors involved in determining the voltage drop on an Area EPS include the primary voltage at which the Area EPS is operating; the number, size and type of conductors; the length of the lines; the size and power factor of the various loads; and the location of loads on the Area EPS. Multiple voltage regulating devices are commonly used on Area EPS s and it is necessary to coordinate the timing of the automatic voltage regulating devices to prevent hunting. The voltage regulating devices commonly used on Area EPS s cannot respond instantaneously to maintain a constant regulated voltage output. When multiple voltage regulating devices are used, the voltage regulating devices closest to the source substation operates with the least amount of time delay while voltage regulating devices located farther from the source substation have increased time delay. In the design of the power system, the number, size, type, and control settings of these regulating devices are chosen based upon known operating ranges of power flow and short circuit duty. IMPACT OF DR Voltage regulation of the Area EPS is based almost entirely upon radial power flow from the substation to the various loads connected to the Area EPS. The introduction of DR introduces meshed power flows that may interfere with the effectiveness of standard voltage regulating practices. DR can affect the Area EPS voltage as follows: 1) Injecting power from a DR device into the power system will offset load current thus reducing the voltage drop on the Area EPS. 2) The DR device may inject leading reactive power (capacitive) into the power system or draw lagging reactive power (inductive) from the power system thus affecting the voltage drop on the Area EPS. For a given load level, if a DR device injects leading reactive power the voltage drop on the Area EPS will be reduced, and if a DR device draws lagging reactive power the voltage drop on the Area EPS will be increased. In accordance with Section of IEEE 1547, DR devices cannot actively regulate the voltage at the PCC and DR devices cannot cause the Area EPS service voltage at the Local EPS s to go outside the 7 Shunt capacitor banks are often used as part of the overall voltage regulation scheme on the Area EPS. Fixed shunt capacitor banks are typically applied to bring the light load power factor on the Area EPS 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%. 18

19 requirements of ANSI C84.1, Range A. These restrictions will prevent many operating problems, but the operation of DR can still result in voltage regulation problems in some situations unless precautions are taken. Examples of some potential operating problems and possible solutions are: Low Voltage - Many feeder voltage regulators use line drop compensation to raise the regulator output voltage in proportion to the load and maintain constant voltage at a point further downstream from the regulator. The line drop compensator raises the regulator output voltage to compensate for line voltage drop between the regulator and the load center. A DR device located downstream of an Area EPS voltage regulator may cause the voltage regulator to lower its output voltage, if the DR output is a significant fraction of the normal regulator load. As a result, low voltage levels may be created downstream from the regulator on the Area EPS, if the DR fails to inject sufficient reactive power into the EPS. If line drop compensation is being used and a DR device is to be located downstream of sufficient size to affect primary voltage regulation, the Area EPS Operator may need to modify the line drop compensator settings or other regulator control settings or relocate or add other voltage regulating devices to the Area EPS. Alternately it may be possible to coordinate the operation of the DR device with the operation of the voltage regulating devices on the Area EPS Low voltage levels may also be created when DR devices draw lagging reactive power. DR devices must cease to energize the Area EPS when the voltage goes out of range as specified in Section of IEEE This Section specifies out of range voltage set points and the clearing times required. By default this Section also specifies the operating voltage range for DR devices as 88% to 110% of nominal voltage. When a DR device is drawing lagging reactive power from the Area EPS and the primary voltage on the Area EPS is near the lower limit of ANSI C84.1, the reactive power draw from the DR device can drag the voltage below the ANSI lower limit but above the DR device s low voltage out of range trip point. Under these conditions unacceptably low voltage conditions will exist until either the DR device increases its real power output to raise the voltage, the Area EPS voltage increases, or the voltage decreases out of range and the DR device trips to disconnect from the Area EPS. This problem is mainly limited to induction generator type DR devices. If the lagging reactive power drawn by a DR device will create low voltage, appropriately sized and located capacitors may be installed by the DR Operator or the Area EPS Operator to eliminate the problem. High Voltage When a DR unit is installed at a point on the Area EPS and the primary voltage on the Area EPS is near the upper limit of ANSI C84.1, the introduction of power (real or leading reactive) flow from the DR can push the voltage higher than the ANSI upper limit but lower than the DR device s high voltage out of range trip point. Under these conditions unacceptably high voltage conditions will exist until either the DR device reduces its output to lower the voltage, the Area EPS voltage decreases, or the voltage increases out of range and the DR device trips to disconnect from the Area EPS. When DR is large enough to influence the service voltage of other customers on the Area EPS and is located on the Area EPS where the primary voltage on the Area EPS is expected to be near the upper limit of ANSI C84.1, the Area EPS Operator may need to change regulating device control settings and add a voltage regulating device. Alternately, the DR Operator may reduce the high voltage out of range trip point on the DR device to prevent the DR device from driving the Area EPS voltage beyond its high limit. Voltage Unbalance Single-phase DR devices generate power on only one phase. By injecting power on only one phase of the Area EPS, the voltage balance between the three phase voltages can be changed. The voltage change created by the DR device may combine with existing unbalanced voltage on the Area EPS to create unacceptably high unbalance. This high unbalance can exist even though the phase voltages may be within the limits of ANSI C84.1 and the power flow from the DR may not push the 19

20 voltage out of range to trip the DR unit. To prevent problems from unbalanced voltage, it may be desirable to transfer single phase load connected to the highest loaded phase to one of the other two phases and to interconnect the DR device to the highest loaded phase. Excessive Operations - The introduction of a DR device, especially one having a fluctuating source such as wind or solar, can disrupt normal operation and interact with voltage regulating devices. Multiple voltage regulating devices are commonly used on Area EPS s and it is necessary to coordinate the timing of the voltage regulating devices. DR device output changes may disrupt the timing of voltage regulating devices and contribute to excessive tap changes or capacitor switch operations. To minimize problems, it may be desirable to change the time delay settings on various voltage regulating devices to provide better coordination with the DR device. In extreme cases, the installation of static VAR compensation or similar device may be necessary. Coupling the DR device having a fluctuating source with another DR device with the ability to flatten out the fluctuations may also be possible. Improper Regulation During Reverse Power Flow Conditions A DR device or multiple DR devices exporting power to an Area EPS may create reverse power flow conditions on voltage regulating devices. The controls on some voltage regulating devices are not designed to regulate the voltage properly under reverse power conditions and the voltage regulating device could push the voltage well outside of the allowable limits on the Area EPS. To avoid this problem the Area EPS Operator may need to replace the controls on the affected voltage regulating devices to provide proper regulation during reverse power flow conditions. Improper Regulation During Alternate Feed Configurations A DR device or multiple DR devices exporting power to the Area EPS may cause voltage-regulating devices to operate improperly under alternate feed conditions. Most Area EPS s are radial and have only one source of power i.e. the distribution substation. However, some Area EPS s have tie points with one or more other Area EPS s. These tie points create the possibility of switching all or a portion of an Area EPS to an alternate source of power. When all or a portion of an Area EPS is properly designed to be switched to an alternate source, the voltage regulating devices will operate to maintain adequate voltage. However, the operation of a DR device or devices, while the Area EPS is in an alternate feed configuration, could result in one or more of the voltage regulation problems described above. To avoid this problem the Area EPS Operator may need to replace the controls on the affected voltage regulating devices to provide proper regulation during reverse power flow conditions or the Area EPS Operator or DR Operator may need to take other measures described earlier depending upon the situation. TIPS, TECHNIQUES AND RULES OF THUMB In most cases, the impact on the primary voltage level of the Area EPS will be negligible for any individual residential scale DR unit (<10kW). This may not be the case when a number of small units or a single larger unit have been installed on the same Area EPS. In this case, the voltage regulation scheme may need to be needed to reviewed to insure that the Area EPS voltage will be maintained within appropriate limits. At secondary voltage levels on the Area EPS, even a small individual residential scale DR device may adversely affect the voltage to other customers when the DR is added to an Area EPS transformer serving multiple customers. When DR devices are added to a transformer serving multiple customers, the voltage regulation may need to be needed reviewed to insure that the Area EPS voltage will be maintained within appropriate limits. The voltage regulation may also need to be reviewed when many individual residential scale DR devices, a larger DR device or multiple DR devices are to be located: 20

21 On the load side of Area EPS voltage regulators or load tap changing transformers that utilize line drop compensation under either system normal or alternate feed configurations Where the voltage approaches the upper ANSI C84.1, Range A limit or approaches the lower ANSI C84.1 Range A limit under either system normal or alternate feed configurations On the Area EPS and the DR device(s) have a fluctuating power source such as wind or solar On the Area EPS and the DR device(s) may create reverse power flow conditions through voltage regulators or load tap changing transformers under either system normal or alternate feed configurations On the Area EPS and there are a significant number of single-phase DR devices On a line section of the Area EPS where the aggregate generation from DR devices will exceed 10% of the line section s peak load. 21

22 Integration with Area Electric Power System Grounding IEEE 1547 Requirement (Section 4.1.2) The grounding scheme of the DR interconnection shall not cause overvoltages that exceed the rating of the equipment connected to the Area EPS and shall not disrupt the coordination of the ground fault protection on the Area EPS. Application Guidance BACKGROUND This requirement is intended to: To prevent damaging phase to ground voltages during temporary islanding conditions which may exist in unintentional islands for the period between when the island forms and when it is detected and de-energized by the DR. To prevent excessive desensitization of the Area EPS ground fault detection device. To facilitate detection by the DR of Area EPS faults. Issues to be considered include desensitization of the Area EPS distribution system ground fault protection, insulation ratings of the DR equipment connected at the PCC (e.g., transformers), MCOV ratings of lightning arresters on the Area EPS, detection of Area EPS ground faults by the DR, insulation ratings of Area EPS equipment, and dynamic conditions such as ferroresonance. 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/NFPA 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. 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. 22

23 U.S. utility distribution feeders are either: 1) four-wire-multigrounded or unigrounded systems, 2) threewire ungrounded systems, or 3) three-wire grounded systems IMPACT OF DR DR interconnection to each type of distribution system can impact protection and coordination as discussed below. 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 threephase three-wire primary distribution circuits, single-phase distribution transformers are connected phaseto-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. 8 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 and practices. 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. 9 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. 10 Three-phase DR 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. 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 8 IEEE Guide for the Application of Neutral Grounding in Power Systems, Part 4, IEEE Std. C 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. 10 IEEE Guide for the Application of Neutral Grounding in Power Systems, Parts 1 4, IEEE Std. C

24 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). However, if the DR does appear as an effectively grounded source to the utility system, the DR connection can significantly desensitize the ground fault protection on the utility distribution system. 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 either present themselves to the utility system as an effectively grounded source or 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. Three-Wire Area EPS Systems DR interconnections to Area EPS primary feeders of three-wire grounded or ungrounded systems, or to tap lines of such systems, should 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. 11 Grounding Considerations for Installations with both Parallel and Isolated Operating Modes Some DR installations can operate either parallel with the Area EPS or as isolated intentional islands (within the Local EPS). It is typical for these installations to operate in parallel with the Area EPS during normal conditions and to reconfigure for isolated operation during abnormal conditions on the Area EPS. The grounding system should be designed so that it is effective both during parallel and isolated operation. Further information can be found in IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Applications (Orange Book). 11 Grounded metallic enclosures or support structures such as steel poles or metallic conduit, should not considered to be metallic paths to ground from the primary feeder. 24

25 Synchronization IEEE 1547 Requirement (Section 4.1.3) The DR unit shall parallel with the Area EPS without causing a voltage fluctuation at the PCC greater than ± 5% of the prevailing voltage level of the Area EPS at the PCC, and meet the flicker requirements of clause Application Guidance BACKGROUND Synchronization is the act of matching voltage, phase angle, and frequency of the DR prior to closing the paralleling device. In order to minimize the transients to both the DR and to the Area EPS, it is important that all three quantities be closely matched across the paralleling device before actually closing the paralleling device. SLIP AND SYNCHRONIZATION Synchronization is, for the most part, only a major concern for synchronous generators or an operating local EPS, which will be generating a voltage prior to closing a device to synchronize to the EPS. Induction generators may be driven to near synchronous speed by the prime mover before closing the paralleling device, but they will connect very similarly to an induction motor before actually generating a voltage of concern. Most inverters will simply start generating voltage when the Area EPS is present. 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. 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. 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 prevailing voltage level of the Area EPS at the PCC. The conditions for three types of DR follows. A. Synchronous Interconnection to an EPS, or an Energized Local EPS to an Energized Area EPS. This test shall demonstrate that at the moment of the paralleling-device closure, all three parameters in the table below 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, the paralleling-device shall not close. B. Induction Interconnection. Self-excited induction generators shall be tested as per clause A above. 25

26 This test shall determine the maximum start up (in-rush) current drawn by the unit 12. The results shall be used, along with utility impedance information for the proposed location, to estimate the starting voltage drop and verify that the unit shall not exceed the synchronization requirements in [IEEE 1547] clause and the flicker requirements in [IEEE 1547] clause C. Inverter Interconnection. 13 An inverter-based interconnection system that produces fundamental voltage before the paralleling device is closed shall be tested according to the procedure for synchronous interconnection as stated in [IEEE 1547] clause A. All other inverter-based interconnection systems shall be tested to determine the maximum startup current. The results shall be used, along with Area EPS impedance for the proposed location, to estimate the starting voltage magnitude change and verify that the unit shall meet the synchronization requirements in [IEEE 1547] clause and the flicker requirements in [IEEE 1547] clause 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 in damage to the electric power system and the distributed generator equipment due to the very high torques that can occur when systems are paralleled out of phase. When operating with a low DR voltage, the DR will experience potentially large VAR flow INTO the generation immediately after synchronization. The Area EPS may experience low voltage due to the large reactive flow. When operating with a high DR voltage, the DR will experience potentially large VAR flow OUT of the generation immediately after synchronization. The Area EPS may experience high voltage due to the large reactive flow. This paragraph refers to sustained low voltage operation, NOT during synchronization. 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 fall 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. Automatic synchronization devices are much preferred for the application, as successful manual synchronization usually requires a highly skilled operator, and unsuccessful synchronization can easily be very damaging, both to equipment on the Area EPS and to the 12 NEMA MG-1 contains an acceptable method for determining inrush current. 13 Some inverter-based interconnection systems may need to be tested to both requirements of [IEEE 1547] clause C. 26

27 DR equipment itself. Indeed, the electric power industry is replete with tales of major damage from abortive attempts to manually synchronize. Considerations in the design and operation of both types are discussed below. Automatic Synchronization Many types of automatic synchronizers are available to replace part or all of the manual synchronizing functions mentioned above. Synch-check relays, which are designed to check the electric power system voltage and the distributed generator voltages, close a contact when the 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 to restore a totally de-energized Local EPS) when the synchronizing relay itself would not provide a signal to close the circuit breaker at point of common coupling. Manual Synchronization Manual synchronization equipment is rare and only 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 DG operating in parallel with the EPS and able to operate as an island are summarized in Table 2. For the similar requirements for DG with no ability to operate as an island, see Table 3. Table 2. Synchronizing Requirements for Paralleled DG Units with Islanding Capability Aggregate Rating of DR Units (kva) Frequency Difference (Δf, Hz) Voltage Difference (ΔV, %) Phase Angle Difference (Δø, ) >500 1, >1,500-10, Table 3. Synchronization Requirements for Paralleled DG Units without Islanding Capability DR Size Volt Meters Freq Meters Phase Angle Meters Sync Scopes >10 kw-500 kw >500 kw-10 MW >10 MW 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. 27

28 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. For 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, two frequency meters, and a synchroscope. 14 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. 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 14 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. Synchronizing lights can also be applied in three phase sets such that one light is connected on a single phase across the synchronizing device, and the other two cross phases on the synchronizing device (e.g., one light connected phase A phase B, one light connected phase B phase A, and the third light connected across phase C), such that two lights are at maximum brilliance and the third light is dark at synchronism. 28

29 system or may consist of power factor correction capacitors located on the EPS circuit to which the DR is directly connected. 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 is good practice to include it for synchronous and induction generators over 10 kw. 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. 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 absorbing vars from the system; it is important to consider the addition of capacitors to improve power factor and reduce reactive power draw. 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 Line Commutated vs. Self Commutated Inverters Inverters may be line commutated or self-commutated. Synchronizing 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 linecommutated 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. 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 29

30 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. 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 non-regulated 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. TIPS TRICKS AND RULES OF THUMB Synchronism check relays are generally suitable to provide a permissive signal for manual synchronizing. Occasionally these relays can exhibit a ratcheting action which can result in incorrect operation. This can occur when the two systems (the DR and the Area EPS) are rotating with respect to each other. In this case, there is a frequency difference between the two systems, and the synchroscope would be slowly rotating either clockwise or counter clockwise. If the synchrocheck relay is left on, and there is not sufficient time for it to reset between successive in phase conditions, the contacts can ratchet closed, at some point other then at the in phase condition. 30

31 This condition was most likely to occur with the older electromechanical relays where the reset time of the induction disk took longer then the time between the in phase condition. The newer static and microprocessor based relays should not suffer from this condition. 31

32 Distributed Resources on Secondary Grid and Spot Networks IEEE 1547 Requirement (Section ) This topic is under consideration for future revisions of this guide. IEEE 1547 Requirement (Section ) Network protectors shall not be used to separate, switch, serve as breaker failure backup or in any manner isolate a network or network primary feeder to which DR is connected from the remainder of the Area EPS, unless the protectors are rated and tested per applicable standards for such an application. 1 Any DR installation connected to a spot network shall not cause operation or prevent reclosing of any network protectors installed on the spot network. This coordination shall be accomplished without requiring any changes to prevailing network protector clearing time practices of the Area EPS. Connection of the DR to the Area EPS is only permitted if the Area EPS network bus is already energized by more than 50% of the installed network protectors. The DR output shall not cause any cycling of network protectors. The network equipment loading and fault interrupting capacity shall not be exceeded with the addition of DR. 1 IEEE C37.108TM-2002 and IEEE C TM-2000 provide guidance on the capabilities of network systems to accept distributed generation. Application Guidance BACKGROUND General Arrangement of Spot Networks. 277Y/480 volt LV supply systems with two or more utility primary feeders supplying network transformers are common. Primary feeders may be dedicated to the network or may have other loads. Integrated transformer, relays, and LV air-break switch (network protector) are usually used. The protector switch opens on reverse power flow to isolate primary feeder trouble. Network Relay Characteristics. Master relay (a very sensitive three-phase reverse power relay) opens protector when real power flow is from the network to the primary feeder. Sensitive reverse power relay picks up on network transformer core losses in order to sense primary feeder outage even when there is no other load on the primary feeder. Relays are typically an electromechanical devices, with electronic types available. Relays have no intentional time delay and are sensitive to reverse var flow at current levels above normal load. 32

33 Problems with Local Generation on Network. If local generation exceeds local load, even momentarily, network protectors open and isolate the network from the utility supply. Fault current contribution from synchronous local generation can cause network protectors to open for faults on other primary feeders, isolating the network. IMPACT OF DR Problems with Local Generation on Network. Attempting to resynchronize an isolated network to the utility may trip the network protector because of power swings; the protector may not be able to interrupt under such conditions. Protector circuit breakers are not rated to interrupt fault current from generators or to withstand out-of-phase conditions across the open switch. Master relay may reclose the protector switch during an out-of-synchronism condition if the network is islanded. Network relays are part of an integrated unit in a submersible enclosure and are not readily modifiable for special conditions. DG on Spot Networks. Use inverter-based generation technology so network protectors will not be opened by fault current contribution from the local generator, or time-coordinate network protector relay with feeder relaying to prevent NP opening from generator fault current contribution. Limit generation to less than local load, with an adequate margin for sudden loss of load conditions, to insure no undesired reverse power conditions, or control inverter power output with tie-line load control so power flow from the utility to the network never reverses. TIPS, TECHNIQUES AND RULES OF THUMB DG with Network Units Alternatives. Trip or isolate local generation from network if network protector relays sense low incoming power flow or, isolate local generation with critical loads by sensing reverse power from critical load bus to network. Prevent islanding of the network: trip generation or isolate it from the network unit with a circuit breaker whenever all network protectors open or when outof-phase voltage is sensed across a protector switch. Substation primary feeders Network Units Y NWP * less critical loads Y * 25 * critical loads Y Islanding local generation * * Time coordinated; critical loads isolate before NP s open Local Gen <= Critical Load Figure 2. Islanding Local Generation Coordinating Network Relays. Most NP relays are electromechanical with no intentional time delay. Some microprocessor-based network relays can be provided with time delays. Time delay slows the clearing of faulted feeders from the network, potentially degrading service quality. 33

34 Inadvertent Energizing of the Area EPS IEEE 1547 Requirement (Section 4.1.5) The DR shall not energize the Area EPS when the Area EPS is de-energized. 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 Area EPS is de-energized. Accordingly, the DR shall not transfer power to the Area EPS side of the PCC when the Area 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 beyond initial fault clearing. IMPACT OF DR Following an event that has caused the DR to cease to energize the Area EPS line, the line shall remain separated from the DR until continuous normal voltage and frequency have been maintained by the Area EPS for a minimum of five minutes as detected on the line side of the PCC. At this time, the DR is allowed to automatically reconnect to the Area EPS, if the Area EPS has authorized automatic reconnection. TIPS, TECHNIQUES AND RULES OF THUMB There is a range of incidents in which de-energization is required and inadvertent re-energization should be prevented. There are a number of different options for accomplishing this, including manual disconnect switch; direct transfer trip; automatic bus transfer switch; and, non-islanding inverter. Each of these options is discussed below. Manual Disconnect Switch 15 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 system 16. This switch may also be referred to as a visible disconnect switch. This switch is not to be confused with disconnect switches that may be required by NEC. The NEC disconnect switches are generally in the direct vicinity of the equipment, and are not in the vicinity of the PCC. 15See subsequent section on Isolation Devices for additional requirements on the use of disconnect switches. 16 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 (commercial, utility union work practices, etc.). 34

35 Direct Transfer Trip Direct transfer trip can provide a remote signal to activate 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. In this application, a transfer trip signal originating from the Area EPS source substation is initiated when the Area EPS line circuit breaker opens (manual or automatic opening). The contact initiated signal is sent to a PCC location or multiple locations, at which point the PCC disconnecting device is opened. An auxiliary contact from the circuit breaker at the Area EPS substation is used to initiate the transfer trip signal. The signals can be sent over a variety of mediums including the power line, microwave, fiber optic, air, and twisted pair copper. Direct Transfer Trip provides very effective inadvertent energization protection. Upon agreement with the Area EPS a breaker other then the one at the PCC can be opened. This may be necessary depending on the operation of the DR facility. For example, if the DR desires to operate as an island, the tripping the PCC breaker is correct. However, the DR may not be able to operate as an island, and may want to be restored to operation as soon as the line is restored. In this case, the generator breaker would probably be the breaker to be tripped. 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 reenergization. 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 CAN A SELF-COMMUTATED INVERTER BE NON-ISLANDING? Self-commutated inverters can be designed as either voltage or current sources. Most EPS-interconnected selfcommutated 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. 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. to appropriate standards on which the non-islanding function is based 17. In these cases, some utilities have allowed the use of such devices and have modified their work practices accordingly. 17 UL 1741 is one example of a standard for inverters used on photovoltaic systems. 35

36 Monitoring Provisions IEEE 1547 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 connection status, real power output, reactive power output and voltage 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 export 18, 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 requirements that may comprise the business arrangement, this section summarizes the fundamental monitoring provisions. 18 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. 36

37 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 monitoring. 19 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 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. 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 < 200 kw...no Monitoring 200 kw to 1 MW...Monitoring not required if DR is prevented via protective relaying from injecting energy into the EPS > 1 MW...Monitoring required 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. 20 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. 37

38 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 alarms. 21 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. 21 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. 38

39 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 milliamperes) Instantaneous voltage (1 phase minimum) Instantaneous current (1 phase minimum) Bi-directional Signals (signals will be -1.0 to 0 to 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. 39

40 Isolation Device IEEE 1547 Requirement (Section 4.1.7) When 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 The isolation device is a mechanical switching device, which in the open position provides an isolation distance. It should be able to open and close a circuit, which carries current up to the rated current. Isolation distance is the gap of specified dielectric strength in gases including air, or liquids in the open current path of the switching device; as protection for people and equipment it must satisfy special conditions and its existence must be clearly perceptible when the switching device is open. For alarm or status of the isolation device, auxiliary switches should be provided. The switch contact should be rated in accordance with applicable standards. BACKGROUND This requirement differs from the earlier requirement, Inadvertent Energizing of the Area EPS (IEEE 1547 Section 4.1.5). 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 safe work practices. The National Electrical Code 22 (NEC) dictates the requirements for disconnect devices, which allow for safe operation and maintenance of the electrical power systems within public or private buildings and structures. Specifically, the NEC requires that generators shall be equipped with a disconnect by means of which the generator and all protective devices and control apparatus are able to be disconnected entirely from the circuits supplied by the generator except where the driving means for the generator can be readily shut down; and the generator is not arranged to operate in parallel with another generator or other source of voltage. Similar to the National Electrical Code, all electric utilities have established practices and procedures which ensure safe operation of the electrical power system under both normal and abnormal conditions. Several of these procedures identify methods that ensure that the electrical system has been properly configured to provide safe working conditions for Area 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 22 National Electrical Code, NEC 2002, NFPA 70, published by the National Fire Protection Association, One Batterymarch Park, Quincy, Mass. 40

41 require visible isolation, protective grounding and 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 judgment 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, or draw-out circuits breaker are used to provide visible isolation of the electrical power source from the utility s electrical system when clearance is to be gained. 23 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 or by the mutual agreement between the DR and the EPS. 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. 23 See the related discussion of disconnect switches as included in the earlier section on Inadvertent Energization of Area EPS. 41

42 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. 8. A draw-out type circuit breaker with provision for pad locking at the draw-out position should be considered as an isolation device if it is approved by the EPS. 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. 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 based. 24 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 isolation device (disconnect switch) or control being used to meet the isolation requirement. 24 UL 1741 is one example of a standard for inverters used on photovoltaic systems. 42

43 Protection from Electromagnetic Interference IEEE 1547 Requirement (Section ) The interconnection system shall have the capability to withstand electromagnetic interference (EMI) environments in accordance with ANSI/IEEE C The influence of EMI shall not result in a change in state or mis-operation of the interconnection system. Application Guidance BACKGROUND The use of hand-held transceivers 25 (walkie-talkies) and cell phones has increased dramatically over the past few years. When operated in close proximity to a static protective relay, these transceivers will produce local, high field-strength electromagnetic radiation that may affect protective relay performance. This interaction has driven the need for a standard on radiated interference and withstand capability for static protective relays. The test field-strength level has been increased from V/m to 35 V/m. The 35 V/m level is intended to roughly approximate the effect of a walkie-talkie operated at 15 cm (6 inches) from the exposed surface of the relay. This value is the result of extensive testing by members of the Working Group formed to update IEEE Std C , IEEE Standard for Withstand Capability of Relay Systems to Radiated Electromagnetic Interference from Transceivers. It is expected that all of the interconnection system components would be subjected to these tests. For new installations this will probably be completed by the equipment manufacturer, however, if existing equipment is put to use for the interconnection system, the DR operator may have to arrange for these tests. Older equipment may not have been tested for Electromagnetic Interference, as the use of radio based equipment was not wide spread years ago. The use of older equipment for the Interconnection System could leave the DR subject to mis-operation in the presence of radio signals. The use of radio based equipment has increased dramatically in the last 10 years. Cell phones, personal digital assistants (PDAs), cameras, walkie-talkies, and other devices may be present as part of the DR installation, or in daily use during DR operation. Further, many DR installations will be installed at existing facilities which may present additional opportunities for interference. The test needs to be applied to all of the Interconnection System equipment. For the purpose of this section, the Interconnection System equipment would consists of any components providing protective or control functions: Relays Programmable Logic Controllers Computers 25 A transceiver is a device or circuit that generates high-frequency electric energy, controlled or modulated, which can be radiated by an antenna. 43

44 For the purposes of this section, this test would not be applied to: Circuit breakers Air switches Disconnect switches Current transformers Potential transformers IMPACT OF DR This IEEE 1547 requirement focuses exclusively on the continued operation of the interconnection system during and after EMI exposure. The DR interconnection system is essentially being held to the same standard of performance as generators, protective relaying and other electrical equipment. Tips, Techniques and Rules of Thumb In the design of equipment for protection against the effects of Radiated Electromagnetic Interference, the use of discrete frequency steps throughout the test frequency range has been made an alternative to a continuous sweep of the pertinent frequencies. These changes are in recognition of the variety of modern equipment used to conduct these types of tests. Single-Frequency Test Parameters Portable radio transmitters provide the most common source of single-frequency interference to static protective and control relays when they are used in close proximity to the relays. The portable transceivers normally used in power system communications have output power less than 10W measured at the base of the antenna. There are other factors, besides power level, that may affect the susceptibility of the relay equipment to these devices, such as the frequency and modulation level. In deciding on a meaningful test level, it is important to know what field strengths are produced by commercial portable transceivers, since these are the dominant interfering sources. 44

45 Surge Withstand Performance IEEE 1547 Requirement (Section ) The interconnection system shall have the capability to withstand voltage and current surges in accordance with the environments defined in IEEE/ANSI C or IEEE C as applicable. Application Guidance BACKGROUND Transient surge voltages occurring in ac power circuits can be the cause of operational upset or product failure in industrial and residential systems and equipment. These problems have received increased attention in recent years because of the widespread application of complex semiconductor devices that are more sensitive to voltage surges than vacuum tubes, relays, and earlier generations of semiconductor devices. Logical and economical design of circuits to protect vulnerable electronic systems from upset or failure requires knowledge of or an estimate of: Transient voltage and current waveforms, Frequency of occurrence of transients with various energy levels, Particular environmental variations such as amplitudes, and Upset or failure threshold of the particular equipment to be protected. Occasionally, attempts will be made to describe surges in terms of energy to help select the rating of a candidate surge-protective device. However, this concept can be a misleading oversimplification because the energy distribution among the circuit elements involved in a surge event depends on the impedance of the power system source (including the ac mains) as well as on the impedance of the surge-protective device called upon to divert the surge. There are no independent, meaningful, and self-contained descriptions of surges in terms of energy alone. The energy delivered to the end-equipment is the significant factor, but it depends on the distribution between the source and the load (equipment or surgediverting protective device, or both). Inverters can occasionally setup standing waves, a phenomenon where harmonics from the operation of the inverter are reflected and the reflections are additive. The result is standing waves, which can reach high magnitudes. The original design of inverters were based on SCRs and similar switching devices which were slow switching. This equipment is characterized by having low order harmonics. The newer inverters based on Pulse Width Modulation technology operate at much higher frequencies, 1000 hertz and up to 10,000 hertz. This equipment is characterized by having high order harmonics. These higher frequencies are the cause of the standing waves. These standing waves have been known to cause the failure of inverters as well as other equipment. IMPACT OF DR This requirement focuses exclusively on the survivability and continued operation of the interconnection system during and after exposure to surge voltages occurring in low-voltage ac power circuits, in this case the Area EPS distribution system. In particular, IEEE C emphasizes the performance of the protective functions of the DR interconnection system in the presence of surges as defined within that standard. 45

46 The DR interconnection system is essentially being held to the same standard of performance as generators, protective relaying and other electrical equipment. TIPS, TECHNIQUES AND RULES OF THUMB These surge voltages originate from two major sources: lightning effects (direct or indirect) on the power system and system switching transients. In the case of standing waves, the system needs to be altered to eliminate the additional of the reflected harmonics. Possible methods to alter the system would be to change to the operating frequency of the inverter, or to apply filters, capacitors, or inductors to change the tuning of the system. Lightning Models of lightning effects consistent with available measurements have been made in order to yield predictions of surge levels, even if the exact mechanism underlying the production of any particular surge is unknown. The major mechanisms by which lightning produces surge voltages are the following: 1. A nearby lightning strike to objects on the ground or within the cloud layer produces electromagnetic fields that can induce voltages on the conductors of the primary and secondary circuits. 2. Lightning ground-current flow resulting from nearby cloud-to-ground discharge couples onto the common ground impedance paths of the grounding network, causing voltage differences across its length and breadth. 3. Operation of a primary gap-type arrester to limit the primary voltage, and the rapid drop of voltage that may occur when the arrester is coupled through the capacitance of a transformer and produces surge voltages in addition to those coupled into the secondary circuit by normal transformer action. 4. A direct lightning strike to high-voltage primary circuits injects high currents into the primary circuits, producing voltages by either flowing through ground resistance and causing a ground potential change or flowing through the surge impedance of the primary conductors. Some of this voltage couples from the primary to the secondary of the service transformers, by capacitance or transformer action or both, thus appearing in low-voltage ac power circuits. 5. Lightning strikes the secondary circuits directly. Very high currents and resulting voltages can be involved, exceeding the withstand capability of equipment and conventional surge protective devices rated for secondary circuit use. Switching Transients System switching transients can be divided into transients associated with normal or abnormal conditions, as follows: 1. Minor switching near the point of interest, such as an appliance turnoff in a household or the turnoff of other loads in the individual system. 2. Periodic transients (voltage notching) that occur each cycle during the commutation in electronic power converters. The voltage notch is caused by a momentary phase-to-phase short circuit with a rapid change in voltage, lasting in the 100 ms range. 3. Multiple re-ignitions or re-strikes during a switching operation are another example. Air contactors or mercury switches can produce, through escalation, surge voltages of complex waveforms and of amplitudes several times greater than the normal system voltage. 46

47 4. Major power system switching disturbances, such as capacitor bank switching, fault clearing, or grid switching Various system faults, such as short circuits and arcing faults Power factor correction capacitor switching. 7. Switching of long runs of underground cable. The most visible effect of a switching surge is generally found on the load side of the switch and involves the equipment that is being switched, as well as the switching device. In the case of the equipment being switched, the prime responsibility for protection rests with either the manufacturer or the user of the equipment in question. However, the presence and source of transients may be unknown to the users of this equipment. This potentially harmful situation occurs often enough to command attention. 26 Transient overvoltages associated with switching of power-factor correction capacitors have levels, at least in the case of restrike-free switching operations, of generally less than twice the normal voltage, though the levels of the transients often can be 1.5 times normal (that is, the absolute value may be 2.5 times the normal peak). These transients can occur daily, and their waveforms generally show longer time durations, such as several hundred microseconds, compared to typical durations on the order of microseconds to tens of microseconds for other switching events and lightning-induced transients. If multiple reignitions or restrikes occur in the capacitor-switching device during opening, then the transient overvoltage can exceed three times the normal system voltage and involve high energy levels. 27 One type of switching transient, for example, results from fast-acting overcurrent protective devices such as current-limiting fuses and circuit breakers capable of arcing times of less than 2 ms. These devices leave inductive energy trapped in the circuit upstream; upon collapse of the field, high voltages are generated. 47

48 Paralleling Devices IEEE 1547 Requirement (Section ) The interconnection system paralleling-device shall be capable of withstanding 220% of the interconnection system rated voltage. Application Guidance BACKGROUND The paralleling device must be able to withstand 220% of the rated voltage across the OPEN contacts. This in not a phase to ground voltage withstand requirement. The paralleling device must not only successfully parallel the DR (or the Local EPS containing the DR) with the Area EPS, but also must be able to withstand all long-term conditions which may result from the DR not being operated in parallel with the Area EPS. This requirement is focused on the latter; the ability to withstand conditions which may result from the DR not being operated in parallel with the Area EPS. This requirement is based on aspects of two other clauses of IEEE 1547, together with normal Area EPS operating criteria. ANSI C84.1 suggests a maximum Area EPS operating voltage of 110% of the nominal voltage, and is usually mandated by various regulatory agencies. IEEE 1547 Clause Voltage Regulation specifies that The DR shall not cause the Area EPS service voltage at other Local EPSs to go outside the requirements of ANSI C84.1, Range A and IEEE 1547 Clause Voltage defines the maximum allowable operating voltage to by 110% of the nominal system voltage as defined in ANSI C84.1 Table 1. The 220% withstand requirement in this clause is based on these factors. If the Local EPS with the DR connected is operating isolated from the Area EPS, with the point of isolation being the paralleling device, the voltage on the Area EPS side of the paralleling device could be 180-degrees out-of-phase with the voltage on the Local EPS side of the paralleling device. Both voltages could be at 110% of nominal system voltage, and both could be operating precisely at 60 hertz, which would result in a long-term steady-state voltage of 220% of nominal across the open paralleling device contacts. Although not mentioned in 1547, the paralleling device should have consistent opening and closing times. The opening time will limit damage and provide consistent coordination with other DR and EPS protective devices or schemes. The closing time is related to the method of synchronizing the DR. If this time is variable, an out of phase closing condition could occur. IMPACT OF DR In practicality, this requirement would seem to apply only to synchronous generators, or to installations that are designed such that the DR of any type can support the Local EPS in an isolated fashion. In the case of synchronous generators, this requirement would be germane whenever the generator is being synchronized to the system. In the latter case, the requirement is meaningful during steady-state operation of the Local EPS while disconnected from the Area EPS. 48

49 When DR use other technologies (e.g. inverter-based interconnections or induction generator interconnections) are intended to operate only in the presence of the Area EPS, these technologies are usually producing a voltage only when the Area EPS is present, and the requirement diminishes to a short-time capability which may be less demanding. There are several new technologies for variable speed asynchronous generators. Many of these use AC- DC-AC type equipment where the generator operates at a variable frequency. This is converted to DC and then to 60 hertz AC. Depending on the specific technology these installations may look like either and induction or synchronous machine just prior to synchronism. The choice of the rating for the paralleling device must match the operation of the connected equipment. TIPS, TECHNIQUES AND RULES OF THUMB The specifications for equipment being considered for use as a paralleling device should be carefully reviewed to assure that it meets this requirement. Failure to adhere to this requirement could result in violent failure of the paralleling device, with attendant collateral damage to other equipment in the vicinity of the paralleling device, together with probable hazard to personnel. 49

50 Response to Area EPS Abnormal Conditions IEEE 1547 Requirement (Section 4.2) 2 Abnormal conditions can arise on the Area EPS that require a response from the connected DR. This response contributes to the safety of utility maintenance personnel and the general public, as well as the avoidance of damage to connected equipment, including the DR. All voltage and frequency parameters specified in these sub-clauses shall be met at the PCC, unless otherwise stated. 2 The insolation of a portion of the Area EPS, presenting the potential for an unintended DR island, is a special concern and is addressed in clause Setting adjustments may only be made as approved by the authority who has jurisdiction over the DR interconnection. Application Guidance This clause from IEEE 1547 is not really a specific requirement, but it sets the stage for the six requirements that follow: Area EPS Faults Area EPS Reclosing Coordination Voltage Frequency Loss of Synchronism Reconnection to Area EPS The significant point here is that all voltage and frequency requirements must be met at the PCC, unless specifically stated otherwise. 50

51 Area EPS Faults IEEE 1547 Requirement (Section 4.2.1) The DR unit shall cease to energize the Area EPS for faults on the Area EPS circuit to which it is connected. Application Guidance BACKGROUND This requirement is based on the premise that if an Area EPS has detected a fault and de-energizes a circuit, any other source on that circuit must also stop energizing the circuit. This started with a requirement that a DR must separate for any fault on the Area EPS. It was acknowledged that a typical Area EPS cannot recognize some faults (such as very high impedance ground faults)and, for those recognized, it will proceed with selective isolation. The requirement as stated is intended to relieve the DR from having to respond to faults that are not seen by the Area EPS and to disregard any seen on another circuit. Short circuit currents on distribution circuits in the United States are from over 200,000 A to values less than 1 A for high-impedance single-phase-to-ground faults. The maximum fault can be controlled by system design. Area EPSs are designed not to exceed the rating of distribution line equipment. Maximum faults are limited by restricting substation transformer size and impedance, or both; by installing bus or circuit reactors; or by inserting reactance or resistance in the transformer neutral. Minimum fault magnitude is largely dependent on fault resistance, which cannot be controlled. These low magnitude faults are the most dangerous and difficult to detect. In order to clear faults, all electrical sources must be isolated from the fault. It is important that all detectable faults be cleared to minimize equipment damage, provide for public safety, and maintain overall reliability and power quality for all customers. Clearing times for short circuits on distribution circuits vary widely, depending on magnitude and the type of protective equipment installed. In general, on most circuits, large current faults will be cleared in 0.1 s or faster. Low current faults frequently require clearing times of 5-10 s or longer; and some very low level but potentially dangerous ground faults may not be cleared at all, except by manual disconnection of the circuit. The most common fault that cannot be seen is a line down at the end of a feeder in dry weather. The impedance may be so high that the fault current may not exceed normal load current. The other condition that is a concern is a low impedance fault on an adjacent feeder that will cause a perceptible voltage drop. It is known that the majority of distribution faults are temporary in nature so it is common practice to isolate long enough for a temporary fault to clear then reclose. Every DR that can sustain a fault must isolate so that the fault can clear. 51

52 Cooperative Circuit Configuration A distribution circuit is typically supplied through a single power circuit breaker located at the supply substation and is divided into various zones by automatic sectionalizing devices. These devices are carefully coordinated, so that a fault in any section can be quickly isolated with minimum or no interruption to other portions of the circuit. Of course, a fault in the main trunk section near the source breaker will require that the entire circuit be interrupted. However, if automatic reclosing is employed, the duration of outages due to transient faults in this zone will be limited to a brief interval, often considerably less than 1 s. It is essential that the DR be promptly disconnected from the EPS after the EPS source is lost, in order to prevent generator damage due to reclosing out-of-synchronism. Faults are categorized as follows, in order of frequency: Single-phase-to-ground; Phase-to-phase; Double-phase-to-ground; and Bolted three-phase. The major causes of failures are summarized in Table 4. Table 4. Major Causes of Failure Type of Fault Insulation Electrical Mechanical Thermal In many jurisdictions, a tariff, or statute, or both define minimum quality-of-service standards. These standards define acceptable voltage and frequency ranges for the service to all customers. Deviations from these standards, in many cases, can actually cause equipment damage. These quality-of-service standards also often prescribe reliability requirements, such as customer-outage-minutes, which motivates the widespread use of automatic reclosing on the Area EPS as described briefly in this clause and in more detail in Clause 5.2. Safety and system restoration requires detection of all faults. This also will limit the damage of both the faulted equipment and nearby equipment. Cause Design Defects Improper Manufacturing Improper Installation Aging Insulation Lightning surges Switching surges Dynamic Overvoltages Animal Contact Tree Contact Vehicle Collisions Wind Snow or Ice Contamination Vandalism Overcurrent Overvoltage Detection and isolation of Area EPS faults is also associated with other 1547 clauses, notably, Integration with Area EPS Grounding, Area EPS Reclosing Coordination, Voltage, Frequency, Reconnection to Area EPS, and Unintentional Islanding. The signature of the fault itself is dependent on the implementation of The effectiveness of the isolation of the fault directly affects and Dependent on the interconnection technology, the actual isolation and detection of the fault may be accomplished by the same methods that are used to satisfy 4.2.3, 4.2.4, and As noted above, the nature of faults involving ground, as well as the means of detecting them will be heavily dependent on how the integration with area EPS Grounding is implemented. This is also very dependent on the nature of the interconnection technology itself, whether the DG appears to the interconnection as a Synchronous Generator, an Induction Generator, or an Inverter. For that reason, separate approaches to fault detection and isolation will be suggested for each different generator technology, and, where appropriate, for each variation of Area EPS Grounding Integration. In order to minimize the amount of the system isolated for faults, both on the Local EPS and on the Area EPS, it is usually necessary to review the coordination between various fault protective devices. In general, the protective devices closest to the fault location must both be the most sensitive of all protective devices which may detect the fault, and also must operate quicker. In general, coordination can 52

53 be best achieved between numerous protective devices if all of the impacted protective devices have similar operating characteristics. The details of reviewing coordination between protective devices are extensive, and are addressed in numerous texts and other reference materials, and thus will not be addressed comprehensively here. IMPACT OF DR Fault current issues and fault clearing issues related to the addition of DR to an Area EPS may result in considerable impacts on the Area EPS, depending on the DR size and the type of DR. If the DR contributes fault current to the area EPS, the coordination of protective devices on the Area EPS may be adversely effected, and the fault current from the DR may thermally over-duty Area EPS equipment, and may also cause fault interrupting equipment on the Area EPS to experience fault current exceeding the equipment ratings. These issues are actually Area EPS impact issues that are not strictly involved in the interconnection, but must be carefully considered both when adding the DR to the Area EPS and when setting fault protective devices at the DR. The DR system should be designed with adequate protection and control equipment, including an interrupting device that will disconnect the generator if the EPS that connects to the DR system or the DR system itself experiences a fault. The DR system should have, as a minimum, an interrupting device(s) with the following characteristics: 1) Sufficient capacity to interrupt maximum available fault current at its location; 2) Sized to meet all applicable ANSI and IEEE standards; and 3) Installed to meet all local, state, and federal codes. A failure of the DR system's protection and control equipment, including loss of control power, should automatically open the disconnecting device 28, thus disconnecting the DR system from the EPS (i.e. fail safe). The specific details of the protection and control equipment will, to a large degree, depend on the nature of the DR and on the method of integration with the Area EPS grounding system. Synchronous Interconnections Interconnections that appear as synchronous generators are notable in that they will produce fault currents for extended periods of time if the fault involves multiple phases. The fault current may initially be as high as 6 times the generator full-load current (or even higher), and may decay over several seconds to less than the generator full-load current as the generator field collapses. However, the terminal voltage on the generator is severely depressed during the entire duration of the fault. The time relationship of the fault current supplied is thoroughly quantified by standard production tests for synchronous generators and described by defined reactances and time-constants which are provided in the generator test report. Induction Generators Induction generators will usually not support a fault, but will instead cease to produce current due to the loss of volt-amperes-reactive (VArs), which are necessary to support a rotating magnetic field within the generator. In these cases, the anti-islanding protection which supports IEEE 1547 Clause will also provide for detection of faults. If sufficient capacitive reactance to supply the VAr requirements of 28 Either a physical device such as a relay or switch, or a computer controllable capability in electronic power equipment, designed to isolate a portion of the Area EPS and/or DR systems. 53

54 the induction generator field is available, either through the installation of power factor correction capacitors or through the presence of considerable cable-type power conductors, it may be necessary to provide for direct detection of faults in a manner similar to synchronous generators. Inverters If an inverter is designed such that it must have other sources of generation present to provide the clocking signal to produce AC electricity (often referred to as line commutated ), the inverter will not support a fault on the Local or Area EPS, and will shut down, either via various self-protective features or via the anti-islanding detection system. If an inverter is designed to provide its own clocking signal (often referred to as self-commutated ), it can usually supply fault current for an extended time period. Unlike synchronous generators, the fault current supplied by a self commutated inverter is a fairly constant value which is determined by the design of the inverter, and usually ranges from 1.2 to 1.5 times the rated load current of the inverter. In this case, undervoltage relaying may be effective at detecting the fault. The various types of relays discussed for synchronous generators may also be effective. Grounding Methods The method of grounding (usually an interface transformer (GSU transformer) or a transformer which connects the Local EPS to the Area EPS) which is implemented at the PCC to satisfy the requirements of IEEE 1547 Clause will have a major effect on the ability of the DR, particularly synchronous DR, to detect faults involving ground. In some cases, direct detection of ground faults via the relays discussed for detection of phase faults may be possible (significantly, at the same voltage level as the generator), but this tends to be unreliable in most cases (particularly for faults on the far side of a transformer). It is far more common to apply protection directly for the purpose of detecting ground faults. TIPS, TECHNIQUES AND RULES OF THUMB A DR (or a Local EPS) has a number of possible means by which to detect a fault. These are generally based on the expectation that a fault will reduce or unbalance the apparent system impedance. There is one important factor that must be recognized. There are several general methods by which the DR can detect an area EPS fault. This section will address all of these to some degree. a. Local (at DR) detection of the initial Area EPS fault condition and subsequent isolation of the DR. b. Remote detection of the initial Area EPS fault condition and subsequent isolation of the DR via <remote> Direct Transfer Tripping. c. Local (at DR) detection of the loss of the Area EPS source due to the Area EPS s response to the initial Area EPS fault condition and subsequent isolation of the DR. For local detection of faults involving ground, the transformer winding configuration between the DR and the Area EPS dictate the means by which a fault can be detected. The most common receiving transformer connections are either delta - grounded wye, floating wye - delta, or grounded wye - grounded wye. Grounded wye - delta is not generally used because the normal Area EPS voltage unbalance will cause serious overloading of the delta winding as it tries to reduce the unbalance. The first two do not contribute directly to primary ground current and will require primary potential transformers or another source of ground current to detect an Area EPS ground fault. When a DR can sustain the isolated section of an Area EPS, it becomes very important that the Area EPS voltages be monitored to prevent serious overvoltage on other Area EPS customers and system lightning (surge) arresters. 54

55 The reduction in impedance can be indicated by an elevated level of current, and/or by a reduction in voltage. These effects can be combined with either a voltage restrained overcurrent relay or a voltage controlled overcurrent relay. They are similarly combined in a distance relay. Each type of relay has its proponents and one may be a best selection for a particular case. They all have some problem being coordinated with some other system relays. A DR may respond to isolation by the Area EPS in several ways. Separation from the Area EPS may be seen as a drop in Area EPS impedance that will cause separation. The Area EPS trip initiation can be passed to the DR as a transfer trip. Either of these can take effect at either the PCC or at the Point of Interconnection. Disconnecting Device Selection Criteria The selection of protective devices and/or functions depends on the type of DR unit. However, regardless of the type of DR, four principles of disconnecting device selection shall be considered: 1. Dependability A high probability of clearing faults that occur on the Area EPS. 2. Security A low probability of interrupting the circuit unnecessarily. 3. Selectivity Ability to discriminate so as not to isolate any area beyond the PCC. 4. Speed Operation as rapidly as possible, consistent with coordination requirements, to minimize damage. Synchronous Interconnections There are three commonly used methods of detecting the time-variant magnitude of multi-phase faults involving synchronous generators: voltage-controlled overcurrent relays, voltage-restrained overcurrent relays, and distance relays. All three of these methods capitalize on the depressed generator terminal voltage during fault conditions to aid in fault detection. The behavior of synchronous generators during fault conditions is traditionally quantified by three reactance values; the sub-transient reactance (typically referred to as X, or X double-prime) which addresses the generator behavior during the early time-domain of a fault, the transient reactance (X, or X prime) which addresses the generator behavior during the medium time-domain of a fault, and the synchronous reactance (Xs) which addresses the generator behavior during the long time-domain of a fault. The duration of the various time-domains is addressed by two time constants; Td (sub-transient time constant) and Td (transient time constant). The effective generator reactance as a function of time is calculated by an exponential equation using all three generator reactances and both time constants. where I(t) = (I -I ) e(-t/t ) + (I -I) e(-t/t ) +I I =1/(X +X system ), I =1/(X +X system ), and I=1/(Xs+X system ) Protective relaying for detection of multi-phase faults is generally located on the generator, or, if provided, on the generator breaker. In order to provide fault detection, these relays will usually also have to detect faults on the opposite sides of various transformers, and, possibly, will also have to account for some amount of system impedance to the fault. Voltage-controlled overcurrent relays will be adjusted for a sensitivity that will adequately detect the minimum appropriate current magnitude during fault conditions. In this relay type, a voltage element controls the overcurrent function, such that the function is enabled only when the voltage is depressed. The sensitivity of this relay type does not vary. The fixed sensitivity of this type of relay forces the relay to be set at a sensitivity which will detect the low 55

56 magnitude of faults which persist for a long period of time, which can cause difficulty in coordinating these relays with other relays, both on the Area EPS and within the Local EPS, such that only the relays which must operate to isolate any particular fault actually trip. Voltage-restrained overcurrent relays are also adjusted for a sensitivity that will adequately detect the minimum appropriate current magnitude during fault conditions. At 25% voltage, this type of relay is typically 4 times as sensitive as it at rated voltage. This allows the relay to respond quicker for the lowermagnitude faults with depressed generator terminal voltage. Distance relays employ measuring principles that calculate apparent impedance from the relay location to the fault location. Since the impedance from the relay location to the fault remains constant throughout the duration of the fault, distance relays can present a very consistent and predicable behavior during faults. Distance relays, however, can often be significantly more difficult to coordinate with other fault protection on both the Local EPS and Area EPS, and are therefore often not a preferred alternative. To illustrate the application of the three general types of relay characteristic, example calculations will be offered, representing a 1 MVA, 4.16 kv synchronous generator with X =20%, X =30%, and X=150%. Td will be 0.05 seconds, and Td will be 1.5 seconds. Furthermore, a 1 MVA transformer will be considered within the area for fault detection, with a 4.5% transformer impedance, together with additional distribution system impedance of 25%, representing a portion of the Area EPS. These impedances are not based on data from any particular manufacturer, but are somewhat representative of values that may be found in a specific application. In all cases, the protective relays will be located in 150/5 amp current transformers located on the generator terminals. There will also be a set of potential transformers having a 4.2 kv-/120 volt ratio located at the generator terminals to provide voltage to the various relays. The following chart describes the voltage and current that will be observed by the relays throughout the duration of a fault, together with an adjustment to indicate the effective operating current to a voltage-restrained type overcurrent relay (noted as a 51V relay in the chart). It may be noted that the impedance to the fault is constant at the value of the total system impedance including the transformer; this represents the constant operating characteristic of a distance relay. It will also be noted that the sensitivity of the voltage restrained overcurrent relay, corrected for the operating voltage, is also relatively constant, representing the relative ease of setting a voltage restrained overcurrent relay. However, a voltage controlled overcurrent relay must be set for the lowest actual generator operating current, which decreases greatly with time. Further investigation shows that the benefits of using a voltage-restrained overcurrent relay versus a voltage controlled overcurrent relay are minimal with little or no system impedance considered, and become appreciable as the system impedance to be considered becomes larger than the X of the generator. Induction Interconnections If an interconnection comprised of induction generators is designed such that the VARs necessary to excite the generators is drawn from the Area EPS, the induction generators will be unable to supply persistent phase fault current. Short-term fault currents will still be supplied, and may be calculated based on the reactance of the induction generators, and ground fault currents may be supplied, depending on the methods used to integrate the DR grounding with the Area EPS grounding. If the induction generator installation is designed such that their VAR requirements are somehow supplied from within the Local EPS, the induction generators may supply persistent phase fault current, and protection similar to that used for synchronous generators may be necessary. 56

57 Inverter Interconnections A salient characteristic of most inverters is their inability to supply excessive currents under Area EPS fault conditions. Fault detection schemes using overcurrent principals that are universally applied to equipment other than inverters are not usually effective. DR units using this technology must rely on other methods to detect electrical faults on the Area EPS. This may involve using protection otherwise intended for detection of unintentional islanding (abnormal voltage and/or frequency) or other methods as discussed below. When an Area EPS fault occurs, abnormal voltage conditions are typically experienced. Under and overvoltage and frequency sensing is typically used to detect these conditions. Detection of these abnormal voltage conditions by voltage sensing circuitry within the inverter can be an effective method to isolate the DR from the fault. Faster disconnection times for the DR should be expected for extreme voltage excursions to reduce the possibility of equipment damage. In addition to the voltage sensing method, detection of off-frequency operation can be used to isolate the DR from the Area EPS fault. The bandwidth of the frequency set points should be small since offfrequency conditions on the Area EPS are rare and sensitivity for islanding conditions is enhanced. This following discussion will include a process by which the fault is detected and a process by which the detection of the fault causes the DR to cease to energize the Area EPS. Detection of Faults in the Area EPS There exists a wide range of protective relay devices that detect fault conditions. In most cases a faultdetection device is installed between the source of energy and the circuit in which the fault is to be detected. In the case of phase-to-phase or phase-to-ground faults, the effectiveness of the fault-detection device typically increases with the level of fault-current supplied from the energy source to fault. If the fault-current level is low enough the fault-detection device may not detect the fault. Fault-detection devices can be deployed either in the Area EPS or in the Local EPS. (The use of faultdetection devices in a Local EPS is limited usually to the detection of faults within the Local EPS and is regulated by national and local codes.) The Area EPS contains sufficient fault-detection devices to detect the vast majority of faults in Area EPS circuits and persistent faults in Local EPS circuits. The faultdetection devices in the Area EPS are used to trip fault-interrupting devices that isolate the faulted circuit from the sources of energy in the Area EPS. Once a DR unit is connected to an Area EPS circuit it is an energy source that can also supply current to a fault in the circuit. The fault-current contribution of the DR unit determines is the amount of current that the DR will supply to a fault in the Area EPS circuit. If the DR fault-current contribution is substantial, it will contribute significantly to the total current supplied to the fault. The Area EPS contribution to the fault will be reduced by the presence of the DR. This may impact the time taken by the Area EPS to detect the fault, or in the extreme case may prevent the Area EPS from detecting the fault. If the proper operation of the Area EPS fault-detection devices is impacted by the presence of DR units then the affected fault-detection devices must be adjusted or supplemented with additional fault-detection devices. For example, it is typical to include devices to detect Area EPS faults in the interconnection system of a DR unit with significant fault-current contribution. If the aggregate fault-current contribution of DR units on an Area EPS circuit does not affect the operation of the Area EPS fault-detection devices, 57

58 then Area EPS faults can be detected without using additional fault-detection devices 29. However, the information that a fault has been detected must be conveyed from the Area EPS fault-detection device to the DR interconnection system, so that the DR can cease to energize the Area EPS 30. Note: For technical or commercial reasons it may still be preferable to include devices in the DR interconnection system to detect Area EPS faults, rather than communicate the status of each Area EPS fault-detection device to the DR interconnection system. For DR units with low fault-current contribution, the direct detection of some phase-to-phase and phaseto-ground faults by devices contained in the DR interconnection system may not be feasible. Many of these DR units are contained in Local EPS systems that are supplied by the Area EPS at low-voltage. In this case the Local EPS does not have access to the medium-voltage feeder for phase-to-ground voltage measurements. Also, the fault-current contribution of the DR may be too small for current-based faultdetection devices to be effective. For example, inverter based systems have typical short-circuit currents of between only 100% and 200% of the rated current. In particular, it may not be feasible for DR units and interconnection systems with low fault-current contribution to detect high-impedance phase-to-phase or phase-to-ground faults. Instead, they must rely on fault-detection devices in the Area EPS. Other types of fault can be detected directly by these DR units and their interconnection systems, such as open-phase faults, island conditions and faults that result in considerable voltage or frequency deviations. Process for the DR Unit to Cease to Energize the Area EPS after Fault Detection Once a fault has been detected in the Area EPS circuit, the DR unit must cease to energize the circuit. This process is simple if the fault-detection device is located in the DR interconnection system. For example, the fault-detection device output can be used to trip a circuit breaker in the interconnection system. If the DR interconnection system relies on fault-detection devices in the Area EPS, the status of these devices must be communicated to the DR interconnection system. One mechanism is to use a dedicated communication channel. For example, this is used in a direct transfer trip scheme. These methods are well known and provide a reliable and rapid means of communicating the status of an Area EPS fault-detection or fault-interrupting device to the DR interconnection system. For small DR installations with low fault-current contribution, the installation and operating costs are typically prohibitive for a dedicated communication channel from each Area EPS fault-detection device to the DR interconnection system. Instead, an indirect detection method is applied for faults that the DR interconnection system cannot detect directly. The principle of this method is outlined below: 1. A fault occurs. 2. A fault-detection device in the Area EPS detects the fault. 3. The fault-detection device operates a fault-isolating device in the Area EPS. 4. The fault-isolating device opens and the Area EPS circuit becomes islanded or open-phase. 5. The DR interconnection system detects the island, open-phase, or under-voltage condition. 6. The DR ceases to energize the Area EPS. 29 Additional fault-detection devices may be required to prevent the total fault-energy rating of any equipment in the Area EPS from being exceeded, or to maintain proper co-ordination during fault conditions. For example, Area EPS fault-detection devices may be required in the DR interconnection system to prevent nuisance tripping of fuses or sectionalizers in the Area EPS. 30 The time lag associated with the communication of the fault-detection device status must be considered during fault co-ordination analysis. 58

59 Considerations for the use of indirect fault detection The main difference between the indirect fault-detection approach and a direct transfer trip is in the time lag between the detection of the fault by the Area EPS device and time when the DR ceases to energize the Area EPS. As permitted in IEEE 1547 the island or open-phase detection may take up to two seconds. The implications of this time lag must be considered when evaluating the suitability of the indirect detection method 31. A primary concern is that the supply of fault-current by the DR unit(s) to the fault during this period should not cause the total fault energy rating of any equipment in the Area EPS to be exceeded. Therefore, a limit exists on the aggregate fault-current contribution that can be allowed on any Area EPS circuit from DR units that use the indirect method to detect certain faults. The assessment should take into account that some DR units use direct detection for low impedance faults and indirect detection for high impedance faults. Other considerations, such as possible phase-to-ground over-voltages and re-closer coordination, are associated with the existence of temporary unintentional-island conditions between the opening of the Area EPS fault-isolation device and the time when the DR ceases to energize the Area EPS. It should be noted that unintentional island conditions can occur for reasons other than faults, so these considerations are not unique to the use of indirect fault detection. However, the rate of occurrence of temporary unintentional-island conditions will be higher for DR units that employ indirect fault detection. Grounding Methods The vast majority of faults on overhead distribution circuits (often over 90%) involve ground. Therefore, it is paramount that the grounding of the DR be integrated with the Area EPS grounding methods (IEEE Std. 1547, Clause and IEEE P Clause 4.2), and that the detection of ground faults by the DR be very carefully addressed. The issues related to detection of ground faults depend heavily on the methods used to integrate the DR with the Area EPS grounding practices, and will not vary considerably with different types of DR If the DR is connected through a transformer connected grounded-wye on both sides, or through a transformer connected Delta on the generator side and grounded-wye on the Area EPS side, it will usually be possible to apply overcurrent relays for ground fault detection. The grounded-wye windings may be either solidly grounded or grounded through and impedance. A current transformer appropriately rated will be connected into the Area EPS side neutral connection of the transformer, and, following fault calculations, a time-overcurrent relay will be connected into these CTs and set to detect the appropriate fault. This method of detecting ground faults is also effective if the DR is connected grounded-wye or impedance-grounded-wye, and is connected directly without an interposing transformer. In the latter case, the current transformer will be located on the DR neutral connection itself. For any other combination of transformer windings, it will be necessary to detect zero-sequence voltage on the Area EPS. A set of potential transformers will be needed on the Area EPS side of the transformer, with the PT primary winding connected grounded-wye and the secondary connected delta, with one corner of the delta left open. A voltage relay can be connected into the open corner of the delta PT winding. A ground fault occurring on the Area EPS will produce a zero-sequence voltage of up to 1.5 times the normal phase-to-ground voltage, and this voltage will be present on the PT secondary after applying the appropriate transformation factors. The time characteristic for the voltage relay will be dependent to some extent on Area EPS fault detection practices. This method is also useful if a deltaconnected DR is connected directly without an interposing transformer. 31 When the actual maximum detection time for islands and single-phase open conditions is known for a DR unit and interconnection system, these values should be used for any analysis in place of the IEEE 1547 two second limit. 59

60 Area EPS Reclosing Coordination IEEE 1547 Requirement (Section 4.2.2) The DR shall cease to energize the Area EPS circuit to which it is connected prior to reclosure by the Area EPS. Application Guidance BACKGROUND The area EPS uses automatic reclosing as a means to limit the duration of interruptions to its customers. This is done by using devices (OCRs and circuit breakers) that can be automatically reclosed after a fault condition. Most (70-95%) of all faults on overhead distribution systems on the area EPS are transient in nature, resulting from factors such as lightning or tree contact. By de-energizing the EPS facility for a short period of time, the arc will extinguish, and the facility can be restored to service if the initial fault does not result in equipment damage. This requirement is intended to prevent out of synchronism conditions during reclosure in order to limit nuisance fuse trips or damage on transformers, motors and the DR. Experience has shown that percent of overhead distribution system line faults can be temporary in nature if the faulted circuit is quickly disconnected from the system. Most line faults are caused by variable factors such as lightning or tree contact; if the initial circuit damage is not severe or the resulting arcing at the fault does not continue long enough to damage conductors or insulators, the line can be returned to service quickly. Modern distribution feeders reclose (reenergize the feeder) automatically after a trip resulting from a feeder fault. This trip-reclose sequence may be initiated by reclosing relays controlling the corresponding feeder breaker at the substation, or by pole mounted reclosers located on the feeder away from the substation. Pole mounted reclosers or sectionalizers are strategically placed so as to limit the number of customers affected per given feeder fault. Although sectionalizers do not interrupt fault current and do not automatically reclose, they open to isolate faulted feeder sections after the feeder has been de-energized by a breaker or recloser. Automatic reclosing allows immediate testing of a previously faulted portion of the feeder and makes it possible to restore service if the fault is no longer present. Depending on the fault magnitude, the first reclosing try can occur very fast, sometimes within 0.2 seconds. This short time interval is characteristic of instantaneous reclosing operations. Automatic reclosing practices vary widely among Area EPS operators. Some installations having cable will have no automatic reclosing. Some facilities will use one shot reclosing, and some will use up to three shot reclosing. In this context, the term shot refers to an attempt to close the associated device. Automatic reclosing schemes will have widely varying timing depending on the operation of the Area EPS. Many Area EPS will use instantaneous reclosing. This is an attempt to reclose the circuit breaker or OCR as quickly as possible after opening for a fault. Typically this first reclosure will occur in 15 to 20 cycles (.24 to.33 seconds) after the fault. Other Area EPS may delay the first reclosure up to several seconds. The faster the reclose occurs, the higher the impact to the DR. This initial attempt is then usually followed by subsequent (typically two or three) time-delayed attempts of varying time intervals. If none of the reclose attempts are successful, the feeder circuit breaker will no longer reclose. Common terminology for this condition is that the circuit breaker is "locked out". 60

61 It is common practice for Area EPS operators to attempt to automatically reclose their circuit breakers associated with overhead distribution system circuits following a relay-initiated trip. This trip-reclose sequence may be initiated by reclosing relays controlling the corresponding feeder breaker at the substation, or by pole mounted reclosers located on the feeder away from the substation. Pole mounted reclosers or sectionalizers are strategically placed so as to limit the number of customers affected per given feeder fault. Although sectionalizers do not interrupt fault current and do not automatically reclose, they open to isolate faulted feeder sections after the feeder has been de-energized by a breaker or recloser. The time delay between tripping and the initial reclose attempt typically ranges from 0.2 seconds (12 cycles) to 15 seconds (or more). For radial feeders, this initial attempt is then usually followed by subsequent (typically two or three) time-delayed attempts of varying time intervals. If none of the reclose attempts are successful, the feeder circuit breaker will no longer reclose. Common terminology for this condition is that the circuit breaker is "locked out". A salient issue should be highlighted. The reclose attempts described above are performed without any undervoltage-permissive supervision (testing to ensure that the circuit is de-energized prior to the reclose attempt) and/or synchronism-check supervision (testing to ensure that the standing angle between the Area EPS voltage and a possible voltage on the feeder side of the open Area EPS feeder breaker is within acceptable limits) since the feeders are radial in design and the Area EPS source is the only source of power. The DR is required to cease to energize the Area EPS prior to the first reclosure of the Area EPS, insuring that the fault completely clears. This will also prevent out of synchronism conditions during reclosure in order to limit nuisance fuse trips or damage on transformers, motors and the DR. This will require careful coordination of the DR protective functions with the Area EPS. IMPACT OF DR The presence of DR on the feeder invalidates the conventional assumption that the Area EPS substation is the sole source of energization for the feeder. DR can potentially maintain energization of the feeder after the Area EPS circuit breaker or circuit recloser opens. The primary concern for DR reclosing coordination remains reliability. If the fault was temporary in nature and the DR does not trip off and extinguish the fault arc prior to the Area EPS reclosing attempt, the reclosing attempt will be unsuccessful and the automatic restoration of that circuit may be jeopardized. This can result in a several hour outage to several thousand customers rather than a less than a 1 second interruption. Second, the islanded feeder is likely to drift out of synchronism with the Area EPS. If the Area EPS breaker should reclose when the Area EPS and the island, energized by the DR, are out of phase, a very severe and potentially damaging transient can result. The following are some of the possible ramifications of an out-of-phase reclose: The DR energizing the island can be subjected to severe electromechanical torques, if the DR is a rotating generator. These torques pose a substantial risk of equipment damage. A severe transient overvoltage surge is likely to be created on the feeder, which can ideally reach three times the normal crest voltage (3 p.u.). With practical values of system damping, the voltage surge will be less severe, but can easily exceed 2 p.u. Figure 3 shows simulation results for a typical system where the peak surge reaches 2.2 p.u. The voltage surges created on the feeder will appear with roughly equivalent per-unit magnitude at the secondary services of other customers connected to the feeder. 61

62 Overvoltage surges of this magnitude can result in failure of utility surge arresters, customer load device damage, and failure of customer surge protectors. Transformers and motors connected to the feeder, reclosed out-of-phase, will experience magnetic inrush currents far more severe than normal energization inrush. Because the inrush will appear simultaneously in all connected magnetic devices, the currents can cause undesired operation of fuses and circuit breakers, both on the utility system and within customer systems. The abrupt change in voltage phase angle created by an out-of-phase reclosing will also cause abnormal electromechanical torques on motors and their mechanical loads. This can result in mechanical damage of customer equipment, including equipment not on the Local EPS where the DR is connected. 2.2 p.u. 1.0 p.u. DG-side voltage Source-side voltage Figure 3. Overvoltage Surge from Out-of-Phase Reclosing For the reasons described above, it is very important to coordinate DR tripping (elimination of DR as a feeder source) with feeder reclosing practices to ensure that out-of-phase reclosing does not occur. Due to the potential for reduced reliability to Area EPS customers and equipment damage, particularly damage to equipment owned by parties other than the Area EPS operators and the DR owner, liability considerations tend to force Area EPS operators to closely and conservatively address the issue of reclosing coordination. COORDINATION OF DR WITH RECLOSING The response of the DR unit must be coordinated with the reclosing strategy of the isolation devices within the Area EPS. Coordination is required to prevent possible damage to Area EPS equipment, to the DR itself, and to equipment connected to the Area EPS other than the DR. The DR and the Area EPS reclosing strategy will be coordinated if one or more of the following conditions are met for all reclosing events: 1. The DR is designed to cease to energize the EPS before the reclosing event. This condition can sometimes be met simply by the rating of the DR relative to the minimum load on the EPS circuit to which it is connected, such as if the DR capacity is sufficiently small that the minimum load on the feeder causes the island to reach an under frequency or undervoltage trip point in sufficient time for the DR to cease to energize the feeder prior to feeder reclosing, allowing for relay time and interruption time of any switchgear needed to cause the DR to cease to energize the feeder 2. The reclosing device is designed to delay the reclosing event until after the DR has ceased to energize the Area EPS. 3. The DR is controlled to ensure that the voltage phase-angle separation magnitude across the isolation device is less than one quarter of a cycle when the reclosing event occurs. 4. The reclosing device is controlled to ensure that the voltage phase-angle separation magnitude across the isolation device is less than one quarter of a cycle when the reclosing 62

63 event occurs. One way that this can be achieved is with a synchrocheck function provided in the relaying scheme controlling the reclosing device. TIPS, TECHNIQUES AND RULES OF THUMB It is preferred to de-energize the Area EPS prior to the reclose to allow arcing faults to extinguish. Typical reclose settings are from instantaneous (no intentional delay) to minutes. This requirement may be more restrictive than the anti-islanding requirement in terms of detection times. (Results from the anti-islanding test may be used to help assess reclose coordination.) Area EPS may delay or block reclose operations to assist with coordination. Use of Transfer Trips Control devices at the DR must recognize that a feeder has tripped and be able to initiate a command to separate the DR from the feeder prior to feeder reclosing. If separation cannot be obtained prior to the Area EPS s initial reclose attempt using local sensing approaches, additional protection may be required. This may include the addition of direct transfer trip (DTT) from the feeder breaker or automatic line sectionalizing devices to the DR, or the addition of synchronism-check relaying 32 or undervoltagepermissive relaying at the feeder breaker or automatic line sectionalizing devices. Even for large facilities, it may be necessary to use a DTT scheme to assure avoidance of accidental paralleling. However, DTT will require communications not only from the substation breaker but also from any automatic line sectionalizing devices upstream from the DR. Reclosing after a trip can be initiated from any one of these devices. Feeder Reconfiguration Many distribution systems can be reconfigured, either manually or automatically. If this technique is employed, the feeder section to which the DR is connected can be potentially connected to the Area EPS through a number of possible paths. It is becoming a more common practice for Area EPS operators to use a loop design for their feeders where two feeders are joined together with a normally open recloser (automatic sectionalizing). Even more complex automatic reconfiguration schemes are sometimes used, involving additional backup sources for the feeder. In addition to automatic reconfiguration, many circuit sections can be manually switched to alternate feeds from other feeders as necessary to equalize loading, allow continuity of service during maintenance, and for restoration following outages. When DR is placed on a feeder with automatic reconfiguration, or where manual reconfiguration is performed, it may be possible for the unit to be connected to the Area EPS through different feeders. This affects coordination of the DR with feeder reclosing because coordination must be maintained for every possible energization source. Any protection that is required on the original feeder (DTT, Synch Check, etc.) may also be required on the alternate feeders, or the DR may need to be prohibited from generating on the alternate feeder. A DTT scheme in re-configurable systems can become quite complex because DTT channels from breakers and reclosers in every possible energization path would need to be provided, along with logic to determine the current system configuration and identify which DTT signals are to be enabled. Coordination with Reclosing Reset Times Area EPS practice today also includes the use of multi-shot reclosers (feeder breaker or a recloser/sectionalizer can reclose not only once but twice and three times for a permanent fault). 32 Synchronism-check relaying may increase the reclosing time, a potential problem in some situations. 63

64 Typically, the multi-shot reclosing process takes place in a period of roughly one to three minutes. Although additional reclosings have no effect on a DR that has promptly separated, the overall reclosing coordination issue must be taken into account if the DR facility is to re-parallel automatically Reclosing Scheme Modification The installation of DR will generally negatively impact the normal reclosing of the Area EPS. Many Area EPS will not be willing to change their reclosing practice, as this will tend to lower the level of service to their existing customers. Therefore, system modifications may be necessary to integrate the operation of the DR with the Area EPS. One way that this is done is by controlling the circuit breakers and OCRs. Equipment is installed to monitor the voltage (27x) on the load side of these devices. If voltage is present, this is an indication that the DR has not yet been isolated. Reclosing is blocked until the voltage goes to zero (or some very low value), at which point the device is allowed to reclose. To determine if it is necessary to install the voltage monitors it is necessary to compare the size of the DR installation to the expected minimum load on the Area EPS system. Voltage monitors will only be necessary if the DR can not be assured to cease to energize an unintentional island prior to the first Area EPS reclosing attempt. Since very few if any Area EPS operators record minimum loads, studies are done to determine typical ratios of peak load to minimum load for various types of feeders. For example, one study (PPL EU reference) lines that are rural in nature typically have a 5 to 1 ratio of peak load to minimum load. Suburban lines have a 4 to 1 ratio, and urban lines have a 3 to 1 ratio. Also, the Area EPS will apply a safety factor of 2 to 1 to 3 to 1 to make sure the DR is overloaded under all reasonable conditions. This requirement is that the remaining load isolated with the DR be 2 to 3 times more then the maximum generation. The result will be rapid overload of the generation, and rapid operation of the protective functions. 3 VTs P- PPL EU 12 kv A B C 27A 27B 27C Line section with 600kW minimum load Line section with 1000 kw minimum load Line section with 800 kw minimum load DR facility, 500 kw Figure 4. Intentional Island That May Not Cease-to-Energize In Figure 4, it can not be assured that the DR will cease-to-energize an intentional island. Therefore, devices C and B would need to be modified to include the voltage check relays: Device C because the estimated minimum load is almost the same as the generation, and device B because the total estimated minimum load would be 1,400 kw which is just less then the 3 to 1 safety ratio generally needed to assure that the DR will cease-to-energize an island. Device A would not need to be modified. 64

65 65

66 Voltage IEEE 1547 Requirement (Section 4.2.3) The protection functions of the interconnection system shall detect the effective (RMS) or fundamental frequency value of each phase-to-phase voltage, except where the transformer connecting the Local EPS to the Area EPS is a grounded wye-wye configuration, or single phase installations, the phase to neutral voltage shall be detected. When any voltage is in a range given below (Table 1), 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. The voltages shall be detected at either the PCC or 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 test for the system to which it is to be connected, (c) the aggregate DR capacity is less than 50% of the total Local EPS minimum annual integrated electrical demand for a 15 minute time period, and export of real or reactive power by the DR to the Area EPS is not permitted. Table 1. Interconnection System Response to Abnormal Voltages Voltage Range (% of base voltage a ) V< V< <V<120 1 Clearing Time b (s) V Notes. (a) Base voltages are the nominal system voltages stated in ANSI C84.1 Table 1. (b) DR 30kW, Maximum Clearing Times; DR > 30kW, Default Clearing Times Application Guidance BACKGROUND This requirement is intended to detail a method of detecting faults on the Area EPS and a means to prevent over-voltage or under-voltage damage to Area EPS equipment and customer equipment, in case the DR is the source of the abnormal condition, for example, during unintentional islanding. Voltage magnitude and frequency are fundamental characteristics of electrical power and thus represent fundamental criteria for determining if the EPS or the DR equipment is experiencing difficulty or failure. The greater the deviation of the magnitude of voltage, whether measured at the PCC or the Point of DR Interconnection, the greater (or more proximate) the likely problem. Therefore, the table above defines two steps of response for over-voltage and two steps of response for under-voltage. These rapid and 66

67 delayed voltage protection functions enable the interconnection system to respond much more quickly to the greater voltage excursions. The rapid under-voltage protection function has a primary purpose of detecting of faults on the Area EPS. The rapid over-voltage protection function has a primary purpose of detecting potentially damaging overvoltages that can occur in an unintentional island. The delayed under-voltage and over-voltage protection functions have a primary purpose of detected more sustained voltage abnormalities in the Area EPS. All of the abnormal voltage protection functions can assist with the detection of unintentional islands. Requiring field adjustable voltage setpoints and clearing times allows the Area EPS Operator some discretion to accommodate specific -Area EPS characteristics. Incidentally, although the wording in the requirements specifies only the voltage setpoints must be adjustable for DR above 30 kw, the intention is that clearing times be adjustable as well (as noted in the footnote). Voltage and frequency deviations may damage equipment on the Area EPS or equipment of other customers served from the Area EPS. However, if instantaneous tripping for voltage and frequency deviations is implemented in the DR Interconnection system, DR nuisance tripping may occur for a variety of external system disturbances; thus the requirement of a time delay for minor variations. Field adjustable setpoints and clearing times are to be protected against unauthorized adjustment. Adjustment by a qualified individual (or automatic adjustment for prevailing conditions) is desirable to allow compensation for voltage difference between the DR and the PCC. For DR units over 30 kw (peak capacity) being fed from medium-voltage switchgear, consideration should be given to measuring the voltage for the requirements of this section at the PCC in order to avoid problems with voltage drop in various transformers, wiring, or feeder circuits within the Local EPS. IMPACT OF DR General The sensing of voltage deviations outside of a range which is defined to be normal is a critical element in detecting faults and possibly unintentional islands. Many DR will have difficulty in maintaining a voltage within narrow bands if they are supplying either a faulted Area EPS circuit or even a mildly fluctuating load without the stabilizing influence of the Area EPS. DR equipment sized well below facility demand and precluded from export will also not sustain an unintentional island as well as DR equipment certified to pass a non-islanding test. These conditions are specifically identified as criteria allowing voltage to be measured at the point of Interconnection rather than the PCC (the default in the standard). If an induction generator is operating self-excited, very high resonant over-voltages can result on an islanded system. Since equipment failures related to these over-voltages happens very quickly as the equipment insulation strength is exceeded, an over-voltage trip level below the equipment insulation level should be established, with an instantaneous trip. This is an example of a case where the Area EPS Operator may wish that all time delay be removed from the 120% voltage over-voltage trip, which is specified in P1547 as a 0.16 second time total clearing time. Voltage-based fault detection to indicate EPS problems. Voltage-based fault detection is intended to replace current-based fault detection for DR units unable to either produce or sustain significant fault current contribution during Area EPS fault conditions. Inverterbased DR is normally current limited by the inverter controls, and induction generator-based DR fault current contribution decays very quickly as the air gap flux collapses under short circuit conditions. Even 67

68 a synchronous generator may fail to see significant increases in current during EPS faults for certain combinations of generator impedance, source impedance fault impedance, and fault duration. Phase-to-phase or phase-to-ground voltage measurements Short circuits on the EPS are primarily unbalanced faults, with single-phase-to-ground, phase-to-phase and phase-to-phase-to-ground faults being far more common than three-phase (balanced) faults. For this reason, it is critical for three-phase DR that over-voltage and under-voltage detection be provided for all three phases, as not all unbalanced fault conditions will affect the voltage on the unfaulted phases in sufficient magnitude to be distinguished from normal operating conditions. Additionally for a four-wire grounded wye connection, it takes only one phase-to-ground fault or phase-to-phase fault to result in short-circuit current flow. Therefore all the phase-to-ground voltages are required to be measured. One of the consequences of the above is that in a three-phase DR installation consisting of three singlephase inverters connected to a four-wire grounded wye connection, the inverters must measure the phaseto-ground voltages, not the phase-to-phase voltage. Even if the inverters are connected between phases, they must at least measure the phase-to-ground voltages. If the DR is connected to the Area EPS comprised of three-phase, three-wire construction, the phase-toground voltages are NOT required to be measured. On these systems, it will take two phase-to-ground faults on different phases to cause fault current to flow. Consequently, measuring the phase-to-phase voltage is sufficient to measure a fault resulting in short-circuit current flow. TIPS, TECHNIQUES AND RULES OF THUMB General Where there are other effective methods of detecting faults it may be appropriate to set the abnormal voltage protection trip times longer than the default values to prevent nuisance trips. Cooperative Requirements Cooperatives should consider the following type of clause in any agreement or tariff in implementing this requirement of IEEE 1547: The DR owner shall have, as a minimum, an interrupting device(s), which is sized to meet all applicable local, state and federal codes, operated by over and under voltage protection (installed in each phase and wired phase to ground), and additional loss of phase protection. (The interrupting device(s) shall also be operated by over and under frequency protection as covered by the next section of this guide.) The set points as listed above shall not be changed or modified by the DR owner or operator at any time. The DR shall automatically initiate a disconnect sequence from the Area EPS as these set points are reached. To avoid out of phase reclosing, the design of the DR unit s protection and control scheme shall take into account the Area EPS practice of automatically reclosing the feeder without synchronism check as quickly as 12 cycles after being tripped. A failure of the DR owner s interconnection protection equipment, including loss of control power, shall open the interrupting device, thus disconnecting the generation from the utility system. The DR s protection equipment shall utilize a non-volatile memory design such that a loss of internal or external control power, including batteries, will not cause a loss of interconnection protection functions including all pickup set points. All interface protection and control equipment shall operate as specified independent of the calendar date. Impact of transformers between the PCC and point of DR interconnection 68

69 Transformers between the PCC and the point of DR interconnection can have a significant effect on the phase-to-phase and/or phase-to-neutral voltages present at the point of DR interconnection for unbalanced voltages on the Area EPS. With the exception of the grounded-wye/grounded-wye transformer connection, voltage imbalances at the PCC that may occur as the result of phase-to-ground or phase-tophase-to-ground faults on the Area EPS can be significantly different when detected at the point of DR interconnection, depending on how the zero sequence component of the voltage is reflected across the transformer(s) and how the positive and negative sequence voltages are affected by any phase shift across the transformer. For some transformer interconnections it may be appropriate to adjust the voltage set-points to reduce the impact of the transformer on the effectiveness of the voltage-based fault detection. Typically this would involve increasing the rapid under-voltage trip level, because this is the primary means for voltage-based detection of faults. For example, with a four wire grounded wye utility service at the PCC, and a delta/grounded-wye transformer between the PCC and point of DR interconnection, a rapid under-voltage trip level of 76% may provide similar voltage based fault detection to that obtained with a groundedwye/grounded-wye transformer and the default rapid under-voltage trip level of 50%. Single-phase and split single phase measurements Single-phase DR interconnection systems are required to sense phase-to-ground voltage. A single voltage measurement is sufficient for a two-wire DR system that is connected to one phase and the neutral. Two phase-to-ground voltage measurements are required for two-wire DR systems that are connected phaseto-phase on split single-phase circuits, or on 4 wire grounded circuits. Two phase-to-ground voltage measurements are required for three-wire DR systems that are connected to two phases and the neutral. It is necessary to measure two phase-to-ground voltages on a two-wire single-phase DR system that is connected to phase-to-phase. This is to detect potentially damaging over-voltages that can occur between one phase and neutral during unintentional islanding. In this case, phase to neutral voltage balance is determined by the impedance balance of the loads connected between each phase and the neutral. When the loads are not balanced, damaging over-voltages can occur between one phase and neutral, even though the phase-to-phase voltage is within the nominal range. Definition of Voltage Disturbances Based on characteristics such as duration, disturbances are identified by a variety of technical terms shown in Table 5. TERM Impulse Notch Momentary Interruption Sustained Interruption Sag Surge Swell Table 5. Voltage Terminology Differences MEANING A short duration disturbance, typically less than one cycle An impulse that subtracts from the fundamental frequency wave Complete loss of line voltage for a duration of 30 cycles to 2 minutes, while automatic equipment is acting to resolve an abnormal circuit condition The complete loss of line voltage for a duration greater than two minutes Momentary under-voltage at the fundamental frequency lasting from a half-cycle to a few seconds Momentary over-voltage at the fundamental frequency lasting from a half-cycle to a few seconds Momentary over-voltage at the fundamental frequency lasting from a half-cycle to a few seconds Original Source: IEEE Std , IEEE Guide for Service to Equipment Sensitive to Momentary Voltage Disturbances. 69

70 Causes of Momentary Disturbances Electrical utility and utilization supply systems are designed to provide an adequate and reliable voltage supply to meet the basic needs of all users. Normally, both utility and utilization systems used for the production and distribution of electricity are subjected to unexpected momentary variations from both natural and man-made disturbances. As a result, most electrical systems will experience certain voltage disturbances. Some electric and electronic equipment, because of special sensitivities, may require a voltage supply that has fewer momentary disturbances than what is otherwise adequate. The nature of the offending disturbances, severity, incidence rate, effects on sensitive equipment (e.g., lost or spurious data, false triggering or other equipment failure), and the degree of control will vary. Many of these disturbances are generated at the user s facility by user equipment or by other user-owned equipment on adjacent circuits; others result from an event on the utility system, such as lightning and equipment switching. Momentary voltage disturbances are generally caused by the following: Lightning Faults (short circuits) Switching Motor starting Cyclic and variable loads Tap changing See Table 6 for more detail. 70

71 Table 6. Description of Momentary Disturbances Disturbance Lightning Faults Switching Capacitor Switching Motor Starting Cyclic and Variable Loads Tap Changing Description Lightning-related surges in the low-voltage system can either occur from direct strikes to the customer s service or by induction from strikes elsewhere. Lightning can cause surges at loads and commonly leads to sags or momentary interruptions as a result of temporary faults (including arrester operation) initiated by lightning. Some lightning-induced transients cause the tripping and automatic reclosing of protective switchgear. Such operations are similar to those caused by line-to-ground faults from tree limbs and other objects grounding or short-circuiting transmission or distribution lines. Faults (short circuits) on the utility system are classified as either temporary or permanent. The normal utility overcurrent protective practice is based on the fact that most faults (on overhead systems) are temporary or can be selectively isolated in order to restore the remainder of the system. Permanent (long-term) faults may be due to equipment failure, accidents with vehicles, a tree limb falling onto the line, etc. They result in service interruptions which can last from minutes to hours. During a permanent fault condition, the breaker is usually programmed to operate three or four times in an attempt to re-establish power before it locks open. The fault must then be located and repaired before service is restored to all customers. Most switching operations, both utility and user, result in momentary voltage disturbances. These operations include fault clearing, rapid clearing, load transfer, fault closing, current chopping, etc. Although most users of sensitive equipment are aware that their equipment may be subjected to transients, many are not aware of the magnitude or source of the transients or the specific sensitivities of their equipment. Transients from within the customer s premises occur with load switching or fault clearing. The transient voltage results from the rapid rate of change of current through the inductance of the wiring. The magnitudes of these transients can be quite high. In addition to voltage regulators and load tap-changers (LTCs), most utilities and many industrial and commercial users employ shunt capacitor banks to help control the power factor or voltage profile by supplying reactive power (vars) to inductive loads, such as motors. Placed strategically on the circuit, shunt capacitors also reduce the losses associated with the primary circuit while improving the power factor. To accommodate widely varying load conditions, most capacitor banks are switched automatically. When capacitor banks are energized, the transient oscillation between the capacitor and the system inductance produces transient voltages as high as 2 times normal at the capacitor location. The magnitude of the over-voltage is usually less than this due to damping provided by systems loads and losses. Certain sensitive loads may not be able to tolerate the normal switching transients associated with routine capacitor switching. The starting of large motors is accompanied by a voltage sag resulting from the inrush current flowing through the system impedance. The maximum voltage sag occurs at the motor terminals and can have a noticeable or even objectionable effect on other customers in the area, or on nearby load sensitive to sags. (See Flicker section.) These loads include automatic spot welders, reciprocating compressors, etc. The human eye is particularly sensitive to this type of disturbance. At six fluctuations per second, the objectionable voltage flicker limit is only 0.5%. (See Flicker section.) The control of operating voltage levels on a distribution system is accomplished through the use of voltage regulators, LTCs and shunt (power factor correction) capacitors. A load tap-changer is functionally equivalent to a voltage regulator. Both consist of an autotransformer with a tapped series winding. A voltage-level-sensing control and a tap-changing mechanism are provided that change the tap position and the voltage level under load. Sensitive Loads Digital electronic devices, particularly those with a memory, are extremely sensitive to even very shortduration power disturbances. These momentary disturbances, impulses, or transients may result in customer complaints unless adequate ride-through capability is provided. Minicomputers, electronic cash registers, and data terminals are a few examples of sensitive loads that often fall victim to momentary voltage disturbances. These disturbances can interrupt the operation of sensitive circuitry and cause memory loss, system malfunction, or component failure. Leading categories of sensitive customer loads are discussed below. 71

72 Computers Computer equipment is more sensitive to voltage disturbances than most other equipment. Computers generate harmonic distortion and typically are not very sensitive to it unless the voltage waveform is very distorted. Distortion of the voltage near the zero-crossings can cause timing errors. The ability of computer equipment to withstand voltage disturbances was first described in 1987 by a group called the Computer and Business Equipment Manufacturers Association (CBEMA) and was illustrated with an over-and-under-voltage chart typically referred to as the CBEMA Curve. This curve was refined in 1997, and is now generally referred to as the ITIC Curve. Process Control Commercial facility management systems typically include sensors for input data, remote terminal units, the central processor, and man-machine interface devices. Functions managed can include heating, ventilating, and air-conditioning; security; access control; and energy management. Industrial flexible manufacturing systems are assemblies of machine tools, cutting tools, and workpiece-handling devices employed to process a variety of finished parts. Process control systems exhibit similar voltage sensitivities as computer equipment. In addition, motor starters, contactors, relays, and other devices held closed by a coil and magnetic structure are especially sensitive to short-time interruptions and voltage sags. As a guide, a voltage sag to 60 or 70% of rated voltage for 0.5 seconds will de-energize many of these devices. Many control relays, sealed-in by their own contacts, will drop out if voltage is lost for 0.5 cycle or more. Telecommunications Most of the critical telecom equipment uses batteries to buffer disturbances and interruptions of the electric utility service, so short-term transients normally have little or no effect. However, the individual terminals that connect to the public telecommunication networks often connect directly to the electric utility service and are subjected to disturbances. Electric Arc Lighting High-intensity discharge (HID) lighting includes mercury, metal halide, and high-pressure sodium lamps used for security and street lighting applications. In the event of a power interruption or voltage sag lasting more than 1 cycle, HID lamps extinguish and do not restart for several minutes. The exact magnitude of the voltage drop causing this condition depends on the lamp ballast. Consumer Electronics An ever-increasing variety and number of digital electronics are found in videocassette recorders, microwave ovens, stereos, televisions, and clocks. Some of these have back-up systems (e.g., batteries) that prevent disruption to timer/clock functions when power is lost for short periods of time. Others do not. Adjustable Speed Drives Adjustable speed drives (ASDs) are used to control the speed, torque, acceleration, and direction of rotation of a motor. Unlike constant speed systems, the ASD permits the selection of an infinite number of speeds within its operating range. Adjustable-frequency ac drives convert three-phase 60 Hz input power to an adjustable frequency and voltage source for controlling the speed of squirrel-cage induction motors or other ac motors. Problems have been documented involving nuisance tripping of some manufacturers ac drives due to switching transients associated with capacitors on the customer s or utility s system. 72

73 Frequency IEEE 1547 Requirement (Section 4.2.4) When the system frequency is in a range given below (Table 2), 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 frequency set points and clearing times shall be either fixed or field adjustable. For DR greater than 30 kw the frequency set points shall be field adjustable. Adjustable underfrequency trip settings shall be coordinated with Area EPS operations. Table 2. Interconnection System Response to Abnormal Frequencies DR SIZE Frequency Range (Hz) Clearing Time a (s) > kw < > < { } (adjustable Adjustable 0.16 to 300 >30 kw setpoint) < Note. (a) DR 30 kw, Maximum Clearing Times; DR > 30 kw, Default Clearing Times Application Guidance BACKGROUND This requirement is intended to establish: The operation of an Area EPS protective device following its detection of an Area EPS fault. A method of detecting islands. Coordination with some load shed schemes. To prevent over-frequency or under-frequency damage to Area EPS equipment and customer equipment. (In case the DR is the source of the abnormal condition, for example during unintentional islanding.) Under and over frequency protective functions are among the most important means of detecting the establishment of a DR island. It is desirable for these protections to operate promptly, but nuisance trips need to be avoided. The frequency in a typical Area EPS is very stable. However, voltage phase-angle swings can occur in transmission and distribution lines due to sudden changes in feeder loading and load current. If extremely short time measurements are employed, these voltage swings can cause nuisance trips of under or over frequency protective functions. The purpose of the allowed time delay in this P1547 requirement is to ride through short-term disturbances to avoid excessive nuisance tripping of the DR. IMPACT OF DR As discussed above, frequency excursions may occur on the Area EPS during the period following the operation of an Area EPS protective device if a DR is isolated with the Area EPS loads and continues to 73

74 operate. The clearing of Area EPS faults, therefore, depends on the DR clearing off line whenever EPS voltage and/or frequency are out of agreed-upon operating ranges. Smaller DR units less than 30 kw potentially have less impact on system operations and typically can disconnect from the Area EPS well within 10 cycles clearing time. DR units larger than 30 kw can have a positive impact on distribution system reliability. The IEEE 1547 requirement takes this into account by allowing the Area EPS operator to specify the frequency setting and time delay for underfrequency trips down to 57 Hz. Causes for EPS Frequency Degradation Area EPS stability depends, in a large part, on the system s ability to withstand the outage of certain lines or equipment without being forced into a system emergency. Stability also depends on the proper matching of system load and generation. When generation is inadequately matched with system load, the EPS frequency will either decline or accelerate. When this happens, the Area EPS and/or generator operators or automatic large generator control systems seek to quickly match load with the available generation. Underfrequency and undervoltage relays may also be installed on the Area EPS to automatically shed load to stabilize operations. Coordination with these stabilizing techniques is the purpose for allowing the Area EPS operators to modify the setting of the DR underfrequency trip relay. Some of these underfrequency relays are sensitive to the rate of EPS frequency decay, providing information to the system operator to assist in the timing of load shedding. Similar problems on the EPS can occur when generation exceeds the available load, as in the case when a large block load is suddenly lost, or when tie lines exporting power quickly relay closed. Significant overfrequency conditions occur less often than significant underfrequency conditions. TIPS, TECHNIQUES AND RULES OF THUMB In large power systems, frequency changes are rare. However, with installed DR, some frequency change is unavoidable when blocks of load are switched. With a modern synchronous governor or static transfer switch used on a distribution system feeder, these disturbances should be under 5 percent frequency change and less than 5s duration, even for full load switching. Both the frequency and voltage trip pickup settings for induction generators and static power converters may be relaxed at the discretion of the Area EPS if it appears that the DR will experience too many nuisance trips. Synchronous generator trip settings can also be relaxed, but not too much due to the increased threat of islanding. EXAMPLE OF GENERATOR GOVERNORS AND IMPACT ON FREQUENCY Governors work in droop or isochronous modes of operation. In a droop mode, the engine s speed decreases as the load increases; in isochronous mode the governor maintains the same steady speed at any load, up to the full load. A typical speed droop setting for a droopoperated generator is 3 5%. Thus, if speed and frequency at full load are 1800 r/min and 60 Hz, respectively, at no load they will be 1872 r/min and 62.4 Hz, with 4% droop. When a generator is parallel with the system for maintenance periods, the governor is set on droop mode, i.e., it is base-loaded. Under an isolated condition, it is desirable to operate the governor under an isochronous mode so that the system frequency is kept constant. Under steady load, frequency tends to vary slightly above and below the normal frequency setting of the governor. The extent of this variation is a measure of the stability of the governor. An isochronous governor should maintain frequency regulation within ± 1/4%. When load is added or removed, speed and frequency dip or rise momentarily, usually for 1 3 s, before the governor causes the engine to settle at a steady speed at the new load. For generators operating in parallel with a primary source of power, the governor may be arranged to automatically switch from droop to isochronous mode upon loss of the primary source. The frequency trip points should be adjustable in increments with a setting resolution of 1/2 Hz or better. Internal microprocessor protection functions in static power converters units may be substituted for external relays if they provide 74

75 suitable accuracy. External test ports for periodic utility testing of the trip pickup settings should be included in the interconnection package. Operation at under frequency may result in synchronous generator hot spots and higher than normal generator insulation temperature. 75

76 Loss of Synchronism IEEE 1547 Requirement (Section 4.2.5) Loss of synchronism protection is not required except as necessary to meet clause Application Guidance BACKGROUND This clause applies only to synchronous generators. Synchronous Generators A synchronous generator typically employs a three-phase stator winding which, when connected to the utility three-phase source, creates a rotating magnetic field inside the stator and cutting through the rotor. The rotor is excited with a dc current that creates a fixed field. The rotor, if spun around at the speed of the stator field, will lock its fixed field into synchronism with rotating stator field. Force (torque) applied to the rotor in this synchronous state will cause power to be generated as long as the force is not so great that the rotor pulls out of step with the stator field. IMPACT OF DR The impact of the DR for a loss of synchronism condition are focused in two areas: response of the generator to an external system fault, and transients within the generator for a remote Area EPS reclosing operation. For loss of synchronism to be a concern, an Area EPS fault must be electrically near the generator, but must also be in a location where it is not necessary for the generator to otherwise cease-toenergize the Area EPS. This fault location will be referred to as being in the electrical vicinity of the generator. Generator Response to an External Fault If a fault occurs on either the Area EPS or the local EPS in the electrical vicinity of a synchronous generator, the governor on the synchronous generator will respond to the fault by causing the prime mover to accelerate in order to attempt to maintain a constant real power output. This accelerating input will remain as long as the fault persists, and has the effect of advancing the generator rotor s electrical relationship relative to the stator. After the fault is cleared, the prime mover shaft input into the generator will exceed the real power demands on the generator, resulting in the governor attempting to slow down the prime mover, which in turn results in retardation of the generator rotor relative to the stator. In many ultimately stable cases, the generator response, the real power output, and the generator rotor electrical relationship will oscillate several times before dampening out. If the response time of the governor and the mechanical inertia of the generator prime mover system are able to respond appropriately to keep the generator rotor from advancing or retarding by at least 120 electrical degrees, the oscillating transients will dampen out and the generator will remain in synchronism with the remaining system. If the system inertia and governor are not able to respond appropriately, the undamped transients will cause the generator to slip a pole, which if left unabated will cause a cascading acceleration of the prime mover, with attendant high generator shaft torques, high generator currents, and highly oscillating generator terminal voltage. 76

77 Generator Transient Response to Area EPS Reclosing An island is formed when a relay-initiated trip causes a section of the Area EPS containing DR to become separated from the main section of the Area EPS. The main section of the EPS and the island will then operate out of synchronism. If an isolation device is reclosed between the main section of the EPS and the island, a voltage and current transient will occur while the island is brought into synchronism with the remainder of the EPS. These voltage and current transients in turn will cause a mechanical transient, which will primarily be evident on the shaft of the combined generator-prime mover system. The severity of these transients will depend upon the voltage phase-angle separation magnitude across the isolation device when the reclosing event occurs. If the voltage phase-angle separation between the islanded system with the generator connected and the remainder of the Area EPS, together with the inertias and other dynamic characteristics of both systems, is acceptable, the transients when closing the systems together will be minor, and the generator will successfully synchronize with the system. If the transients are excessively severe, the resulting mechanical transients may cause extensive damage to the generator-prime mover system. TIPS, TECHNIQUES AND RULES OF THUMB It is a matter of considerable controversy whether a loss-of-synchronism condition (also known as an outof-step condition) is really of a concern with synchronous DR. Various technical references suggest that a loss-of-synchronism condition should not violate IEEE 1547 Clause unless the stiffness ratio is 20 or less. Impact of Loss-of-Synchronism Conditions on Generators A loss-of-synchronism condition on an operating generator is a very serious concern for the electrical and mechanical integrity of the generator and prime mover. Serious damage can result from this condition. A loss-of-synchronism condition produces heavy surge currents in the armature windings of a magnitude that may exceed those associated with the generator short-circuit capabilities and may cause serious thermal damage to the windings. Out-of-synchronism conditions also cause torque reversals that crate, in many parts of the generatorprime mover system, high mechanical stresses of magnitudes that may be several times the system rated torque. These excessive torques may cause damage to the shaft of the generator or prime mover, or may actually cause the generator and/or prime mover to wrench free of the mountings to the foundations. High induced voltages and currents in the field circuit may also cause flashover of the collector rings and of the commutator of an associated exciter, and may cause damage to solid-state exciter components and systems. For these reasons, out-of-synchronism operation must be promptly identified and the condition remedied. Possible corrective action includes the tripping of the unit from the EPS. Impacts of Loss-of-Synchronism Conditions on the Area EPS The clause in IEEE 1547 disregards the effects of a loss-of-synchronism condition on DR equipment, and addresses only the requirements for interconnection of the DR to an EPS. Since a loss-of-synchronism condition presents a phenomenon at the PCC which appears very similar to Flicker (see IEEE 1547, Clause and IEEE , Clause 8.3.2), IEEE 1547 addresses this condition as only being a concern if the requirements of that clause become an issue. In order to accurately predict a loss-of-synchronism phenomena (also called an out-of-step condition), it is necessary to perform complex (and costly) stability studies, which must address the EPS inertia, the 77

78 generator prime mover system inertia, the generator governor behavior, prime mover fuel supply, the generator excitation design, and any features of the generator control system which may be intended to ameliorate loss-of-synchronism conditions. If loss-of-synchronism presents a problem as presented in IEEE 1547, it will probably be necessary to add relaying or other equipment with loss-of-synchronism protective functions to immediately isolate the DR from the Area EPS. It will usually be necessary to perform the stability studies noted above in order to adequately apply these protective functions. 78

79 Reconnection To Area EPS IEEE 1547 Requirement (Section 4.2.6) After an Area EPS disturbance, no DR reconnection shall take place until the Area EPS voltage is within Range B of ANSI C84.1 Table 1, and frequency range of 59.3Hz to 60.5Hz. The DR interconnection system shall include an adjustable delay (or a fixed delay of five minutes) that may delay reconnection for up to five minutes after the Area EPS steady state voltage and frequency are restored to the ranges identified above. Application Guidance This requirement is closely related to the requirements in Clause 4.2.1, Area EPS Faults, and Clause 4.2.2, Area EPS Reclosing Coordination. As the requirements of IEEE 1547 were being developed, these two clauses and this section on Reconnection were discussed as a group. The sequence of events begins with the DR detection of a fault on the Area EPS, followed by coordination with the feeder restoration activities of the distribution circuit, and then ultimately reconnection of the DR with the Area EPS. As noted in the other clauses, the response of the DR unit must be coordinated with the reclosing strategy of the isolation devices within the Area EPS. Coordination is required to prevent possible damage to Area EPS equipment and to other connected equipment. As noted in Clause 4.2.1, a distribution circuit is typically supplied through a single power circuit breaker located at the supply substation and is divided into various zones by automatic sectionalizing devices. The intent of this design is to quickly isolate a faulted section of a feeder with limited or no interruption of service to adjacent customers on unfaulted portions of the same feeder. This requirement (Clause 4.2.6) allows DR reconnection once the Area EPS voltage is within Range B of ANSI C84.1, Table 1. Ranges A and B in the referenced standard cover normal (steady state) and infrequent operating levels of most Area EPS circuits. Range B is a wider range of voltage than Range A, with the caveat being that Range B operation is infrequent. For example, for a nominal system voltage of 120 volts, Range B allows customer utilization voltage (at the terminals of the customer s equipment) to vary between 106 to 127, while Range A requires the voltage to be held between 110 and 126. Consequently, by allowing reconnection under Area EPS Range B voltage conditions, this requirement is more lenient than it could be (if Range A operation were the required conditions). Range B voltages for low and medium voltage services from ANSI C84.1 are listed in Table 7. 79

80 Table 7. ANSI Standard C84.1 Range B Voltage Voltage Class Low Voltage Medium Voltage 120 Nominal System Voltage Twowire Threewire Four-wire Nominal Utilization Voltage Maximum Utilization and Service Voltage Voltage Range B Service Voltage Minimum Utilization Voltage Single-Phase / / / / /212 Three-Phase 208Y/ Y/ Y/ Y/ / / Y/ Y/ Y/ Y/ Y/ Y/ Y/ / Y/ Y/ Y/ Y/ Y/ Y/ Y/ Y/ Y/ Y/ Y/ Y/ / Y/ Y/ Y 22000Y/ Y/ Y 24200Y/ Y/ Y/ Y/ Y/ Y/ Y/ Y/

81 Limitation of DC Injection IEEE 1547 Requirement (Section 4.3.1) The DR and its interconnection system shall not inject dc current greater than 0.5% of the full rated output current at the point of DR connection. Application Guidance BACKGROUND DC injection produces a dc offset in the basic power system waveform. This offset increases the peak voltage of one half of the power system waveform (and decreases the peak voltage in the other half of the waveform.) The increased half-cycle voltage has the potential to increase saturation of magnetic components, such as cores of distribution transformers. This saturation, in turn, causes increased power system distortion. DC injection is an issue because of the economics of magnetic component design. These economics dictate using the smallest amount of magnetic core material possible to accomplish the needed task. This results in the magnetic circuit of the component operating near that part of the B-H curve where the curve begins to become very non-linear. IMPACT OF DR There is a concern that transformerless inverters may inject sufficient current into distribution circuits to cause distribution transformer saturation. Distribution transformers range in size from 25 to over 100 kva. A 25 kva transformer would typically carry 4-6 houses. A 100 kva unit typically carries houses. These numbers vary depending on the amount of electric heating that is used, but averages about 5 kva per residence. What DC Current Can A Transformer Tolerate? A transformer operates at a peak flux that is defined normally by its magnetizing inductance and the applied voltage. An exciting current flows in the primary that is equal to the applied voltage divided by the magnetizing inductive reactance. Ignoring leakage, the peak flux does not change as the transformer is loaded (the primary ampere-turns increase to compensate for the additional secondary ampere-turns). Typical design peak flux densities are 15 kilogauss (kg) for low loss transformers and 17 kg for less efficient ones. Saturation is at about kg. This does not leave a lot of headroom. If the applied AC voltage is increased, the excitation current, and consequently peak flux in the core, will increase. Any DC current applied to the transformer windings will offset the AC excitation current and also increase the peak flux. It might be expected that an increase in excitation current of only 15% would cause saturation. However, since operation would then be beyond the knee of the B-H iron saturation curve, it turns out that doubling the excitation current only increases peak flux by about 10%. This will not adversely affect transformer operation. Accordingly, a DC injection limit that is of the same magnitude as the excitation current is acceptable. This conclusion is supported by language in another relevant IEEE Standard (IEEE C , Recommended Practice for Establishing Transformer Capability When Supplying Nonsinusoidal Load Currents): 81

82 "DC Components of Load Current Harmonic load currents are frequently accompanied by a dc component in the load current. A dc component of load current will increase the transformer core loss slightly, but will increase the magnetizing current and audible sound level more substantially. Relatively small dc components (up to the rms magnitude of the transformer excitation current at rated voltage) are expected to have no effect on the load carrying capability of a transformer determined by this recommended practice. Higher dc load current components may adversely affect transformer capability and should be avoided." Because the peak excitation occurs at the peak (root(2) times the rms) of the transformer winding current, a DC component equal to the RMS excitation current increases peak current by only 171%, further increasing the safety margin. An injected DC component equal to the normal AC rms transformer excitation current is then an easily justifiable limit. Excitation currents for typical distribution transformers run at about 1% of full load rating, but some very efficient transformers may have excitation currents as low as 0.3%. Given the above peak to RMS ratio, the IEEE 1547 DC injection limit requirement of 0.5% is reasonable. TIPS, TECHNIQUES AND RULES OF THUMB This requirement only applies to inverter-based DR. Results from the testing requirement of Section of IEEE 1547 should be verified. Rely on test results from the DR or inverter manufacturer initially, with third-party independent certification at a later date as soon as this certification process has been developed and testing laboratories have been approved. Cooperatives with a significant amount of DR today, and an expectation that inverter-based DR will be increasing in the future, may want to consider establishing their own testing capability in accordance with this requirement. This testing arrangement could be outsourced or done in-house. The IEEE 1547 testing requirement from Section is: Inverter based DR shall be tested to confirm that the DR does not inject DC current greater than prescribed limits that are listed in clause

83 Limitation of Flicker Induced by the DR IEEE 1547 Requirement (4.3.2) The DR shall not create objectionable flicker for other customers on the Area EPS. 3 3 [For guidance refer to IEEE Std 519, IEEE Flicker Task Force P1453 and technical report IEC , IEC , and IEC ] Application Guidance BACKGROUND Flicker is a relatively old subject that has recently gained considerable attention due to the increased awareness of issues concerning power quality. Power engineers first dealt with flicker in the 1880 s when the decision of using ac over dc was of concern. Low frequency ac voltages resulted in a flickering of the lights. To avoid this problem, a higher 60 Hz frequency was chosen as the standard frequency in North America. Voltage Change and Frequency Range The frequency content of voltage flicker is extremely important in determining whether or not flicker levels are observable (or objectionable). The typical frequency range of observable flicker is from 0.5 Hz to 30.0 Hz, with observable magnitudes starting at less than 1.0%. The most sensitive frequency range for voltage flicker is approximately 5-10 Hz. In essence, this means that the human eye is more susceptible to voltage fluctuations in this 5-10 Hz range. As the frequency of flicker increases or decreases away from this range, the human eye generally becomes more tolerant to luminance fluctuations. What is Flicker? The term flicker is sometimes considered synonymous with voltage fluctuations, voltage flicker, light flicker, or lamp flicker. The phenomena being referred to can be defined as a fluctuation in system voltage that can result in observable changes (flickering) in light output. Because voltage flicker is mostly a problem when the human eye observes it, usually it is considered to be a problem of perception. There are, however, rare cases where voltage flicker can affect equipment operation such as electric drives and UPS systems. Voltage flicker - a condition of fluctuating voltage on a power system that can lead to noticeable fluctuations in the output of lighting systems. Voltage flicker can be separated into two types: cyclic and noncyclic. Cyclic flicker is a result of periodic voltage fluctuations in the system voltage, with noncyclic referring to occasional voltage fluctuations. The IEEE 1547 specifications are not intended to cover these application issues or to 1) apportion allowances for flicker emissions among various DR or loads on an Area EPS, or 2) whether distributed generators should be treated differently than distributed loads. Individuals vary widely in their susceptibility to light flicker. Tests indicate that some individuals are irritated by a flicker that is barely noticeable to others. Studies show that sensitivity depends on how much the illumination changes (magnitude), how often it occurs (frequency), and the type of work activity undertaken. The problem is further compounded by the fact that fluorescent and other lighting systems have different response characteristics to voltage changes. For example, incandescent illumination changes more than fluorescent, but fluorescent illumination changes faster than incandescent. 83

84 Sudden voltage changes from one cycle to the next are more noticeable than gradual changes over several cycles. Illumination flicker can be especially objectionable if it occurs often and is cyclical. Figure 3 from IEEE Std , IEEE Recommended Practice for Electric Power Distribution for Industrial Plants, shows acceptable voltage flicker limits for incandescent lights used by a large number of utilities. Two curves show how the acceptable voltage flicker magnitude depends on the frequency of occurrence. The lower curve shows a borderline where people begin to detect flicker. The upper curve is the borderline where some people will find the flicker objectionable. At 10 per hour, people begin to detect incandescent lamp flicker for voltage fluctuations larger than 1% and begin to object when the magnitude exceeds 3%. In using this curve, the purpose for which the lighting is provided needs to be considered. For example, lighting used for close work such as drafting requires flicker limits approaching the borderline of visibility curve. For general area lighting such as storage areas, the flicker limits may approach the borderline of the irritation curve. Note that the effect of voltage flicker depends on the frequency of occurrence. An occasional dip, even though quite large, is rarely objectionable. When objectionable flicker occurs, either the load causing the flicker should be reduced or eliminated, or the capacity of the Figure 5. Acceptable Voltage Flicker Limits for Incandescent Lights supply system increased to reduce the voltage drop caused by the fluctuating load. In large plants, flickerproducing equipment should be segregated on separate transformers and feeders so as not to disturb flicker-sensitive equipment. Objectionable flicker in the supply voltage from the utility should be reported to the utility for correction. Flexibility in approach and effective communications between the customer and the utility can be invaluable in resolving potential flicker problems. Voltage flicker due to DG could occur on any radial distribution system. The risk of flicker needs to be evaluated for any type of distribution system. Flicker may be either a simple issue or a complex issue as far as its analysis and mitigation are concerned. From the simple perspective, it can be the result of starting a machine (e.g. induction generator) or step changes in DG output which result in a significant voltage change on the feeder. If a generator starts, or its output fluctuates frequently enough, flicker of lighting loads may be noticeable to customers. 84

85 IMPACT OF DR Determination of the risk of flicker problems due to basic generator starting conditions or output fluctuations is fairly straightforward using the flicker curve approach, particularly if the rate of these fluctuations is well defined, the fluctuations are step changes, and there are no complex dynamic interactions of equipment. The dynamic behavior of machines and their interactions with upstream voltage regulators and generators can complicate matters considerably. For example, it is possible for output fluctuations of a DG (even smoother ones from solar or wind systems) to cause hunting of an upstream regulator and, while the DG fluctuations alone may not create visible flicker, the hunting regulator may create visible flicker. Thus, flicker can involve factors beyond simply starting and stopping of generation machines or their basic fluctuations. Dealing with these interactions requires an analysis that is far beyond the ordinary voltage drop calculation performed for generator starting. Identifying and solving these types of flicker problems when they arise can be difficult and the engineer must have a keen understanding of the interactions between the DG unit and the system. Wind Turbine Generators and Flicker Wind turbine generators (WTGs) can cause voltage flicker because their power output can vary substantially with time. Flicker from wind systems can potentially be caused by three characteristics: 1) Switching Events Flicker can be caused by switching events, such as starting, stopping, or switching between a small generator and a large generator. Each time a WTG synchronizes with the line, there is a surge of magnetizing current and sometimes a surge of power. The initial surge of current might vary from 75% to several times nameplate current rating. SCRs are often used to limit these high initial currents. These high starting currents cause the distribution line voltage to drop. A surge of power causes the voltage to rise. Likewise, switching between a small generator used at lower wind speeds and a larger generator used at high speeds also cause a sudden change in power levels. These changes in voltage levels might be 1% to 4% in magnitude and they occur somewhat infrequently, perhaps once every 5 to 15 minutes, depending upon the WTG controller settings. 2) Flicker Can Be Caused by the Blades Flicker can be caused by rhythmic fluctuations in power output due to the blades passing the tower. When a blade passes the tower, its torque is reduced due to the interference of the tower. Lattice towers with upwind blades result in the least change in torque, while tubular towers with down-wind blades have the most change in torque. For 3-bladed wind turbines, this pulsing power is called the 3P effect, since there are three pulses in power for each revolution of the rotor. WTGs using standard induction generators translate this drop in torque directly into a dip in the power output, while WTG s that are designed for variable speed operation usually translate this change in torque into a change in rotational speed, thus smoothing out the dip in power. Manufacturers have been designing turbines to reduce this type of flicker. The frequency of this 3P effect varies with rotor RPM, which is inversely proportional to WTG size. A small 50 kw wind turbine would have a 3P flicker frequency of about 10 Hz, while a large 700 kw wind turbine would have 1.5 Hz. These frequencies are in a range that is very noticeable to the typical customer. 85

86 3) Turbulent and Gusty Winds This type of flicker is proportionately reduced when more wind turbines are connected together due to the non-coincident nature of wind gusts. It is the most prevalent with a single turbine. Figure 6 illustrates how much the power can vary from a single wind turbine during variable wind conditions during a onehour period. Each data point is the average generation for a one-minute period. Sub-minute variations are also quite variable. This wind turbine has a fixed-blade pitch and uses a simple fixed speed induction generator. Figure 6. Fluctuation in Power Output from Wind Generator TIPS, TECHNIQUES AND RULES OF THUMB Comparing the IEEE and the IEC Flicker Curves Figure 7 is drawn from a paper written by the IEEE Flicker Task Force and compares two flicker curves. The vertical axis is the percentage of voltage variation from 0.1% to 10%. The bottom axis is the frequency of voltage changes. The top curve is the IEC borderline-of-irritation curve for 120 volts. The bottom curve is the borderlineof-irritation curve from IEEE 141. Flicker above these curves will begin to cause customer complaints. In general, the IEC Standard allows a slightly higher level of flicker for frequencies below 12 Hz, but lower levels above 12 Hz. Most experts agree that this IEC curve more accurately represents the typical customer s visual perceptions of annoying flicker. Present Evaluation and Measurement Techniques Historically, voltage flicker has been measured using rms meters, load duty cycle, and a flicker curve. If sudden rms voltage deviations occurred with specified frequencies exceeding values found in flicker curves, the system was said to have experienced voltage flicker. 86

87 Because of the different types of variation in voltage that can occur, it is very difficult to use the IEEE flicker curves to assess the level of flicker. Each type of voltage change can contribute in its own way to the overall flicker seen by customers. Of course, flicker measurements can always be taken after the DR has been installed, but if a problem is discovered, the DR unit would have to be shut off or limited until a distribution system reinforcement could be installed. This approach is not good practice. Figure 7. Flicker Curves Distribution Planning Requires a Prediction of DR Flicker Contributions The distribution system planner needs a method to determine if a proposed DR installation will cause objectionable flicker on the distribution system. No such procedure exists in the U.S. using the IEEE flicker curves. Furthermore, the IEEE flicker curves are not universally used in the U.S. Typically, utilities either use the IEEE curves, some variant of the curves, or curves developed years ago in their own utility. The IEC procedures for calculating flicker levels are more universally accepted overseas. Since Denmark has had literally thousands of wind turbines on its distribution system for many years, it has developed methods for predicting when wind turbines might cause objectionable flicker to nearby customers. The IEC has very comprehensive standards for assessing flicker levels on Area EPSs. These standards take into account complex disturbances and multiple sources. For example, IEC provides very detailed explanation and calculation methods for determining if any type of voltage change can cause objectionable flicker. All major wind turbine manufacturers publish data that can be used with this IEC standard to predict flicker levels at any location on the electric grid. 87