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- Herausgeber: John Wiley & Sons
- Kategorie: Wissenschaft und neue Technologien
- Sprache: Englisch
With emphasis on power system protection from the network operator perspective, this classic textbook explains the fundamentals of relaying and power system phenomena including stability, protection and reliability. The fourth edition brings coverage up-to-date with important advancements in protective relaying due to significant changes in the conventional electric power system that will integrate renewable forms of energy and, in some countries, adoption of the Smart Grid initiative.
New features of the Fourth Edition include:
- an entirely new chapter on protection considerations for renewable energy sources, looking at grid interconnection techniques, codes, protection considerations and practices.
- new concepts in power system protection such as Wide Area Measurement Systems (WAMS) and system integrity protection (SIPS) -how to use WAMS for protection, and SIPS and control with WAMS.
- phasor measurement units (PMU), transmission line current differential, high voltage dead tank circuit breakers, and relays for multi-terminal lines.
- revisions to the Bus Protection Guide IEEE C37.234 (2009) and to the sections on additional protective requirements and restoration.
Used by universities and industry courses throughout the world, Power System Relaying is an essential text for graduate students in electric power engineering and a reference for practising relay and protection engineers who want to be kept up to date with the latest advances in the industry.
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Table of Contents
Title Page
Copyright
Preface to the Fourth Edition
Preface to the Third Edition
Preface to the Second Edition
Preface to the First Edition
Chapter 1: Introduction to Protective Relaying
1.1 What is Relaying?
1.2 Power System Structural Considerations
1.3 Power System Bus Configurations
1.4 The Nature of Relaying
1.5 Elements of a Protection System
1.6 International Practices
1.7 Summary
Problems
References
Chapter 2: Relay Operating Principles
2.1 Introduction
2.2 Detection of Faults
2.3 Relay Designs
2.4 Electromechanical Relays
2.5 Solid-State Relays
2.6 Computer Relays
2.7 Other Relay Design Considerations
2.8 Control Circuits: A Beginning
2.9 Summary
Problems
References
Chapter 3: Current and Voltage Transformers
3.1 Introduction
3.2 Steady-State Performance of Current Transformers
3.3 Transient Performance of Current Transformers
3.4 Special Connections of Current Transformers
3.5 Linear Couplers and Electronic Current Transformers
3.6 Voltage Transformers
3.7 Coupling Capacitor Voltage Transformers
3.8 Transient Performance of CCVTs
3.9 Electronic Voltage Transformers
3.10 Summary
Problems
References
Chapter 4: Nonpilot Overcurrent Protection of Transmission Lines
4.1 Introduction
4.2 Fuses, Sectionalizers, and Reclosers
4.3 Inverse, Time-Delay Overcurrent Relays
4.4 Instantaneous Overcurrent Relays
4.5 Directional Overcurrent Relays
4.6 Polarizing
4.7 Summary
Problems
References
Chapter 5: Nonpilot Distance Protection of Transmission Lines
5.1 Introduction
5.2 Stepped Distance Protection
5.3 – Diagram
5.4 Three-Phase Distance Relays
5.5 Distance Relay Types
5.6 Relay Operation with Zero Voltage
5.7 Polyphase Relays
5.8 Relays for Multiterminal Lines
5.9 Protection of Parallel Lines
5.10 Effect of Transmission Line Compensation Devices
5.11 Loadability of Relays
5.12 Summary
Problems
References
Chapter 6: Pilot Protection of Transmission Lines
6.1 Introduction
6.2 Communication Channels
6.3 Tripping Versus Blocking
6.4 Directional Comparison Blocking
6.5 Directional Comparison Unblocking
6.6 Underreaching Transfer Trip
6.7 Permissive Overreaching Transfer Trip
6.8 Permissive Underreaching Transfer Trip
6.9 Phase Comparison Relaying
6.10 Current Differential
6.11 Pilot Wire Relaying
6.12 Multiterminal Lines
6.13 The Smart Grid
6.14 Summary
Problems
References
Chapter 7: Rotating Machinery Protection
7.1 Introduction
7.2 Stator Faults
7.3 Rotor Faults
7.4 Unbalanced Currents
7.5 Overload
7.6 Overspeed
7.7 Abnormal Voltages and Frequencies
7.8 Loss of Excitation
7.9 Loss of Synchronism
7.10 Power Plant Auxiliary System
7.11 Winding Connections
7.12 Startup and Motoring
7.13 Inadvertent Energization
7.14 Torsional Vibration
7.15 Sequential Tripping
7.16 Summary
Problems
References
Chapter 8: Transformer Protection
8.1 Introduction
8.2 Overcurrent Protection
8.3 Percentage Differential Protection
8.4 Causes of False Differential Currents
8.5 Supervised Differential Relays
8.6 Three-Phase Transformer Protection
8.7 Volts-per-Hertz Protection
8.8 Nonelectrical Protection
8.9 Protection Systems for Transformers
8.10 Summary
Problems
References
Chapter 9: Bus, Reactor, and Capacitor Protection
9.1 Introduction to Bus Protection
9.2 Overcurrent Relays
9.3 Percentage Differential Relays
9.4 High-Impedance Voltage Relays
9.5 Moderately High-Impedance Relay
9.6 Linear Couplers
9.7 Directional Comparison
9.8 Partial Differential Protection
9.9 Introduction to Shunt Reactor Protection
9.10 Dry-Type Reactors
9.11 Oil-Immersed Reactors
9.12 Introduction to Shunt Capacitor Bank Protection
9.13 Static Var Compensator Protection
9.14 Static Compensator
9.15 Summary
Problems
References
Chapter 10: Power System Phenomena and Relaying Considerations
10.1 Introduction
10.2 Power System Stability
10.3 Steady-State Stability
10.4 Transient Stability
10.5 Voltage Stability
10.6 Dynamics of System Frequency
10.7 Series Capacitors and Reactors
10.8 Independent Power Producers
10.9 Islanding
10.10 Blackouts and Restoration
10.11 Summary
Problems
References
Chapter 11: Relaying for System Performance
11.1 Introduction
11.2 System Integrity Protection Schemes
11.3 Underfrequency Load Shedding
11.4 Undervoltage Load Shedding
11.5 Out-of-Step Relaying
11.6 Loss-of-Field Relaying
11.7 Adaptive relaying
11.8 Hidden Failures
11.9 Distance Relay Polarizing
11.10 Summary
Problems
References
Chapter 12: Switching Schemes and Procedures
12.1 Introduction
12.2 Relay Testing
12.3 Computer Programs for Relay Setting
12.4 Breaker Failure Relaying
12.5 Reclosing
12.6 Single-Phase Operation
12.7 Summary
References
Chapter 13: Monitoring Performance of Power Systems
13.1 Introduction
13.2 Oscillograph Analysis
13.3 Synchronized Sampling
13.4 Fault Location
13.5 Alarms
13.6 COMTRADE and SYNCHROPHASOR Standards
13.7 Summary
Problems
References
Chapter 14: Improved Protection with Wide Area Measurements (WAMS)
14.1 Introduction
14.2 WAMS Organization
14.3 Using WAMS for Protection
14.4 Supervising Backup Protection
14.5 Impedance Excursions into Relay Settings
14.6 Stability-Related Protections
14.7 SIPS and Control with WAMS
14.8 Summary and Future Prospects
References
Chapter 15: Protection Considerations for Renewable Resources
15.1 Introduction
15.2 Types of Renewable Generation
15.3 Connections to the Power Grid and Protection Considerations
15.4 Grid Codes for Connection of Renewables
15.5 Summary
References
Appendix A: IEEE Device Numbers and Functions
Appendix B: Symmetrical Components
B.1 Definitions
B.2 Identities
B.3 Sequence Impedances
B.4 Representations of Faults
References
Appendix C: Power Equipment Parameters
C.1 Typical Constants of Three-Phase Synchronous Machines
C.2 Typical Constants of Three-Phase Transformers
C.3 Typical Constants of Three-Phase Transmission Lines
References
Appendix D: Inverse Time Overcurrent Relay Characteristics
Type CO-6 (Courtesy of ABB Power T&D Company)
Type CO-11 (Courtesy of ABB Power T&D Company)
Type IAC-53 and IAC-54 (Courtesy of General Electric Company)
Index
This edition first published 2014
© 2014 John Wiley and Sons Ltd
Previous Edition
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Library of Congress Cataloging-in-Publication Data
Horowitz, Stanley H., 1925—
Power system relaying / Stanley H. Horowitz, Arun G. Phadke, James K. Niemira.— Fourth edition.
pages cm
Includes bibliographical references and index.
ISBN 978-1-118-66200-7 (hardback)
1. Protective relays. 2. Electric power systems— Protection. I. Phadke, Arun G. II. Niemira, James K.
III. Title.
TK2861.H67 2013
621.31′7— dc23
2013022871
Preface to the Fourth Edition
The third edition of our book, issued with corrections in 2009, continued to be used as a text book in several universities around the world. The success of our book and the positive feedback we continue to receive from our colleagues is gratifying. Since that time, we have had a few other typos and errors pointed out to us, which we are correcting in this fourth edition.
However, the major change in this edition is the inclusion of two new chapters. Chapter 14 gives an account of the application of Wide Area Measurements (WAMS) in the field of protection. WAMS technology using Global Positioning Satellite (GPS) satellites for synchronized measurements of power system voltages and currents is finding many applications in monitoring, protection, and control of power systems. Field installations of such systems are taking place in most countries around the world, and we believe that an account of what is possible with this technology, as discussed in Chapter 14, is timely and will give the student using this edition an appreciation of these exciting changes taking place in the field of power system protection. Chapter 14 also provides a list of relevant references for the reader who is interested in pursuing this technology in depth.
Another major development in the field of power system protection on the advent of renewable resources for generation of electricity is reported in the new Chapter 15. This also is a technology that is being deployed in most modern power systems around the world. As the penetration of renewable resources in the mix of generation increases, many challenges are faced by power system engineers. In particular, how to handle the interconnection of these resources with proper protection systems is a very important subject. We are very fortunate to have a distinguished expert, James Niemira of S&C Electric Company, Chicago, contributor of this chapter to our book. The chapter also includes a list of references for the interested reader. We believe this chapter will answer many of the questions asked by our students.
Finally, we would welcome continued correspondence from our readers who give us valuable comments about what they like in the book, and what other material should be included in future editions. We wish to thank all the readers who let us have their views, and assure them that we greatly value their inputs.
April 24, 2013S.H. HorowitzColumbusA.G. PhadkeBlacksburg
Preface to the Third Edition
The second edition of our book, issued in 1995, continued to receive favorable response from our colleagues and is being used as a textbook by universities and in industry courses worldwide. The first edition presented the fundamental theory of protective relaying as applied to individual system components. This concept was continued throughout the second edition. In addition, the second edition added material on generating plant auxiliary systems, distribution protection concepts, and the application of electronic inductive and capacitive devices to regulate system voltage. The second edition also presented additional material covering monitoring power system performance and fault analysis. The application of synchronized sampling and advanced timing technologies using the Global Positioning Satellite (GPS) system was explained.
This third edition takes the problem of power system protection an additional step forward by introducing power system phenomena which influence protective relays and for which protective schemes, applications, and settings must be considered and implemented. The consideration of power system stability and the associated application of relays to mitigate its harmful effects are presented in detail. New concepts such as undervoltage load shedding, adaptive relaying, hidden failures, and the Internet standard COMTRADE and its uses are presented. The history of notable blackouts, particularly as affected by relays, is presented to enable students to appreciate the impact that protection systems have on the overall system reliability.
As mentioned previously, we are gratified with the response that the first and second editions have received as both a textbook and a reference book. Recent changes in the electric power industry have resulted in power system protection assuming a vital role in maintaining power system reliability and security. It is the authors' hope that the additions embodied in this third edition will enable all electric power system engineers, designers, and operators to better integrate these concepts and to understand the complex interaction of relaying and system performance.
S. H. HorowitzColumbusA. G. PhadkeBlacksburg
Preface to the Second Edition
The first edition, issued in 1992, has been used as a textbook by universities and in industry courses throughout the world. Although not intended as a reference book for practicing protection engineers, it has been widely used as one. As a result of this experience and of the dialog between the authors and teachers, students and engineers using the first edition, it was decided to issue a second edition, incorporating material which would be of significant value. The theory and fundamentals of relaying constituted the major part of the first edition and it remains so in the second edition. In addition, the second edition includes concepts and practices that add another dimension to the study of power system protection.
A chapter has been added covering monitoring power system performance and fault analysis. Examples of oscillographic records introduce the student to the means by which disturbances can be analyzed and corrective action and maintenance initiated. The application of synchronized sampling for technologies such as the GPS satellite is explained. This chapter extends the basic performance of protective relays to include typical power system operating problems and analysis. A section covering power plant auxiliary systems has been added to the chapter on the protection of rotating machinery. Distribution protection concepts have been expanded to bridge the gap between the protection of distribution and transmission systems. The emerging technology of static var compensators to provide inductive and capacitive elements to regulate system voltage has been added to the chapter on bus protection. The subject index has been significantly revised to facilitate reference from both the equipment and the operating perspective.
We are gratified with the response that the first edition has received as a text and reference book. The authors thank the instructors and students whose comments generated many of the ideas included in this second edition. We hope that the book will continue to be beneficial and of interest to students, teachers, and power system engineers.
S. H. HorowitzColumbusA. G. PhadkeBlacksburg
Preface to the First Edition
This book is primarily intended to be a textbook on protection, suitable for final year undergraduate students wishing to specialize in the field of electric power engineering. It is assumed that the student is familiar with techniques of power system analysis, such as three-phase systems, symmetrical components, short-circuit calculations, load flow, and transients in power systems. The reader is also assumed to be familiar with calculus, matrix algebra, and Laplace and Fourier transforms, and Fourier series. Typically, this is the background of a student who is taking power option courses at a US university. The book is also suitable for a first year graduate course in power system engineering.
An important part of the book is the large number of examples and problems included in each chapter. Some of the problems are decidedly difficult. However, no problems are unrealistic, and, difficult or not, our aim is always to educate the reader, help the student realize that many of the problems that will be faced in practice will require careful analysis, consideration, and some approximations.
The book is not a reference book, although we hope it may be of interest to practicing relay engineers as well. We offer derivations of several important results, which are normally taken for granted in many relaying textbooks. It is our belief that by studying the theory behind these results, students may gain an insight into the phenomena involved, and point themselves in the direction of newer solutions which may not have been considered. The emphasis throughout the book is on giving the reader an understanding of power system protection principles. The numerous practical details of relay system design are covered to a limited extent only, as required to support the underlying theory. Subjects which are the province of the specialist are left out. The engineer interested in such detail should consult the many excellent reference works on the subject, and the technical literature of various relay manufacturers.
The authors owe a great deal to published books and papers on the subject of power system protection. These works are referred to at appropriate places in the text. We would like to single out the book by the late C. R. Mason, The Art and Science of Protective Relaying, for special praise. We, and many generations of power engineers, have learned relaying from this book. It is a model of clarity, and its treatment of the protection practices of that day is outstanding.
Our training as relay engineers has been enhanced by our association with the Power System Relaying Committee of the Institute of Electrical and Electronics Engineers (IEEE), and the Study Committee SC34 of the Conférence Internationale des Grands Réseaux Electriques des Hautes Tensions (CIGRE). Much of our technical work has been under the auspicesof these organizations. The activities of the two organizations, and our interaction with the international relaying community, have resulted in an appreciation of the differing practices throughout the world. We have tried to introduce an awareness of these differences in this book. Our long association with the American Electric Power (AEP) Service Corporation has helped sustain our interest in electric power engineering, and particularly in the field of protective relaying. We have learned much from our friends in AEP. AEP has a well-deserved reputation for pioneering in many phases of electric power engineering, and particularly in power system protection. We are fortunate to be a part of many important relaying research and development efforts conducted at AEP. We have tried to inject this experience of fundamental theory and practical implementation throughout this text. Our colleagues in the educational community have also been instrumental in getting us started on this project, and we hope they find this book useful. No doubt some errors remain, and we will be grateful if readers bring these errors to our attention.
S. H. HorowitzColumbusA. G. PhadkeBlacksburg
Chapter 1
Introduction to Protective Relaying
1.1 What is Relaying?
In order to understand the function of protective relaying systems, one must be familiar with the nature and the modes of operation of an electric power system. Electric energy is one of the fundamental resources of modern industrial society. Electric power is available to the user instantly, at the correct voltage and frequency, and exactly in the amount that is needed. This remarkable performance is achieved through careful planning, design, installation, and operation of a very complex network of generators, transformers, and transmission and distribution lines. To the user of electricity, the power system appears to be in a steady state: imperturbable, constant, and infinite in capacity. Yet, the power system is subject to constant disturbances created by random load changes, by faults created by natural causes, and sometimes as a result of equipment or operator failure. In spite of these constant perturbations, the power system maintains its quasi-steady state because of two basic factors: the large size of the power system in relation to the size of individual loads or generators and correct and quick remedial action taken by the protective relaying equipment.
Relaying is the branch of electric power engineering concerned with the principles of design and operation of equipment (called “relays” or “protective relays”) that detects abnormal power system conditions and initiates corrective action as quickly as possible in order to return the power system to its normal state. The quickness of response is an essential element of protective relaying systems—response times of the order of a few milliseconds are often required. Consequently, human intervention in the protection system operation is not possible. The response must be automatic, quick, and should cause a minimum amount of disruption to the power system. As the principles of protective relaying are developed in this book, the reader will perceive that the entire subject is governed by these general requirements: correct diagnosis of trouble, quickness of response, and minimum disturbance to the power system. To accomplish these goals, we must examine all possible types of fault or abnormal conditions that may occur in the power system. We must analyze the required response to each of these events and design protective equipment that will provide such a response. We must further examine the possibility that protective relaying equipment itself may fail to operate correctly, and provide for a backup protective function. It should be clear that extensive and sophisticated equipment is needed to accomplish these tasks.
1.2 Power System Structural Considerations
1.2.1 Multilayered Structure of Power Systems
A power system is made up of interconnected equipment that can be said to belong to one of the three layers from the point of view of the functions performed. This is illustrated in Figure 1.1.
Figure 1.1 Three-layered structure of power systems
At the basic level is the power apparatus that generates, transforms, and distributes the electric power to the loads. Next, there is the layer of control equipment. This equipment helps to maintain the power system at its normal voltage and frequency, generates sufficient power to meet the load, and maintains optimum economy and security in the interconnected network. The control equipment is organized in a hierarchy of its own, consisting of local and central control functions. Finally, there is the protection equipment layer. The response time of protection functions is generally faster than that of the control functions. Protection acts to open- and closed-circuit breakers (CBs), thus changing the structure of the power system, whereas the control functions act continuously to adjust system variables, such as the voltages, currents, and power flow on the network. Oftentimes, the distinction between a control function and a protection function becomes blurred. This is becoming even more of a problem with the recent advent of computer-based protection systems in substations. For our purposes, we may arbitrarily define all functions that lead to operation of power switches or CBs to be the tasks of protective relays, while all actions that change the operating state (voltages, currents, and power flows) of the power system without changing its structure to be the domain of control functions.
1.2.2 Neutral Grounding of Power Systems
Neutrals of power transformers and generators can be grounded in a variety of ways, depending upon the needs of the affected portion of the power system. As grounding practices affect fault current levels, they have a direct bearing upon relay system designs. In this section, we examine the types of grounding system in use in modern power systems and the reasons for each of the grounding choices. Influence of grounding practices on relay system design will be considered at appropriate places throughout the remainder of this book.
It is obvious that there is no ground fault current in a truly ungrounded system. This is the main reason for operating the power system ungrounded. As the vast majority of faults on a power system are ground faults, service interruptions due to faults on an ungrounded system are greatly reduced. However, as the number of transmission lines connected to the power system grows, the capacitive coupling of the feeder conductors with ground provides a path to ground, and a ground fault on such a system produces a capacitive fault current. This is illustrated in Figure 1.2a. The coupling capacitors to ground provide the return path for the fault current. The interphase capacitors 1/3 play no role in this fault. When the size of the capacitance becomes sufficiently large, the capacitive ground fault current becomes self-sustaining, and does not clear by itself. It then becomes necessary to open the CBs to clear the fault, and the relaying problem becomes one of detecting such low magnitudes of fault currents. In order to produce a sufficient fault current, a resistance is introduced between the neutral and the ground—inside the box shown by a dotted line in Figure 1.2a. One of the design considerations in selecting the grounding resistance is the thermal capacity of the resistance to handle a sustained ground fault.
Figure 1.2 Neutral grounding impedance. (a) System diagram and (b) phasor diagram showing neutral shift on ground fault
Ungrounded systems produce good service continuity, but are subjected to high overvoltages on the unfaulted phases when a ground fault occurs. It is clear from the phasor diagram of Figure 1.2b that when a ground fault occurs on phase a, the steady-state voltages of phases b and c become times their normal value. Transient overvoltages become correspondingly higher. This places additional stress on the insulation of all connected equipments. As the insulation level of lower voltage systems is primarily influenced by lightning-induced phenomena, it is possible to accept the fault-induced overvoltages as they are lower than the lightning-induced overvoltages. However, as the system voltages increase to higher than about 100 kV, the fault-induced overvoltages begin to assume a critical role in insulation design, especially of power transformers. At high voltages, it is therefore common to use solidly grounded neutrals (more precisely “effectively grounded”). Such systems have high ground fault currents, and each ground fault must be cleared by CBs. As high-voltage systems are generally heavily interconnected, with several alternative paths to load centers, operation of CBs for ground faults does not lead to a reduced service continuity.
In certain heavily meshed systems, particularly at 69 and 138 kV, the ground fault current could become excessive because of very low zero-sequence impedance at some buses. If ground fault current is beyond the capability of the CBs, it becomes necessary to insert an inductance in the neutral in order to limit the ground fault current to a safe value. As the network Thévenin impedance is primarily inductive, a neutral inductance is much more effective (than resistance) in reducing the fault current. Also, there is no significant power loss in the neutral reactor during ground faults.
In several lower voltage networks, a very effective alternative to ungrounded operation can be found if the capacitive fault current causes ground faults to be self-sustaining. This is the use of a Petersen coil, also known as the ground fault neutralizer (GFN). Consider the symmetrical component representation of a ground fault on a power system that is grounded through a grounding reactance of (Figure 1.3). If is made equal to (the zero-sequence capacitive reactance of the connected network), the parallel resonant circuit formed by these two elements creates an open circuit in the fault path, and the ground fault current is once again zero. No CB operation is necessary upon the occurrence of such a fault, and service reliability is essentially the same as that of a truly ungrounded system. The overvoltages produced on the unfaulted conductors are comparable to those of ungrounded systems, and consequently GFN use is limited to system voltages below 100 kV. In practice, GFNs must be tuned to the entire connected zero-sequence capacitance on the network, and thus if some lines are out of service, the GFN reactance must be adjusted accordingly. Petersen coils have found much greater use in several European countries than in the United States.
Figure 1.3 Symmetrical component representation for ground fault with grounding reactor
1.3 Power System Bus Configurations
The manner in which the power apparatus is connected together in substations and switching stations, and the general layout of the power network, has a profound influence on protective relaying. It is therefore necessary to review the alternatives and the underlying reasons for selecting a particular configuration. A radial system is a single-source arrangement with multiple loads, and is generally associated with a distribution system (defined as a system operating at voltages below 100 kV) or an industrial complex (Figure 1.4).
Figure 1.4 Radial power system
Such a system is most economical to build; but from the reliability point of view, the loss of the single source will result in the loss of service to all of the users. Opening main line reclosers or other sectionalizing devices for faults on the line sections will disconnect the loads downstream of the switching device. From the protection point of view, a radial system presents a less complex problem. The fault current can only flow in one direction, that is, away from the source and toward the fault. Since radial systems are generally electrically remote from generators, the fault current does not vary much with changes in generation capacity.
A network has multiple sources and multiple loops between the sources and the loads. Subtransmission and transmission systems (generally defined as systems operating at voltages of 100–200 kV and above) are network systems (Figure 1.5).
Figure 1.5 Network power system
In a network, the number of lines and their interconnections provide more flexibility in maintaining service to customers, and the impact of the loss of a single generator or transmission line on service reliability is minimal. Since sources of power exist on all sides of a fault, fault current contributions from each direction must be considered in designing the protection system. In addition, the magnitude of the fault current varies greatly with changes in system configuration and installed generation capacity. The situation is dramatically increased with the introduction of the smart grid discussed in Section 6.3.
Substations are designed for reliability of service and flexibility in operation and to allow for equipment maintenance with a minimum interruption of service. The most common bus arrangements in a substation are (a) single bus, singlebreaker, (b) two buses, single breaker, (c) two buses, two breakers, (d) ring bus, and (e) breaker-and-a-half. These bus arrangements are illustrated in Figure 1.7.
Figure 1.7 Substation bus arrangements: (a) single bus, single breaker; (b) two buses, one breaker; (c) two buses, two breakers; (d) ring bus; and (e) breaker-and-a-half
A single-bus, single-breaker arrangement, shown in Figure 1.7a, is the simplest, and probably the least expensive to build. However, it is also the least flexible. To do maintenance work on the bus, a breaker, or a disconnect switch, de-energizing the associated transmission lines is necessary. A two-bus, single-breaker arrangement, shown in Figure 1.7b, allows the breakers to be maintained without de-energizing the associated line. For system flexibility, and particularly to prevent a bus fault from splitting the system too drastically, some of the lines are connected to bus 1 and some to bus 2 (the transfer bus). When maintaining a breaker, all of the lines that are normally connected to bus 2 are transferred to bus 1, the breaker to be maintained is bypassed by transferring its line to bus 2 and the bus tie breaker becomes the line breaker. Only one breaker can be maintained at a time. Note that the protective relaying associated with the buses and the line whose breaker is being maintained must also be reconnected to accommodate this new configuration. This will be covered in greater detail as we discuss the specific protection schemes.
A two-bus, two-breaker arrangement is shown in Figure 1.7c. This allows any bus or breaker to be removed from service, and the lines can be kept in service through the companion bus or breaker. A line fault requires two breakers to trip to clear a fault. A bus fault must trip all of the breakers on the faulted bus, but does not affect the other bus or any of the lines. This station arrangement provides the greatest flexibility for system maintenance and operation; however, this is at a considerable expense: the total number of breakers in a station equals twice the number of the lines. A ring bus arrangement shown in Figure 1.7d achieves similar flexibility while the ring is intact. When one breaker is being maintained, the ring is broken, and the remaining bus arrangement is no longer as flexible. Finally, the breaker-and-a-half scheme, shown in Figure 1.7e, is most commonly used in most extra high-voltage (EHV) transmission substations. It provides for the same flexibility as the two-bus, two-breaker arrangement at the cost of just one-and-a-half breakers per line on an average. This scheme also allows for future expansions in an orderly fashion.1 In recent years, however, a new concept, popularly and commonly described as the “smart grid,” has entered the lexicon of bus configuration, introducing ideas and practices that are changing the fundamental design, operation, and performance of the “distribution” system. The fundamental basis of the “smart grid” transforms the previously held definition of a “distribution system,” that is, a single-source, radial system to a transmission-like configuration with multiple generating sites, communication, operating, and protective equipment similar to high-voltage and extra-high-voltage transmission.
The impact of system and bus configurations on relaying practices will become clear in the chapters that follow.
1.4 The Nature of Relaying
We will now discuss certain attributes of relays that are inherent to the process of relaying, and can be discussed without reference to a particular relay. The function of protective relaying is to promptly remove from service any element of the power system that starts to operate in an abnormal manner. In general, relays do not prevent damage to equipment: they operate after some detectable damage has already occurred. Their purpose is to limit, to the extent possible, further damage to equipment, to minimize danger to people, to reduce stress on other equipments and, above all, to remove the faulted equipment from the power system as quickly as possible so that the integrity and stability of the remaining system are maintained. The control aspect of relaying systems also helps to return the power system to an acceptable configuration as soon as possible so that service to customers can be restored.
1.4.1 Reliability, Dependability, and Security
Reliability is generally understood to measure the degree of certainty that a piece of equipment will perform as intended. Relays, in contrast with most other equipments, have two alternative ways in which they can be unreliable: they may fail to operate when they are expected to, or they may operate when they are not expected to. This leads to a two-pronged definition of reliability of relaying systems: a reliable relaying system must be dependable and secure [1]. Dependability is defined as the measure of the certainty that the relays will operate correctly for all the faults for which they are designed to operate. Security is defined as the measure of the certainty that the relays will not operate incorrectly for any fault.
Most protection systems are designed for high dependability. In other words, a fault is always cleared by some relay. As a relaying system becomes dependable, its tendency to become less secure increases. Thus, in present-day relaying system designs, there is a bias toward making them more dependable at the expense of some degree of security. Consequently, a majority of relay system misoperations are found to be the result of unwanted trips caused by insecure relay operations. This design philosophy correctly reflects the fact that a power system provides many alternative paths for power to flow from generators to loads. Loss of a power system element due to an unnecessary trip is therefore less objectionable than the presence of a sustained fault. This philosophy is no longer appropriate when the number of alternatives for power transfer is limited, as in a radial power system, or in a power system in an emergency operating state.
1.4.2 Selectivity of Relays and Zones of Protection
The property of security of relays, that is, the requirement that they not operate for faults for which they are not designed to operate, is defined in terms of regions of a power system—called zones of protection—for which a given relay or protective system is responsible. The relay will be considered to be secure if it responds only to faults within its zone of protection. Relays usually have inputs from several current transformers (CTs), and the zone of protection is bounded by these CTs. The CTs provide a window through which the associated relays “see” the power system inside the zone of protection. While the CTs provide the ability to detect a fault inside the zone of protection, the CBs provide the ability to isolate the fault by disconnecting all of the power equipment inside the zone. Thus, a zone boundary is usually defined by a CT and a CB. When the CT is part of the CB, it becomes a natural zone boundary. When the CT is not an integral part of the CB, special attention must be paid to the fault detection and fault interruption logic. The CT still defines the zone of protection, but communication channels must be used to implement the tripping function from appropriate remote locations where the CBs may be located. We return to this point later in Section 1.5 where CBs are discussed.
In order to cover all power equipments by protection systems, the zones of protection must meet the following requirements.
All power system elements must be encompassed by at least one zone. Good relaying practice is to be sure that the more important elements are included in at least two zones.
Zones of protection must overlap to prevent any system element from being unprotected. Without such an overlap, the boundary between two nonoverlapping zones may go unprotected. The region of overlap must be finite but small, so that the likelihood of a fault occurring inside the region of overlap is minimized. Such faults will cause the protection belonging to both zones to operate, thus removing a larger segment of the power system from service.
A zone of protection may be closed or open. When the zone is closed, all power apparatus entering the zone is monitored at the entry points of the zone. Such a zone of protection is also known as “differential,” “unit,” or “absolutely selective.” Conversely, if the zone of protection is not unambiguously defined by the CTs, that is, the limit of the zone varies with the fault current, the zone is said to be “nonunit,” “unrestricted,” or “relatively selective.” There is a certain degree of uncertainty about the location of the boundary of an open zone of protection. Generally, the nonpilot protection of transmission lines employs open zones of protection.
1.4.3 Relay Speed
It is, of course, desirable to remove a fault from the power system as quickly as possible. However, the relay must make its decision based upon voltage and current waveforms that are severely distorted due to transient phenomena which must follow the occurrence of a fault. The relay must separate the meaningful and significant information contained in these waveforms upon which a secure relaying decision must be based. These considerations demand that the relay takes a certain amount of time to arrive at a decision with the necessary degree of certainty. The relationship between the relay response time and its degree of certainty is an inverse one [2], and this inverse-time operating characteristic of relays is one of the most basic properties of all protection systems.
Although the operating time of relays often varies between wide limits, relays are generally classified by their speed of operation as follows [3].
1.4.4 Primary and Backup Protection
A protection system may fail to operate and, as a result, fail to clear a fault. It is thus essential that provision be made to clear the fault by some alternative protection system or systems [4, 5]. These alternative protection system(s) are referred to as duplicate, backup, or breaker failure protection systems. The main protection system for a given zone of protection is called the primary protection system. It operates in the fastest time possible and removes the least amount of equipment from service. On EHV systems, it is common to use duplicate primary protection systems in case an element in one primary protection chain may fail to operate. This duplication is therefore intended to cover the failure of the relays themselves. One may use relays from a different manufacturer, or relays based upon a different principle of operation, so that some inadequacy in the design of one of the primary relays is not repeated in the duplicate system. The operating times of the primary and the duplicate systems are the same.
It is not always practical to duplicate every element of the protection chain—on high-voltage and EHV systems, the transducers or the CBs are very expensive, andthe cost of duplicate equipment may not be justified. On lower voltage systems, even the relays themselves may not be duplicated. In such situations, only backup relaying is used. Backup relays are generally slower than the primary relays and remove more system elements than may be necessary to clear a fault. Backup relaying may be installed locally, that is, in the same substation as the primary protection, or remotely. Remote backup relays are completely independent of the relays, transducers, batteries, and CBs of the protection system they are backing up. There are no common failures that can affect both sets of relays. However, complex system configurations may significantly affect the ability of remote backup relays to “see” all the faults for which backup is desired. In addition, remote backup relays may remove more loads in the system than can be allowed. Local backup relaying does not suffer from these deficiencies, but it does use common elements such as the transducers, batteries, and CBs, and can thus fail to operate for the same reasons as the primary protection.
Breaker failure relays are a subset of local backup relaying that is provided specifically to cover a failure of the CB. This can be accomplished in a variety of ways. The most common, and simplest, breaker failure relay system consists of a separate timer that is energized whenever the breaker trip coil is energized and is de-energized when the fault current through the breaker disappears. If the fault current persists for longer than the timer setting, a trip signal is given to all local and remote breakers that are required to clear the fault. Occasionally, a separate set of relays is installed to provide this breaker failure protection, in which case it uses independent transducers and batteries. (Also see Chapter 12 (Section 12.4).)
These ideas are illustrated by the following example, and will be further examined when specific relaying systems are considered in detail later.
1.4.5 Single- and Three-Phase Tripping and Reclosing
The prevailing practice in the United States is to trip all three phases of the faulted power system element for all types of fault. In several European and Asian countries, it is a common practice to trip only the faulted phase for a phase-to-ground fault, and to trip all three phases for all multiphase faults on transmission lines. These differences in the tripping practice are the result of several fundamental differences in the design and operation of power systems, as discussed in Section 1.6.
As a large proportion of faults on a power system are of a temporary nature, the power system can be returned to its prefault state if the tripped CBs are reclosed as soon as possible. Reclosing can be manual. That is, it is initiated by an operator working from the switching device itself, from a control panel in the substation control house or from a remote system control center through a supervisory control and data acquisition (SCADA) system. Clearly, manual reclosing is too slow for the purpose of restoring the power system to its prefault state when the system is in danger of becoming unstable. Automatic reclosing of CBs is initiated by dedicated relays for each switching device, or it may be controlled from a substation or central reclosing computer. All reclosing operations should be supervised (i.e., controlled) by appropriate interlocks to prevent an unsafe, damaging, or undesirable reclosing operation. Some of the common interlocks for reclosing are thefollowing.
These interlocks can be used either in the manual or in the automatic mode. It is the practice of some utilities, however, not to inhibit the manual reclose operation of CBs, on the assumption that the operator will make the necessary checks before reclosing the CB. In extreme situations, sometimes the only way to restore a power system is through operator intervention, and automatic interlocks may prevent or delay the restoration operation. On the other hand, if left to the operator during manual operation, there is the possibility that the operator may not make the necessary checks before reclosing.
Automatic reclosing can be high speed, or it may be delayed. The term high speed generally implies reclosing in times shorter than a second. Many utilities may initiate high-speed reclosing for some types of fault (such as ground faults), and not for others. Delayed reclosing usually operates in several seconds or even in minutes. The timing for the delayed reclosing is determined by specific conditions for which the delay is introduced.
1.5 Elements of a Protection System
Although, in common usage, a protection system may mean only the relays, the actual protection system consists of many other subsystems that contribute to the detection and removal of faults. As shown in Figure 1.11, the major subsystems of the protection system are the transducers, relays, battery, and CBs. The transducers, that is, the current and voltage transformers, constitute a major component of the protection system, and are considered in detail in Chapter 3. Relays are the logic elements that initiate the tripping and closing operations, and we will, of course, discuss relays and their performance in the rest of this book.
Figure 1.11 Elements of a protection system
1.5.1 Battery and DC Supply
Since the primary function of a protection system is to remove a fault, the ability to trip a CB through a relay must not be compromised during a fault, when the AC voltage available in the substation may not be of sufficient magnitude. For example, a close-in three-phase fault can result in zero AC voltage at the substation AC outlets. Tripping power, as well as the power required by the relays, cannot therefore be obtained from the AC system, and is usually provided by the station battery.
The battery is permanently connected through a charger to the station AC service, and normally, during steady-state conditions, it floats on the charger. The charger is of a sufficient volt–ampere capacity to provide all steady-state loads powered by the battery. Usually, the battery is also rated to maintain adequate DC power for 8–12 h following a station blackout. Although the battery is probably the most reliable piece of equipment in a station, in EHV stations, it is not uncommon to have duplicate batteries, each connected to its own charger and complement of relays. Electromechanical relays are known to produce severe transients on the battery leads during operation, which may cause misoperation of other sensitive relays in the substation, or may even damage them. It is therefore common practice, insofar as practical, to separate electromechanical and solid-state equipment by connecting them to different batteries.
1.5.2 Circuit Breakers
It would take too much space to describe various CB designs and their operating principles here. Indeed, several excellent references do just that [6, 7]. Instead, we will describe a few salient features about CBs, which are particularly significant from the point of view of relaying.
Knowledge of CB operation and performance is essential to an understanding of protective relaying. It is the coordinated action of both that results in successful fault clearing. The CB isolates the fault by interrupting the current at or near a current zero. At the present time, an EHV CB can interrupt fault currents of the order of A at system voltages up to 800 kV. It can do this as quickly as the first current zero after the initiation of a fault, although it more often interrupts at the second or third current zero. As the CB contacts move to interrupt the fault current, there is a race between the establishment of the dielectric strength of the interrupting medium and the rate at which the recovery voltage reappears across the breaker contacts. If the recovery voltage wins the race, the arc reignites, and the breaker must wait for the next current zero when the contacts are farther apart.
CBs of several designs can be found in a power system. One of the first designs, and one that is still in common use, incorporates a tank of oil in which the breaker contacts and operating mechanism are immersed. The oil serves as the insulation between the tank, which is at the ground potential, and the main contacts, which are at line potential. The oil also acts as the cooling medium to quench the arc when the contacts open to interrupt load or fault current. An oil CB rated for 138 kV service is shown in Figure 1.12.
Figure 1.12 A 138 kV oil circuit breaker
(Courtesy of Appalachian Power Company)
As transmission system voltages increased, it was not practical to build a tank large enough to provide the dielectric strength required in the interrupting chamber. In addition, better insulating materials, better arc quenching systems, and faster operating requirements resulted in a variety of CB characteristics: interrupting medium of oil, gas, air, or vacuum; insulating medium of oil, air, gas, or solid dielectric; and operating mechanisms using impulse coil, solenoid, spring–motor–pneumatic, or hydraulic. This broad selection of CB types and accompanying selection of ratings offers a high degree of flexibility. Each user has unique requirements and no design can be identified as the best or preferred design. One of the most important parameters to be considered in the specification of a CB is the interrupting medium. Oil does not require energy input from the operating mechanism to extinguish the arc. It gets that energy directly from the arc itself. Sulfur hexafluoride (), however, does require additional energy and must operate at high pressure or develop a blast of gas or air during the interruption phase. When environmental factors are considered, however, oil CBs produce high noise and ground shock during interruption, and for this reason may be rejected. They are also potential fire hazards or water table pollutants. CBs have essentially no emission, although the noise accompanying their operation may require special shielding and housing. And as with all engineering decisions, the cost of the CB must be an important consideration. At present, oil-filled CBs are the least expensive, and may be preferred if they are technically feasible, but this may change in the future. A typical CB is shown in Figure 1.13.
Figure 1.13 A 345 kV circuit breaker
(Courtesy of Appalachian Power Company)
An important design change in CBs with a significant impact on protection systems was the introduction of the “live-tank” design [8]. By placing the contact enclosure at the same potential as the contacts themselves, the need for the insulation between the two was eliminated. However, the earlier “dead-tank” (Figure 1.12) designs incorporated CTs in the bushing pocket of the tank, thereby providing CTs on both sides of the contacts. This arrangement provided a very nice mechanism for providing overlapping zones of protection on the two sides of the CBs. In the live-tank design, since the entire equipment is at line potential, it is not possible to incorporate CTs that have their secondary windings essentially at the ground potential. It then becomes necessary to design the CTs with their own insulating system, as separate free-standing devices, a design that is quite expensive. With free-standing CTs, it is no longer economical to provide CTs on both sides of a CB, and one must make do with only one CT on one side of the breaker. Of course, a free-standing CT has multiple secondaries, and protection zone overlap is achieved using secondary windings on opposite sides of the zones of protection. This is illustrated in Figure 1.14a. A live-tank air-blast CB and a free-standing CT rated at 800 kV are shown in Figure 1.15. The location of the primary winding and the protective assignments of the secondary winding of the CTs have a very significant implication for the protection being provided. The dead-tank CB usually associated with the medium and lower voltage transmission systems can provide CTs on either side of the interrupting mechanism and allow the protection to easily determine the appropriate tripping scheme. The live-tank, air-blast CB, associated with the higher voltages introduces, with the CTs located on only one side of the tripping mechanism forces, a more complex tripping logic. This is illustrated in Example 1.5 below. With advanced technology, however, using sulpha-hexafloride (SF6) for tripping and quenching the arc the interruption of EHV faults within a dead tank, that is, a tank whose enclosure can be grounded, is possible and therefore the ability to provide grounded CTs on either side of the interrupter removes the difficulty discussed above. This is illustrated in the following example.
Figure 1.14 Zone overlap with different types of CTs and circuit breakers
Figure 1.15 Live-tank air-blast circuit breaker and a current transformer for 800 kV
(Courtesy of Appalachian Power Company)
1.6 International Practices
Although the fundamental protective and relay operating concepts are similar throughout the world, there are very significant differences in their implementation. These differences arise through different traditions, operating philosophies, experiences, and national standards. Electric power utilities in many countries are organs of the national government. In such cases, the specific relaying schemes employed by these utilities may reflect the national interest. For example, their preference may be for relays manufactured inside their respective countries. In some developing countries, the choice of relays may be influenced by the availability of low-cost hard-currency loans or a transfer-of-technology agreement with the prospective vendor of the protective equipment. The evolutionary stage of the power system itself may have an influence on the protection philosophy. Thus, more mature power systems may opt for a more dependable protection system at the expense of some degradation of its (protection system's) security. A developing power network has fewer alternative paths for power transfer between the load and generation, and a highly secure protection system may be the desired objective. Long transmission lines are quite common in countries with large areas, for example, the United States or Russia. Many European and Asian countries have relatively short transmission lines, and, since the protection practice for long lines is significantly different from that for short lines, this may be reflected in the established relaying philosophy.
