Power system protection and communications 9781781831748, 9781523118786, 1523118784

Table of contents :
Cover......Page 1
Preface......Page 6
List of Acronyms......Page 8
Contents......Page 12
Recommended ProtectionTerminology......Page 16
Part A Power System Protection......Page 42
1.1 Introduction to Protective Relaying......Page 44
1.2 Power System Plant and Layout......Page 46
1.3 Switching Arrangements......Page 49
1.4 The Function of Protective Relaying......Page 54
1.5 Principles of Protective Relaying......Page 55
1.6 Unit and Non-Unit Schemes......Page 58
1.7 Zones of Protection......Page 60
1.8 Common Terminologies......Page 61
2.1 Faults on Power System......Page 63
2.2 Faults Type......Page 64
2.3 Fault Level Calculations......Page 65
2.4 Limiting Short-Circuit Levels......Page 67
2.5 Transient During A Balanced Fault......Page 68
2.6 Sequence Networks for Calculation of Unbalanced Faults......Page 71
2.7 Calculation of Voltages in the Network......Page 79
2.8 Short-Circuit Fault Calculations......Page 80
3.1 Introduction......Page 92
3.2 Power System Arrangements and Construction Features......Page 93
3.3 Earth Potential Rise......Page 98
3.4 Safety Considerations......Page 104
3.5 Application of Safety Criteria......Page 105
3.6 Demands on Protection Arising From Safety, Reliability and Interference Considerations......Page 106
3.7 Interference on Supplied and Other Systems......Page 116
4.2 Voltage Transformers......Page 121
4.3 Current Transformers (CTs)......Page 126
4.4 Guidance in Application of CTs......Page 133
5.1 Introduction......Page 142
5.2 Types and Construction......Page 143
5.3 System Analysis......Page 147
5.4 Settings of IDMT Relays......Page 148
5.5 Relay Discrimination......Page 150
5.6 Grading Margin......Page 162
5.7 Earth Fault Protection......Page 163
6.1 Introduction......Page 167
6.2 Categories of Fuses......Page 169
6.3 Fuse Operating Osallograms......Page 186
6.4 Time vs Current Characteristic......Page 189
6.5 Discrimination......Page 196
6.6 Testing of Fuses......Page 202
6.7 Future Developments......Page 207
7.2 Principle of Distance Protection......Page 208
7.3 Analog Amplitude and Phase Comparison......Page 214
7.4 Relay Types and Their Application......Page 217
7.5 Derivation of Signals for Distance Protection......Page 224
7.6 Methods of Realising Comparators......Page 226
7.7 Signal S2......Page 234
7.8 Pre-Filters Used in Power System Protective Relaying......Page 235
7.9 Effect of the Ratio Source Impedance to Line Impedance (Zs/Z1)......Page 237
7.10 Time Grading of Distance Relays......Page 238
7.11 Requirements of Definite-Distance Schemes......Page 240
7.12 Reach of Distance Relay......Page 241
7.13 Digital Computation By A Microprocessor......Page 243
8.2 Circulating Current Differential (Low Impedance)......Page 250
8.3 Biased Differential Protection......Page 253
8.4 High Impedance Current Differential......Page 254
8.5 Pilot Wire Protection......Page 256
8.6 Phase Comparison Protection......Page 258
9.1 Unit and Non-Unit Protection Schemes......Page 260
9.2 Remote and Local Back Up Protection......Page 265
9.3 Example Demonstrating a Method to Determine Current Settings of Circuit Breaker Failure Schemes......Page 278
Part B Power System Communications......Page 282
1.2 Electric Power Research Institute (EPRI)......Page 284
1.3 Innovative Integration Developments (IEDs)......Page 285
2.1 Terminologies......Page 287
2.2 Architectures......Page 292
3.1 Introduction to Power System Communication......Page 301
3.2 Protocols in General......Page 305
3.3 Expand on DNP......Page 306
3.4 Standardisation Developments......Page 308
4.1 Introduction......Page 320
4.2 Automation Systems and Communication Needs......Page 321
4.3 Middleware Requirements for Protection Applications......Page 326
4.4 Middleware Architectures......Page 329
4.5 Publish/Subscribe Middleware......Page 335
4.6 Corba and ITS Features......Page 343
4.7 Common Architectures for Communication Devices......Page 351
5.1 Overview of Communication Networking Requirements......Page 357
5.2 Information Embedded Power System Via LAN/WAN......Page 358
5.3 The Benefits of Using IEPS-LAN/WAN Technology......Page 362
6.1 Backgroun......Page 364
6.2 Current Power System Data Communication Media......Page 365
6.3 Networks and Information Technology......Page 367
6.4 Wide Area Communication Infrastructure......Page 370
6.5 Local Area Substation Network Design......Page 372
6.6 Time Data Communication and Exchange......Page 373
Conclusion to Chapter Three on Protocols......Page 376
Overall Conclusion to IEC61850 And DNP-3......Page 377
Conclusion to Chapter Four on Middleware......Page 379
Conclusion to Chapter Five on Information Embedded Power System......Page 381
Conclusion to Chapter Six on Fiber Optic Network Infrastructure as Next Generation Power System Communications......Page 382
References......Page 384
Index......Page 396

Citation preview

Power System Protection and Communications

AKHTAR KALAM D P KOTHARI

Power System Protection and Communications

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Power System Protection and Communications

AKHTAR KALAM Professor School of Engineering and Science Faculty of Health, Engineering and Science Victoria University, Australia

D P KOTHARI Vice Chancellor, VIT University, Vellore Formerly Director In-charge, IIT, Delhi Formerly Professor, Centre for Energy Studies IIT, Delhi, India

The Control Centre, 11 A Little Mount Sion Tunbridge Wells, Kent TN1 1YS, UK www.newagescience.co.uk • e-mail: [email protected]

Copyright © 2010 by New Academic Science Limited 27 Old Gloucester Street, London, WC1N 3AX, UK www.newacademicscience.co.uk • e-mail: [email protected] ISBN : 978 1 78183 174 8 All rights reserved. No part of this book may be reproduced in any form, by photostat, microfilm, xerography, or any other means, or incorporated into any information retrieval system, electronic or mechanical, without the written permission of the copyright owner. British Library Cataloguing in Publication Data A Catalogue record for this book is available from the British Library Every effort has been made to make the book error free. However, the author and publisher have no warranty of any kind, expressed or implied, with regard to the documentation contained in this book.

Preface Electrical protection is as fundamental to the generation, transmission and distribution of electricity as generators, transformers and transmission lines themselves. It is an interesting and complex area of power engineering and many engineers have devoted their life’s work to the subject. There is always a need to provide education in the theory and practice of protection engineering for engineers and technical personnel, because of its importance in design and operation of the power system. Victoria University (VU) has conducted courses in protection for many years and over the past five years, has presented a three day course as part of the Electricity Supply Association of Australia (ESAA)/Australian Power Institute (API) Continuing Professional Development Program. Over 700 engineers and senior technical staff have participated in these courses and have indicated that they found the experience of great value. The text is designed to give participants the basic skills to commence practice in the basic protection system principles. About two decades ago microprocessor based relays replaced the traditional electromechanical ones and it found increasing usage in the various types of protection relays and other Intelligent Electronic Devices (IEDs). This was due to the fact that there were many components in an IED that are similar and in some cases identical between substation protection, control, monitoring and recording devices. Microprocessor technology was extensively used by manufacturers of devices required by the different domains in the substation. Protection relay manufacturers started implementing protection functions by emulating the principles of electromechanical or solid state relays using numerical methods. Both vendors and users realized that microprocessor based technology allows the development and application of functions that were impossible in the world of electromechanical devices. This process occurred simultaneously from several directions. Protection relay manufacturers

vi

PREFACE

started adding other features like fault locators, measurements and recording capabilities. Advancements in communications and acceptance of standard international or industry protocols resulted in the widespread of substation automation systems and further expanded the functionality of substation IEDs. The second part of the book highlights the new international standard for substation communications (IEC 61850) which will completely change the ways protection, control, monitoring and recording has been traditionally done in the substation. This standard for communication networks and systems in substations allows the development of high-speed peer-to-peer communications based distributed protection applications that result in significant changes in the ways protection functions are implemented. This replacement of functions implemented in a single device with equivalents using exchange of analogue and status information over the substation local area network has revolutionized the conventional power system protection. We are indebted to the industry experts who have given valuable time to set up the new IEC standard 61850. This book will try and give not only the basic understanding of the basic protection principles but also the numerous protocols as developed by the communication engineers and which is now going to be extensively used by the 21st century power industry. This book describes in detail the principles of different IEC 61850 distributed functions and analyses the factors that will affect their performance. The definitions of the individual components of distributed functions are presented in detail, including the different possible allocations of sub-functions and functional elements in physical devices. We are thankful to our colleagues at Victoria University, Melbourne and VIT University, Vellore, who have helped us directly or indirectly in completing the book. First author is grateful to Dr. Rushan Lloyd Muttucumaru, Postdoctoral Fellow and Dr. Cagil Ozansoy and Dr. Amanullah Maung Than Oo for their help in preparing the latter part of the work. The second author is thankful to Dr. G. Viswanathan, Chancellor, VIT University, Vellore for his constant encouragement for completing this project. We thank our families for their patience and encouragement shown while we were working on this project and Mr. Prabhakar Kartikeyan for his help in preparing the manuscript. Akhtar Kalam D.P. Kothari

List of Acronyms

RTU PLC EMS IED I&C SCADA ISO OSI SER MTBF HMI LAN WAN UCA RS485

— — — — — — — — — — — — — — —

RS232

—

ACSI — CORBA — IEC 61850 —

SA MMS DCOM SCSM

— — — —

Remote Terminal Units Programmable Logic Controllers Energy Management System Intelligent Electronic Devices Instrumentation and Control Supervisory Control And Data Acquisition International Standards Organization Open System Interconnection Sequential Events Recorder Mean Time Between Failures Human Machine Interface Local Area Network Wide Area Network Utility Communication Architecture The Electronics Industry Association, Recommended Standard 485 The Electronics Industry Association, Recommended Standard 232 Abstract Communication Service Interface Common Object Request Broker Architecture Is a framework for substation automation that addresses more of what is required for interoperability of Intelligent Electronic Devices. Substation Automation Machine Monitoring Systems Distributed Component Object Model Specific Communication Service Mapping

viii

LIST OF ACRONYMS

GOOSE — EPRI — MODBUS — Profibus TCP/IP VTs CTs RTDs VAR Controllers CIGRE IEEE DMS DA CVTs PQ CQ WFQ WRED CAR RSVP QoS Tspeck RESV OMA IDL CASM MMS IEC TC

— — — — — —

IEC NIS IEPS SNMP NTP FACTS VBR MPCS

— — — — — — — —

— — — — — — — — — — — — — — — — — — —

Generic Object Oriented Substation Event Electric Power Research Institute A popular protocol with industrial users, popular in substations Protocol Transmission Control Protocol/Internet Protocol Voltage Transformers Current Transformers Resistance Thermal Detectors Voltage Ampere Reactive Controllers International Council on Large Electric Systems Institute of Electrical and Electronic Engineers Distribution Management System Distribution Automation Capacitor Voltage Transformers Priority Queuing Custom Queuing Weighted Fair Queuing Weighted Random Early Detection Committed Access Rate Resource Reservation Protocol Quality of Service Traffic Specification Reservation Request Object Management Architecture Interface Definition Language Common Applications Service Models Manufacturing Message Specification International Electrotechnical Committee Technical Committee International Engineering Consortium Network Integrated System Information Embedded Power System Simple Network Management Protocol Network Time Protocol Flexible AC Transmission System Various Bit Rates Massively Parallel Computing Systems OR (Mathematics, Physics and Computer Science)

LIST OF ACRONYMS

XML JSP DTD DOM CSV OASIS XSL OXC OADM FDDI UDP IP NIS SQL DAType ToS IEE VOIP ATM TDM

— — — — — — — — — — — — — — — — — — — —

Extensible Markup Language Java Server Pages Document Type Definition Document Object Model Comma Separated Variable Open Access Sametime Information Systems Extensible Stylesheet Language Optical Cross-Connects Optical Add-Drop Multiplexer Fiber Distributed Data Interface User Datagram Protocol Internet Protocol Network Integrated System Structured Query Language Data Attribute Type Type of Service Institute of Electrical Engineers Voice Over IP Asynchronous Transfer Mode Time-Division Multiplexing

ix

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Contents

Preface ............................................................................................................. v List of Acronyms .......................................................................................... vii Recommended Protection Terminology ........................................................ xv

Part A POWER SYTSEM PROTECTION Chapter 1 Basic Principles 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8

Introduction to Protective Relaying 3 Power System Plant and Layout 5 Switching Arrangements 8 The Function of Protective Relaying 13 Principles of Protective Relaying 14 Unit and Non-unit Schemes 17 Zones of Protection 19 Common Terminologies 20

Chapter 2 Network Analysis and Fault Calculations 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

3–21

22–50

Faults on Power System 22 Faults Type 23 Fault Level Calculations 24 Limiting Short-circuit Levels 26 Transients During a Balanced Fault 27 Sequence Networks for Calculation of Unbalanced Faults 30 Calculation of Voltages in the Network 38 Short-circuit Fault Calculations 39

xii

CONTENTS

Chapter 3 Earth Fault and Interferences 3.1 3.2 3.3 3.4 3.5 3.6 3.7

Introduction 51 Power System Arrangements and Construction Features 52 Earth Potential Rise 57 Safety Considerations 63 Application of Safety Criteria 64 Demands on Protection Arising from Safety, Reliability and Interference Considerations 65 Interference on Supplied and other Systems 75

Chapter 4 Relaying Transducers 4.1 4.2 4.3 4.4

126–166

Introduction 126 Categories of Fuses 128 Fuse Operating Oscillograms 145 Time vs Current Characteristic 148 Discrimination 155 Testing of Fuses 161 Future Developments 166

Chapter 7 Distance/Impedance Protection 7.1 7.2 7.3

101–125

Introduction 101 Types and Construction 102 System Analysis 106 Settings of IDMT Relays 107 Relay Discrimination 109 Grading Margin 121 Earth Fault Protection 122

Chapter 6 Fuses 6.1 6.2 6.3 6.4 6.5 6.6 6.7

80–100

Introduction 80 Voltage Transformers 80 Current Transformers (CTs) 85 Guidance in Application of CTs 92

Chapter 5 Overcurrent Protection 5.1 5.2 5.3 5.4 5.5 5.6 5.7

51–79

Overview of Distance Protection 167 Principle of Distance Protection 167 Analog Amplitude and Phase Comparison 173

167–208

xiii

CONTENTS

7.4 7.5 7.6 7.7 7.8 7.9 7.10 7.11 7.12 7.13

Relay Types and Their Application 176 Derivation of Signals for Distance Protection 183 Methods of Realising Comparators 185 Signal S2 193 Pre-filters Used in Power System Protective Relaying 194 Effect of the Ratio Source Impedance to Line Impedance (ZS/ZL) 196 Time Grading of Distance Relays 197 Requirements of Definite-distance Schemes 199 Reach of Distance Relay 200 Digital Computation by a Microprocessor 202

Chapter 8 Differential Protection 8.1 8.2 8.3 8.4 8.5 8.6

Introduction 209 Circulating Current Differential (Low Impedance) 209 Biased Differential Protection 212 High Impedance Current Differential 213 Pilot Wire Protection 215 Phase Comparison Protection 217

Chapter 9 Unit, Remote and Back Up Protection 9.1 9.2 9.3

209–218

219–239

Unit and Non-unit Protection Schemes 219 Remote and Local Back Up Protection 224 Example Demonstrating a Method to Determine Current Settings of Circuit Breaker Failure Schemes 237

Part B POWER SYTSEM COMMUNICATIONS Chapter 1 Introduction 1.1 1.2 1.3

International Electrotechnical Committee (IEC) Technical Committee (TC) 57 243 Electric Power Research Institute (EPRI) 243 Innovative Integration Developments (IEDs) 244

Chapter 2 Communication Principle 2.1 2.2

243–245

Terminologies 246 Architectures 251

246–259

xiv

CONTENTS

Chapter 3 Protocols 3.1 3.2 3.3 3.4

Introduction to Power System Communication 260 Protocols in General 264 Expand on DNP 265 Standardisation Developments 267

Chapter 4 Middleware 4.1 4.2 4.3 4.4 4.5 4.6 4.7

•

323–334

Background 323 Current Power System Data Communication Media 324 Networks and Information Technology 326 Wide Area Communication Infrastructure 329 Local Area Substation Network Design 331 Time Data Communication and Exchange 332

Chapter 7 Conclusions • • • •

316–322

Overview of Communication Networking Requirements 316 Information Embedded Power System via LAN/WAN 317 The Benefits of using IEPS-LAN/WAN Technology 321

Chapter 6 Fiber Optic Network Infrastructure as Next Generation Power System Communications 6.1 6.2 6.3 6.4 6.5 6.6

279–315

Introduction 279 Automation Systems and Communication Needs 280 Middleware Requirements for Protection Applications 285 Middleware Architectures 288 Publish/Subscribe Middleware 294 Corba and its Features 302 Common Architectures for Communication Devices 310

Chapter 5 Information Embedded Power Systems 5.1 5.2 5.3

260–278

335–342

Conclusion to Chapter Three on Protocols 335 Overall Conclusion to IEC61850 and DNP-3 336 Conclusion to Chapter Four on Middleware 338 Conclusion to Chapter Five on Information Embedded Power System 340 Conclusion to Chapter Six on Fiber Optic Network Infrastructure as Next Generation Power System Communications 341

References

343–354

Index

355–357

Recommended Protection Terminology

ESAA COMMITTEE NO. 2.14 – PROTECTION 1. INTRODUCTION The purpose of this study was to compile a list of recommended terms to enable authorities of ESAA to discuss protective schemes, with mutual understanding of the terms used to describe these schemes and their performance parameters. No attempt has been made to categories the various terms, which are set out in alphabetical order alone. Where possible, standard items of terminology from either IEC or BS have been adopted in toto and the appropriate reference appears in parentheses below the term. Terminology of a purely telecommunications nature is not included herein; reference for such terminology should be made to ESAA Publication D (b) 7-1968: Communication Terms for Power System Telecommunications. Terms associated with auto-reclosing applications, as contained in ESAA Publication D(b) 12-1971: Guide to the Application of Auto Reclosing to Radial Overhead Lines Supplying Urban and Rural Areas, are not repeated herein. The terms as listed below are commonly used by the larger supply authorities in Australia.

xvi

POWER SYSTEM PROTECTION AND COMMUNICATIONS

2. REFERENCES The basic references used in this study were as follows: BS 142-1966 Electrical Protective Relays BS 3950-1965 Electrical Protective Systems for AC Plant (withdrawn and not replaced October 1981) IEC 50(16)-1956 Protective Relays IEC 255.4-1976 Appx.E. Impulse Voltage Withstand and High Frequency Disturbance Tests.

3. RECOMMENDED TERMINOLOGY Term

Definition

Remarks

Acceleration

A term applied to describe the action of speeding up the operation of a distance relay which would otherwise be time delayed.

e.g. reducing the operating time for a fault within Zone 2 at one end of a line by an ‘endto-end’ signal from the Zone 1 operation at the other end of the line.

Algorithm

A procedure for processing information.

Arc Supression Coil

An earthing reactor so designed that its inductive reactive current to earth under fault conditions balances the capacitive current to earth flowing from the power line so that the earth current at the fault is limited to practically zero.

Arcing Time

The time between the instant of arc initiation at the circuitbreaker contacts and the final extinction on all poles.

Backup Protection

A protection which is intended to operate when a system fault is not cleared in due time because of failure or inability of the main protection or the associated circuit-breaker to operate.

Preferred to the term ‘Petersen Coil’. Similar to BS 204 definition.

See also Local Backup Protection. Similar to IEC 50 — Section 448-03.

(Contd...)

xvii

RECOMMENDED PROTECTION TERMINOLOGY

Balanced Fault

A fault giving rise to steady state symmetrical phase currents in a 3-phase system.

Balanced Voltage Protection

A differential protective system See also Longitudinal where equal primary current Differential Protection. flow into and out of the protected zone ideally produces no net circulating current through the CT secondary circuit and a series connected relay.

Biased Relay

An electrical measuring relay the operating characteristic of which is changed by the application of restraint derived from input energising quantity(ies).

Similar to IEC 50(16).

Blind Spot

A fault location between a circuit-breaker and its associated transformers where post-type current transformers are used and are provided on one side of the breaker only.

Preferred to the term ‘dead zone’. A fault in the blind spot, although within the zone of a particular protective system, is not cleared completely by the operation of that protective system alone.

Blocking Protection

A protection system associated IEC 50 — Section 448-03. with a signalling system in which the receipt of a signal blocks tripping locally initiated.

Blinder

A relay whose characteristic, when plotted on a R-X diagram, is a straight line crossing the characteristic of another relay and arranged to prevent tripping on one side of its own characteristic.

Usually applied to long, heavily-loaded lines to prevent tripping on power swings by confining the tripping characteristic of the line protection relays.

Bolted Fault

A balanced fault of virtually zero impedance between each phase and the neutral point of a 3-phase system, reducing voltage measurements for protection purposes to negligible values.

Typically a fault arising as a result of working earths applied but not removed prior to energising a line. Requires special measures to ensure correct clearance (see switchin fault protection). (Contd...)

xviii

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Breaker Failure A specific form of local backup Protection protection which operates in the event of a circuit-breaker failing to clear a fault and trips all other circuits feeding into the same section of busbar as that breaker.

Frequently by means of a sequential tripping scheme working through the busbar protection trip circuits. Also provides protection for blind spots.

Buchholz Relay

A protective relay, responsive either to the collection of gas produced by incipient faults or to oil surges caused by explosive faults within a transformer tank, arranged to operate an alarm or to trip the transformer out of circuit.

Preferred to the term ‘gas relay’.

Characteristic Angle

The phase angle at which the performance of a relay is declared. It is usually the angle between the energising quantities at which maximum sensitivity occurs.

Similar to BS 142 definition.

Characteristic Impedance Ratio

The maximum value of system Similar to BS 3950. impedance ratio up to which the relay performance remains within the prescribed limits of accuracy.

Characteristic Quantity

An electrical quantity, or one of e.g. current for an over-current its attributes, the name of relay; frequency for a frequency which characterises the relay relay, etc. and the value(s) of which are the subject of accuracy requirements.

Check Protective An auxiliary protective system Similar to BS 3950. System intended to prevent tripping due to inadvertent operation of the main protective system. Check Relay

A relay forming part of a protection system which confirms the presence of a fault condition, independently of other detectors and allows a trip command to be issued.

A current check relay in a voltage balance Pilot Wire Protection System which allows tripping only in the presence of fault current, e.g. not as a result of Pilot Wire short-circuit. (Contd...)

xix

RECOMMENDED PROTECTION TERMINOLOGY

Also, a relay which by its contact state confirms a particular primary circuit condition and in conjunction with other indicators, determines trip circuit action.

A current check relay in a local back-up protection system which together with main protection status and a time function, establishes the breaker failure criterion.

Check Zone

Term applied to the nonselective part of a multi-zone bus protection system, supervising current flow at the terminals of the complete station. Tripping is conditional on operation of both the check and a discriminative zone.

Circulating Current Protection

A differential protective system The classical Merz-Price where the equal primary system. See also Differential current flow into and out of the Protective System. protected zone ideally produces a circulating current through the CT secondary circuit but no net current through a shunt connected relay.

Comparator

A device which compares two or more input signals and produces an output when a predetermined relationship between the inputs occurs.

In most distance relays, either phase comparators or amplitude comparators are used. Some modern solid state distance relays have multiinput comparators.

Component Test

A test to determine the characteristics of an individual component.

BS 3950.

Conjunctive Test

A test on a protective system, BS 3950. including all relevant components and auxiliary equipment appropriately interconnected.

Counter

A logic device which cycles through a defined set of states in response to input transitions. (Contd...)

xx Cross-country Fault

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Simultaneous flashover to Common on unearthed earth of two different phases in systems or systems earthed different line sections of the through arc suppression coils. same power system generally, although not necessarily, at the same voltage level.

DC/DC Converter A power supply employing solid state switching devices and saturable electromagnetic components with suitable control circuitry to convert direct current power from one voltage level to another and provide galvanic input/output separation. Dead Zone

See ‘Blind Spot’.

Not recommended

Dependent Time Lag Relay

A measuring relay having an operating time which is a function of the value of the characteristic quantity.

Differential Protective System

A unit protective system in Similar to BS 3950 definition. which an algebraic comparison is made of currents at two or more points in the power system.

Digital Relay

A relay which processes the actuating quantity in a digital format, the analogue to digital conversion being normally accomplished internally.

Direct Intertrip

The signal initiated by local protection which, when received at the remote end of the protection section, trips that circuit-breaker without reference to the state of the remote protection. (Contd...)

xxi

RECOMMENDED PROTECTION TERMINOLOGY

Directional Comparison Protective System

A unit protection system associated with signalling, the operation and selectivity of which depends on the comparison of the directions of power flow at the ends of the protected section.

Directional Overcurrent Protection

A non-unit protection, the operation of which depends on the magnitude of the current and its phase angle relative to a voltage reference at the point of measurement.

Discrimination

The quality whereby a protective system distinguishes between those conditions for which it is intended to operate and those for which it shall not operate.

Discriminative Zone

Term applied to the selective part of a multi-zone bus protection system, supervising current flow at the terminals of a particular bus zone. Tripping is conditional on operation of both a Discriminative and the Check Zone.

Distance Protection

A non-unit protection system, IEC 50 Section 448-03. the operation and selectivity of which depend on local measurement of parameters from which the equivalent distance to the fault is evaluated and compared with zone settings.

BS 3950.

(Contd...)

xxii

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Distance Protection with Permissive Overreach

A Distance Protection System associated with signalling in which the shortest zone setting corresponds to a distance longer than the length of the protected section and in which tripping to clear a fault in the protected section without a deliberate time delay is only permitted when fault detection at one end is coincident with receipt of a tripping signal from the opposite end.

Distance Protection with Permissive Underreach

A Distance Protection System associated with signalling in which the shortest zone setting corresponds to a distance shorter than the length of the protected section and in which tripping of the end remote from the fault without a deliberate time delay is only permitted when fault detection at that end is coincident with receipt of a tripping signal from the opposite end.

Distance Protection with Acceleration

An Underreaching Distance Protection System associated with signalling in which the shortest zone setting at one end is extended corresponding to a distance longer than the length of the protected section, by transmission of a signal from the protection at the opposite end.

Distance Protection with Blocking Overreach

A Distance Protection System associated with signalling in which reverse looking fault detectors transmit a signal to the opposite end of the protected section to block tripping by overreaching forward looking elements of the system. (Contd...)

RECOMMENDED PROTECTION TERMINOLOGY

xxiii

Distance Protection with Blocking Underreach

A Distance Protection System associated with signalling in which the shortest zone setting corresponds to a distance shorter than the length of the protected section, which provides for clearance of faults in the section beyond this zone setting in less than Zone 2 time, but which contains reverse looking fault detectors to initiate signalling to the protection at the opposite end of the section in order to extend its tripping delay to Zone 2 time, so as to discriminate against external faults.

Drawout Relay

A relay whose construction is such that it can be inserted into and withdrawn from a case or other such fitting and provide with sliding contact fingers for establishing the electrical connections between the withdrawable element and the fixed portion.

Usually applies to a complete relay chassis as distinct from individual relay elements. Provision is made in the construction of the case to automatically short-circuit any external current transformer secondary circuit when the relay is withdrawn.

Duplicate Protection

The provision of two completely separate protective systems at a particular relaying point, either of which is capable of fulfilling the required protective function.

The two protective systems may share common supplies. However, duplication in its full sense implies that no failure of one system to operate correctly may prevent the other system from performing its intended function.

Dynamic Test

A test measuring the (relay) Typically includes the response to both the transient transient DC component of the and steady state components of fault current. the primary circuit actuating quantity.

Earth Fault Protection

Protection for faults between conductors and earth.

Similar to IEC 50(16). Use of the term ‘earth leakage protection’ is not recommended. (Contd...)

xxiv

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Electro-mechanical Relay

An electrical relay or relay element whose characteristic is determined partly or wholly by moving parts.

External Fault

A fault outside the defined zone of protection.

Preferred to the term ‘through fault’.

Fast Transient Surge Withstand Capability Test

A type test intended for energised solid state relay systems, to determine whether they will operate without erroneous output, component failure or calibration change beyond normal tolerances when specified high voltage fast rising transients such as occur during the interruption of inductive devices in DC circuits, are applied.

ANSI 37-90-1978 and IEEE Guide P472/D2-1982.

Fault Clearance Time

The time interval between inception of fault current and arc extinction. The sum of the relay operating time, circuitbreaker opening time and arc duration.

Fault Detector

An element of a protection Alternative term for Starting relay which responds to faults Element. or abnormal service conditions, not necessarily only within the protected zone, and initiates the operation of other elements of the protection.

Fault Level

The rms value of the fault current in kA at rated system voltage available at the point of fault in a particular location of the power system.

Fault Setting

The limiting value of the May be referred either to measured quantity at which primary or the secondary operation of the protective circuit. BS 3950. system occurs. (Contd...)

xxv

RECOMMENDED PROTECTION TERMINOLOGY

Fault Throwing

A method in which operation IEC 50(16). of the protection of a circuit not provided with a circuit-breaker at one end causes an intentional fault on the circuit at that end, so enabling the protection at the other end or ends to operate to disconnect the circuit.

Field Failure Protection

A protective system which operates when the field supply to a synchronous machine drops below the required level.

Final Tripping

A tripping command issued by a self-reset relay which does not initiate reclosing.

Flag Indicator

An indicating device which shows that the associated relay element has operated.

Flip-Flop

A bistable logic device with defined responses to various input levels and/or transitions.

Preferred to the term ‘target’. Includes indicating lights.

Frame Leakage Protection in which the Similar to IEC 50(16). Protection actuating quantity is the current flowing between the metal framework enclosing the protection zone and earth. Frequency Relay

which the quantity is

May be of the under-or overfrequency type.

Gas Impulse Relay A relay which responds to a sudden change of pressure of the air cushion above oilimmersed equipment.

This device is an alternative to the Buchholz relay and may be used on transformers not fitted with a conservator.

Harmonic Bias

A relay in characteristic frequency.

A method of making Frequently used in differential differential relays insensitive to protective systems. magnetic inrush currents, wherein the harmonics are filtered out from the differential current and used to provide additional restraint. (Contd...)

xxvi High Frequency Disturbance Test

POWER SYSTEM PROTECTION AND COMMUNICATIONS

A type test intended for AS 2481-1981. energised solid state relays to determine whether they will operate in a faulty manner when specified high-frequency transients representative of practical system conditions are applied.

High-Impedance A single-input relay having a Frequently used in differential Relay high input impedance such protective systems. that, when fed from a current transformer, the relay current is substantially different from that obtained using the transformation ratio. High-speed Protection

A protective system whereby Preferred to the term no intentional time delay is ‘instantaneous protection’. introduced between the onset of a fault and the initiation of tripping power.

Impedance Relay

A specific type of distance protection relay whose polar characteristic, when plotted on an R-X diagram, is a circle having its centre at the origin.

Impulse Starter

A starting element in a protective relay system responsive to step changes rather than the absolute value of the actuating quantity.

Often used to discriminate between faults and high balanced load conditions.

Impulse Withstand Test

A type test intended to determine the ability of a relay to withstand, without damage, very high value and short duration over-voltages.

AS 2481-81.

Independent Definite Time Lag Relay

A measuring relay having an operating time which, after a predetermined value is reached, is independent of the value of the characteristic quantity. (Contd...)

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RECOMMENDED PROTECTION TERMINOLOGY

Inrush Factor

The peak value of the first BS 3950. major loop of the magnetising inrush of the power transformer winding being switched, expressed as a multiple of the rms value of the rated current of that winding.

Internal Fault

A fault within the defined zone of protection.

Intertripping

The tripping of circuit- Synonymous with Transfer breaker(s) by signals initiated Tripping (British usage). by protection at a remote location.

Integrator

A device whereby the output signal is the integral of the input signal.

Integrated Circuit

A single, homogeneous device containing a large number of semi-conductor components, e.g. transistors, grouped and connected in such a way as to form a complete circuit.

Knee Point Voltage

That point on the open-circuit excitation curve of a current transformer where a 10% increase in applied voltage causes a 50% increase in exciting current.

Level Detector

A device whose output changes state when the input signal has attained a desired threshold level.

Local Backup Protection

A form of backup protection in which determination and initiation of the required action takes place at the same location as that at which the main protection is situated.

Can also involve the intertripping of remote circuitbreakers. Similar to IEC 50, Section 448-01.

(Contd...)

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Lockout Tripping

A tripping command issued by a relay having a manual (local or remote) reset facility. The tripping command is maintained in case of attempted reclosure until the relay is reset.

Logic Gate

A device whereby the output signal is related to the input signals by a prescribed form of mathematical logic.

Longitudinal Differential Protection

A unit protection system, the operation and selectivity of which depends on the comparison of the phase and/ or magnitude of the currents at the ends of the protected section.

IEC 50, Section 448-03.

Main Protection

A protection system expected to have priority over backup systems in initiating fault clearance.

Similar to IEC 50, Section 448-01.

Memory Relay

A specific type of distance relay whose polarising circuit is oscillatory in nature, so that a polarising signal persists in the relay for a short time after the collapse of system voltage at the instant of fault.

The term ‘Memory Trip’ is used when such a relay is employed for switch-in fault protection, i.e. in distance protection with bus VTs.

Mho Relays

A specific type of distance relay whose polar characteristic, when plotted on an R-X diagram, is a circle which either passes through the origin (polarised mho) or is offset from the origin (offset mho). (Contd...)

RECOMMENDED PROTECTION TERMINOLOGY

Microprocessor

An integrated circuit incorporating the majority of the principal components of a computer processing unit, viz. control unit, arithmetic and logic unit, data registers and possibly also clock generator, memory and input/output ports.

Modified Impedance Relay

A specific type of distance relay whose polar characteristic, when plotted on an R-X diagram, is a circle having its centre located at a set point along the R axis.

Negative Phase Sequence Protection

A non-unit protection system in which the operation is dependent upon the level of negative phase sequence component in the characteristic quantity.

Opening Time

The time between the application of tripping power to the circuit-breaker when closed and the instant of separation of the contacts.

Operating Time

The time which elapses from IEC 50(16). the appearance of the abnormal conditions which cause the operation of the protection until the protection initiates tripping or alarm.

Operational Amplifier

An amplifier with very high gain and differential input. Used to perform various mathematical functions depending on the feedback arrangement used, e.g. inverting, summation, integration, etc.

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(Contd...)

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Oscillatory Surge Withstand Capability Test

A type test intended for energised solid state relay systems to determine whether they will operate without erroneous output, component failure or calibration change beyond normal tolerances, when specified oscillatory surge voltages representative of practical system conditions, are applied.

Out of Step Protection

Protection which separates the IEC 50(16). appropriate parts of a power system in the event of sustained power transfer oscillations.

Overcurrent Protection

Protection which operates when the current exceeds a predetermined value.

Overload Protection

Protection which operates Refers specifically to plant in when the protected zone is the protected zone. IEC 50(16). overloaded.

Overreach

The unintentional extension of the protection operation zone beyond that indicated by the relay setting.

Overreaching Protection

A form of protection in which relays at one terminal are set to operate for faults on and beyond a specified line section.

Overvoltage Protection

Protection that operates at a predetermined voltage level which is greater than normal.

Permissive Intertrip

The trip signal initiated by local protection which, when received at the remote end of the protected section, permits the remote protection to trip the associated circuit-breaker.

Term used by ANSI 37.90-1978 and IEEE guide P472/D2-1982 to describe the High Frequency Disturbance Test of AS 2481-1981.

Use of ‘overload protection’ as a general term is not recommended. IEC 50(16).

Usually associated with ‘end to end’ signalling.

(Contd...)

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Permissive Protection

A protection system associated IEC 50, Section 448-03. with a signalling system in which the receipt of a signal permits tripping locally initiated.

Phase Comparator

Component of a protection relay designed to respond to the phase angle between energising quantities.

Phase Comparison Protection

A unit protection system, the operation and selectivity of which depend on measurement, at each end of the protected zone, of the phase angle between local and remote end currents.

Phase Sequence Network

Circuitry designed to separate positive, negative or zero sequence current or voltage components or a combination of these from a 3-phase supply system to protective relays.

Pilot Isolating Transformer

A transformer for isolating pilot wires from the terminal relay equipment to provide protection against the effects of any longitudinal voltages induced in the pilot wires.

Pilot Supervision

A method for monitoring the integrity of pilot-wire circuits.

Pilot-wire Protection

A differential protective system in which a metallic circuit is used to inter connect the relays at the terminals of the protected zone.

Frequently involves the injection of a small DC circulating current, any significant change in which initiates an alarm.

(Contd...)

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Plug-in Relay

A relay designed to the inserted in a fitting by means of plugs serving as terminals.

Polar Characteristic

The graphic representation of a See R-X diagram. protective relay’s operating range in terms of a polar coordinate system.

Polarisation

Method of making the operation of a relay dependent on the phase angle between fault current and voltage.

Polygonal Characteristic

A distance relay characteristic which, when plotted on an R-X diagram, is a closed figure having three or more (usually four) straight sides.

Protected Zone (BS 3950)

That portion of a power system protected by a given protective system or part of that protective system.

Protective Equipment

The apparatus, including Similar to BS 3950 definition. protective relays, transformers and auxiliary equipment, for use in a protective system.

Protective Scheme

The coordinated arrangements A protective scheme may for the protection of one or involve several protective more elements in a power systems. BS 2950. system.

Protective System

A combination of protective Similar to BS 3950 definition. equipments designed to secure, under predetermined abnormal conditions, the disconnection of an element of a power system.

Reach

For stepped curve distance- IEC 50(16). time protection: the distance corresponding to the farther end of each step or zone.

IEC 50(16).

Similar to IEC 50(16).

(Contd...)

RECOMMENDED PROTECTION TERMINOLOGY

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Reactance Relay

A specific type of distance protection relay whose polar characteristic, when plotted on an R-X diagram, is a straight line running parallel to the R axis.

Reclosing Relay

A relay designed to close a circuit-breaker in accordance with a predetermined sequence after the circuit-breaker has been opened by the operation of protective equipment.

Relay Backup

Protection located either locally May comprise part of a local or remotely which will operate backup scheme. for faults within the reach of the relay being considered in the event of its failure to operate.

Relay Burden

The loading imposed by the circuits of the relay on the energising power source expressed as the product of voltage and current (VA or watts if DC) for a given condition, which may be either at setting or at rated current or voltage.

Relaying Point

A location on a power system equipped with means of deriving information, e.g. current and/or voltage transformers, and relay equipment to which this information is supplied.

Reliability

The quality of a protective system that ensures it will operates whenever the specific conditions required for it to operate are present. (Contd...)

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Remote Backup Protection

A form of backup protection in Similar to IEC 50, Section which determination and 448-01. initiation of the required action takes place at a location other than that at which the main protection is situated.

Replica Impedance

Components of a relay simulating the magnitude and phase angle of a section of the protected zone impedance to ensure correct reach and/or orientation of the comparator polar characteristic.

Resetting Time

The time which elapses between the disappearance of the abnormal conditions which caused the operation of the protection and the restoration of the protection to its initial condition.

Residual Compensation

A method of ensuring that fault distance relays measure accurately irrespective of the distribution of the return fault current between the various power system neutrals.

Compensation is provided by adding a portion of the residual current from all three phases to the current in the faulted phase.

Residual Current

The vectorial sum, in a multiphase system, of all the line currents.

Similar to BS 2950 definition.

Residual Voltage

The vectorial sum, in a multiphase system of all the line-to-earth voltages.

Similar to BS 3950 definition.

Reverse Power Protection

Protection which detects the reversal of power flow at a particular point (or points) in a system.

Reverse Reach

The operating range of a distance relay in the direction opposite to that of principal concern. (Contd...)

RECOMMENDED PROTECTION TERMINOLOGY

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R-X Diagram

The graphic representation of a See polar characteristics. protective relay’s operating range in terms of a rectangular coordinate system.

Schmitt-trigger

A level detector incorporating hysteresis to separate the trigger and reset thresholds.

Secondary Impedance

Impedance of the primary circuit referred to the protection relay terminals using CT and VT transformation ratio; i.e. Zs = Zp ×

CT ratio VT ratio

Secondary Injection

Application of the actuating quantity to a protection relay directly, rather than via the primary circuits of current or voltage transformers.

Security

The quality of a protective system that ensures it will not operate unless the specific conditions required for it to operate are present.

Selective Protection

Protection which determines that the fault is within its own zone and isolates that zone only.

Series Regulator

Part of a power supply employing a linear device to stabilise the output voltage in the presence of input voltage and load current variations.

The selectivity is absolute if the protection responds only to faults within its own zone (unit protection), and relative if it is obtained by grading the setting (e.g. time or current) of the protections of several zones, all of which may respond to a given fault. Similar to IEC 50, Section 1448-01.

(Contd...)

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Sensitivity

A measure of the minimum operating quantity, e.g. current/voltage necessary to cause the correct operation of a relay or complete protection system.

Solid State Relay

An electrical relay or relay element whose characteristic is determined by solid state semiconductor components (e.g. diodes, transistors).

Stability

The quality of a protective system that ensures it will not operate for faults outside the defined zone of protection.

Starting Element

An element of a protective system which responds to faults or abnormal service conditions, and initiates the operation of other more selective elements of the protection.

Static Relay

A relay in which the designed The term includes a solid state response is developed by relay. AS 2481-1981. electronic, magnetic, optical or other components without mechanical motion.

Static Test

A test measuring the (relay) Also termed Steady State Test. response to the steady state components only, of the primary circuit actuating quantity.

Summation

The principle of a combination of a number of inputs in a polyphase system to produce one representative output.

Switch-in-Fault Protection

An auxiliary protective system which, when using distance relays as the main protection, ensures high-speed clearance for closing on a 3-phase fault close to the relaying point.

Usually associated with the use of line VTs, by allowing the distance protection starting elements to trip directly for a short time after closing the circuit-breaker. For busbar VTs, a memory relay may be used. (Contd...)

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RECOMMENDED PROTECTION TERMINOLOGY

Switched Distance Distance protection which Protection employs one comparator to perform a number of measuring functions, the correct quantities being supplied to the comparator by a switching technique controlled by the starting elements. System Impedance At a given measurement IEC 50, Section 448-03, Ratio location, commonly at one end BS 3950. of a line, the ratio of the power system source impedance to the impedance of the protected zone. System Instability

A condition of unstable power transfer leading to collapse of the system in the absence of stabilising forces.

Tapped Circuit

A multi-ended circuit in which a number of the terminations comprise transformers with circuit-breakers only on the lower voltage side.

Teed Circuit

A multi-ended circuit controlled by circuit-breakers at each end, at the same system voltage.

Through Fault

See ‘External Fault’.

Not recommended.

Time Lag

A delay intentionally introduced into the operation of a protective system.

BS 3950.

Transfer Tripping

The tripping of circuit- Synonymous with Interbreaker(s) by signals initiated tripping (American usage). by protection at a remote Not recommended. location.

Transient Factor

The factor by which the steady IEC 50, Section 448-03. state value of the core flux of a protection CT is multiplied during the period of transient asymmetric primary current. (Contd...)

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Transverse Differential Protection

A unit protection system applied to parallel connected circuits in which operation depends on unbalanced distribution of currents between them.

Trip Circuit Supervision

A method for monitoring the May be done either by a continuity of a circuit-breaker supervision relay or by a ‘trip trip circuit. healthy’ lamp.

Underreach

The unintentional reduction of the protection operating zone below that indicated by the relay setting.

Underreaching Protection

A form of protection in which the relays at a given terminal are intended to operate only for faults at or nearer than a specified remote location on the protected line or equipment.

Undervoltage Protection

Protection that operates at a predetermined voltage level which is less than normal.

Unit Protection

A protection system, the IEC 50, Section 448-01. operation and selectivity of which are solely dependent on the comparison of electrical quantities at the boundaries of the protected section.

Zener Diode

A semiconductor diode with a sharply defined reverse breakdown voltage, most often used as a constant voltage source. (Contd...)

RECOMMENDED PROTECTION TERMINOLOGY

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DEVICE NUMBERS The following is a selected list of device numbers commonly used on protection drawings: 2 3 12 14 21 25 27 30 32 37 40 46 47 49 50 50E 51 52 52(a) 52(b) 55 56 59 60 63 64 67 68 74 76 78 79 81 83 85 86 87 95 96

Time delay starting or closing coil Checking or interlocking relay Overspeed device Underspeed device Distance relay Synchronising or synchronism check relay Undervoltage relay Annunciator relay Directional power relay/reverse power Undercurrent or underpower relay Field failure relay Reverse phase or phase balance current relay Reverse phase sequence voltage relay Machine or transformer thermal relay Instantaneous earth fault relay Instantaneous earth fault relay AC time overcurrent relay AC circuit breaker Circuit breaker auxiliary switch-normally open Circuit breaker auxiliary switch-normally closed Power factor relay Field application relay Overvoltage relay Voltage and current balance relay Buchholz gas device Earth fault protection relay AC directional overcurrent relay Blocking relay Alarm relay DC overcurrent relay Phase angle or out-of-step protective relay AC reclosing relay Frequency relay Automatic selective control or transfer relay Carrier of pilot receive relay Locking-out relay Differential protective relay Neutral displacement relay Undervoltage control for tap changers

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PART A

POWER SYTSEM PROTECTION

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CHAPTER

1 BASIC PRINCIPLES

1.1

INTRODUCTION TO PROTECTIVE RELAYING

‘Protective Relaying’ or ‘Protection’ is the term that defines the branch of electric power engineering that is concerned with the detection and disconnection of short-circuits (faults) and other abnormal conditions on the power system. There are three aspects of the design and operation of a power system that are important in considering the role of protective relaying: • Normal operation • Prevention of electrical failure • Mitigation of the effects of electrical failure. The term ‘normal operation’ assumes no failures of equipment, no mistakes of personnel, nor ‘acts of God’. It involves the minimum requirements for supplying the existing customer load and a certain amount of anticipated future load. Design of the power system for normal operation involves major expense for equipment and includes consideration of: • Choice between hydro, steam, or other sources of power • Location of generating stations • Transmission of power to the load • Study of the load characteristics and planning for its future growth • Metering • Voltage and frequency regulation • System operation

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

• Maintenance requirements • The consequences of equipment or plant failure. Protection systems must not interfere with or limit the normal operation of the system but must continuously monitor the system to detect electrical failure or abnormal electrical conditions. Further important aspects in the design of the power system are: • Incorporation of features aimed at preventing failures, and • Provisions for mitigating the effects of failure when it occurs. Modern power system design employs both recourse as dictated by the economics of any particular situation. Notable advances continue to be made toward greater reliability. However also, increasingly greater reliance is being placed on electric power. Consequently, even though the probability of failure is decreased, the tolerance of the possible harm to the service is also decreased. The type of electrical failure that causes greatest concern is the short-circuit, or ‘fault’ as it is usually called, but there are other abnormal operating conditions peculiar to certain elements of the system that also require attention. Some of the features of design and operation aimed at preventing electrical failure are: • Provision of adequate insulation • Coordination of insulation strength with the capabilities of lightning surge arresters • Use of overhead ground wires and low tower-footing resistance • Design for mechanical strength to reduce exposure, and to minimise the likelihood of failure caused by animals, birds, insects, dirt, sleet, bushfires, etc. • Proper operation and maintenance practice. Some of the features of design and operation for mitigating the effects of failure are: • Features that mitigate the immediate effects of an electrical failure 1. Design to limit the magnitude of short-circuit current (a) By avoiding too large concentrations of generating capacity (b) By using current-limiting impedance 2. Design to withstand mechanical stresses and heating owing to short-circuit currents 3. Time-delay undervoltage devices on circuit breakers to prevent dropping loads during momentary voltage dips 4. Ground-fault neutralisers.

BASIC PRINCIPLES

5

• Features for promptly disconnecting the faulty element 1. Protective relaying 2. Circuit breakers with sufficient interrupting capacity 3. Fuses. • Features that mitigate the loss of the faulty element 1. Alternate circuits 2. Reserve generator and transformer capacity 3. Automatic reclosing. • Features that operate throughout the period from the inception of the fault until after its removal, to maintain voltage and stability 1. Automatic voltage regulation 2. Stability characteristics of generators. • Means for observing the effectiveness of the foregoing features 1. Automatic oscillographs 2. Efficient human observation and record keeping. • Frequent surveys as system changes or additions are made, to be sure that the foregoing features are still adequate. Thus, protective relaying is one of several features of system design concerned with minimising damage to equipment and interruptions to service when electrical failures occur. WHEN WE SAY THAT RELAYS ‘PROTECT’, WE MEAN THAT, TOGETHER WITH OTHER EQUIPMENT, THE RELAYS HELP TO MINIMISE DAMAGE AND IMPROVE SERVICE AT A MINIMUM COST. It will be evident that all the mitigation features are dependent on one another for successfully minimising the effects of failure.

1.2

POWER SYSTEM PLANT AND LAYOUT

The following section gives an overview of plant and the electrical characteristic that are relevant to design of the protection system. They also outline some of the various switching arrangements that are likely to be encountered on the power system. The aim is to identify, for the reader, some of the underlying issues that need to be considered in the design of protection.

1.2.1 Power System Plant The system for generation, transmission and distribution of electricity is made up of generators, lines, transformers, reactive plant (capacitors and static compensators) etc. connected in a network to provide reliable transport of electrical energy from the generation source to the customer. The parameters of the plant (size and electrical specifications) and its

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

associated auxiliary equipment, together with the arrangement of the network, have a significant influence on the design of the protection system. Plant impedances and earthing arrangements will determine the magnitude and path of fault currents. Number and location of current and voltage transformers will determine the arrangement of protection zones which, in turn affects the reliability of the whole power system. Consequently, the protection engineer must have a sound knowledge of the design of both the electrical plant and the power system in order to influence the design. The following paragraphs briefly outline some of the plant and system design considerations.

1.2.2 Generators Generators appear in a number of sizes ranging from less than 1 MW (typically in a cogeneration plant) to 600 MW or more in a large fossil fuelled station. Generated voltages are generally constrained in the range of 6.6 kV to 33 kV due to design limitations in the generator insulation systems. This means that step-up transformers are generally needed to connect the generator to the transmission system. Important parameters in the design of protection for the system and the generator are the generator impedances. A distinction is made for two conditions, namely the direct and quadrature axis which cover the positions when the axis of the rotor poles are in phase with the machine poles, or 90 electrical degrees out of phase. Fault currents (resulting from a short-circuit on the power system) are mainly reactive and as they cause drops in the direct axis voltage, we use the direct axis impedances for fault calculations. The impedance of the generator varies with time following inception of a fault, due to the inductive nature of the generator electrical circuit. The value depends on the time that has elapsed from the inception of a short-circuit. Impedances in three time zones are specified for calculation of currents and voltages: • Subtransient impedance (X d ”)—determines the level for short-circuit current during the first 1 to 3 cycles after short-circuit inception. • Transient impedance (Xd’)—determines the level of current that a particular generator will contribute to a short-circuit during the transient period between 3 to 20 cycles. • Synchronous impedance (Xd)—determines the steady state value of short-circuit current after the transient period.

BASIC PRINCIPLES

7

The time constant that determines the duration of the subtransient and transient periods and related ‘offset’ of the short-circuit current is determined by the inductance and resistance of the generator. It is often referred to as the X/R ratio of the generator. In a multi-generator system the X/R ratio is highest near the generation source and reduces as lines and transformers are interposed between the generation and the load. The X/R ratio is important in the determination of required current transformer performance, as you will see in Chapter 4. For protection calculations, we assume that the nominal terminal voltage of all machines is acting behind the machine impedance i.e., all machines are unloaded, and their voltages are all in phase. Some organisations use the subtransient impedance Xd” for fault calculations and apply a decrement to reduce current with time, depending on the measuring and operating time of the protection relays. This can be appropriate if accurate high speed measurement is required, however, the majority use the transient impedance Xd’ and assume that the current does not change during the protection relay operating period. This is adequate for most applications and these sections are based on the use of the transient impedance Xd’. Also of importance in the design of the protection system is the method of earthing, which determines the paths for earth fault currents in the system. Generator neutrals are generally earthed through a high impedance to limit the flow of earth fault currents in the generator windings and eliminate the damage that this would cause. The path for earth fault currents on the external power system is established through earthing of transformer neutral connections.

1.2.3 Transformers Power transformers of various sizes are located throughout the power system. ‘Step-up’ transformers convert the generator voltage to levels suitable for the transmission system which transmits bulk power to the load centres. Depending on the size of the system, transmission voltages will range from 132 kV to 500 kV. ‘Step-down’ transformers reduce the voltages at the bulk load centres to typically 66 kV or 33 kV for distribution through a ‘subtransmission network’ which supplies the high voltage distribution system. The distributions system is typically 33, 22 or 11 kV and supplies distribution substations that transform the voltage to the customer level.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Large transformers in the generating stations or transmission stations may be made up of three single phase units or a single three phase unit. Physical size and transport limitations can frequently determine the choice that has to be made. Single phase units, as well as taking up more space, have more complex connection arrangements, particularly with the connection of the delta or tertiary winding. The external delta connections are more exposed to faults and failure can result in high short-circuit currents, which can be disastrous mechanically for the delta windings. Inter-winding impedances, winding connections (i.e., delta, star, interstar) and earthing arrangements are important for the protection engineer. These factors determine the magnitude and path of fault currents and consequently the ability for protection systems to selectively detect and clear faults from the system. It is usually sufficient to use the inductive component of the transformer impedance in protection calculations and this will usually be expressed as a per cent or per unit at rating i.e., per cent impedance is the percentage voltage drop across the transformer at rated voltage and current. With a short-circuit on the terminals the current will be: I Rated × 100 %Z

1.2.4 Lines Impedances, for calculation of fault currents, are the most important line parameter for protection purposes. These are usually calculated in resistive and reactive ohms at system frequency and are expressed in the form R + jx or Z∠Q. The R term is the resistance per phase and the jx term is obtained from the basic equation of the type jx = k log10

F Separation of conductors I GH k × Radius of conductor JK 1

Factors that influence the impedance include the presence of overhead earth wire and mutual coupling with parallel lines.

1.3

SWITCHING ARRANGEMENTS

Switching arrangements used in a particular power system or individual stations within the system are influenced by a number of factors and there is no clear right or wrong arrangement. Factors that need to be considered are:

BASIC PRINCIPLES

9

• Economic and business investment criteria, • History of development of the individual power system i.e., decisions made in the past can be uneconomic to change because of widespread changes that may be required, • Ease and safety of operation and maintenance, • Security, reliability and quality of supply to the customer, • Flexibility for future development. There are many switching arrangements used on the power system, all of which influence the design of the protection system. A major consideration for the Protection Engineer is the ability to establish appropriate protection zones that will selectively isolate faulty items of plant. In this respect the number and location of current and voltage transformers is a major consideration. The preference would be to locate current transformers on each side of the circuit breaker, transformer and generator so that independent overlapping zones of protection can be established for each plant item. This practice can result in significant costs, either in the cost of the plant item itself (e.g., if the CT’s are mounted within the CB structure) or in the cost of additional space and structures to mount free standing CT’s in the switchyard. A frequent compromise is to provide CT’s on one side of the plant. With this arrangement it is possible to achieve overlapping zones of protection but it can result in “blind spots” or “dead zones” which requires special measures. For example, with CT’s located on the line side of a circuit breaker, a fault between the CB and the CT post will be detected by the busbar protection zone but is outside the line protection zone. The bus protection will operate to trip the local circuit breakers but the protection at the other end of the line must detect and clear the fault from that end.

1.3.1 Single Switching Each item of plant has its own CB. This arrangement: (see Fig. 1.1) • is economic in terms of plant requirements, • is straight forward and safe to operate and maintain, • has few complications from a protection viewpoint, apart from selecting the location for CT’s and VT’s. The major disadvantage is the inflexibility in programming maintenance. For example, an outage of a CB will result in the loss of the associated plant item to the system (possible a major generator or transformer).

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

FIGURE 1.1 Single switching

1.3.2 Double Switching Each plant item has two circuit breakers to provide the ability to switch to either of two bus-bars. This is a very flexible arrangement (Fig. 1.2) and has the major advantage that any item of plant can be transferred from bus to bus without interrupting the circuit that it feeds. Again there are no particular design problems from a protection viewpoint. It is relatively easy to establish selective zones for protection of each plant item, the bus-bars and the incoming and outgoing circuits.

FIGURE 1.2 Double switching

11

BASIC PRINCIPLES

The major disadvantage is the high cost of providing circuit breaker and their associated auxiliary equipment and space requirements. This additional expenditure has to be weighed against the gain in revenue or convenience of keeping generation and other plant in service during outages of circuit breakers or bus-bars for maintenance or as a result of plant failure. Some savings can be achieved by using a combination of single and double switching. For example, it can be argued that the generator could be single switched and any maintenance requirements on the CB would be to coordinate with generator maintenance. In this case the generators shown in the double switched arrangement, two CB’s could be eliminated by single switching the generators to alternate bus-bars.

1.3.3 Mesh Layout This scheme (Fig. 1.3) has most of the advantages of a double bus layout, in that all plant can be kept in service for the outage of any one CB. But, it requires only one CB for each item of plant in its simplest form compared with the two CB’s for each item of plant in the double switched arrangement. The limit on the number of items of plant in a mesh layout is usually around six in order not to prejudice the system in the event of outages e.g., if CB A is open for maintenance and a fault occurs on Feeder 1, the system G1

Feeder 1 A

G2

FIGURE 1.3 Six circuit breaker mesh

is left with generator 2 disconnected. The mesh layout is flexible and uses less CB’s than the double switched arrangement. There are no particular

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

design problems from a protection viewpoint. It is relatively easy to establish selective zones for protection of each plant item and the incoming and outgoing circuits provided current transformers are provided with each circuit breaker and plant item and, depending on the protection selected, voltage transformers are provided in the outgoing lines.

1.3.4 1½ CB Switching A more elaborate system than the mesh system is the 1½ CB arrangement (Fig. 1.4).

FIGURE 1.4 1½ Circuit breaker

This arrangement uses more CBs than the mesh arrangement but gives better reliability for faults in the transmission lines or generation plant. Again, provided current transformers and voltage transformers are carefully located the protection arrangements is straight forward.

1.3.5 Transfer Bus Arrangement This arrangement (Fig. 1.5) is applicable to stations where there are a large number of feeders. It permits more flexibility than the single switched arrangement as any feeder may be kept in service while its CB is out of service, by using the transfer bus and connecting the feeder either in parallel with another feeder or to a spare CB. The system is more complex to operate and can require switching of current transformers and protection circuits through auxiliary switches on the transfer isolators, to maintain adequate protection on the feeders. Problems can also arise with the operation of earth fault protection when feeders are operated in parallel due to the unbalance in load currents

13

BASIC PRINCIPLES

giving rise to artificial ‘earth fault current’ in the relay circuits. Special operating procedures may be required to overcome this problem.

FIGURE 1.5 Transfer bus

1.4

THE FUNCTION OF PROTECTIVE RELAYING

The function of protective relaying is to cause the prompt removal from service of any element of a power system when it suffers a short-circuit, or when it starts to operate in any abnormal manner that might cause damage or otherwise interfere with the effective operation of the rest of the system. It achieves this through relays and protection schemes that measure power system quantities, detect a fault or abnormal condition and open (trip) appropriate circuit breakers. Circuit breakers are generally located so that each generator, transformer, bus, transmission line, etc., can be completely disconnected from the rest of the system. These circuit breakers must have sufficient capacity so that they can carry momentarily the maximum short-circuit current that can flow through them, and then interrupt this current; they must also withstand closing in on such a short-circuit and then interrupting it according to certain prescribed standards. Fusing is employed where protective relays and circuit breakers are not economically justifiable. A secondary function of protective relaying is to provide indication of the location and type of failure. Such data not only assists in expediting repair but also, by comparison with human observation and automatic oscillograph records, they provide means for analysing the effectiveness of the fault-prevention and mitigation features including the protective relaying itself.

14

1.5

POWER SYSTEM PROTECTION AND COMMUNICATIONS

PRINCIPLES OF PROTECTIVE RELAYING

The protection system can be divided into two main groups: • ‘primary’ relaying • ‘back up’ relaying. Primary relaying is the first line of defence, whereas back up relaying provides for failure of the primary protection to clear the fault or abnormality, either through failure of protection equipment or primary plant.

1.5.1 Primary Relaying Fig. 1.6 illustrates primary relaying. Circuit breaker Generator

Low voltage switchgear

High voltage switchgear

Power transformer

High voltage switchgear

Transmission line

FIGURE 1.6 Single line diagram of a portion of an electric power system showing primary relaying

Observation: • Circuit breakers are located in close proximity to each power system element. This provision makes it possible to disconnect only a faulty element. Occasionally, a breaker between two adjacent elements may be omitted, in which event both elements must be disconnected for a failure in either one. • A separate zone of protection is established around each system element. The significance of this is that any failure occurring within a given zone will cause the ‘tripping’ (i.e., opening) of all circuit breakers within that zone, and only those breakers. It will become evident that, for failures within the region where two adjacent protective zones overlap, more breakers will be tripped than the minimum necessary to disconnect the faulty element. However, if there were no overlap, a failure in a region between zones would not lie in either zone, and therefore no

BASIC PRINCIPLES

15

breakers would be tripped. The overlap is the lesser of the two evils. The extent of the overlap is relatively small, and the probability of failure in this region is low; consequently, the tripping of too many breakers will be quite infrequent. • Adjacent protective zones of Fig. 1.6 overlap around a circuit breaker. This is the preferred practice because, for failures anywhere except in the overlap region, the minimum numbers of circuit breakers need to be tripped. When it becomes desirable for economic or space-saving reasons to overlap on one side of a breaker, as is frequently true in metal-clad switchgear, the relaying equipment of the zone that overlaps the breaker must be arranged to trip not only the breakers within its zone but also one or more breakers of the adjacent zone, in order to completely disconnect certain faults.

1.5.2 Back up Relaying Back up relaying is intended to operate when a system fault is not cleared in due time because of failure or inability of the main protection or the associated protection to operate. A clear understanding of the possible causes of primary-relaying failure is necessary for a better appreciation of the practices involved in back up relaying. When primary relaying fail several things may happen to prevent primary relaying from causing the disconnection of a power system fault. Primary relaying may fail because of failure in any of the following: • Current or voltage supply to the relays • DC tripping-voltage supply • Protective relays • Tripping circuit or breaker mechanism • Circuit breaker. It is highly desirable that back up relaying be arranged so that anything that might cause primary relaying to fail will not also cause failure of back up relaying. Two principles are applied: • Remote back up • Local back up. With remote back up the back up relays are located so that they do not employ or control anything in common with the primary relays that are to be backed up. So far as possible, the practice is to locate the back up relays at a different station. Consider, for example, the back up relaying for the transmission line section EF of Fig. 1.7. The back up relays for this

16

POWER SYSTEM PROTECTION AND COMMUNICATIONS

line section is normally arranged to trip breakers A, B, I, and J. Should breaker E fail to trip for a fault on the line section EF, breakers A and B are tripped; breakers A and B and their associated back up relaying equipment, being physically apart from the equipment that has failed, are not likely to be simultaneously affected as might be the case if breakers C and D were chosen instead. Station K A

C

B

D

E

G

I

H

J

F

FIGURE 1.7 Illustration for back up protection

The back up relays at locations A, B, and F provide back up protection if bus faults occur at station K. Also, the back up relays at A and F provides back up protection for faults in the line DB. In other words, the zone of protection of back up relaying extends in one direction from the location of any back up relay and at least overlaps each adjacent system element. Where adjacent line sections are of different length, the back up relays must overreach some line sections more than others in order to provide back up protection for the longest line. A given set of back up relays will provide incidental back up protection for faults in the circuit whose breaker the back up relays control. For example, the back up relays that trip breaker A of Fig. 1.7 may also act as back up for faults in the line section AB. However, this duplication of protection is only an incidental benefit and is not to be relied on to the exclusion of a conventional back up arrangement when such arrangement is possible; to differentiate between the two, this type might be called ‘duplicate primary relaying’. A second function of back up relaying is often to provide primary protection when the primary-relaying equipment is out of service for maintenance or repair. It is perhaps evident that, when back up relaying functions, a larger part of the system is disconnected than when primary relaying operates correctly. This is inevitable if back up relaying is to be made independent of those factors that might cause primary relaying to fail. However, it emphasises the importance of the second requirement of back up relaying, that it must operate with sufficient time delay so that primary relaying will be given enough time to function if it is able to. In other words, when a short-circuit occurs, both primary relaying and back up relaying will

BASIC PRINCIPLES

17

normally start to operate, but primary relaying is expected to trip the necessary breakers to remove the short-circuited element from the system, and back up relaying will then reset without having had time to complete its function. When a given set of relays provides back up protection for several adjacent system elements, the slowest primary relaying of any of those adjacent elements will determine the necessary time delay of the given back up relays. Local back up provides for the initiation of the required action at the same location as that at which the main protection is situated. Local back up usually involves the provision of two completely independent (duplicate) protection systems including relays, current transformers, circuit breaker trip coils, etc. For many applications, it is impossible to abide by the principle of complete segregation of the back up relays. Then one tries to supply the back up relays from sources other than those that supply the primary relays of the system element in question, and to trip other breakers. This can usually be accomplished; however, the same tripping battery may be employed in common, to save money and because it is considered only a minor risk.

1.6

UNIT AND NON-UNIT SCHEMES

The purpose of an electrical power generation system is to distribute energy to a multiplicity of points for diverse applications. The system should be designed and managed to deliver this energy to the utilisation points with both reliability and economy. As there is a natural conflict between these two requirements, some compromise is necessary. Reliability in system design is very important and although it is possible to achieve very high reliability, the economics of doing so due to the excess plant required are prohibitive. Several ways of improving security of supply without adding too much to the costs are by: • improving plant design • increasing the spare capacity • arranging alternative circuits to supply loads. Also such division of the system into zones, each controlled by its own switchgear in association with protective gear, provides flexibility during normal operation and ensures a minimum of dislocation following a breakdown. In practical power systems any fault condition, especially a short-circuit, is a potential threat to a secure supply as such a condition cannot only disrupt supply to consumers but can also cause irreparable

18

POWER SYSTEM PROTECTION AND COMMUNICATIONS

damage to very expensive equipment. The importance of removing such abnormal conditions as rapidly as possible, is therefore, quite obvious. This is where the protective gear plays its part. It is the function of protective gear to detect and initiate action to remove disturbances, as soon as it is practicable. Protection is therefore applied in overlapping zones to cover the system completely, leaving no part unprotected. Another important requirement of the protective equipment is that only the faulted section should be disconnected and protective devices must therefore be selective i.e., when a fault occurs the protection is required to select and trip only the nearest circuit breakers. This property of selective tripping is also called discrimination and is achieved by two general methods. 1. Non Unit Schemes These are invariably time-graded systems that utilise information (voltages and currents) derived from a particular point on the system. Protection systems in successive zones as shown in Fig. 1.8 are arranged to operate in times that are graded through the sequence of equipments to that upon occurrence of a fault, although a number of protective equipments respond, only those relevant to the faulted zone complete the tripping function. The others make incomplete operations and reset. Distance protection and time graded overcurrent devices are prime examples of non-unit protection. End Zone Z3A Z2A Z1A Y Time

A

X

B

Z1B Z2B Z3B End Zone Zone 1 Zone 2 Zone 1 X Y

= = = = =

80-90% of protected line Protected line + 50% of shortest line Protected line + longest second line + 25% of third line Circuit breaker operating time Discriminating time

FIGURE 1.8 Protective systems arranged in successive zones

19

BASIC PRINCIPLES

2. Unit Protection These are schemes that respond to fault conditions lying within a clearly defined zone. They utilise information from two or occasionally more points in a system. In most cases a unit protection system involves the measurement of quantities at each end of the zone, and the transmission of information between the equipment at zone boundaries. Examples of unit protection are differential current relays where the current entering a zone is compared with that which leaves it. Also phase comparison carrier protection is another example.

1.7

ZONES OF PROTECTION

The protected zone is that part of a power system guarded by a certain protection and usually contains one or at the most two elements of the power system. For a non-unit scheme, the zone lies between the current transformers and the point or points on the protected circuit beyond which the system is unable to detect the presence of a fault (Figs. 1.9 & 1.10). For a unit scheme, the zone lies between the two or several sets of current transformers and the point or points which together with the relays constitute the protective system (Fig. 1.11). A

B

Protected zone

FIGURE 1.9 Protected and back up zones of a non-unit system of protection

A

C R

Protected zone

R

Y

Back up zone

FIGURE 1.10 Application of a non-unit scheme of protection (i.e. distance protection with its associated VTs on the line side of the isolator) and the standby protection zone of the normally shorted standby protection

20

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Standby protection zone Line Voltage transformer X

Y

X = Main protection relay Y = Standby protection relay

FIGURE 1.11 Protected zone of a unit system protection

1.8

COMMON TERMINOLOGIES

A list of Recommended Terminology is included at the beginning of the book. Some of the terms that are important for understanding the basic principles of the protection system are: Stability This term refers to the ability of the system to remain inoperative to all load conditions and faults external to the relevant zone. This quality is present in unit system, as they remain inoperative under all conditions, with faults outside their own zone. However, non-unit systems can respond to faults anywhere on the power system. Selectivity Protection is arranged in zones so as to assure no part is left unprotected. When a fault occurs the protection is required to select and trip the nearest circuit breakers only. Also known widely as ‘Discrimination’. In the nonunit systems the discrimination is not absolute, but it is dependant on responses of a number of similar systems, all of which respond to a given abnormal condition. However, for the unit systems, the discrimination is absolute and it is able to detect and respond to abnormal condition occurring within the zone of protection. Sensitivity This term is frequently used when referring to the minimum operating current of a complete protective system. Hence protective system is sensitive, if the primary current is low. The requirements of all relays should be quite sensitive for reliable operation. This term is usually expressed in amperes referred to the primary

21

BASIC PRINCIPLES

Load power

circuit or as a percentage of the rated current of the current transformers. Reliability Power system represents a large capital investment and in order to get maximum return it must be loaded to its maximum. The purpose of power system is not only to supply energy but also to keep the system in full operation, in order to give the best service to the consumers and earn revenue for the supply authority. Failure is not confined to the protective gear but may also be due to the failure of the circuit breaker. Hence every component involved in fault clearance can be regarded as a source of failure. Failures can be reduced by: • reliable designs • regular maintenance • site testing. Speed The objective of speed is to safeguard continuity of supply. Hence if fault can be isolated in the shortest time, the greater the system can be loaded. Fig. 1.12 shows typical values of power that can be transmitted as a function of fault clearing times for various types of faults. It can be seen that the fault involving phases has marked effect on stability compared with the line-to-earth faults. The other advantage of having fast clearance times is that unnecessary changes can occur in the system due to: • high fault arc • burn copper conductors • machine or transformer lamination weld.

Phase-earth Phase-phase Two phase-earth Three phase

Time

FIGURE 1.12 Typical values of power that can be transmitted as a function of fault clearance time

Fault currents can cause irreparable damage if allowed to continue for more than a few seconds. Hence fast fault clearance is imperative.

CHAPTER

2 Network Analysis and Fault Calculations

2.1

FAULTS ON POWER SYSTEM

A fault is the intentional or unintentional connecting together of two or more conductors that ordinarily operate with a difference of potential between them. The connection between the conductors may be by physical metallic contact or it may be through an arc. At the fault, the voltage between the two parts is reduced to zero in the case of metal-to-metal contacts or to a very low value in case the connection is through an arc. Currents of abnormally high magnitude flow through the network to the point of fault. These short-circuit currents will usually be much greater than the designed thermal ability of the conductors in the lines or machines feeding the fault. The resultant rise in temperature may cause damage by the annealing of conductors and by the charring of insulation. In a power system consisting of generators, circuit breakers, transformers, transmission and distribution circuits, it is inevitable that sooner or later in such a large network some failure will occur somewhere in the system. The probability of such failures is more on the power transmission lines, because of their greater length and bare exposure to atmosphere. A fault or short-circuit may occur due to: • deterioration of insulation • damage due to unpredictable causes such as perching of birds, accidental short-circuiting by snakes, tree branches, bush fires etc. • abnormal voltage viz., lightning or switching surges.

NETWORK ANALYSIS AND FAULT CALCULATIONS

23

However, faults must not be confused with overcurrent. The latter implies that loads greater than the designed values have been imposed on the system. Under such conditions voltage at the load point or in it vicinity may be low, but not zero. The currents in the overloaded equipment are high and may exceed the thermal design limit. Nevertheless, such currents are substantially lower than in the case of a fault. Service frequency may be maintained, but at below-standard voltage.

2.2

FAULTS TYPE

Faults may be classified as permanent or transient. Permanent faults are those in which insulation failure or structure failure produces damage that makes operations of the equipment impossible and requires repairs to be made. Transient faults are momentarily faults that may be removed by de-energising the equipment for a short period of time; short-circuits on overhead lines frequently are of this nature. In general, faults on transmission systems may be categorised under two headings: Series and shunt type. Series faults may involve single-pole switching and one or more conductor opening. These conductors may be at one busbar or at different busbars. They may occur either due to breaking of the conductors or through the action of the circuit breakers and other devices that may not result in the opening of all the three phases simultaneously. Series faults form some sort of unbalance in the system impedances and does not involve either the earth or any interconnection between phases. Shunt faults such as single-phase-to-ground, two-phaseto-ground, phase-to-phase, three-phase faults with or without ground and their combination, again form some sort of unbalance between phases or between phases and ground. These faults may occur either through impedances or direct short-circuits. The most serious result of a major uncleared fault is fire that may not only destroy equipment but may spread into the system and cause complete outage. Short-circuit may have the following consequences: • Reduction of line voltage, which will lead to the breakdown of supply to the consumer. • Damage may be caused to the elements of the system. • Damage to other apparatus due to overheating and abnormal mechanical forces. • Make the system unstable. • Reduction in voltage, causing relays with pressure coil to maloperate.

24

POWER SYSTEM PROTECTION AND COMMUNICATIONS

• Reduction in voltage on healthy feeders connected to the system having fault, which may cause consumer’s motor to draw excessively large currents. In order to achieve designs that result in a reliable system it is of importance to have some idea of the frequency of the incidence of faults on different equipment in a power system. A typical analysis of fault types is: Overhead lines 50% Cables 10% Circuit breakers 15% Transformers 12% Current and voltage transformers 2% Control equipment 3% Others 8% It has already been mentioned that the two types of shunt and series faults may produce balanced or unbalanced currents and hence they can be classified as balanced or unbalanced faults. However, in practice, majority of the faults that occur on power transmission systems are unsymmetrical shunt faults. The frequency of occurrence of these faults is as follows: Single line-to-ground 90% Line-to-line 5% Line-to-line-to-ground 3% Line-to-line-to-line 2%

2.3

FAULT LEVEL CALCULATIONS

It is usual to express the short-circuit capacity in kVA or MVA. The shortcircuit level is obtained from the product of the greatest r.m.s. current that can be interrupted and the r.m.s. voltage across the contacts immediately after final arc extinction. Short-circuit MVA = √3 × (Nominal kV) × ISC × 10–3 The Thevenin’s equivalent circuit that represents the system is an e.m.f. equal to the nominal line voltage divided by inductive reactance of XTH =

eNominal kV/ 3 j × 1000 Ω I SC

(Nominal kV) 2 = Ω Short-circuit MVA

3 in series with an

25

NETWORK ANALYSIS AND FAULT CALCULATIONS

For ease of calculation, it is usual to express all impedances on a common base. If base kilovolts is equal to nominal kilovolts, then Base MVA per unit XTh = Short-circuit MVA I base per unit I SC The elements of a power system are specified as follows: (a) Generators and transformers are shown in percentage impedance on rating. (b) Feeders and interconnectors are based on actual impedance per phase. (c) Reactors are based on voltage drop at the rated current. To convert these to p.u. values on a common base. MVA base Z% × (i) Z p.u. = 100 MVA rating

=

(ii) Z p.u. = Z Ω ×

MVA base

kV 2 MVA base V (iii) Z p.u. = R × IR kV 2 Let us consider a typical impedance value of the components of a power system as indicated in Fig. 2.1. A

B Transformer C

4 MVA 7%

D Feeder 0.009 W

E Reactor

42.5 V 750 A 3.3 kV

FIGURE. 2.1 Typical impedance value of the componet of a power system

Using a 10 MVA base Generator: 25 MVA, 30%

30 10 = 0.12 p.u. × 100 25 Interconnector: 0.04 Ω, 11 kV XG =

10 × 0.04 = 0.0033 p.u. 112 Transformer: 4 MVA, 7% 7 10 XT = = 0.175 p.u. × 100 4 XI =

26

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Feeder: 0.009 Ω, 3.3 kV XF =

10 × 0.009 = 0.0083 p.u. 3.3 2

Reactor: 42.5 V, 750 A. XR =

10 42.5 × = 0.052 p.u. 2 750 3.3

Fault at

A=

10 = 83.33 MVA 0.12

Fault at

B=

10 = 81.10 MVA 0.12 + 0.0033

Fault at

C=

10 = 33.52 MVA 0.12 + 0.0033 + 0.175

Fault at

D=

10 = 32.62 MVA 0.12 + 0.0033 + 0.175 + 0.0083

Fault at

E=

10 = 27.89 MVA 0.12 + 0.0033 + 0.175 + 0.0083 + 0.052

Tutorial problem Example 1, gives a further example of the calculations. For more complex networks with a larger number of components, the process of ‘network reduction’ to obtain the Thevenin equivalent is the same as in the above examples and is just a matter of applying normal circuit analysis theorems. Tutorial Example 2 gives a worked example to demonstrate the techniques commonly used.

2.4

LIMITING SHORT-CIRCUIT LEVELS

When a short-circuit to earth or between phases occurs the current is limited by the system impedance (which is fundamentally the impedance of the alternators, bus-bar interconnectors, transformers and feeders). The impedance of a small system with limited generator capacity may be sufficient to limit the short-circuit kVA at any point to a value that the circuit breakers are capable of interrupting. In large systems, however, additional impedance may be required. This is provided by reactors that limit the short-circuit current to a value that can be interrupted by the breakers before damage to plant occurs.

NETWORK ANALYSIS AND FAULT CALCULATIONS

27

There are three possible locations for reactors: (a) in series with the alternators (b) in series with the feeders (c) between the bus-bar sections. (a) This scheme is not commonly used as: (i) modern power station alternators have sufficient leakage reactance to withstand short-circuit (ii) under normal healthy conditions large voltage drop and power loss in each reactor occurs due to load current (iii) in case of short-circuit on or near the bus-bar end of a feeder, large fault current causes large voltage drops in the reactors which reduce the bus-bar voltage to such a low value that the alternators can fall out of synchronism. (b) These are not commonly used for the following reasons: (i) normally there are hundreds of feeder circuit breakers but only a few alternator circuit breakers. It is essential to limit the short-circuit which the feeder breakers will have to interrupt in order to reduce cost (ii) in case of fault there is large voltage drop in its reactor with small reduction in bus-bar voltage and synchronism is not lost (iii) feeder reactor do not protect the alternators against bus-bar faults, however leakage reactance should afford enough protection. The disadvantage of using feeder reactors are: (i) large voltage drop and power loss (ii) in case of number of alternators, the value of reactance has to be increased to keep the short-circuit levels within the ratings. (c) These are the most commonly used and gives all the advantages without the disadvantages of (b) above.

2.5

TRANSIENTS DURING A BALANCED FAULT

In order to consider the basic points a simple circuit model of an a.c. generator (or alternator) is shown in Fig. 2.2. The voltage e(t) is a fictitious generated voltage that is assumed R X to be dependent only on the speed of the machine and the value of the + field current. The resistance R is the e(t) – a.c. resistance of the machine winding. The reactance X = jxL is also fictitious, and its value is FIGURE 2.2 Approximate equivalent circuit chosen to fit the problem, as follows: of an a.c. generator (or synchronous motor)

28

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Xd Xd’

is synchronous reactance (steady state value) is transient reactance (3–10 cycles after sudden changes on the machine) Xd” subtransient reactance (1–3 cycles immediately after sudden changes on the machine) The various values of X are represented in Table 2.1. This value depends upon whether condition of steady state or rapid change is being considered. Suppose a short-circuit is suddenly applied at the terminals of an a.c. generator. The power frequency that flows in anyone of the windings will vary with time as shown in Fig. 2.3. The current initially has a high magnitude, falls in value rapidly in the first 5–15 cycles, and eventually comes to steady state.

1 X¢d

Steady state

Transient

Subtransient

Current

1 X²d

1 Xd Time

FIGURE 2.3 The circuit in a short-circuited a.c. generator

TABLE 2.1: Typical sequence reactance values for synchronous machines Two Pole Turbine Generator

Four Pole Turbine Generator

Salient Pole Generator with Dampers

Salient Pole Synchronous Generator Compensators Without Dampers

Low Av. High Low

Av. High Low Av. High Low Av. High Low Av. High

Xd

0.95 1.2

1.2

Xd’

0.12 0.15 0.21 0.2

Xd”

1.45 1.0

1.45 0.6

1.25 1.5

0.6

1.25 1.5

1.25

2.65 2.65

0.3

0.5

0.2

0.3

0.5

0.3

0.48 0.6

0.07 0.09 0.14 0.12 0.14 0.17 0.13 0.2

0.32

0.2

0.3

0.5

0.19

0.32 0.36

X_

0.07 0.09 0.14 0.12 0.14 0.17 0.13 0.2

0.32

0.35 0.48 0.65 0.18

0.31 0.48

X0

0.01 0.03 0.18 0.015 0.08 0.14 0.03 0.18 0.23

0.23 0.28 0.2

0.03 0.19 0.24 0.025 0.14 .018

29

NETWORK ANALYSIS AND FAULT CALCULATIONS

The phenomena that occur with a synchronous machine that make necessary use of the three aforementioned values of reactance involve transients in the field and in the rotor of the machine. An analysis of this behaviour is mathematically considered as follows: The voltage e(t) is assumed to be e(t) = Em sin (ωt + α) It can be seen that at time t = 0, a d.c. term exist whose initial magnitude may be equal to the magnitude of the steady state current term. The transient current i(t) is given by: i(t) = (Em/Z)[sin (ωt + α – θ) – sin (α – θ) exp (–Rt/L)] where Z = √(R2 + ω2L2) and

θ = tan–1 (ωL/R) The worst possible case occurs when θ – α = (i) 0° or (ii) 90°. (i) In this case the transient current is given by i(t) = (Em/Z) sin ωt The waveform for this case is shown in Fig. 2.4. (i). (ii) For this case, the current wave form [Fig. 2.4 (ii)] approaches twice the steady state maximum value just after the initiation of short-circuit. The transient current is given by i(t) = (Em/Z)(– cos ωt + exp (– Rt/L)] For small values of t, exp(– Rt/L) = 1 i(t) = (Em/Z)(1 – cos ωt)

Thus, ∴

i(t) = 2Em/Z i

i

t t

(i)

(ii)

FIGURE 2.4 Short-circuit wave form for case (i) and (ii)

Looking at the response of the Figs. 2.3 and 2.4, we can note that the reactance of the machine appears to be time varying. The symmetrical r.m.s. short-circuit currents are usually desired. These are calculated using the synchronous, transient and sub-transient reactance (Fig. 2.5).

30

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Steady state current = I = E/Xd = 1.414 Transient current = I′ = E/Xd’ = 2.83 Sub-transient current = I″ = E/Xd″ = 3.54 i(t)

Xd 2l²

lmax(t)

2l¢

x(t)

Xd¢ i(t)

2l

t

X²d

Subtransient

Transient

Steady state

FIGURE 2.5 Symmetrical short-circuit and reactances for a synchronous machine

In fault calculations the initial symmetrical r.m.s. current, which is the sub-transient current is usually desired. On occasion, the symmetrical r.m.s. current must be approximated at a time of (say) five cycles after fault occurs. Then the transient current is used as approximation. For calculations of fault current in a power system, each generator is represented as an e.m.f. E in series with an approximated reactance (usually Xd”). The reactance of all transformers and lines are inserted into the single line diagram and the short-circuit calculation is performed using any valid circuit solution method.

2.6

SEQUENCE NETWORKS FOR CALCULATION OF UNBALANCED FAULTS

Up to date, our analysis of fault currents and voltages has been based on a three phase balanced short-circuit and the equivalent impedance network

NETWORK ANALYSIS AND FAULT CALCULATIONS

31

has represented the reactances of one phase. However, the majority of faults on the power system involve one or two phases and earth. This means that the currents and voltages are no longer a balanced three phase system. The maximum unbalance occurs at the fault point where one or more phases will have their voltage reduced to near zero and fault current will flow. A technique called ‘Symmetrical Components’ is used to represent the unbalanced three phase currents and voltages as three symmetrical systems, each of which can be solved using three phase calculation techniques. Symmetrical components were first proposed for the calculation of fault currents and voltages in 1918, in a paper to the AIEE by C.L. Fortescue. They have been a major tool for the calculation of fault currents since that time. The concepts of symmetrical components are relatively easy to understand but the application, in dealing with different combinations of phases and earth for different fault conditions, can be complex and very time consuming. As mentioned previously, there are many computer packages available today to perform fault calculations and most protection practitioners would have limited need to perform complex manual calculations. Nevertheless, it is important to understand the concepts and be able to employ the techniques to small systems. An overview and some practice with the use of the techniques is given in the following paragraphs. If the reader wishes to investigate the technique further there are a number of texts that give a comprehensive treatment, including the Westinghouse, Electrical Transmission and Distribution Reference Book. Symmetrical component analysis is based on the principle that three sets of balanced (symmetrical) vectors can be used to represent an unbalanced three phase voltage or current. One set (a, b, c) using the impedances associated with the normal operation of the power system, called the positive sequence impedances, a second set using impedances that would be presented by the network to a set of vectors having a phase sequence of a, c, b, called the negative sequence impedances and a third with three vectors of the same angle called the zero sequence impedances. The sequence impedance of plant in a network can be imagined as the impedance derived from the equation of the voltage drop resulting from the circulation of the sequence current through the network impedance i.e., the voltage could actually be measured by measuring the voltage drop when the current of a particular sequence is circulated through the network element.

32

POWER SYSTEM PROTECTION AND COMMUNICATIONS

The following tabulation demonstrates the concepts: a

a

c

a

b

b

Positive phase sequence (PPS) Denoted: Ea1 Eb1 Ec1 Ia1 Ib1 Ic1

b

c

c

Negative phase sequence (NPS)

Zero phase sequence (ZPS)

Denoted: Ea2 Eb2 Ec2 Ia2 Ic2 Ib2

Denoted: Ea0 Eb0 Ec0 Ia0 Ib0 Ic0

For a phase to phase fault between phases b and c of a three phase. With the positive and negative sequence vectors having the relationship shown it can be seen that adding the two sequence vectors gives the resultant fault currents in phases b and c. There is no earth or neutral connection so the zero phase sequence vectors are zero. a b c a

c

b

Ic c

Ib

a

b

Consider an unloaded generator connected through a reactor as shown in Fig. 2.6. The equations for the components are as follows: V1 = Ea – I1Z1 V2 =

– I2Z2

V0 =

– I0Z0 la a ln Zn c

+ Ea Ec – – E b + – +

b

lb

lc

FIGURE 2.6 Circuit diagram of an unloaded generator grounded through a reactance

33

NETWORK ANALYSIS AND FAULT CALCULATIONS

where Ea is the positive sequence no-load voltage to neutral and Z0 is defined as Z0 = 3Zn + Zg 0

Zg is the sequence impedance per phase of the generator. 0 The sequence components of current are shown in Fig. 2.7. The generated e.m.f. in the positive sequence network is the no load terminal voltage to neutral, which is also equal to the transient and subtransient internal voltage since the generator is not loaded. la1 a Z1 + E Ec – – a Eb – + + Z1 lb1 b

Z1 c

Reference bus Ea – + Ve 1 Z1 a le

lc

2

1

(a) Positive sequence current paths la

(a) Positive sequence network

1

a Reference bus

Z1

c

Z1

b

Z1

lb1

Ve

Z2

a le

2

lc1 (b) Negative sequence current paths

la 0 lb0 – la 0 lc0 – la0

(b) Negative sequence network

la0

a

Reference bus

Zg

0

Zn c

Zg

2

Zg 0 b

lb

Z0 0

3Zn Ve0

Ze

0

0

a lc 0

(c) Zero sequence current paths

le 0 (c) Zero sequence network

FIGURE 2.7 Paths for current of each sequence in a generator and the corresponding sequence networks

34

POWER SYSTEM PROTECTION AND COMMUNICATIONS

The reference bus for the positive and negative sequence networks is the neutral of the generator. So far as the positive and negative sequence components are concerned, the neutral of the generator is at ground potential if there is a connection between neutral and ground having a finite or zero impedance since the connection will carry no positive and negative sequence current. Remember the negative sequence paths are the same as those of positive sequence currents. However, the impedance to the flow of negative sequence current in a rotating machine is not the same as that of the positive sequence. This difference is not significant for most fault calculations, and is usually neglected. Transformers and lines have equal positive and negative sequence impedances. The zero sequence currents are a single phase set, and must flow up through the neutral from ground; consequently the zero sequence network is different from the other two, both in the values of the impedances and the structure of the network. In apparatus that has no neutral (i.e., delta connected) or that has no connection between ground and neutral, there is no path for the flow of zero sequence current. The zero sequence currents from each of the three phases of the wye connected generator must flow through the neutral impedance Zn. The current flowing in the impedance Zn between neutral and ground is 3I0 and the voltage drop across the neutral impedance is 3ZnI0. Since the current in the zero sequence network is I0, the impedance must be 3Zn. In case of an ungrounded wye connected load, the positive and negative sequence networks are identical, whereas the zero sequence network is not connected from the neutral, since the wye is ungrounded. If the wye is grounded, then there is a path for zero sequence currents to flow, and the neutral will be connected to the reference bus. The positive and negative sequence networks for a delta connected load have the same form as the wye connected load. The zero sequence current is, however, different. No zero sequence current paths exist for line currents, however, zero sequence currents may circulate around the delta. This circulating, path is not normally energised, except in the case of third harmonic exciting currents of transformer windings in a delta winding. Third and its odd multiple harmonics are necessarily zero sequence components.

2.6.1 Transformer The positive and negative sequence networks of transformers are identical to the per phase equivalent circuit used in normal balanced analysis. The form of the zero sequence network is very much dependent on the actual

35

NETWORK ANALYSIS AND FAULT CALCULATIONS

connection of the primary and secondary. Windings in delta connections prevent zero sequence line currents, but allow zero sequence phase currents to circulate around the delta. Windings in ungrounded wye prevent all zero sequence current flow. In all cases, current flow on one side of the transformer must produce a current flow on the other side (to balance the mmf’s produced by each winding). Magnetising paths are not included, since they are very high impedance paths. Table 2.2 gives zero sequence equivalent circuit for three phase transformers with different possible type of connections. TABLE 2.2: Zero sequence equivalent circuits of three phase transformer banks Symbols

P

P

Zero-sequence Equivalent Circuits

Connection Diagrams P

Q

P

Q

P

Q

P

Q

P

Z0

Q

Q

P

Reference bus Z0 Q

Q

Reference bus P

Q

P

Z0

Q

Reference bus P

P

Q

Q

P

Q

P

Z0

Reference bus Z0 P

Q

Q

Reference bus

The phase shift introduced by delta-wye transformers has no effect on the magnitude of the fault currents at the point of fault, but it should be taken into account in determining voltages on the far side of the transformer. Include the normal 30° phase shift for the required transformation.

36

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Three winding transformers and auto-transformers pose interesting problems. On considering grounded wye-wye three winding transformers with a delta tertiary, which has the same equivalent circuit as the grounded wye auto-transformer with a delta tertiary. The tertiary is assumed to be brought out to terminals, although this is not always the case (particularly in the case of auto-transformer). The positive and negative sequence are shown in Fig. 2.8. The zero sequence network must show that no zero sequence line currents can flow from the delta tertiary, but that the zero sequence phase currents in the delta allow the bank to serve as a source of ground currents. Fig. 2.9 shows the zero sequence network for three transformer banks, together with diagrams of connections and the symbols for one line diagram.

ZHV

ZLV

ZT ZT

ZHV

FIGURE 2.8 Positive and negative sequence network for auto-transformer and three winding transformer

ZLV

FIGURE 2.9 Zero sequence network for auto-transformer and three winding transformer

On most fault calculations, the main interest in using this circuit is to calculate through faults involving ground. Thus the tertiary connection is often not shown on the positive and negative sequence diagrams. The tertiary must be shown connected to ground in the zero sequence diagram to correctly represent the fact that the bank can supply ground current to the fault. If the delta tertiary were omitted from the bank, then the wye auto-transformer would have sequence networks of the same form as those of a wye-wye two winding transformer, which can pass ground fault currents from one side to the other, but cannot supply zero sequence current to a fault.

2.6.2

Synchronous Machines

In case of synchronous machines, the only source of voltage on the system is the positive sequence. Machines will contribute to fault currents whether operating to produce voltage or operating as spinning reserve. The positive sequence impedance Z1 is the normal transient/subtransient value. Negative sequence current set up a rotating magnetic field in the opposite direction to that of positive sequence currents and which rotates around

NETWORK ANALYSIS AND FAULT CALCULATIONS

37

the rotor surface at twice the synchronous speed; hence the effective impedance, being the negative sequence impedance Z2 is different from Z1. In the absence of information Z2 is approximately 70% of Z1, as the system impedance will swamp the small difference for system fault calculations. The zero sequence impedance Z0 will depend on the nature of the connection between the star point of the windings and earth and the single phase impedance of the stator windings in series. Because zero sequence currents are all in phase, there will be considerable demagnetisation of the generator iron circuit which means that Z0 is very low, say half of Z1. Resistors or reactors are frequently connected between the star point of the windings and earth for reasons associated with protective gear and limitation of overvoltages and this completely swamps the machine impedance. Further as the machines are usually connected to the system via delta-wye transformers, they cannot supply zero sequence currents to system faults because they cannot flow outside the delta winding.

2.6.3

Induction Motors

Even though there is no external excitation, the flux present within an induction motor will contribute to the fault current, but the contribution will decay to zero. For system fault studies, only the very large motors need be considered and they may be lumped as an equivalent motor with power rating equal to the sum of the motors considered. Four times full load current of this motor may be used to give a reasonable figure for the equivalent source impedance.

2.6.4

Lines and Cables

The positive and negative sequence impedances are the normal balanced values and are identical because the impedances are independent of phase order for balanced applied voltages. The zero sequence impedance depends on the nature of the return path through the earth if no fourth wire is provided. It is also modified by the presence of earth wires on the towers. The zero sequence mutual impedance between parallel circuits can be appreciable because they share an earth return path, in addition to mutual coupling effects. Table 2.3 summarises the expressions to be used to determine fault current and the forms of interconnection of the sequence networks for various unsymmetrical fault conditions.

38

POWER SYSTEM PROTECTION AND COMMUNICATIONS

TABLE 2.3: Summary of fault current of sequence networks for various fault conditions a

a G

b

G

b

c

c

F1

F2

N1

N2

F0

F1

N0

N1

F2

F0

N2

N0

V

V Three phase fault, a–b–c

One phase to ground fault a

G

a G

b

b

c

F1

N1

F2

N2

F0

F1

F2

F0

N0

N1

N2

N0

Double phase fault, b–c

2.7

c

Double phase to earth fault

CALCULATION OF VOLTAGES IN THE NETWORK

While studying a power system, it is essential to know the short-circuit currents and kVA the system carries under various fault conditions and at different points in the system. Since the system remains balanced during symmetrical (three phase) faults, analysis can proceed on a single-phase basis. The solution can be obtained directly by normal method of reducing the network up to point of fault, expressing the system parts in terms of impedances in per unit values, and then solving the related equations by network laws. The faults can also be represented by symmetrical components and the solution obtained by method of symmetrical components. However, as earlier mentioned various types of unsymmetrical faults (both shunt and series) do occur. These unbalanced type of faults can be solved by the use of symmetrical component method.

NETWORK ANALYSIS AND FAULT CALCULATIONS

39

The faults may occur at the terminals of an unloaded generator or at any point in the system under different operating conditions; the fault may be complete dead short or it may be leakage through some impedance. In the latter case, the fault impedance comes into the circuit at the proper place depending on the type of fault when solving symmetrical component sequence networks. When considering the fault at any point in the system, the fault point should be located in various sequence impedance networks and voltages and impedances up to the point of fault in each sequence network should be considered for solution of fault current. When the network currents have been determined, the sequence voltage at any point in the network can be found by subtracting the impedance drops of that sequence from the generated voltage (if any), taking the neutral point of the network as the point of zero voltage. The voltages at any point in the network (including the fault point) are given by: V1 = Ea – I1Z1 V2 = Ea – I2Z2 V0 = Ea – I0Z0 The actual voltages on each phase can be calculated using the transformation as covered in standard Power System textbooks. [Vabc] = [A] [V012] A similar procedure may be used to calculate the potential rise on neutral points, given that there is some impedance between the neutral point and earth. Such an impedance appears only in the zero sequence network, and then as three times the actual impedance, as described earlier.

2.8

SHORT-CIRCUIT FAULT CALCULATIONS

2.8.1 Tutorial Problems and Solutions Example 1. A single line diagram of a generating station is shown in Fig. 2.10. The ratings and percentage reactances of different elements are as indicated. If a 3-phase short-circuit occurs on any feeder near transformer secondary (indicated by point F), find the short-circuit MVA fed to the fault.

40

POWER SYSTEM PROTECTION AND COMMUNICATIONS

A

B

10 MVA 30%

C

10 MVA 30%

10 MVA 10%

10 MVA 10%

5 MVA 5%

10 MVA 30%

10 MVA 10%

5 MVA 5%

5 MVA 5%

FIGURE 2.10

Solution. Choose 5 MVA as the base value. The percentage reactance of each generator on the base MVA 5 = 15% = 30 × 10 The percentage reactance of each reactor on the base MVA 5 = 5% = 10 × 10 The percentage reactance of each transformer on the base MVA 5 = 5 × = 5% 5 When a 3-phase short-circuit occurs at point F on the feeder near the secondary of the transformer, the reactance diagram will be as shown in Fig. 2.11(i). This circuit can be further reduced to Fig. 2.11(ii). A

B

(i)

C

(ii)

FIGURE 2.11 Reactance diagram for example 1

41

NETWORK ANALYSIS AND FAULT CALCULATIONS

The total percentage reactance from generator neutral up to fault point F = (10 + 5)% in parallel with (15 + 5)% =

15 × 15 +5 15 + 15

= 7.5 + 5 = 12.5% Short-circuit (MVA) = MVAbase ×

100 % Fault reactance

100 = 200. 2.5 Example 2. Consider the network shown in Fig. 2.12(i). With the plant details listed below, it is required to calculate the three phase current for a fault F on line M. The example calculations show the application of a number of techniques used in network reduction. Fig. 2.12(ii) shows the impedance network, with all impedances converted to a 25 MVA base and Fig. 2.12(iii) the steps in reducing the network to a single impedance to the fault. Note the use of the star-delta conversion. =5×

E R

GA Line H 11/66 kV

N GC

D Line K

GB

66/3.3/6.6 kV

11/66 kV

Line L Line M

G

Fault

GD 11/6.6/66 kV (i) Power system

9.38

R

12.5

A

10 20

8

B

6

Line H 8

Line K 8

2.29

25 4 8

18.18 C

5

6.04 3.96

3

Line L

Line M

(ii) Equivalent impedance network

42

POWER SYSTEM PROTECTION AND COMMUNICATIONS 12.28

10 6

16.33

20.24 5 8

12.28

20.24 5

2.5

12.2

3.33

2 16.33 (iii) Steps in reducing newtork

FIGURE 2.12 Network reduction

Note: All impedances shown as % on 25 MVA Base

11/66 kV ∆/Y, rating 20 MVA Test—with short circuit on 66 kV winding 1.1 kV applied to 11 kV winding produced full load current. D 11/66 kV, ∆/Y, rating 25 MVA Impedance 8% on rating (25 MVA) G 66/11/6.6 kV, Y/Y/∆, rating 30/20 MVA Impedances—66/11 kV, 10% on 30 MVA 66/6.6 kV, 8% on 20 MVA 11/6.6 kV, 5% on 20 MVA N 66/6.6/3.3 kV, Y/Y/∆ Impedances—HV-LV 12 %, at 25 MVA HV-MV 11% at 25 MVA MV-LV 7% at 25 MVA Generators A Z1 = j15% at rating, 40 MVA B Z1 = j20% at rating, 25 MVA C Z1 = j20% at rating, 27.5 MVA D Z1 = j8% at rating, 25 MVA Compensator R Z1 = j25% on 25 MVA Lines (all % on 25 MVA Base). Transformers

E

H = 10, K = 6, L = 8, M = 5. For this example we will use a common 25 MVA base for analysis of the circuit, so all impedances must be converted to this base. For a three winding transformer, an equivalent diagram of impedances is used to represent the three windings. For example, transformer N is represented in the network by three impedances:

43

NETWORK ANALYSIS AND FAULT CALCULATIONS 8%

3%

66 kV

6.6 kV

4%

3.3 kV

The impedances are obtained from the data provided, by solving the three simultaneous equations HV + LV = 11 HV + MV = 12 MV + LV = 7 The equivalent impedance obtained from reduction of the network, Fig. 2.12 is: 12.2% on 25 MVA base. Fault MVA

=

Fault current

=

25 × 100 = 204.9 MVA 12.2 204.9 × 10 6 3 × 66 × 10 3

= 1782 A.

Example 3. A wye connected balanced 3-phase load is shown in Fig. 2.13. This load draws 90 A from a balanced 3-phase supply. There are fuses in phase B and Y. Find the symmetrical components of the line currents. R

Y B

Fuse Fuse

FIGURE 2.13

(i) Before the fuses are removed (ii) After the fuses are removed. Solution. (i) Before fuse removal The system under this condition is balanced and current in each line is 90 A. Hence, IR = 90 ∠0°; IY = 90 ∠240°; IB = 90 ∠120°

44

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Since the system is balanced, there will be no negative and zero sequence components. IR = IY = IB 0

0

0

1 = [IR + IY + IB] 3 =

1 [90 ∠0° + 90 ∠240° + 90 ∠120°] 3

1 [90 ∠0° + 90 ∠ –120° + 90 ∠120°] 3 =0

=

IR = 2

1 [I + a2 IY + a IB] 3 R

=

1 [90 ∠0° + 1 ∠–120° × 90 ∠240° + 1 ∠120° × 90 ∠120°] 3

=

1 [90 ∠0° + 90 ∠120° + 90 ∠240°] 3

1 [90 ∠0° + 90 ∠120° + 90 ∠− 120°] 3 =0 IY = a IR = 1 ∠120° × 0 = 0 =

Also,

2

2

IB = a2 IR = 1 ∠240° × 0 = 0 2

2

The positive sequence components will have finite values. IR = IR = 90 ∠0° 1

IY = IY = 90 ∠240° 1

IB = IB = 90 ∠120° 1

(ii) After fuse removal When the fuses are removed the system becomes unbalanced IR = 90 ∠0°; IY = IB = 0 The sequence currents in the three lines are as follows: IR = IY = IB 0

0

0

1 = [IR + IY + IB] 3 1 = [90 ∠0° + 0 + 0] 3 = 30 ∠0°

NETWORK ANALYSIS AND FAULT CALCULATIONS

IR = 1

45

1 [I + a IY + a2 IB] 3 R

1 [90 ∠0° + 0 + 0] 3 = 30∠0° =

IY = a2 IR = 1 ∠240° × 30 ∠0° = 30 ∠240° 1

1

IB = a IR = 1 ∠120° × 30 ∠0° = 30 ∠120° 1

1

IR = 2

1 [I + a2 IY + a IB] 3 R

1 [90 ∠0° + 0 + 0] 3 = 30 ∠0° =

IY = a IR = 1 ∠120° × 30 ∠0° = 30 ∠120° 2

2

IB = a2 IR = 1 ∠240° × 30 ∠0° = 30 ∠240° 2

2

In spite of the fuse removal there are sequence currents in both the Y and B phases. They are just mathematical components of the currents. However the current in the phases are actually zero. IY = IY + IY + IY 0

1

2

= 30 ∠0° + 30 ∠240° + 30 ∠120° = 30 ∠0° + 30 ∠–120° + 30 ∠120° =0 and similarly IB can be shown = 0. Example 4. A 25 MVA, 11 kV, 3-phase generator has a subtransient reactance of 20%. The generator supplies two motors over a transmission line with transformers at both ends as shown in the one-line diagram of Fig. 2.14. The motors have rated inputs of 15 and 7.5 MVA, both 10 kV with 25% subtransient reactance. The 3-phase transformers are both rated 30 MVA, 10.8/121 kV, connection delta/wye with leakage reactance of 10% each. The series reactance of the line is 100 W. Note the following: • Negative sequence reactance of each machine is equal to its subtransient reactance. • Omit resistances. • Select generator rating as base in the generator circuit. • Zero sequence reactance for the generator and motors are 6% each. • Current limiting reactors of 2.5 W each are connected in the neutral of the generator and motor number 2.

46

POWER SYSTEM PROTECTION AND COMMUNICATIONS Mot 1 Gen Mot 2

FIGURE 2.14 One-line diagram

• Zero sequence reactance of the transmission line is 300 W. • Zero sequence reactance of the transformer is equal to its positive sequence reactance. Draw the positive, negative and zero sequence networks of the system. Solution. A base of 25 MVA, 11 kV in the generator circuit requires a 25 MVA base in all other circuits and the following voltage bases. Transmission line voltage base = 11 ×

121 10.8

= 123.2 kV Motor voltage base

10.8 121

= 123.2 ×

= 11 kV The reactances of transformers, line and motors are converted to per unit values on appropriate bases as follows: Transformer reactance = 0.1 × Line reactance

=

FG IJ H K

25 10.8 30 11

2

= 0.0805 p.u.

100 × 25 (123.2) 2

= 0.164 p.u. Reactance of motor 1

= 0.25 ×

FG IJ H K

25 10 × 15 11

2

= 0.345 p.u. Reactance of motor 2

= 0.25 ×

FG IJ H K

25 10 × 7.5 11

= 0.69 p.u.

2

47

NETWORK ANALYSIS AND FAULT CALCULATIONS – Eg +

– Em1 + j0.345

j0.0805

j0.164

– Em2 + j0.69

j0.0805

FIGURE 2.15 Positive sequence network

The positive sequence diagram is shown in Fig. 2.15. The negative sequence reactances are identical to the positive sequence reactances, hence the network is identical. However, note that in the negative sequence network there is omission of voltage sources. The negative sequence network is illustrated in Fig. 2.16. j0.2

j0.345

j0.0805

j0.164

j0.69

j0.0805

FIGURE 2.16 Negative sequence network

Transformer zero sequence reactance

= 0.0805 p.u.

Generator zero sequence reactance

= 0.06 p.u.

Zero sequence reactance of motor 1

= 0.06 ×

Zero sequence reactance of motor 2

2

FG IJ H K 25 F 10 I ×G J = 0.06 × 7.5 H 11 K

25 10 × 15 11 = 0.082 p.u.

2

= 0.164 p.u. 2.5 × 25 Reactance of current limiting reactors = (11) 2 = 0.516 p.u. Reactance of current limiting reactor included in zero sequence network = 3 × 0.516 = 1.548 p.u. Zero sequence reactance of transmission line 300 × 25 = (123.2) 2 = 0.494 p.u.

48

POWER SYSTEM PROTECTION AND COMMUNICATIONS

The zero sequence network is shown in Fig 2.17. j1.548

j1.548 j0.082

j0.06 j0.0805

j0.494

j0.164

j0.0805

FIGURE 2.17 Zero sequence network

2.8.2 Further Problems 1. A simple system representing a distribution line is shown in Fig. 2.18. Assume that the sending end voltage is held constant at 6.6 kV and the line impedances are as indicated. Load points are A, B and C. Find the currents and voltages at A, B and C. 2. Faults on network. Fig 2.19 shows a simple network consisting of a transformer bank supplying a load over two parallel lines on one of which a fault is assumed to exist. Neglecting the load find the voltage at each bus and the current in each line. 6 ohm

A

6 ohm

L

B

6 ohm

L

C

L

FIGURE 2.18 Normal distribution circuit with three load points X fr

Source

I

II Line A Line B X Fault

L

FIGURE 2.19 One-line diagram of a typical power system with a fault

3. General approach Using Thevenin’s theorem a general procedure for obtaining fault currents in any network can be evolved. In Fig. 2.20 a single phase impedance diagram is shown where F is the fault point and N the neutral. Find the Thevenin’s equivalent at point F in the absence of a fault.

49

NETWORK ANALYSIS AND FAULT CALCULATIONS 0.5 0.1 0.25 V

0.25 F N

FIGURE 2.20 Single phase equivalent circuit in the absence of fault

4. Calculate the symmetrical short circuit current at point F in Fig. 2.21 given the following data: M

G

F

Heat + Light

FIGURE 2.21 Power system

Generator: 6.6 kV, 20 MVA, Z = (2 + j 25)%. Motor: Induction, 3.0 kV, 6000 h.p., Z = (2 + j 20)%. Transformer 1: 6.6/13.6 kV, 20 MVA, Z = (0.4 + j 6)%. Transformer 2: 13.6/3.0 kV, 7 MVA, Z = (1 + j 7)%. Transformer 3: 13.6/0.415 kV, 12 MVA, Z = (1.5 + j 10)%. Line: Z = 0.05 + j 0.35 Ω Choose 20 MVA as the base value and neglect the heating and lighting load. 5. A 20 kVA, 440/110 V single phase transformer has a per unit reactance of 0.08. Calculate the primary current and the short-circuit kVA, when a zero impedance short-circuit occurs on the secondary whilst rated voltage is applied to primary. Change the base to 40 kVA and repeat the calculations. 6. A three-phase, 22 kV alternator having p.u. X of 0.25 at 25 MVA is connected to the primary of a three-phase transformer having per unit X equal to 0.15 at 40 MVA. Calculate the primary current and short-circuit MVA when a three-phase symmetrical short-circuit occurs on the secondary of the transformer (a) using a 25 MVA base, (b) using a 40 MVA base. 7. Calculate the short-circuit fault current and short-circuit MVA when a three phase symmetrical short-circuit occurs at F in the three phase system represented by the one-line diagram in Fig. 2.22 (a) using a 50 MVA base, (b) using a 100 MVA base.

50

POWER SYSTEM PROTECTION AND COMMUNICATIONS X = 0.3 pu Alt at 50 MVA

Alt

X = 0.3 pu at 50 MVA

X = 0.3 pu at 100 MVA

11/66 kV

Fault

FIGURE 2.22 Power system

8. Using a 50 MVA base, calculate the p.u. X and inductance of reactor ‘x’ required to limit the short-circuit MVA to 100 when a three phase symmetrical short circuit occurs at F in the three-phase, 50 Hz system represented by the one-line diagram in Fig. 2.23. X = 0.2 pu at 25 MVA

Alt X = 0.25 pu B at 50 MVA

Alt A

X = 0.00 pu at 10 MVA

33/132 kV

Fault

FIGURE 2.23 Power system

CHAPTER

3 Earth Fault and Interferences

3.1

INTRODUCTION

Safety reliability (continuity) of supply and welfare of plant are the fundamental reasons or justifications for the protection and control arrangements provided in electric power systems. Protection and control viewed in this context obviously covers a broader field than that concerned with the workings of circuit breakers relays and other devices used to sense and control faults and abnormalities: It includes consideration of aspects of system design especially system earthing; circuit breaker provision; safety earthing; prevention and/or mitigation of interference with public or private facilities or systems e.g., telecommunication systems, pipelines, railway systems, swimming pools etc. The protection engineer by virtue of their need to study prospective and actual faults and abnormalities, which effect a power system, is well placed, indeed obliged, to be active and accept considerable responsibility in ensuring that the power system with which they are concerned has been designed and is operated in a manner which maximises safety, continuity of supply and welfare of plant. This arises largely because considerations in these areas are more intimately connected with their work of providing protection systems than they are with other aspects of system design construction and operation.

52

3.2

POWER SYSTEM PROTECTION AND COMMUNICATIONS

POWER SYSTEM ARRANGEMENTS AND CONSTRUCTION FEATURES

3.2.1 General Comments Power system arrangements evolve overtime from considerations of factors such as: load size, type and location; energy source type and location; economics of voltage levels; economic, reliability and other considerations of interconnections between sources and loads for the provision of the desired degree of continuity of supply. Adequate planning will ensure that at any time there is a high probability that the system load can be carried despite the non-availability of one or more system elements due to breakdown or maintenance. However, a deeper look into how the system is interconnected and operated is required to ensure overall integrity of the system and safety, particularly during abnormal conditions ranging from overloading to faults. For example, system design considerations, particularly those of system stability and plant welfare, are inseparable from protection considerations: A too slow protection operation may precipitate instability. Furthermore when applying protection schemes at any point in a system it is necessary to consider its application in the broader context referred to above and at the same time, bear in mind that a protection scheme applied at any point in a system has a duty to the system, as well as the plant it nominally protects. The relative importance of these duties, to the system and the plant protected, is related to the voltage level and/or its position in the system e.g., at the lowest level, say for a 240 V appliance the protection is almost exclusively concerned with the appliance and its environment, whereas, at the EHV end of the scale the concern is largely with the stability of the system and consequently, in this case, the amount of money spent on protection usually greatly exceeds the particular requirements of the line or plant concerned.

3.2.2 System Types Public utility HV electric power systems are almost always three phase systems, but may be either three or four wire systems and have their neutrals either solidly earthed or earthed through an impedance. Australian HV systems are predominantly 3-phase three wire solidly earthed systems. However, some small sections of these systems usually have impedance earthing e.g., generators and some HV distribution. Other small sections need to be treated as unearthed systems during fault clearance.

53

EARTH FAULT AND INTERFERENCES

Fig. 3.1A shows some typical arrangements used to connect power sources to loads. The single line system diagram is amplified in the insets to show the three phase arrangement and the system earthing. Inset 1 shows a solidly earthed system being fed from the output side of the transformer by virtue of its neutral being connected directly to earth. This arrangement could be converted to impedance earthing by inserting an impedance (inductance or resistance) in the connection to earth. Other power & terminal STNs CCT

Main transmission

BKR Power station

Subtransmission

Zone substation

1

If B W R 1 If

CCT BKR

1

If

If

N

B W R

If Resistance to Earth

If

Inset1 If Distribution substation

Fault current path HV distribution

LV customer

11

IR

11 IW 11 IB

B W R

IR¢ IW¢ IB¢ Metal structures

IR IW IB LV Earthing system

Station earthing GRD

HV Earthing Inset 2 system Load current flow 3-phase system

FIGURE 3.1A Power system diagram

B W R N Fuses

Customer load

54

POWER SYSTEM PROTECTION AND COMMUNICATIONS

3.2.3 Protection/Safety Implications of System Arrangements It can be seen from Fig. 3.1 how the high voltage winding of a zone substation transformer can be back fed from the lower voltage side and how under these conditions the part of the system it feeds would be unearthed e.g., with the high side B/T open and only a radial line fed from the bus we would have an unearthed system feeding out into the public domain. Whilst this type of condition is not usually created deliberately, because operational authorities are aware of it, care has to be taken that if it does occur during a fault clearance sequence, protection exists to detect it and control it. The hazard to be avoided either by protection operation or by suitable operating procedures is a conductor on the ground fed from an unearthed system i.e., a condition where no fault current flows. The type of system earthing used, greatly influences the currents and voltages associated with earth faults and consequently the safety considerations and the characteristics required of the protection schemes. Recently impedance earthing of more HV distribution systems has become necessary, because of safety/protection problems associated with conducting overhead line support structures, e.g., concrete poles. In this context it should be noted that replacing wood poles (virtually a double insulated arrangement) with conducting poles markedly increases the incidence of high current earth faults and with it voltage disturbances to other parts of the system, thus imposing a requirement of faster fault clearance and/or reduction of fault magnitude.

3.2.4 System Earthing and Equipment Earthing Earthing systems serve two distinct but related purposes: System and safety earthing.

System Earthing System earthing involves connecting the neutral points of transformers, generators, reactors, capacitor banks, etc. either directly to earth or through an impedance, in order to hold the voltages of the system substantially symmetrical with respect to the earth and to provide a path for certain earth fault current. It is possible to operate a high voltage system without having the system earthed, however faults must then be detected by the displacement of the voltages of the phases of the system with respect to earth. With this arrangement the location of the fault usually involves a complex set of operating procedures. Where the system neutrals are earthed (directly or through an impedance) current operated earth fault protection can provide a fast and/or sensitive means of locating and clearing an earth faults.

EARTH FAULT AND INTERFERENCES

55

The introduction of an impedance into the earthing of neutrals will limit the magnitude of the earth fault current and consequently reduce earth potential rises. This is the subject of the next section. Another effect of the introduction of earthing impedance is increased difficulty in detecting earth faults within the transformers or on the output side buses of zone substations and in providing back up from the station, or stations supplying the zone substation. Practical solutions of these problems may involve one or more of the following: Limited choice of system arrangement, more circuit breaker on the input side of the zone substation and signalling to the source stations. Zone substation protection is covered in another section.

Safety Earthing This involves connecting to earth all the conducting metal cases, frames, supporting structures etc. associated with the generation, transmission, distribution, utilisation of electric power, to ensure that in the event insulation failure (fault) these cases, frames, etc. will be held at, or as close as practicable to the potential of the general mass of the earth. Otherwise these cases, frames, etc. would assume the voltage of the phase conductor where the insulation failed and present a hazard to life. In practice many cases arise where difficulty is experienced in providing a sufficiently good connection to earth to ensure the elimination of the possibility of hazardous voltages appearing on equipment frames, etc. during faults. The foregoing remarks are made in the context of protection of high voltage systems, however, the principles involved have application in low voltage systems and indeed where common or bonded HV and LV earthing systems are used safety requirements of the LV system will be a major consideration in the HV earthing system design. The philosophy in designing LV system earthing has emphasised keeping the impedance specified through resistance limitations of connections within them low enough to operate the protective devices provided (CB’s or fuses) and keep voltage rise on any part of the earthing system low enough to avoid hazard to life. The safety aspect has been enhanced by the availability of more reliable and low cost RCD's which because of their very high sensitivity and rapid operation can prevent electrocution. There is no equivalent detection and fault clearance equipment available for HV systems consequently emphasis has to be placed on avoiding hazardous voltages and preventing direct contact.

56

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Various forms of earthing systems are depicted in Fig. 3.1B.

Bon

d

utral

e LV n

N

A

Conducting pole (concrete) or metal

Bond

May or may not have a supplementary earthing system LV earthing system HV earthing system (case of separate HV & LV earthing systems bonded for conservation to CMEN)

(a) Some typical earthing systems—CMEN (Common multiple earthed neutral) system HV cable

Station boundary Buried grid

Earthing electrodes LV earthing system

(b) Some typical earthing systems— earthing for large station (Note: Hazard zone may extend beyond station boundary)

(c) Some typical earthing systems— one type of kiosk substation earthing systems

FIGURE 3.1B

57

EARTH FAULT AND INTERFERENCES

3.3

EARTH POTENTIAL RISE

3.3.1 Occurrence Current flowing through the resistance to earth of an earthing system, or the resistance to earth of the medium of earth contact, causes the earthing system, or point of contact with the earth, as the case may be, to rise in potential above that of the general mass of the earth, i.e., above the potential of remote points. The gradients of the potential drop away from the fault point and the source station earthing system will be steep near the earthing system and the fault point and slight well away from them. The step and touch potentials adjacent to the earthing system will be the critical ones with respect to the safety of people who are in the vicinity of earthing system when an earth fault occurs, nevertheless, the total rise of potential above remote earth is of concern for people working on metallic circuits, e.g., telephone circuits, passing through that part of the gradient area where the potential rise is significant in relation to personnel safety. The total rise is the main concern in respect to the rating and treatment of the circuits entering the hazard zone and/or station. The total rise of potential is termed the transfer potential. Fig. 3.2 depicts gradients and transfer potentials. Hazard zone surrounding substation

Hazard zone surrounding fault point

If Station VR E earth grid (Resistance to E earse RSE) (Remote point) Fault point Telephone (Resistance to earth RFE) cable

FIGURE 3.2 (a) Geographic arrangement V EPRFP

A

Station EPRS

Fault point

E VAE Remote earth V

FIGURE 3.2 (b) Voltage relative to remote earth

58

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Power system impedance Power source voltage

Fault point

IF

VS

Station earth grid

RSE

EPR of station grid relative to REM earth

RFE

EPR of fault point relative to remote earth

Remote earth

FIGURE 3.2 (c) Simplified electrical circuit transfer to potential

3.3.2 Magnitude Various factors which influence the magnitude of earth potential rises are discussed in the following paragraphs.

Earth System Resistances The resistance to earth of the earthing system depends upon its size and arrangement and the soil resistivity. Resistances to earth of earthing systems vary from small fractions of an ohm (0.001 Ω) for a large power or terminal station to perhaps several hundred ohms for an isolated distribution structure without supplementary earthing, e.g., a concrete pole in an area of high soil resistivity.

Station Earthing Even low earthing system resistances may be associated with significant voltage rises if the fault current is high enough, e.g., the earthing system of a particular zone substation with a 40 m × 40 m earthing grid in an area with 10 ohm metre soil resistivity (resistance to earth 0.2 ohms) would rise to 2400 volts above remote earth for a maximum fault current of 12,000 amps. [(refer Fig. 3.3a)] Constant voltage contours Earthing grid 40 × 40 m

Hazard zone may extend outside station boundary

FIGURE 3.3 (a) Zone substation hazard zone

EARTH FAULT AND INTERFERENCES

59

The hazard zone in this case would extend roughly 30 to 40 metres beyond the edge of the grid. In cases where a very low resistance is obtained there may be no hazard zone, despite large fault currents, e.g., a case in point with a resistance of 0.006 ohms gives 96 volts rise above remote earth for a current of 16,000 amps. In areas of high soil resistivity, extensive earthing systems similar to those referred to above may have quite high resistance to earth and, consequently, be subject to quite high voltage rises, necessitating measures to control both the rise of the grid above remote earth and the steepness of the voltage gradients (particularly those at the edge of the grid). Any non-homogeneity in the soil will result in distortion of the uniformity of voltage gradients which would otherwise be expected, e.g., for a simple symmetrical grid. Also more significant distortion of the constant voltage contours and gradients may occur due to buried conductors, e.g., high voltage underground cable metal sheaths and/or armouring [refer Fig. (3.3b)]. Earthing grid 40 × 40 m

FIGURE 3.3 (b) Distortion of hazard zone by UG cable sheath in contact with earth and grid

Furthermore, other metal circuits such as pipelines, running in close proximity to earthing systems, will distort the constant voltage contours and hence gradients. Where services, e.g., water supply or communication circuits enter stations, insulated sections, interruption of sheath continuity and transformer isolation of cable cores, as appropriate, are employed to avoid transferring the EPR voltages to points outside the hazard zone to minimise distortion of voltage gradients and to avoid the possibility of substantial earth fault currents being carried by these circuits. Where high voltage underground cables are required, distortion of the voltage gradients can be avoided by using substantial plastic sheathing and earthing metal sheaths and armouring etc. only at the station end.

Isolated Structure Earths Commonly encountered resistance values lie in the range 1 to 50 ohms.

60

POWER SYSTEM PROTECTION AND COMMUNICATIONS

The extent of the hazard zone will depend on the fault current available, the soil resistivity, the earthing system geometry and the safety criteria used. For the purpose of illustration we will use the criteria adopted by ESAA and Telecom Australia in the ‘Earth Potential Rise Code’(1). The relevant criterion for a distribution system earthing system is an EPR of 430 volts. For a high reliability system an EPR of 1000 volts is acceptable, without special precautions being taken. Fig. 3.4 illustrates the case of a conducting distribution or subtransmission pole, e.g., a concrete pole, in homogeneous soil. Voltage above remote earth (EPR) 1m VT rl for d ® r ERP = 2pd (See pS of code) Voltage gradient E1000 1 mm

lf

d Hazard zone VT

I

I

VS

Surface of earth

0 r (a) Constant voltage contours

d1000 d430 (b)

d Distance from structure

22 kV r = 100 Wm

20

d430 volt

VS

E430

15 10 22 kV r = 10 Wm 11 kV r = 10 Wm

5 0

5

10 15 20 kM Distance from structure (Fault levels at source 22 kV 500 MVA 11 kV 350 MVA)

(c)

FIGURE 3.4 Variation of extent of hazard zone with soil resistivity and fault level for metal pole without supplementary earthing system

Note the considerable influence that fault current and resistivity have on the extent of the hazard zone. The physical arrangement of the earthing system and the differing resistivities of the layers of soil, considerably modify the voltage gradients, the step and tough potentials at the surface and the location and shape of the 430, 1000 and 1500 volt hazard zone contours (refer Fig. 3.5).

61

EARTH FAULT AND INTERFERENCES

Wood pole

Transformer

Insulated earth lead

Earthing electrodes

Buried earthing system

FIGURE 3.5 Pole mounted substation earthing

Control and Mitigation of Earth Potential Rises and Step and Touch Potentials Power authorities use safety criteria similar to those used by Telecom to determine maximum step and touch potentials and earth potential rises. These are discussed in more detail in the next section of these notes. It is only within ‘hazard zones’ that step and touch potentials are significant. The control of these potentials to within acceptable limits is usually the major objective in the design of earthing systems for HV installations, since it is frequently economically impossible to keep the potential rise with respect to remote earth to a safe value. As a consequence, methods of working on power circuits which run to remote points, are designed to ensure that personnel are not subjected to transfer potentials caused by faults on adjacent circuits. Fig. 3.6(a) illustrates a method of isolating workmen from transfer and step and touch potentials. Fig. 3.6(b) illustrates an arrangement used to facilitate work on communication circuits entering a substation surrounded by a hazard zone. In Fig. 3.5 the advantage of wood poles in respect to the avoidance of touch potentials is clearly evident. The insulation of earth lead can also help in reducing potential across the surface by deeper burial of the electrodes.

62

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Live circuit Circuit under access Safety earthing arranged to keep out of service & pole at same potential if live circuit faults to pole

Insulated ladder

(a) Precaution for power authority work Isolating links

Insulated box

Cable to telecom

Insulating met station earth grid

Cable to substation

(b) Work on telecom cable entering substation

FIGURE 3.6 Safe working arrangements for work inside a hazard zone

Earthing systems for large substations can and are designed specifically for each application taking into account site conditions. The design is often verified by current injection tests after installation of the earthing system. In the case of distribution earthing systems this practice is impracticable and standard designs have to be used. The results achieved can vary widely from expectations. Furthermore it is usually not possible to get a satisfactory standard for conducting poles. Methods of reducing EPR’s and step and touch potentials for conducting structure cases as shown in Fig. 3.2 will involve supplementary earthing systems and/or overhead earth wires to common the earthing systems of a number of adjacent structures, with a view to reducing the resistance to earth and distributing the fault current through a number of adjacent earthing systems. Reduction of earth fault current and hence, reduction of potential rises can be achieved by inserting impedance between the transformer neutrals and the station earth grid.

EARTH FAULT AND INTERFERENCES

63

Justification for adopting these measures and solutions to some of the protection problems they introduce, will be apparent after examining the safety requirements and difficulties in realising them which are discussed in the next section of these notes.

3.4

SAFETY CONSIDERATIONS

3.4.1 Nature of Hazards Associated with High Voltage Power System Earth Faults The Step, Touch, Transfer and Induced Voltages associated with HV earth faults very seldom last longer than a few seconds. Earth faults involving high current, i.e., those involving significant step, touch, transfer and/or induced voltages, are usually cleared in less than one second. Since these voltages are by nature transient, the prevention of electrocution is concerned with avoiding ventricular fibrillation rather than let-go currents, as is the case with low voltage circuits, (where the voltage frequently remains applied to the victim and asphyxiation will most likely be the cause of death). Consequently the currents associated with HV faults which can flow through the human body, without threatening life, are considerably higher than the let-go current. The current allowable in any case is a function of: the duration of the shock; condition of application (arm to arm, arm to leg etc.); body weight; health factors.

3.4.2 Assessment of Risks The relationship between the available voltage and the resultant current will be a function of: body resistance; contact resistance and voltage [body resistance is a function of voltage and is approximately 1000 ohms at 250 volts (2)]. Contact resistance will vary widely with the type of contact and factors such as perspiration. When prospective EPR’s and induced voltages are determined for typical existing earthing systems associated with HV distribution (e.g., substation earthing systems), it is frequently found that they exceed those required to cause fibrillation, yet there is virtually no historical evidence of death or injury from this reason. The major cause of this discrepancy is the low probability of somebody being present when a fault occurs. If conducting poles eventually replace all wood poles then the number of earthing systems will have increased about ten-fold, changing the probability dramatically. Power system engineers have opted to make this type of installation inherently safer. Various national and international standards, codes and technical papers are available to enable policies and practices to be determined. Some of these are listed in the references. The graphs as shown

64

POWER SYSTEM PROTECTION AND COMMUNICATIONS

depict allowable touch voltage versus time as specified by some of these standards and codes (refer figure given below). 10

(1) rs = 10000[W Metre] (2) rs = 10000 (3) rs = 5000 (4) rs = 5000 (5) rs = 1000 (6) rs = 1000 (7) rs = 100 (8) rs = 10 (9) rs = 100 (10) rs = 10

4

1 2 3 4

6 7

8

9 10 101 –2 10

10

–1

0

10 Time (Seconds)

10

1

10

IEEE STD 80–1976

5

102

IEEE STD 80–1961

Touch voltage (Volt)

103

2

FIGURE 3.7

3.5

APPLICATION OF SAFETY CRITERIA

3.5.1 Control of Touch Potentials By way of example let us use AS2007 and see what the implications are in relation to commonly encountered fault levels and protection operating times. A clearance time of 0.1 sec. (the fastest practical time for subtransmission and distribution) would allow 300 volts max. for touch potentials; a clearance time of 1 sec. would allow 120 volts max. Consider an earth fault on a conducting pole in a 22 kV feeder 1 km from a zone substation with a max. fault level of 500 MVA. Assume the pole has a resistance to earth of 10 ohms. The fault current will be approximately 1200 amps. and the touch potential will be about 7 kV. If the pole was 10 km from the zone substation the fault current would be about 800 amps. and the touch voltage about 5 kV. Reduction of earthing resistance to say 1 ohm would result in voltages of about 3 kV and 800 volts respectively. A resistance of 1 ohm is impractically low in most cases for a pole earthing system.

EARTH FAULT AND INTERFERENCES

65

Commoning all pole and LV earths will reduce the touch voltages to about 800 and 200 volts respectively. Reducing the fault current by installing a resistor between the transformer neutrals and earth, to limit the maximum fault current to say 2000 amps, together with CMEN (common multiple earthed neutral), will reduce the prospective voltages to about 150 and 100 volts respectively, i.e., within the limits previously postulated, when typical clearance times apply. The comparable voltages for 11 kV, and 6.6 kV systems for faults distant 1km stations with maximum fault levels of 350 and 250 MVA respectively and no CMEN or EFCL (earth fault current limitation) are of the order of 2 kV and 1.5 kV respectively. Still a problem. Subtransmission may also use similar poles and the maximum fault currents are often high so solutions have to be found. In some respects the difficulties are greater and CMEN and EFCL may not provide a solution. In the case of main transmission other factors enable economically practical solutions to be obtained e.g., specifically designed tower earthing systems and ground wires are required for other reasons; the lines are run in easements; faults are cleared rapidly; faults are rare.

3.5.2 Control of Step Potentials These will usually be the major concern only where touch potentials have been eliminated by appropriate insulation.

3.5.3 Control of Transfer Potentials Communication circuits and other metallic services entering or passing through hazard zones are prevented from transporting potentials out of the hazard zone by suitable isolation and insulation, as mentioned earlier. Where the means of transport could be the neutral of a CMEN system the transfer potential may need to be kept within the voltage limits for touch potentials.

3.6

DEMANDS ON PROTECTION ARISING FROM SAFETY, RELIABILITY AND INTERFERENCE CONSIDERATIONS

3.6.1 General Comments Sensitivity, reliability and security are the characteristics required of the protection systems installed on a power system, if the inherent reliability of the elements of the power system, is to be realised, as a power system operating safely, to provide a high degree of continuity of supply to its customer.

66

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Continuity implies more than simply remaining connected, it also implies maintenance of voltage and frequency and indirectly selectability and discrimination by the protection systems, together with security against mal-operation, speed of operation and reliability. Sensitivity and reliability are the main attributes required for safety. Protection equipment and systems generally exhibit a high degree of reliability: Failures occur on only a few per cent of occasions when protection is required to operate. However, this is not good enough since the consequences of failure to operate for many fault conditions would be catastrophic. It is, therefore, necessary to provide back up. Generally speaking it is more difficult to provide back up than primary protection. Measures required for safety such as EFCL add greatly to the difficulties and cost of providing protection. If EFCL had to be added to an existing large system the total cost would most likely run to hundreds of millions of dollars. Some illustration of this is contained in the following paragraphs.

3.6.2 High Voltage Distribution Systems There are always conflict of interest between the requirements phase fault sensitivity and loading and between earth fault sensitivity and out of balances in the system. For example, on a long radial feeder there may be heavy load near the start which will effectively limit the sensitivity of the phase fault protection and make it difficult to see faults at the remote end of the feeder. Also, if there were fuses in the backbone of the feeder with long lines beyond them, earth fault sensitivity will be restricted (when 1 fuse is blown there will be an unbalance of capacitance in the circuit due to the missing phase conductor and consequently zero sequence current in the earth fault relay). In both cases safety and welfare of the feeder can only be assured, if consideration of protection requirements are an integral part of design process for establishing the line and operating it as part of a system where load transfers and alternative feeds apply. E/F sensitivities, in the range 5–10 amps primary, can be achieved easily, for both primary and back up protection. Greater sensitivity can be achieved with short feeders and for longer or more complex feeders by careful attention to distribution design. The addition of resistors to limit the maximum earth fault current has an insignificant effect on feeder protection design, however, it considerably increases the difficulty of protecting the plant within the zone substation.

3.6.3 Zone Substation and Sub-transmission Line Protection Differential, distance and other protection schemes for zone substations and sub-transmission are dealt with comprehensively in other lectures and

67

EARTH FAULT AND INTERFERENCES

all that is intended here is to discuss aspects of the philosophy of application. Figure 3.8 depicts a zone substation switching arrangement intended to ensure reliability (or continuity) of supply to the feeders despite the loss of either an incoming line or a transformer. Obviously separate protection is required on each element (separately switched portion) of the system to realise the inherent reliability of the system. Shorting switch (Fault make capability)

Isolation of cap bank neut

FDR

FDR

(a) Arrangement of NER’s in a fully switched sub with line CBs and no pilot cable system

Master & BU E/F

X & Y Diff.

Res E/F (b) Application of restricted earth fault protection (a differential protection covering earth faults on the star connected winding and its connection)

FIGURE 3.8

68

POWER SYSTEM PROTECTION AND COMMUNICATIONS

The reliability of supply to the feeders is jeopardised by protection equipment or circuit breaker failure or inadequacy to cope with all the prospective fault conditions. The design process must begin with a thorough examination of all the prospective fault conditions for normal and abnormal system conditions, taking into account conditions applying during the sequences of fault clearance, failures of relaying equipment and circuit breakers, system stability requirements (if applicable), short and long term ratings of lines and plant (protection to be stable for all loads up to line or plant ratings or maximum expected load and in some situations responsive to overloads). Figure 3.9 depicts a situation where the primary protection (differential and gas) has some local back up relaying (overcurrent) but would use distance protection at the source station to cover failure of the line CB, since it would usually be possible to detect most faults on the low side of the transformer under radial feed conditions from the remote station.

Diff O/C 20 MVA Gas MEF 1f – G Fault

FIGURE 3.9 Typical pilot for fully SW subs

The addition of a resistor to the transformer neutral circuits, as depicted in Fig. 3.10 eliminates overcurrent and the remote distance protection as satisfactory back up necessitating duplication of the differential protection and supplementation with restricted earth fault and back up earth fault. (Note: for the case of a 66/22 kV 20 MVA transformer with an NER limiting earth fault current to 2000 amps the resulting current on the 66 kV side is approximately 400 amps, but the maximum load current could be as high as 350 amps with forced cooling i.e., no margin to set an overcurrent relay). Circuit breaker failure protection would have to be achieved by signalling to the remote end. An alternative to signalling may be to use a shorting switch on the resistor.

69

EARTH FAULT AND INTERFERENCES

Dup diff.

20 MVA 66/22

Gas MEF 1f – G

BU RCS EF EF

Dup diff. REF

FIGURE 3.10 Likely arrangement after inclusion of NERs

It is possible that the arrangement depicted in Fig. 3.9 may be protected by a protection scheme similar to that of Fig. 3.10 if high speed back up was required, say, because of system stability requirements. This would probably be the case with most main transmission stations. Note: Local back up coupled with back up for CB failure will achieve the minimum disconnection of healthy plant or lines when failures occur and will do so at a faster speed than remote back up. Thus it will contribute to greater reliability of supply.

3.6.4 Zone Substation Feeder Protection Fault Current Paths The fault current paths for earth faults fed from zone substations are depicted in Figs. 3.11, 3.12 and 3.13 for various transformer winding connections and neutral earthing arrangements. I66

I22 max 5 KA

FIGURE 3.11 Fault currents obtained with NER for a 66/22 kV 20 MVA transformer

70

POWER SYSTEM PROTECTION AND COMMUNICATIONS I66 =

I22 3n

max abt 400°C n = Tr ratio

I22 Max NB. 20 MVA TRS may have short time load ratings up to 40 MVA i.e. 350

FIGURE 3.12 Fault currents obtained without NER for a 66/22 kV 20 MVA transformer Note: For 66/11 kV 20 MVA transformers currents on 66 kV side for NER case are half those for 22 kV case) 1 I ² 2 F 1 I ² 2 F IF² IF¢ IF¢

IF

IF

IF (a) Single phase to earth fault fed through a star/delta/star transformer with unearthed hv star winding

(Note: No zero sequence currents on supply side of transformer No scope for back up for light earth by monitoring currents on high side of transformers No LFI on high side of transformers as a consequence of low side faults EPR of station earth grid). Si0IF¢² IA IB IC IF²

IF

IF¢² (b) Single phase to earth fault fed through a star/delta/star transformer with hv star winding earthed

IF IF

71

EARTH FAULT AND INTERFERENCES

(Note: No zero sequence currents on high side for low side fault May be a need for co-ordination of E/F prots on high and low sides LFI and EPRs may need to be considered). R Y B

Ic¢ Ib¢

Ib

Ic¢

Ia IE

IE

(c) Two phase to earth fault fed through a delta/star transformer

(Note: No zero sequence currents on high side for low side fault. Max current not as high as for single phase to earth fault. No LF1 on high side.) FIGURE 3.13

Except for the case of an earthed star connection on the input winding of the transformers, currents flowing in the earth are confined to the low side of the transformer. The most common arrangements for zone substations and HV customer substations fed from sub-transmission involve unearthed HV windings. Note: 1.

2.

Main transmission systems usually have earthed input and output star connected windings consequently ‘reflected’ or compensating currents flow in the earth for other parts of the system in response to a fault on element of system, e.g., in the system depicted in Fig. 3.13(c) compensating currents will flow in both the sub-transmission and main transmission systems (albeit of low magnitude compared with fault current). Distribution substations have unearthed HV windings and customer generators and SWER systems are isolated by transformers with unearthed supply side HV windings. Fig. 3.14 depicts a typical HV distribution system arrangement.

Protection Implications of System Loading and Earthing Arrangements The essential features of these system arrangements which impinge on safety, reliability and interference considerations are: (a) Loads on HV distribution systems are effectively connected between the phases and consequently current flows in the earth only when there is an earth fault, hence earth fault protection sensitivity is limited only by: (i) small earth current caused largely

72

POWER SYSTEM PROTECTION AND COMMUNICATIONS

by small out of balance of line to ground capacitance and (ii) CT errors. (b) Under normal system conditionals there is only one point at which the system is earthed, hence there can be no currents in the earth arising as a consequence of source voltage imbalances and thus sensitive earth fault protection can be applied. This would not be the case if there were two or more points at which transformer neutrals were earthed. Note: Where two sources are paralleled to transfer a feeder from one zone substation to another it will often be necessary to suppress the sensitive earth fault protection whilst the sources are in parallel. In cases where two feeders from the same source are paralleled to effect transfers of load master control of the feeder earth fault protections can be used to avoid the need to suppress protection during the switching operations. Suppressing protection during switching operations is an undesirable procedure since faults can be precipitated by operating equipment e.g., an insulator may break when an isolating switch is operated.

(c) Since earth currents will in most cases be seen as such only on the output side of zone substation transformers (except where there are earthed star windings on the input windings of the transformers) back up for failure of the protection must be done locally and the broader implications in respect to the independence of the primary and back up protections must be considered if the success rate in the detection and clearance of faults is to be maximised. These latter remarks also apply to faults not involving earth and to high current earth faults, however in these cases remote back up can often be achieved and complete independence of the detection and clearance equipment is assured (relays, CTs, auxiliary supplies and circuit breakers). In the arrangement of sensitive primary the (master earth fault scheme) and back up earth fault protection depicted in Fig. 3.13 the independence of the fault detection functions of the primary and back up protections are obvious. Independence of the fault clearance arrangements is achieved by using the bus tie and transformer CBs; for back up for CB failure and using independent DC supplies for powering primary and back up relaying and CB tripping.

73

EARTH FAULT AND INTERFERENCES DC supply for parallel prot Master E/F FDR E/F Master BU E/F E/F

FDR E/F

DC supply for BU

TP FDR

BU E/F TP TR + B/T CBs

o/c

Zone substation

HV customer (may include generators) substation LV Distr.

LV customer IL¢

LV Distr.

SWER ISOL, substation IL

LV customer SWER substation

FIGURE 3.14 Typical arrangements for 3-phase hv feeders showing (i) hv feeder system earthed at one point only and all loading connected phase to phase (ii) primary and backup E/F prot.

Calculation and Analysis of Earth Currents Calculation of prospective fault currents using symmetrical component analysis is dealt with in another section however to reinforce the description of current flows given in, Section on ‘Fault Current Paths’ described earlier, Fig. 3.15 depicts graphically the symmetrical components and the real currents for a single phase to ground fault fed through a delta/star transformer.

74

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Z1s Equiv Z2s imp of system

Z1T Z2T Z0T

c¢

Z1F Z2F Z0F

b¢

IF

la¢ ia¢

n

ia¢

1

a

iaa iba ica

IF

2

¢

ib

1

b

lb¢

a¢

ic¢

c

If

1

ib¢

2

ia¢

ib¢ ia¢

c2

ic

1¢

ib¢

2

ia¢

RF i¢

2

1

ia

ic

ib1

2¢

ib¢

2

ia = ia2 = ia0 =

ic¢ = 0 Ean

Z1 + Z2 + Z0 + 3RF IF = Ia = IN = ia + ia + ia0 2 1 Z1 = Z1s + Z1T + Z1F 1

ia ib ic 0 0

ia 2

1

ic1

ib 1 ib

0

ib2

ic2

ic 1 ic

0

ib 2 IB = 0

ic 2 IC = 0

ic 1 ib 1

Ia

ia 1

Z2 = Z2s + Z2T + Z2F Z0 = Z0T + Z0F

FIGURE 3.15 Single phase to earth fault for fed through a delta/star transformer

Problems Associated with High Impedance in the Path of the Fault Current Not all faults can be detected because in some instances the magnitude of the fault current will be less than spurious currents arising out of system out of balances. One type of example is a failed insulator on a wooden pole which may result in a pole fire before there is sufficient current to cause protection operation. Another more serious problem arises when a fallen conductor is back fed from a lightly loaded distribution substation. A case involving a single phase transformer is illustrated in Fig. 3.16 where it can be seen that for even a fully loaded 10 kVA transformer the fault current is limited to about 60% of the full load current of the transformer i.e., about 0.3 amps for a 22 kV case. Thus to get current above a minimum operating current of 5 amps for the earth fault protection requires a fairly sizeable load.

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EARTH FAULT AND INTERFERENCES

IF IF = 0.6IL

IF

IL = Normal load current

Load

EF – E IF

IF

FIGURE 3.16 Conductor on earth back fed from single phase substation

Fortunately this case has a low probability but it does illustrate the desirability of arranging the system to minimise spurious currents and hence be able to use low protection settings. One of the measures which could be taken is to avoid long sections of fuse protected line: the blowing of one fuse will unbalance the phase to ground capacitances and increase the spurious earth currents.

3.6.5 Main Transmission Systems There is obviously more need and justification for maximising the reliability, security (stability) and selectability of protection systems in this type of application. Duplicated protection with back up for CB failure together with various enhancements to achieve faster clearance are essential. Automatic monitoring and self checking arrangements are quite common.

3.7

INTERFERENCE ON SUPPLIED AND OTHER SYSTEMS

3.7.1 Preamble There are numerous ways in which electrical interference can occur between electric power systems and other systems and between parts of the power system. Examples of interference with other systems are: Transferred and/ or induced 50 Hz voltages during earth faults; injections of high or low voltage due to direct contact between the systems; TV and radio interference due to faulty line hardware; induction into communication circuits of 50 Hz fundamental and harmonic voltages from load currents in the power system. Examples of interferences within the power system are: Voltage distortion due to fluctuating loads (e.g., arc furnaces, traction); induction

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into in service and out of service circuits during faults on adjacent circuits; EPR's in the vicinity of out of service lines, etc. which are under access for work; interference by low and high frequency noise signals generated by faults and their associated arcs, in the power system's protection and control circuits. As mentioned earlier the protection engineer is usually in a good position to deal with these problems because of the type of studies he must do, to set and examine the performance of his equipment. Indeed it is absolutely vital, in the interests of reliability of supply, that the protection and control systems are immunised against interferences. Some of these interferences are examined in the following paragraphs.

3.7.2 Induced Voltages and EPR’s Imposed on Other Systems Induction in Telecommunication Circuits Fig. 3.17 depicts the electromagnetic coupling which exists during earth faults on a power line. The induced voltage is given by the formula Power line

Alternating magnetic field Induced current

Telecommunication line Induced voltage

Earth fault

Low frequency electromagnetic induction (a) Induced longitudinal voltage E 0

Length of exposure l Induced longitudinal voltage in an open-circuit telecommunication line (b)

Induced longitudinal voltage 1 relative 2 to earth

+

1 E 2

0 E –

Length of exposure l (c)

FIGURE 3.17 Induced longitudinal voltage between a telecommuinication conductor and earth

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EARTH FAULT AND INTERFERENCES

E = C × I × L × K where, C = 50 Hz mutual impedance per unit length of exposure; I = fault current; L = length of exposure; K = shielding factor. C is a function of the separation and the soil resistivity and a 10 metre separation, C = 0.28 ohms/km; for a 50 metre separation, C = 0.05 ohms. Telecommunication lines often run parallel to power lines for considerable distances and fault currents can be very large, hence induced voltages can be high even with large separation, e.g., for L = 10 km, I = 10,000 amps, K = 1, separation = 0.5 km, E = 2.5 kV. If the separation was only two or three metres, as may apply where an aerial supervisory cable is strung under the line, the induced voltage would be 17.5 kV.

EPR’s in Telecommunication Circuits Telecommunication cables entering or passing through a gradient area will encounter EPR’s. These EPR's will be significant in respect to equipment and personnel safety, only if a hazard zone is entered. Refer to Figs. 3.17 and 3.18. Hazard zone

Earthing system

PIT

or p

illar

During fault voltage at this point exceeds alloable voltage

Cable

Exchange

FIGURE 3.18 Hazard zone

Pipelines Oil and gas pipelines are often insulated from earth for electrolysis reasons and thus they need to be treated similarly to telecommunication cables in respect to EPR’s and induced voltages.

3.7.3 Induction into Adjacent Lines Voltages induced into adjacent lines are usually of little consequence, except in a few circumstances, notably where an out of service circuit is being worked on and where sensitive earth fault protection is applied to a line in a network which shares poles with other lines, (which perhaps may be operating at a different voltage level e.g., distribution HV often shares poles with sub-transmission).

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The diagram of Fig. 3.19 helps to explain how sensitive earth fault protection, on lines in a network, can mal-operate during a fault on a feeder running parallel to one of the lines in the network, viz. in each phase of the network continuous paths can be traced, one leg of which is in close proximity to the faulted feeder. Currents resulting from the voltage induced in each of the phases will be summed in the earth fault protection circuits associated with the network. If the exposure is long enough and the subtransmission protection is sensitive enough the relays will respond and may operate before the feeder protection has been able to clear the fault. Obtaining discrimination is usually fairly easy in this case, however in cases where different networks are involved it is difficult to achieve discrimination and retain sensitivity. B

A

C

E/F OK

Ei

Zm

Earth fault Distribution feeder sharing poles with subtransmission (a)

B

A e as e B h s C P a e Ph as h P

C

Ii Ii

A

I i I i Ii

Ii

3Ii Induced current are summed into E/F pilot at both ends of each line (b)

FIGURE 3.19 Induced currents interfering with protection on another pilot of system

EARTH FAULT AND INTERFERENCES

79

(Note: Problem only arises where exposure is long-earth fault too low for quick operation for feeder protection-sensitive earth fault protection on loop).

3.7.4 Impulses and High Frequency Disturbances Protection and control equipment is often situated in very hostile electromagnetic and electrostatic environments especially when faults occur in close proximity to relay houses. It must not be damaged nor mal-function. Electromechanical equipments used in the past and still in common use exhibit considerable resistibility to damage by quite high transient voltages and are insensitive to high frequency disturbances. Semiconductor equipments now used need to be designed and housed to resist and avoid severe impulses and a wide band of electrical noise, if their performance is to allow the intrinsic reliability of the primary system elements to be fully utilised. Specifications for impulse and high frequency tests are contained in standard specifications such as IEC Publication 255-4, Appendix E. I.8.

CHAPTER

4 Relaying Transducers

4.1

INTRODUCTION

In power systems, the levels of voltage or current are usually too high to permit direct connection to measuring instruments or relays, coupling is therefore made through voltage and current transformers that are designed to reproduce an accurate scaled down replica of the input quantity. Protective relays are required to measure during the transient period (which invariably follows a fault) so that both accuracy and transient response of the transducers are important. Errors in transformer output may abnormally delay the operation of the protection, or cause unnecessary operations. The functioning of such transformers must, therefore, be examined analytically.

4.2

VOLTAGE TRANSFORMERS

The equivalent circuit of a wound electromagnetic transformer is of the well-known form as shown in Fig. 4.1. The system voltage Vp is connected across the primary winding. The voltage Vs developed across the burden (relays of meters connected to the secondary winding) is required to be independent of Zb over the specified range. One way of achieving this is to make the winding impedances Zp and Zs as low as possible. Secondly, the nominal core flux density is arranged to be well below the saturation level.

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RELAYING TRANSDUCERS

n:1

ZP

Vp

ZS

Ze

Zb

VS

(Perfect coupling assumed) C1 = High voltage capacitance C2 = Low voltage capacitance T = Intermediate transformer

FIGURE 4.1 Equivalent circuit of a transformer

Errors: Two errors are important. Firstly, the ratio error which is defined as (n Vs – Vp)/Vp × 100%, where n is the turns ratio primary/ secondary. If the error is positive the secondary voltage exceeds the nominal value. The turns ratio need not be equal to a whole number, some turns compensation often being applied to ensure that error is positive for low burdens and negative for high burdens. The phase error is the phase difference between the primary and secondary voltages. Permissible errors are +/– 3% (ratio) and +/– 2% (phase). All voltage transformers are required by standards to have ratio and phase angle errors within prescribed limits over a 80% to 120% range of voltage and a range of burden from 25% to 100%. For protection purposes, accuracy of measurement may be important during fault conditions when the voltage is greatly suppressed. Therefore, a voltage transformer for protection must meet the extended range of requirements over a range of 5% to 80% rated voltage and for certain applications, between 120% and 190% rated voltage.

4.2.1 Transient Performance of a Voltage Transformer Transient errors cause few difficulties in the use of electromagnetic VTs although some do occur. If a voltage is suddenly applied, an inrush transient will occur, as with ordinary power transformers. The effect is however less severe than the power transformers because of the lower flux density for which the VT is designed. When the supply to a VT is interrupted (e.g., primary open circuited) the core flux will not immediately collapse and a more or less exponential current flows in the burden. The condition must not be confused with collapse of primary voltage due for example to a system fault when the secondary voltage collapses also.

4.2.2 The Capacitor Voltage Transformer (CVT) At voltages above 132 kV, the cost of conventional VTs is often prohibitive because for higher voltages, the size becomes largely proportional to the

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rated voltage. The CVT is a useful and more economical alternative, the arrangement being as shown in Fig. 4.2. C1

L

T

Zb

C2

FIGURE 4.2 Capacitor voltage transformer arrangement C = C1 + C2

Vi = Vp

C1 C1 + C2

L

Zb

FIGURE 4.3 Thevenin’s equivalent circuit of a capacitor voltage transformer

This device is basically a capacitor potential divider, the low-voltage end of which energies a wound voltage transformer. There are several variations of this basic circuit. The inductance L may be a separate unit or it may be incorporated in the form of leakage reactance in the intermediate transformer. A Thevenin equivalent circuit is shown in Fig. 4.3 and it can be seen that at nominal system frequency when C and L are in resonance and therefore cancel, the circuit behaves in a manner similar to a conventional electromagnetic VT. At other frequencies, however, a reactive component exists which modifies the errors. Provided that the reactive voltages across C and L are not too large in relation to Vi, the change of error with frequency is not excessive. For a typical design, in which C has the value 2000 pF and Vi = 12 kV, the change in phase error, with 150 VA UPF output per Hz of frequency change (in the region of rated frequency) is about 15/20/40 minutes for a 400/275/132 kV capacitor voltage transformer. Transient Behaviour of CVTs The transient response of CVTs is much inferior to that of a electromagnetic VT and there are errors influenced by so many factors. A CVT as can be seen is a series resonant circuit. For example, under conditions of sudden voltage change (such as a collapse due to a fault) on the primary, oscillations caused by the interaction of the series capacitance, and the magnetising

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RELAYING TRANSDUCERS

inductance of the intermediate transformer (of typically 10 kHz) will often occur. Oscillations at around 300 Hz will also occur under similar conditions due to the interaction of the series tuning reactance and the winding capacitance of the intermediate transformer. The exact equivalent circuit of a CVT is shown in Fig. 4.4. C

Vi = V p

L

C1 C1 + C2

Rs

RP

RM Lm

Ls

Vx

Cm

FIGURE 4.4 Simplified equivalent circuit of a capacitor voltage transformer

It should be noted that the power factor of the burden greatly influences transient responses. It can dominate the CVT behaviour, allowing the same CVT with two different burdens to exhibit different transients. In general, an increase in resistive burden results in larger-amplitude transients but faster decay. On the other hand, a reactive burden constitutes a further tuned circuit and introduces new modes of oscillations that can persist for several cycles of the system frequency. It is generally found that higher power factor burdens are better. Ferro-resonance It is possible when energising CVTs to induce sustained subharmonic ferro-resonance that takes place between the inductance of the exciting impedance and the capacitance of the potential divider. One quite common condition occurs in which a stable one-third sub-harmonic persists. A resistive burden tends to reduce the likelihood of such oscillations and it is common to build in special anti-ferro resonance devices that use parallel tuned circuits. Some compromise is however necessary because the latter tends to impair transient response. The High Fidelity CVT It is now widely appreciated the CVTs cannot respond quickly to changes in primary voltage. A capacitor divider on the other hand (as shown in Fig. 4.5), overcomes the transientresponse difficulties of CVTs by interposing a buffer amplifier between the divider and its burden. This preserves the divider’s homogeneous nature and allows it to respond accurately over a wide range of frequencies.

C1 Buffer amplifier C2

FIGURE 4.5 Capacitor divider buffer amplifier

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Ideally one would want new purpose-built units of such CVTs but this is not economically viable at present. A closer approach to the response of a capacitor divider can be achieved by modifying a conventional CVT to produce a capacitor divider output in addition to the traditional output from the intermediate voltage transformer. Such a scheme is shown in Fig. 4.6. Ic

Vp

VC1

C1

VC2

C2

L

B Vs Power

Pre-amplifier VC3

B

C3 Matching impedance

Power amplifier

FIGURE 4.6 A hi fi capacitor voltage transformer

The capacitor C3 is introduced into the CVT circuit so that it conducts the whole of the capacitor current ic and therefore reflects the voltage VC . 1 The value of C3 is large compared with C1 and C2 and does not affect the transient or steady-state characteristics of the traditional output voltage Vs in any way. With this arrangement, the less accurate output Vs of the conventional CVT can be used for purposes of metering, telemetry, back up protection, etc., and the very accurate output (VA) of the capacitor divider used for the high speed distance relays.

4.2.3 Other Voltage Transducers A high voltage resistor divider is an attractive alternative from a transient point of view, but is prohibitively expensive and produces a ratio error which is burden dependent. Another more practical alternative is a cascade voltage transformer which has a better frequency and transient response than the conventional CVT. The principle is illustrated in Fig. 4.7. The conventional type of VT has a single primary winding, the insulation which presents a great problem for voltages above 132 kV. The cascade VT avoids these difficulties by breaking down the primary voltage into several distinct and separate stages. The complete VT is made up of several individual transformers, the primary windings of which are connected in series. Each magnetic core has primary windings P on two opposite sides and the secondary winding S consists of a single winding on the last stage only. Coupling windings C connected in pairs between stages, provide low

85

RELAYING TRANSDUCERS

impedance circuits for the transfer load ampere-turns between stages and ensure equal voltage distribution over the several primary windings. The primary and coupling windings are connected to the cores of selected points and all stages are housed in a vertical stack which is filled with oil and sealed together with a cushion of nitrogen to permit expansion during temperature changes. These cascaded devices are presently very expensive, but in view of their superior transient response, they are likely to find more widespread use in the future. A

C P

C

C

C

C

S N

n a

FIGURE 4.7 Schematic diagram of a typical cascade voltage transformer

4.3

CURRENT TRANSFORMERS (CTs)

Current transformers convert the primary current to a level suitable for measurement by the protective relays, usually with a rated secondary current of 5 or 1 amp. The primary winding of a CT is connected in series with the power circuit. Its equivalent circuit is the same as for any other transformer (as shown in Fig. 4.8). The object is:

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

(a) minimum interference with power circuit i.e., Zp and Zs are made very small by design. (b) that Is is a faithful replica of Ip. Ip

Zp

Ip¢

Zs

I:n

Is = Ip¢/n Rm

Es

Xm

Vs

Zb

FIGURE 4.8 Equivalent circuit of a current transformer

4.3.1 Construction of CT Current transformers are usually designed so that the primary winding is the line conductor that is passed through an iron ring which carries the secondary winding. They are mostly of this type and are known as barprimary or ring-wound current transformers. The construction of a typical ring-wound current transformer is shown in Fig. 4.9. Grain-oriented sheet-steel strip is wound to form a core and is covered with a layer of insulation. The secondary winding is wound over this and consists of the number of turns needed to produce the required ratio of wire of sufficient cross-sectional area to carry rated current, followed by a further layer of insulation which covers the secondary winding. When installed, the primary conductor which acts as a single turn, is passed through the centre of the ring. The making of the core by stacked annular laminations has now been superseded by the wound-type method.

Core construction

P1

Insulation

S1

S2

Tape wound core

Secondary winding Insulator

FIGURE 4.9 Construction of a current transformer

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RELAYING TRANSDUCERS

4.3.2 Design of CT For protection purposes, current transformer specifications are normally laid out in terms of the knee-point e.m.f. The knee point of the excitation curve is defined as that point of which a further increase of 10% of secondary emf would require an increment of exciting current of 50% (Fig. 4.10). We can say that at voltages above knee point, saturation occurs quickly.

Exciting voltage (Vk)

Vk

10% Vk

50% Irk

Irk Exciting current (Ir)

FIGURE 4.10 Definition of knee point of excitation curve

Magnetising current, and consequently flux, changes from zero to maximum in 1/4 cycle and therefore the rate of change of flux is φ−0 = 4φ webers/cycle 1/4 or at a frequency of ‘f ’ cycles/s = 4φ f webers giving an average induced voltage Vav of 4φ fN, where N is the number of turns or in r.m.s. values, the knee-point voltage is V = 4.44φf N as V = 1.11Vav Also as flux φ = flux density which is B(tesla) × core area × s (m2), the knee-point voltage is V = 4.44Bsf N The flux density of electrical sheet steel is about 1.5 tesla at knee-point which for a ring-type current transformer of known ratio makes the kneepoint voltage fairly easy to estimate if the approximate dimension of the core is known. For example, a CT ratio of 200/1 with a core area of 30 × 20 mm2 would have a knee point flux of 1.5 × 30 × 20 × 10–6 = 0.0009 weber

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

which on a 50 Hz system would produce a knee point voltage of V = 4.44 × 0.0009 × 200 × 50 = 40 V.

4.3.3 Burden of CT The load connected to a current transformer is called the burden and can be expressed either as a VA load or as an impedance. In the former case the VA is taken to be at the CT nominal secondary current. For example, a 5 VA burden on a 1 A transformer would have an impedance of 5 ohms:

5 VA =5V 1A impedance =

5V =5Ω 1A

or on a 5 A current transformer:

5 VA =1V 5A impedance =

1V = 0.2 Ω 5A

All burdens are connected in series and the increase in impedance increases the burden on the current transformer. A current transformer is unloaded if the secondary winding is short-circuited as under this condition the VA burden is zero because the voltage is zero. The errors of transformation depend on the angle of the burden as well as its impedance.

4.3.4 Errors of CT Besides the ratio and phase errors, composite errors are to be considered. The composite error is defined as the r.m.s. value of the difference between the ideal secondary current and the actual secondary current (included are the effects of phase displacement and harmonics of the exciting current). In CTs with negligible leakage flux and no turn correction i.e., with turns ratio equal to the nominal current ratio, the composite error corresponds to the r.m.s. value of the exciting current (usually expressed as a percentage of the primary current). CTs are therefore designed to give as high a value as possible of magnetising impedance. This involves high quality core material. The more closely the value Ie tend to zero the greater is the accuracy, but it is not possible to eliminate both ratio and phase errors. The phasor diagram (as shown in Fig. 4.11) illustrates this point. It can be clearly seen that the exciting current Ie is responsible for all the errors. The component Ir of Ie, which is cophasal with Is causes the ratio error and the component Iq which

89

RELAYING TRANSDUCERS

is in quadrature with Is causes the phase error θ. The problem is that Ie is also dependent on the magnitude of the p.f. of the burden. It will be seen that with a moderately inductive burden, with Is and Ie approximately in phase, there will be little phase error and the exciting component will result almost entirely in ratio error. It is possible to partially compensate for ratio error by reducing the secondary winding by one or two turns. IsRs Es IsXs

Ir

Iq Ip

Vs

q Is

Ie F Es = Secondary induced e.m.f. Vs = Secondary output voltage Ip = Primary current Is = Secondary current q = Phase angle error

IsRs = Secondary resistance voltage drop IsXs = Secondary reactance voltage drop Ie = Exciting current Ir = Component of Ic in phase with Is Iq = Component of Ic in quadrature with Is

FIGURE 4.11 Vector diagram for a current transformer

On assuming 1/1 turns ratio Is = Ip – Ie. The exciting current depends on induced emf Es which is approximately equal to Is(Zs + Zb) and also in exciting impedance Ze. If Ze is linear, then Ie would be the composite error. In practice, Ze is non-linear and if Ie contain harmonics of the fundamental frequency which increases its r.m.s. value and hence the composite error increases too. This is quite noticeable in the saturation requirement.

4.3.5 Specifications of Current Transformers Australian Standard AS 1675–1986 provides standards for the specification of CT’s. For protection schemes where the operating times are greater than around 0.2 second i.e., there are no significant transients or dc component present in the fault current, a Class P CT is used, specified in the format: 10 P 150 F20 10 — represents the composite error, % at the accuracy limit current (preferred values 2.5, 5, 10), P — protection class,

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

50 — rated secondary reference voltage; secondary voltage required to drive secondary current through the connected burden at the accuracy limit current, F20 — accuracy limit factor, either 5, 10, 15, 20, or 30 times rated secondary current (20 preferred). For protection schemes which operate in less than 0.2 second and where it is necessary for the CT to perform in the face of the DC transient present in the fault current, a PL Class CT is used. This Class is specified in terms of the knee point voltage, in the format: 0.05 PL 950 R3 0.05 — represents the magnetising current (amps) at the knee point voltage of the CT excitation curve, PL — class, 950 — chosen knee point voltage, R3 — maximum secondary winding resistance (ohms). The knee point of the magnetisation curve (Vk) is defined as that point at which an increase of 10% of secondary voltage would increase the magnetising current by 50%. For the PL Class CT Vk is chosen to provide a margin so that the CT will not saturate during the primary system DC transient, by allowing for the primary transient factor (TF). Vk = TF × I(Rs + Rb) Rs—CT secondary resistance (ohms) Rb—Resistance of connected relays plus leads (ohms). British Standard BS 3938 1973 is a little different in that burden, accuracy class and accuracy limit are used to define the Class P type CT. Standard values of rated burden are: 2.5, 5, 7.5, 10, 15 and 30 VA. Two accuracy classes are quoted 5P and 10P which gives a composite error at rated accuracy limit of 5% and 10% respectively. Standard accuracy limit factors are: 5, 10, 15, 20 and 30. The method of describing a current transformer is as follows: 15 VA Class 5P20 which means that it is rated for a burden 15 VA and will not have more than 5% error at 20 times rated current.

4.3.6 Application In specifying current transformers the connected burden and mode of operation must be taken into account paying attention not only to the wide range of devices which may be connected, but also to the variation of

91

RELAYING TRANSDUCERS

impedance over the range of setting any relay. For example, the normal burden of an overcurrent relay is 3 VA at setting. The normal setting range of the relay is 50% to 200% of nominal current. Therefore, a 1 A relay set to 50% would have a setting current of 0.5 A and the voltage across the coil at this current would be V=

3 VA =6V 0.5 A

and the impedance would be Z=

6V = 12 Ω 0.5 A

At a setting of 200% the setting current would be 2 A, the voltage V=

3 VA = 1.5 V 2A

Z=

1.5 V = 0.75 Ω 2A

and the impedance

If the characteristic of the relay is to be maintained up to 20 times the relay setting, then a knee point voltage of not less than 20 × 6 V = 120 V for a 50% setting or 20 × 1.5 V = 30 V for a 200% setting would be required. The former is more onerous and therefore the lowest setting must be taken into account when specifying the knee point voltage. There is, however, an alleviating factor in that a relay operating at 20 times its setting will saturated magnetically and therefore the impedance will be reduced. The reduction for an overcurrent relay is about half the impedance at setting, which means that in the above case a knee point voltage of 60 V would be satisfactory. In many cases the current transformers associated with the over current protection must also cater for earth-fault relays. An earth-fault relay having a minimum setting of 20% would have voltage at setting of

15 V 3 VA = 15 V and impedance of = 75 Ω 0.2 A 0.2 A The maximum earth-fault level may be restricted to, say, twice the CT primary rating and therefore 10 times the relay setting. The knee-point voltage should therefore be greater than 10 × 15 V = 150 V, or allowing for saturation, 75 V.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

In this case, the size is determined by the earth-fault relay. A suitable current transformer would be a 7.5 VA Class 5P10. This would produce a voltage of 7.5 V at rated current when connected to a 7.5 Ω burden and would have only 5% error at 10 times rated current, i.e., at a voltage of 10 × 7.5 V = 75 V. From the specification in the form 7.5 VA class 5P10, the knee point voltage can be estimated. If it has a 5 A secondary winding then at rated current it would produce 1.5 V across the rated burden and at 15 times rated current 22.5 V. As a rough guide the knee point voltage is the product of the VA rating and the accuracy limit factor divided by the rated secondary current. Class 5P is specified when phase-fault stability and accurate time grading is required. When these are unimportant, Class 10P is suitable. It may be that more than one relay is to be connected to one set of current transformers in which case the total burden must be calculated. It is generally sufficient to add the burdens arithmetically but it should be borne in mind some alleviation may be available by adding the burden vectorially in case of difficulties in design. It is not good engineering practice to specify a current transformer which is substantially larger than necessary as there is no advantage in performance and its cost would be higher and its dimensions greater.

4.4

GUIDANCE IN APPLICATION OF CTs

4.4.1 Correlation of Transformer Class, Maximum Operating Level and Categories of Protection (AS1675–1986) The class, output voltage and accuracy required for a CT is determined by the type of relay system to be driven, together with the fault level and possibly the X/R ratio of the supply system. Typical protection schemes are categorised in two ways: (a) low speed schemes (b) high accuracy high speed schemes. Low Speed Protection Schemes These are protection schemes having intentional time delays (fixed or time dependent) of 0.2 sec. or greater. For such schemes good transient performance is not necessary, since the initial saturation at maximum fault current does not seriously affect the timing of the relay. For example, induction disc IDMT overcurrent and earth fault; definite time overcurrent and earth fault. Typically a class 10P CT is satisfactory and terminal voltage should be selected to drive the steady state maximum fault current through the combined relay and secondary lead burden.

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RELAYING TRANSDUCERS

Care should be exercised when using solid state relays which measure peak current and can be affected by offsets. (c.f. induction disc relays measuring r.m.s. of fundamental components) Short cuts in the CT design have been undertaken. For example, under dimensioning CTs which saturate at much less than maximum fault current where time delays and discrimination are not critical. High Accuracy High Speed Protection Schemes These are schemes (Fig. 4.12) for applications in which either accuracy of setting and operating times, or through fault stability, or both are important. Class P

Spaces (optional) e.g. AS 1675–1986 : 10P

150 F15

Rated composite error at accuracy limit Class Rated secondary reference voltage (volts) Rated accuracy limit factor Class PL Spaces (optional) e.g. AS 1675–1986 : 0.05PL

950 R3

Maximum secondary exciting current (amps) at rated knee point voltage Class Rated knee point voltage Maximum secondary winding resistance (ohms) at 75°C or maximum service temperature

FIGURE 4.12 Examples of class P and class PL

At distribution levels high impedance differential protection schemes are typical. While a Class P CT may be suitable a Class PL will always be better. For this application, the PL CT is not essential for accuracy or transient performance but it is convenient because the magnetising current and CT secondary resistance are both required to be known for design of the relay scheme. It is intentionally allowed to saturate heavily at maximum fault current and the output voltage should be designed to be in the range 2 to 5 times necessary for relay pick up.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

4.4.2 Core Saturation and Current Limiting Action In CT practice core saturation is frequently used to limit secondary current which could otherwise reach a level high enough to cause damage to equipment connected into the secondary circuit. A measurement CT with a comparatively low accuracy class can be designed as a much more effective saturation CT than a measurement CT with a high accuracy class. For example, Consider a CT of say class 5 (5%) (the permissible current error is relatively high and no limit on the phase error). At 125% of rated primary current the core can be operated at a fairly high flux density. A small increase in primary current above 125% raises the operating point of the magnetisation curve into saturation and current limiting will occur. For a CT of higher accuracy class say 0.5 (0.5%) made of the same core material the operating flux density at 125% of rated current has to be established further down the magnetisation curve to maintain the ratio and phase errors. The core will be operating low down on the linear portion of the magnetisation curve and any increase in current will require significant change in magnetisation before saturation will occur. The principle applies equally to protection CTs so that a class 10P CT may be preferable for a saturation CT rather than a class 2.5P.

4.4.3 Through Primary and Wound Primary CTs Current transformers appear in countless shapes, sizes, forms and types. The through primary CT may be complete with a bar primary provided by the manufacturer or it may be a window type or bushing type to be fitted at installation stage on an existing primary bar or cable (Fig. 4.13). THROUGH-PRIMARY CT

WOUND-PRIMARY CT S2

P2

P1

S2 P1 S1

P2

FIGURE 4.13 Primary current transformer

S1

RELAYING TRANSDUCERS

95

The primary is essentially a straight conductor which does not mechanically encircle the core but effectively constitutes a single turn. The through type CT is inherently extremely robust, both mechanically and electrically. When correctly designed, it is able to withstand the heavy electromagnetic forces and thermal effects of major short circuits. The inherent robustness and reliability have made this type of CT the first choice except in those cases where the available primary current is too small to enable the desired output, accuracy or performance to be obtained economically. A wound primary CT provides additional primary amp turns by passing the primary current through a coil having any specified number of turns. This easy way of increasing output and accuracy has a penalty. In the event of a short-circuit on the system, the mechanical forces on the primary conductors are directly proportional to the number of turns. This type of CT is not capable of withstanding heavy fault currents. A further penalty is the increase in the internal burden of the CT due to increased resistance of windings. Often for testing and perhaps other reasons, it is convenient to convert through primary CTs to a wound primary CT. The primary cable can be looped through the window several times creating an inserted primary CT. As the primary amp-turns on the CT are unchanged the output and accuracy will be the same. However this approach should not be adopted in situation where the prospective fault level is high enough to damage the CT. Limits for a typical CT, it is worth considering some current limits and their relative size. For example, 500/5 CT rated primary current 500 A (thermal limit) 1000 A Primary Currents (accuracy limit) 10000 A (short-time rated current) 50000 A

4.4.4 Derived Burden The derived burden of a protection CT is roughly equivalent to the rated burden of a measurement CT. As the design of a CT is based on its performance at accuracy limit primary current, it is important that the burden specified is the value at accuracy limit primary current.

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The burden represented by an electromagnetic relay when expressed in ohms may be considerably less at twenty times setting current than at setting current (as a consequence of relay core magnetic path saturation). In the selection of a protection CT what matters most is the maximum impedance of connected burden at rated accuracy limit current. Derived burden =

Secondary reference voltage accuracy limit Rated secondary current × Accuracy limit factor

4.4.5 Special Dimension C Ts In the field due to close spacing of busbars or other dimensional limitations, it is sometimes found that a standard CT has too large an OD (outside diameter). This problem can be solved by staggering the CTs. For example, with the two outer phase CTs in line and the centre phase offset the CT OD can be almost doubled. A rectangular shape CT can overcome problems if staggering is not appropriate or fails to meet the physical requirements.

4.4.6 CT Selection Relay burdens are usually obtained in manufacturers specifications in units (VA) at various current settings. The VA obtained should be adjusted to a VA value at rated secondary current. The rated CT burden can then be selected. Where a problem has occurred in matching a CT to a relay or specifying a CT, more often the selection has been made without the above mentioned appropriate step. For example, if a nominal 5 amp induction relay is to be used at the 50% tap (2.5 amps) and the burden of the relay is “2 VA at current setting” then the actual burden at the selected tap will be 52 × 2 VA = 8 VA at 2.5 amp setting 2.5 2

As the current setting is reduced more relay turns are connected across the CT, hence it stands to reason that the impedance will increase. Using the relay manufacturers information and the ratio of squares of current as a multiplier of nominal rated burden may lead to a very conservatively designed CT. A grossly over specified CT may be required to meet the calculated demand. A larger CT would be necessary to provide a higher output voltage.

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Measurements on relays (electromechanical) indicate that the impedance is not a fixed value and that the impedance could be a fraction of its initial nominal value at 20 times setting current. Unfortunately, few manufacturers provide relay impedance values in ohms on the various tappings for a range of overcurrent conditions. Some persistence from the user in demanding this information can provide the desired outcome. Somewhere in the relay manufacturers organisation, e.g., in a laboratory, full scale tests including ohmic values for various taps on ranges of overcurrent conditions will be available. Alternatively the relay user can perform its own tests (Fig.4.14).

Impedance (W)

0.4

1

Log-current times plug setting

2.5 A 5A 10 A 20

CDG14 0.5-2 A 0.5 A

1.4

Impedance (W)

CDG11 2.5-10 A 3 VA

1A

0.2

2A 1

Log-current times plug setting

20

FIGURE 4.14 Realy impedance curves

If multi-tap relays are to be used over a full range of current tappings, the burden on the CT should be calculated on the lowest relay current setting. This setting incorporates the maximum number of turns and the highest coil impedance. In practice, at distribution voltage levels, the range of settings is limited and it is rare to vary the tapping point of the relay from one end to the other. The min-op conditions typically being set by the CB rating. If CTs are required for a triple pole relay it is important to determine whether the relay incorporates three overcurrent elements or alternatively two overcurrent and one earth leakage unit. In the latter case a higher secondary reference voltage will be required because of the typically low current setting adopted for the residual earth leakage relay. The relay manufacturers characteristic curve is a good preliminary indicator of the accuracy limit factor of the selected CT. For example, if relay operating times are still significant up to 20 times current setting then an accuracy limit factor of 20 will be required for the CT.

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If a 1 amp relay is used rather than a 5 amp relay then the secondary reference voltage will be 5 times that of the equivalent 5 A secondary CT. Saturation CTs with low accuracy limit factors should be used for thermal relays (or devices) as heating is proportional to the square of the CT output current.

4.4.7 CT Secondary Currents other than 5 A Throughout most of the world CT ratings of 5 A or 1 A prevail. North American utilities use the 5 A rating almost exclusively, however, elsewhere lower ratings predominate. It is worth examining the factors and relationships which influence the decision to select a particular rating.

4.4.8 Insulation Requirements Two aspects are considered, insulation between primary and secondary for the system voltage and the insulation of the secondary winding to withstand the secondary voltage produced during fault and test conditions. The primary insulation is independent of the CT secondary current rating, but the secondary insulation is not. For a given core and five times the number of turns, a knee point voltage of the 1 A CT would be five times that of a 5 A CT. Volts per turn would be unchanged. Where a lower knee point voltage is acceptable, the core section can be reduced, resulting in a lower volts per turn. It is apparent that a prime consideration is designing the secondary system with coordinated insulation capability of the relays, interconnecting cables, terminal blocks etc. It may be considered that even when discussing 1 A and 5 A secondaries that an arbitrary decision has been made. What is a ‘convenient value’ of secondary current with respect to technical requirements and economics. Except in special cases nominal secondary currents above 5 A are neither convenient nor economical. Relay systems are designed to withstand fault currents in the range 20 times rating. Higher secondary currents result in excessive secondary currents. Lower secondary ratings offer advantages where lead burden represents a significant portion of the total burden. For a given wire size the lead burden at 1 A is only 4% of that for 5 A. Cost savings can be achieved using the 1 A secondary by reducing the secondary wire size or using a smaller core etc.

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99

4.4.9 Working Voltage For a given amount of power out of a CT the required voltage must increase in direct proportion to the current reduction. Existing voltages in many 5 A systems are probably at a maximum desirable level. The requirement for CT output power will tend to be less with lower secondary currents due to reduced copper losses in the leads. Modern static relays require less operating power 0.5–1.0 VA versus nominal 3 VA for electromechanical. Although the CT knee point of a 1.0 voltage secondary is higher, it should not be considered as a problem. This voltage is normally present under excitation tests and the voltage is distributed across the CT resistance. Under operational conditions the terminal voltage is the more important factor. The connected burden under the most arduous fault conditions will determine this. It is probably prudent to ensure that the terminal voltage does not exceed 1 kV to allow adequate safety margin for insulation rating. Where tapped CTs are used, a check should be performed to ensure that autotransformer action does not overstress the open end of the CT. Generally the terminal voltage of a 1 A CT will be less for cases where the lead resistance RL is more than 20% of the relay burden at rated current.

4.4.10 Transient Performance Where consistent relay operating times are required, the CT may need to have a large saturation factor, Ks. The saturation factor relates the CT knee point voltage to the maximum required steady state secondary voltage. The higher this factor the better the CT performance under transient conditions. The CT should not saturate when fully offset faults occur. This requirement usually necessitates that the physical size of the CT could be a problem, situating CTs within bushings or in metal clad switchgear. The smaller 1 A secondary CT offers an advantage. For equivalent transient performance the CT lead resistance of a 1 A system can be 12.5 times that of a 5 A system (assuming that the relay resistance is a small fraction of the lead resistance).

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4.4.11 Practical Considerations Interchange ability and spares may be considered as detrimental factors where an organisation is already committed to a 5 A system. Note that perceived problems are just that. Many modern relays are suitable for use on both systems. Interposing CTs can be used to marry and mix 5 A and 1 A systems.

4.4.12 Safety Considerations The open circuit voltage of a 1 A CT could be higher than an equivalent 5 A CT. Safe operating procedures are essential for all CTs and hence the hazard is not a relative measure worth considering. The 1 A CT can offer the following advantages: • improved transient performance • reduced cable or CT size • reduced voltage stress in certain applications In all cases, advantages are strongest when the relay resistance to cable resistance ratio decreases. Although 5 A secondaries are still desirable for the lower end of high voltage at high current ratio applications all the pertinent parameters should be considered for an engineering evaluation of specific installations.

CHAPTER

5 Overcurrent Protection

5.1

INTRODUCTION

This type of protection which was developed some 70–80 years ago, is the earliest, cheapest and simplest form of protection still widely used in the power industry today. It operates on the principle that once a predetermined level of current is reached the relay will operate in a predetermined time. These relays are generally classified broadly in terms of their time characteristic e.g., instantaneous, inverse time, extremely inverse time, fixed or definite time. Overcurrent protections should not be confused with ‘overload’ type protections which consider the thermal capability of the plant to be protected. The overcurrent protections are directed entirely to the clearance of faults, although with the settings usually adopted some sort of overload protection is normally provided. These overcurrent protection schemes are commonly used to provide short-circuit protection for many different types of plant. As well as being applied to detect phase-phase short-circuits, such relays can be used to provide earth leakage (phase-ground fault) protection. The overcurrent relay in this case is connected in the neutral of the current transformer secondary circuit. Although the overcurrent protections are inherently non-directional (i.e., they will operate for primary current flow in either direction), it is possible for them to be controlled so that they effectively respond to primary current in one direction only and this is done using a separate ‘directional’ relay to control the ‘secondary’ circuit of the overcurrent protection. A

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‘directional’ over current protection facilitates the setting of overcurrent protections on tie lines or ring systems. Depending on the particular application, overcurrent relays would be used: • in unit or non-unit type schemes (the more common is in nonunit type schemes) or, • with directional or non-directional features (the more common is non-directional). In the case of the non-unit type schemes, it is necessary to achieve discrimination between the local and the remote over current protections. This discrimination is usually achieved by the application of appropriately chosen settings. With the advent of microprocessor based overcurrent protections, additional and more enhanced features have been provided to the traditional electromechanical overcurrent protections, these enhanced features have increased the potential range of applications. Overcurrent protections find greatest application in the distribution area and to a somewhat lesser extent in the sub-transmission area, both for the purpose of phase fault and earth fault protection. These protections may be found on generators, lines/feeders, busbars, transformers, transformer/feeder combination, reactors, capacitor banks, etc. However, non-unit type overcurrent protections do not have significant application on EHV transmission plant because of their limited sensitivity and non-discriminatory nature requiring operating times that are generally unacceptable at that system level.

5.2

TYPES AND CONSTRUCTION

The design/construction technology of the overcurrent relays range from the electromechanical single characteristic inverse curve relay (induction disk type) to the microprocessor based relay with the choice of multicharacteristic curves. The operating time characteristics and limits of accuracy of the overcurrent relays are in accordance with the limits set by IEC255-4 and BS142 for an inverse definite minimum time (IDMT) overcurrent relay. Typical operating time characteristic and tolerance limits are as shown in Fig. 5.1. The operating time of the instantaneous and definite time relays is, practically, independent of the magnitude of the fault current once the magnitude exceeds the operating threshold of the relay.

103

OVERCURRENT PROTECTION 50 40

Pick-up 1.05-1.3 Times setting

30

Time (Seconds)

20

10 8 7 6 5 4 3 2

1

2

3 4 5 6 7 8 10 Current (multiples of plug setting)

20

30

Time/Current characteristic allowable limit: At 2 times setting 2.5 × Declared error At 5 times setting 1.5 × Declared error At 10 times setting 1.0 × Declared error At 20 times setting 1.0 × Declared error

FIGURE 5.1 Typical operating characteristic and operating tolerance limits

The range of typical operating time characteristics (including mathematical formula applicable for the static/digital) of the various types of inverse overcurrent relays are shown in Fig. 5.2, and are as follows: (a) Definite time (b) Standard inverse (IDMT)

Tm = 0.14/((PSM)0.02 – 1.0)

(c) Very inverse

Tm = 13.5/(PSM – 1.0)

(d) Extremely inverse

Tm = 80/((PSM)2 – 1.0)

(e) Long time standby earth fault

Tm = 120/(PSM – 1.0)

where Tm = Relay operating time (seconds) at TMS = 1.0 PSM = Plug setting multiplier (multiple of tap/plug setting) It should be noted that all the operating time characteristics, including mathematical formula are shown at 1.0 time multiplier setting (TMS). The microprocessor based versions which are available from most relay manufacturers have many advantages over the electromechanical relay, these include the following:

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• lower ac burdens, • wider application ranges, • more accurate, not affected by mechanical problems such as pivot friction, • can be utilised to provide disturbance records, event records, system load data and fault quantities, • has communication capability to enable remote interrogation, • self monitoring to ensure improved reliability and availability capabilities. 2

10

1

Definite 8 seconds

Operating time, t(seconds)

10

Definite 4 seconds Long time standby Earth fault 120 t= I–1

Definite 2 seconds

Standard inverse 0.14 t = 0.02 I –1

0

10

Very inverse 13.5 t= I–1 Extremely inverse 80 t= 2 I –1

–1

10

0

10

1

10 Current (multiple of setting)

2

10

FIGURE 5.2 Various types of inverse type characteristics including mathematical formulae

Although the microprocessor version will find increasing applications, the electromechanical induction type relays will continue to remain in service for many years.

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OVERCURRENT PROTECTION

All relays are provided with a number of tap/plug settings, each of which represents the minimum current at which the relay will start to operate (this is referred to as the minimum pickup value). A relay that has been set on a particular tap/plug will begin to operate at that tap/plug setting plus/minus the manufacturer’s tolerance. However at this current the time can be extremely long and unpredictable, any small deviation at this level will result in significant time changes. For this reason manufacturer’s generally do not show their time curves below 1.5 to 2.0 times minimum pickup. In practice this part of the curve should not be used for protection. 100 80 60 50 40 30 20

Time (Seconds)

10 8 6 5 4 3 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3

2 1 0.8 0.6 0.5 0.4 0.3 0.2

0.2

inst = 1 × Is

0.1

inst = 2 × Is 0.1 0.08 0.06 0.05 0.04 0.03

inst = 3 × Is

inst = 4 × Is inst = 5 × Is to 31 × Is Instantaneous Unit

0.02 0.01 1

0.05

2

3

4 5 6 8 10 20 30 40 5060 80100 Current (multiple of setting)

FIGURE 5.2 (a) Typical family of inverse type operating time characteristics for the various time multiplier settings

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POWER SYSTEM PROTECTION AND COMMUNICATIONS 10 9 8 7 6

Time current characteristic inverse time relay CDGIl 1-3 sec

5

5

4

4

3

3

2

2

Operating time in secs

Operating time in secs

10 9 8 7 6

Time current characteristic inverse time relay CDGII 3 sec to B.S.142

1.0 0.9 0.8 0.7 0.6 0.5

1 0.9 0.8 0.7 0.6

1 0.9 0.8 0.7 0.6

1.0 0.9 0.8 0.7 0.6

0.5

0.5

0.5

0.4

0.4

0.4

0.3

0.3

0.3

0.2

0.2

0.2

0.1 20

0.1

0.4 0.3 0.2

0.1

0.1 2

3

4 5 6 7 8 910

2

Multiples of plug setting current Curve reference 398. s23. 15

3

4 5 6 7 8 910

20

Multiples of plug setting current Curve reference S77398z06.017

FIGURE 5.2 (b)

The current axis of the characteristic curves is shown in multiples of tap/plug or pickup current, this is for the convenience of providing one scale for all tap/plug settings. In addition to the tap/plug settings, there are further adjustable settings which are identified by the scale known as ‘time multiplier’, ‘time lever’ or ‘time dial’ settings. These settings provide different operating times for the same operating current level, thus a family of operating time curves are available for use. Typical family of inverse type operating time characteristics for the various time dial settings are shown in Fig. 5.2(a).

5.3

SYSTEM ANALYSIS

To achieve correct coordination of overcurrent protection, it is necessary to have a detailed knowledge of: • the protection schemes themselves,

OVERCURRENT PROTECTION

107

• the possible operating conditions of the system to be protected, and • the minimum and maximum fault currents that can flow in each part of the network to be protected. Since large scale tests of the system are not practical, theoretical system analysis must be carried out. As a consequence to enable the protection settings to be determined, the data that may be needed includes the following: (a) A single-line diagram of the power system, indicating the type and rating of the protective devices and their associated current transformers. (b) The impedance in ohms, per cent or per-unit of all power transformers, rotating machines and feeder circuits. (c) The starting current requirement of large motors, as well as starting and stalling times of the induction motors. (d) The maximum and minimum values of short-circuit currents that are expected to flow through each of the protective devices. (e) The maximum peak load current (which includes all short-time overloads due to motor starting or otherwise and does not refer to the peak of the current waveform) through protective devices. (f) The decrement curves showing the rate of decay of the fault current supplied by the generators, if applicable. (g) The excitation curves of the current transformers and details of secondary winding resistance, load burden and other connected burdens.

5.4

SETTINGS OF IDMT RELAYS

Given that the type of characteristic to be applied has been selected (i.e., standard inverse, very inverse, etc.), then there are two factors to be considered whilst grading IDMT relays, these are the basic adjustable settings which apply to all inverse time relays: (i) TMS —time multiplier setting, and (ii) PSM—plug setting multiplier. The operating time characteristics covering the range of relay characteristics and TMS settings, for static/digital relays can be expressed by the following general formula: where

T = K × [TMS]/[(I/IS)α – 1.0] T = actual relay operate time (seconds) K = constant for the particular characteristic: 0.14 for standard inverse

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13.5 for very inverse 80 for extremely inverse 120 for long time standby earth current TMS = time multiplier setting (seconds) I = fault current (ampere) IS = current threshold setting of the relay – tap/plug setting (ampere) α = constant for the particular characteristic 0.02 for standard inverse 1.0 for very inverse 2.0 for extremely inverse 1.0 for long time standby earth current The value of TMS for an inverse time relay is generally adjustable from 0.05–1.0, and its setting is defined as: TMS = T/Tm (for electromechanical relays)

TMS = T/Tm = (T × [(PSM)α – 1.0])/K (for static/digital relays) where

T = The required time of operation (seconds) Tm = The time obtained from the relay characteristic curve (or from the formula) at TMS = 1.0, and using the PSM equivalent to the maximum fault current. The value of PSM is defined as:

Fault current (I) Current threshold setting of the realy – Tap/plug setting (I S ) Note that the current values for both I and IS must have a common reference, it can either be in terms of primary currents or in terms of secondary currents.

5.4.1 TMS Examples Consider the standard inverse characteristic as shown in Fig. 5.2(a), if TMS is 0.1 and the time Tm obtained from the curve, for a particular PSM current, is 4.0 seconds then the actual operating time will be: T = T m × TMS = 4.0 × 0.1 = 0.4 seconds. Conversely, if the required operating time is 0.4 seconds for a particular PSM current, and the time Tm obtained from the curve is 4.0 seconds then the required TMS should be

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OVERCURRENT PROTECTION

TMS =

0.4 T = 0.1 = Tm 4.0

Increasing the TMS has the affect moving the curve higher on time scale.

5.4.2 PSM Examples Consider the situation where the maximum fault current flowing through the relay location is 3000 A (primary) and the relay is set to operate at 200 A (primary), then

PSM = 3000/200 = 15

Consider the same example, but in this case the relay setting has been given as a tap/plug setting of 50% and the CT ratio of 400/5, then to calculate PSM it necessary to refer all currents to either primary or secondary values. If currents are referred to the primary, then

PSM =

3000 3000 = = 15 (as above) (0.5 × 5) × (400 / 5) 200

However, if the same primary current was considered but with a relay current setting of 200%, then

5.5

PSM =

3000 3000 = = 3.75 (2.0 × 5) × (400 / 5) 10 × 80

RELAY DISCRIMINATION

To ensure that the protection will correctly select and isolate the faulty section of the network only, thereby leaving the rest of the system undisturbed, it is necessary to achieve proper relay coordination/ discrimination. Discrimination can be achieved by: 1. time 2. current 3. combination of time and current.

5.5.1 Discrimination by Time To ensure selectivity of operation under all circumstances in a radial feeder, the operating time of the protection is increased by the grading margin (usually 0.4 or 0.5 seconds) from the far end of protected circuit towards the generating source. This grading is very conveniently achieved with the help of definite time-delay relays (which consist of an instantaneous

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

overcurrent relay followed by a timing relay), the contacts of the latter initiate the trip the breaker. Let us consider a simple radial system as illustrated by Fig. 5.3. (Time grading in this instance has been assumed to be 0.4 seconds). A

B

1.45

C

1.05

E

D

0.65

0.25

F

FIGURE 5.3 Simple radial case (time grading assumed 0.4 seconds)

The protection is provided at the sending end of each section A, B, C, D, and E, the relay at D is set to the shortest possible time to allow the fuse to blow for a fault which is in the secondary side of the transformer E. Hence, if there is a fault at F, the relay at D operates at 0.2 seconds, the circuit breaker at D clears the fault. The protections at C, B and A provide back up. For faults between C and D the relay at C trips breaker at C and so on. One of the greatest disadvantages of this system is that the longest fault clearance time occurs for faults in the section closest to the source where the fault level is highest. Let us consider another simple radial system as illustrated in Fig. 5.3(a). (Time grading in this instance has been assumed to be 0.5 seconds). D 200/5

C 300/5

2000 A

B 300/5

3000 A

A 400/5

5000 A

6000 A

Max. fault level (3 phase)

FIGURE 5.3 (a) Simple radial case (time grading assumed 0.5 seconds)

Start with the relay at ‘D’ Choose TMS = 0.1 (say). Assume that the load current does not exceed 80 A (CT is 200/5), then the relay tap/plug setting can be set to (1.2 × 80)/(200/5) = 2.4 A select say 2.5 A (i.e., 50%), then Fault current 2000 (primary) PSM = = 20 = Relay current setting 2.5 × 40 (primary) If reference is made to the standard IDMT curve, Fig. 5.2(a) (at TMS = 1.0), it can be seen that with PSM equal to 20, the corresponding Tm is 2.3 seconds.

OVERCURRENT PROTECTION

111

When the formula for the static/digital relays is used, the same result is obtained. Tm = 0.14/((PSM)0.02 – 1.0) = 2.3 seconds as

TMS =

T Tm

T = 2.3 × 0.1 = 0.23 seconds T = K × [TMS]/[(I/IS)α – 1.0] = (0.14 × 0.1)/[200.02 – 1.0] = 0.23 seconds Continue with the relay at ‘C’ Now, for the same current of 2000 A the relay at ‘C’ must be set to operate at 0.5 seconds (time delay step) longer than the relay at ‘D’, i.e., 0.23 + 0.5 = 0.73 seconds. If one assumes that the load at ‘C’ is higher than the load at ‘D’, then the current setting at ‘C’ must be increased as compared to that of ‘D’. Assume that the setting at ‘C’ needs to be 100% and uses 300/5 CT, then PSM =

Fault current 2000 (primary) = 6.67 = Realy current setting 5.0 × 60 (primary)

If reference is made to the standard IDMT curve (at TMS= 1.0), it can be seen that with PSM equal to 6.67, the corresponding Tm is 3.6 seconds. When the formula for the static/digital relays is used, the same result is obtained. Tm = 0.14/((PSM)0.02 – 1.0) = 3.6 seconds Hence for the required operating time of 0.73 seconds, the value of TMS =

T = 0.73/3.6 = 0.20 seconds Tm

When the formula for the static/digital relays is used, the same result is obtained for TMS. TMS = (T × [(I/IS)α – 1.0])/K =(0.73 × [6.670.02 – 1.0])/0.14 = 0.20 seconds When faults occur close to ‘C’ the fault current is 3000 A, the corresponding PSM value for the relay at ‘C’ is, PSM =

3000 = 10 5 × 60

With PSM equal to 10, the corresponding Tm is 3.0 seconds and, with TMS = 0.20 seconds the actual operate time for the relay is

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

T = 0.20 × 3.0 = 0.60 seconds When the formula for the static/digital relays is used, the same result is obtained for T. T = K × [TMS]/[(I/IS)α – 1.0] = (0.14 × 0.2)/[100.02 – 1.0] = 0.60 seconds Continue with the relay at ‘B’ Now at ‘B’ the required operating time for a fault at ‘C’ is 0.6 + 0.5 = 1.1 seconds. Because of increased load assume that the current setting at B needs to be increased to 150%, then PSM =

3000 = 6.67 7.5 × 60

With PSM equal to 6.67, the corresponding Tm is 3.6 seconds. Hence for the required operating time of 1.1 seconds, the value of TMS =

T = 1.1/3.6 = 0.31 seconds Tm

When the formula for the static/digital relays is used, the same result is obtained for TMS. TMS = (T × [(I/IS)α – 1.0])/K = (1.1 × [6.670.02 – 1.0])/0.14 = 0.30 seconds When faults occur close to ‘B’ the fault current is 5000 A, the corresponding PSM value for the relay at ‘B’ is, PSM =

5000 = 11.1 7.5 × 60

With PSM equal to 11.1, the corresponding Tm is 2.84 seconds and, with TMS = 0.30 seconds the actual operate time for the relay is T = 0.30 × 2.84 = 0.85 seconds When the formula for the static/digital relays is used, the same result is obtained for T. T = K × [TMS]/[(I/IS)α – 1.0] = (0.14 × 0.3)/[11.10.02 – 1.0] = 0.85 seconds Continue with the relay at ‘A’ Now at ‘A’ the required operating time for a fault at ‘C’ is 0.85 + 0.5 = 1.35 seconds. Because of increased load, assume that the current setting

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OVERCURRENT PROTECTION

at ‘A’ needs to be increased, but because of the higher CT ratio, sufficient margin is achieved by having the relay tap/plug setting on 150%, then PSM =

5000 = 8.34 7.5 × 80

With PSM equal to 8.34, the corresponding Tm is 3.23 seconds. Hence for the required operating time of 1.35 seconds, the value of TMS =

T = 1.35/3.23 = 0.42 seconds Tm

When the formula for the static/digital relays is used, the same result is obtained for TMS. TMS = (T × [(I/IS)α – 1.0])/K = (1.35 × [8.340.02 – 1.0])/0.14 = 0.42 seconds When faults occur close to ‘A’ the fault current is 6000 A, the corresponding PSM value for the relay at ‘A’ is, PSM =

6000 = 10 7.5 × 80

With PSM equal to 10, the corresponding Tm is 3.0 seconds and, with TMS = 0.42 seconds the actual operate time for the relay is T = 3.0 × 0.42 = 1.26 seconds The summary of corresponding operating times for the above example are shown in Fig. 5.3(b). A 1.35

B 1.1

C 0.73

E

D 0.23

F

FIGURE 5.3 (b) Summary of operating times for example

5.5.2 Discrimination by Current Grading by current alone relies on the fact that the fault current along the length of the protected circuit decreases as the distance from the source to the fault location increases. The relays controlling the various circuit breakers need to be set to operate at suitable values such that only the relay nearest to the fault trips its breaker. This method, however, relies on significant differences between the fault levels at the consecutive stations, for most practical applications this

114

POWER SYSTEM PROTECTION AND COMMUNICATIONS

is very rarely achieved. In addition it would not be possible to use current grading as the sole protection scheme of a primary plant because the protection operation zones of such a scheme would not overlap and large ‘blind’ sections of the network would be created, and these in turn would remain unprotected. This method, therefore, is used mainly in a supplementary capacity in some schemes. Let us consider a simple radial system as illustrated by Fig. 5.3(c). 0.12 W/km 2000 metres

11 kV 2 250 MVA 240 mm source P.l.C. cable

F1

C

0.02 W/km 2000 metres 2

120 mm P.l.C. cable

B

F2

F3

4 MVA 11/3.3 kV 7%

A

F4

FIGURE 5.3 (c) Radial system using current and time

Consider the three phase fault levels at F1 IF = 1

where

Vf

1

(Z S + Z11 )

Vf = Source phase to ground voltage 1

Zs = Positive sequence source impedance (ohm) = (kV)2/MVA = 112/250 = 0.484 ohms

Z L1 = Positive sequence line impedance (ohm) = 0.12 × 2 = 0.24 ohms ∴

IF = 1

6350 = 8.77 kA (0.484 + 0.24)

The relay controlling the CB at ‘C’, if set to operate at 8.77 kA, would in theory protect the whole of the cable section between ‘C’ and ‘B’. However, two important practical aspects which affect the method of coordination can be demonstrated here, they are as follows: 1. The relay would not be able to distinguish between faults at F1 and F2 (as the difference between the distance may be very small (a few metres)). Hence the corresponding change in IF would 1 be negligible. 2 . The relay settings would have assumed that the source fault level is constant, whereas for the practical operating environment, it

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is possible that the source fault level is reduced from 250 MVA to 130 MVA. Under these conditions the source impedance would increase and the fault levels would reduce accordingly. Zs = 112/130 = 0.93 ohms ∴

IF = 1

6350 = 5.43 kA (0.93 + 0.24)

At the lower fault level IF = 5.43 kA, the relay if it had been set 1 for 8.77 kA would not protect the cable section. Hence, in this case current grading would not be a practical solution. Consider the three phase fault levels at F4 (assume the source fault level to be 250 MVA) ∴

IF = 4

6350 (Z s + Z L1 + Z L2 + Z T )

where ZL = Positive sequence line impedance = 2 × 0.02 = 0.04 ohms 2

ZT = Positive sequence transformer impedance = 0.07 × [(112)/4 = 2.12 ohms ∴

IF = 4

6350 = 2200 A (0.484 + 0.24 + 0.04 + 2.12)

The relay controlling the CB at ‘B’, if set to operate at 2.2 kA, would in theory protect the whole of the cable/transformer section between ‘B’ and ‘A’. However, it would not discriminate with the relay controlling the CB at ‘A’. If discrimination were to be achieved, a safety margin of say 30% would need to be allowed for (assume 20% for relay error and 10% for variation in the system impedance values). ∴ Choose a relay setting of 1.3 × 2.2 kA = 2.86 kA (relay at ‘B’) However, the increased setting for the relay at ‘B’ would create a ‘blind’ spot where no protection was being provided. Again this would not be a practical solution. Consider the three phase fault levels at F3 (assume the source fault level to be 250 MVA) ∴

IF = 3

6350 6350 = (Z s + Z L1 + Z L 2 ) (0.484 + 0.24 + 0.04)

= 8.3 kA

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If the source fault level was 130 MVA then, IF = 3

6350 = 5.25 kA (0.93 + 0.24 + 0.04)

Therefore, for this application with the relay at ‘B’ set to 2.86 kA, the section of line from ‘B’ to the transformer would be protected.

5.5.3 Discrimination by the Combination of Time and Current As demonstrated in earlier sections, discrimination by time alone will cause the more severe faults to be cleared in the longest operating time, discrimination by current alone can only be applied when there is appreciable impedance between the two circuit breakers concerned, however, even in these cases ‘blind’ spots would be created. Therefore, there are severe limitations with both of these methods. Because of these limitations, the inverse time overcurrent relay characteristic has evolved where both the functions of time and current are considered for achieving discrimination. If the fault level falls substantially from substation to substation with increasing distance from the source, then much faster fault clearance than that in the time grading method may be achieved through grading by time and current. By proper selection and setting of the inverse characteristics, a discriminative plan of relatively fast tripping can be developed as detailed in Fig. 5.3(d). As can be seen, even with the proper grading margin of at least 0.4 seconds being maintained, fault clearance times near the source are almost as quick in this scheme as clearing a fault a long way from the source. The 0.4 seconds grading margin is required to cover such delays as circuit breaker clearance time, relay overshoot time and relay timing errors. The advantages of this method of relay coordination are demonstrated by considering the system as shown in Fig. 5.3(d), and the following calculations. It should be noted that the graph in Fig. 5.3(d) illustrates the use of ‘discrimination curves’ which are an essential aid to ensure correct protection coordination. For the example, being considered, the 200 A fuse is the first curve to be plotted as it is assumed to protect the largest outgoing 3.3 kV circuit. Note that all fault currents have been referred to a 3.3 kV voltage base so that all the protective devices to be considered can be plotted on the same graph. The protection relays for this system have been assumed to be of the Extremely Inverse type (CDG14 type characteristic). Once the 200 A fuse has been plotted, then the grading of the overcurrent relays from the remote station ‘E’ to the source station ‘A’ are carried out progressively.

117

OVERCURRENT PROTECTION 1000

Relay A

Relay C

100

Relay D

Relay B

Time (seconds)

10 200 A fuse

1

0.1

35.7

0.01 100

1000

98.7123

10,000

1540 3500 MVA 100,000

Fault current (amperes) 3.3 kV Base

3500 MVA

1540 MVA

15,000 metres 2

240 mm 132 kV overhead line 3500 MVA 6.2 ohms source 500/1 A

A 132 kV

123 MVA

98.7 MVA

2000 metres 2 30 MVA 240 mm P.l.C. 132/11 kV cable 22.5% 0.24 ohms

150/1 A B

500/5 A

C 11 kV

35.7 MVA

200 metres 2

120 mm P.l.C. cable 0.04 ohms

Fuses 200 A

150 A 250/5 A 4 MVA 11/3.3 kV D E 7% 3.3 kV

FIGURE 5.3 (d) Discrimination plan as detailed in 0.4 seconds grading

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In addition for the purposes of this example, all the fault calculations demonstrated below are all referred to a common 10 MVA base. Per cent impedance of the system elements on l0 MVA base 4 MVA transformer

= 7 × 10/4 = 17.5%

11 kV cable (ED)

= 0.04 ×

10 × 100 = 0.33% 112

10 × 100 = 1.98% 112 30 MVA transformer = 22.5 × 10/30 = 7.5%

11 kV cable (DC)

= 0.24 ×

132 kV overhead line = 6.2 × 132 kV source

=

10 × 100 = 0.36% 132 2

10 × 100 = 0.29% 3500

Consider SUBSTATION ‘D’ The protection at this substation is the first relay that must discriminate with the 200 A fuse at fault levels up to:

10 × 100 = 35.77 MVA 17.5 + 0.33 + 1.98 + 7.5 + 0.36 + 0.29 i.e.,

If =

or

If =

35.77 × 1000 3 × 3.3 35.77 × 1000 3 × 11

= 6258 A at 3.3 kV = 1877 A at 11 kV

For satisfactory coordination between the fuse and the relay, the primary current setting of the relay should be approximately three times the current rating of the fuse and, the time grading margin, when expressed as a fixed quantity should not be less than 0.4 seconds, or when expressed as a variable quantity should have a minimum value of (0.4t + 0.15) seconds, where ‘t‘ is the nominal operating time of the fuse. For the above fault condition the fuse operating time at 6258 A is approximately 0.01 seconds, therefore the required operating time of the relay should be equal to or greater than (0.01 × 0.4 + 0.15) = 0.154 seconds. The relay current setting must also accommodate a safe load of 4 MVA (the rating of the 11/3.3 kV transformer). By selecting a 100% plug setting i.e., 250 A and 4.76 MVA at 11 kV this requirement will be satisfied (19% safety margin), also the requirement of three times the current rating of the fuse is satisfied (i.e. [250 × (11/3.3)]/200 = 4.2). As a consequence PSM = 1877/250 = 7.51.

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119

From the above data, the time multiplier setting can then be selected using the following formula: TMS = T/Tm for electromechanical relays = T/Tm = (T × [(PSM)2 – 1.0])/80 (for static/digital based relays) From the characteristic curve of the extremely inverse relay for 1.0 TMS, the Tm for PSM of 7.51 is 0.9 seconds, therefore TMS = 0.154/0.9 = 0.17 Select the next highest available time multiplier setting, in this case 0.2, this setting will ensure that suitable discrimination with the fuse is achieved. Consider SUBSTATION ‘C’ The relay in this case must discriminate with the relay in substation ‘D’ at fault levels up to:

10 × 100 = 98.7 MVA 1.98 + 7.5 + 0.36 + 0.29 i.e.,

17.27 kA at 3.3 kV or 5180 A at 11 kV

In addition to providing primary protection to the section ‘C’ to ‘D’, relay ‘C’ must also provide backup protection to relay ‘D’ protection covering the section ‘D’ to ‘E’. By selecting 100% plug setting i.e., 500 A and 9.33 MVA at 11 kV (1667 A at 3.3 kV ) the sensitivity of the relay meets both the primary and backup requirements. Following the same procedure as was detailed for SUBSTATION ‘D’ by selecting a time multiplier setting of 0.7 for relay ‘C’, the required discrimination with relay at substation ‘B’ is achieved. Consider SUBSTATION ‘B’ The relay in this case must discriminate with the relay in substation ‘C’ at fault levels up to:

10 × 100 = 123 MVA 7.5 + 0.36 + 0.29 i.e.,

21.5 kA at 3.3 kV or 6.46 kA at 11 kV or 537 A at 132 kV. In addition to providing primary protection to the section ‘B’ to ‘C’, relay ‘B’ must also provide back up protection to relay ‘C’ protection covering the section ‘C’ to ‘D’.

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Following the same procedures as was detailed for SUBSTATION ‘C’, by selecting at 132 kV, 100% plug setting (i.e., 150 A and 34.3 MVA at 132 kV), and a time multiplier setting of 0.7 for relay ‘B’, the required discrimination with relay at substation ‘C’ is achieved. Consider SUBSTATION ‘A’ The relay in this case must discriminate with the relay in substation ‘B’ at fault levels up to:

10 × 100 = 1540 MVA 0.36 + 0.29 i.e.,

269.4 kA at 3.3 kV or 16.1 kA at 11 kV or 6.75 kA at 132 kV.

In addition to providing primary protection to the section ‘A’ to ‘B’, relay ‘A’ must also provide backup protection to relay ‘B’ protection covering the section ‘B’ to ‘C’. Following the same procedures as were detailed for SUBSTATION ‘C’, by selecting at 132 kV, 100% plug setting (i.e., 500 A and 114 MVA at 132 kV), and a time multiplier setting of 0.9 for relay ‘A’, the required discrimination with relay at substation ‘B’ is achieved. If a comparison is made of the fault clearance times between the ‘time’ and ‘time and current’ grading approaches, as summarised in the following table, it is evident that the ‘time and current’ (inverse time characteristic) is far superior to the definite time overcurrent relay approach. Relay

Fault (MVA)

Time Grading Concept (Seconds)

Time and Current Grading Concept (Seconds)

Advantage of Time and Current Concept (Seconds)

D

98.7/35.7

0.25

0.07/0.17

0.18/0.08

C

122.7/98.7

0.65

0.33/0.42

0.32/0.23

B

1540/122.7

1.05

0.07/0.86

0.98/0.19

1.45

0.25/0.39

1.20/1.06

A

3500/1540

Consequently for faults close to the relaying points, the inverse time characteristic can achieve SIGNIFICANT reductions in fault clearance times. Even for faults at the remote end of the line, considerable time reductions are also achieved.

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5.6

121

GRADING MARGIN

The time interval between the operation of two adjacent relays is dependent on a number of factors, these include the following: (i) Circuit Breaker Time to Interrupt Fault Current (ii) Overshoot Time of the Relay (iii) Tolerances/Errors (iv) Final or Safety Margin

5.6.1 Circuit Breaker Time to Interrupt Fault Current The circuit breaker must have completely interrupted the fault current before the discriminating relays cease to continue operating. Therefore, the circuit breaker total operating time must be included as part of the time interval that is to be allowed for between discriminating relays.

5.6.2 Overshoot Time of the Relay Even after a fault has been cleared by the remote protection, the local relay may continue to operate until all the stored energy from the system fault condition has been dissipated e.g., an induction disc relay has stored kinetic energy in the motion of the disc, static relays have energy in its capacitors. Although relay design is directed to minimise and absorb these energies, the problem in general still remains. As a consequence some allowance for overshoot must be included as part of the time interval that is to be allowed for between discriminating relays (overshoot is more predominant with electromechanical relays).

5.6.3 Tolerances/Errors All components (i.e., relays, current transformers, system parameters used to calculate fault currents, etc.) have errors. The operating time characteristic of relays may have positive or negative errors, the current transformers may have phase and ratio errors and the system parameters such as impedances have positive or negative errors. Therefore, it cannot be assumed that the information on relay characteristics, etc. as supplied by manufacturers are without error. Manufacturers generally supply tolerances for their equipment. As a consequence some allowance must be made for these tolerances/errors when applying the settings of discriminating relays.

5.6.4 Final or Safety Margin In spite of the aforementioned allowances the discriminating relay must ensure that the remote relay has been given the opportunity to clear the fault and therefore not complete its own operation and unnecessarily trip a section of line/plant that is not faulted.

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Some extra allowance is generally required to ensure that a satisfactory safety margin remains. The total recommended time interval between discriminating relays depends on the operating speed of the circuit breakers, relay performances and accuracy of the system data. In the past, 0.5 seconds was the normal grading margin. However, with the advent of faster circuit breakers and reduced relay overshoot times, it has been possible to reduce the total time for the grading of successive relays to 0.4 seconds. This margin allows up to: • • • •

0.15 seconds for circuit breaker to interrupt the fault current, 0.05 seconds for overshoot time, 0.10 seconds for the tolerances in the relays and CTs, and 0.10 seconds for safety margin.

However, instead of using a fixed grading margin (0.5, 0.4 seconds or other), it is preferable to adjust the time to satisfy the particular application. In general it is preferable for the grading margin to use a fixed time value for the operating time of the circuit breaker and relay overshoot and, a variable time which takes into account the relay and CT errors as well as the safety margin. On this basis the following could then apply: • Select a fixed time value for the circuit breaker fault clearance time (say 0.10 seconds), • Select a fixed time value for the relay overshoot time (say 0.05 seconds), • Select a fixed time of 0.1 seconds for the safety margin, and • Allow 15% as total effective error and 10% as CT errors (total error 25%). Hence the time interval t’ between inverse time overcurrent relays is given as: t’ = (0.25t + 0.25) seconds where, t is the nominal operating time of relay nearest to the fault. The above demonstrates that each case study should be evaluated on its own merits, however, the factors that need to be considered to determine the grading time between discriminating relays remain unchanged.

5.7

EARTH FAULT PROTECTION

Earth faults are the most frequent of all faults. The magnitude of earth fault current is usually low when compared to the phase fault currents, which is due to the fault impedance path. The fault impedance path may

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OVERCURRENT PROTECTION

include earth resistance or neutral earth impedance, this will depend on whether the system is solidly earthed, insulated or earthed through some resistance and/or reactance. Hence, as a general rule more sensitive protections need to be provided for the earth faults when compared to the multi-phase type faults. Therefore, the connections made for the earth fault protections will need to be different when compared to those used for the multi-phase fault protections. More sensitive earth fault protection can be provided by the use of relays which respond only to the residual current of the system (as the residual component only exists when fault current flows to the earth). This then allows these protections to be set independent of load current (balanced or otherwise) and settings below normal load current can be achieved. Therefore, the earth fault relays have low settings which are generally between 20% to 80% of CT rated current. However, in the case of electromechanical relays with low current setting values, the relay could impose significantly higher burdens on the CT. Hence, special considerations may apply when low settings are to be applied on electromechanical type earth fault relays. In some applications time/current grading of earth fault relays may not be practicable unless earth fault currents are limited or special CTs with a higher output are used. Figure 5.4 illustrates the principle of earth fault protection. The residual current component is extracted by connecting the line CTs in parallel and having the earth fault relay connected in the neutral return path of the CTs. IA

CTs

A

ia

IB B

ib

CT = Current transformer E/F = Earth fault relay

IC C

ic if

E/F

FIGURE 5.4 Principal of earth fault protection

Figure 5.5 is basically the extension of Fig. 5.4. Here the phase overcurrent elements are connected in the individual phases and the earth fault relay is connected between the star point of the relay group and the neutral of the CTs. A current will flow through the relay winding only when a fault involving earth occurs.

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It is normal practice to use overcurrent relays only on two phases as these will detect any interphase fault; the connections to the earth fault relay are unaffected by this consideration (Fig. 5.6). This is done purely from an economical point of view. If all the CTs were ideal then under normal operating and interphase fault conditions no current would flow through the earth fault relay. However, with commercial CTs, due to the difference in errors and amount of residual magnetism, some current may flow through the relay. The magnitude of such unbalance or false residual current is usually in the order of 0.01 to 0.1 Ampere at rated primary current. It could be higher for heavy phase-fault currents. CTs CT = Current transformer O/C = Overcurrent relay E/F = Earth fault relay

O/C

E/F

FIGURE 5.5 Extension of Figure 5.4 O/C = Overcurrent relay E/F = Earth fault relay

O/C

O/C

E/F

FIGURE 5.6 Connection of overcurrent relays only on two phases for phase fault and on neutral for ground faults

The grading of earth fault relays is normally limited to one system voltage (due to the use of ∆/Y step down transformers), as an earth fault in one section (Y) may not cause earth fault current to flow in the other section (∆). Therefore, the earth fault on the Y side of the transformer will

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125

not be seen by the earth fault relays on the ∆ side of the transformer, hence the grading between earth relays on different voltage systems may not be required (grading would be required if Y/Y transformers with neutrals earthed are involved). However grading between the phase fault relays on the ∆ side of the transformer and the earth fault relays on the Y side of the transformer will be necessary, since phase currents are present in the ∆ side of the transformer.

CHAPTER

6 Fuses

6.1

INTRODUCTION

Fuses are the best known electrical devices and most of us at sometime or the other have been made aware of their presence when one must be replaced because it has blown/operated. They are basically simple and relatively cheap devices although their behaviour is much more complex and quite deceiving. Fuses perform the important duty of protecting the equipment cheaply, efficiently and quickly and ensure that the effects of faults are limited and that the continuity of supply is retained at all times. Although the construction of fuses are not all that complex, but their design and construction must be carried out with utmost care and precision so that its reliability of operation is ensured. The International Electrotechnical Commission (IEC) defines fuses as “a switching device that, by the melting of one or more of its specially designed and proportioned components, opens the circuit in which it is inserted and breaks the current when this exceeds a given value for a given time.” Australian Standards 1033 and 1034 cover the high voltage range of the fuses. The fuse is said to comprise all the parts that form the complete device. The complete device being: (a) the fuseholder, which carries the base and carrier and (b) the fuselink. The fuselink is a device comprising of a fuse element or several fuse elements connected in parallel enclosed in a cartridge, usually filled with an arc extinguishing medium and connected to terminations. The fuselink is the part of a fuse which requires replacement after the fuse has operated/blown.

FUSES

127

The fuse is a weak link and hence it has advantages over circuit breakers. Generally the circuit breaker interrupts the current one to five cycles after initiation at a natural current zero, whereas the fuse can operate faster at any time and at any point on the current wave depending on the magnitude of the overcurrent and the fuse characteristic. As element of fuse is smaller in cross sectional area than the cable it protects, hence it reaches melting point prior to the cable (provided both cable and fuse element are of the same type of material). As the current increases the element melts fast. Unlike circuit breaker, on deterioration it has tendency of still faster operation. Hence ensuring its ‘fail-safe’ nature at all times. The operation of the fuses can be made tamper proof when it is in sealed and the cartridge type makes it silent and non-flammable. Hence the sealed cartridge type which have element of silver (say) can be non-deteriorating and gives consistent and reliable performance. The biggest advantages fuses have is the devices are much cheaper than the circuit breaker of similar rating and breaking capacity. Also the maintenance cost is much lower. The disadvantage of fuses is the replacement time, although modern cartridge fuses can easily be replaced, but the time to detect the faulty fuse may be an added liability. Also, it has no switching ability at normal currents and must be replaced after each fault operation. Hence if the fault in the system occurs quite frequently, its replacement cost may make the device quite expensive. However, a fuse-switch combination may overcome the poor protection performance against small overcurrent.

6.1.1 Basic Definitions The minimum fusing current is the minimum current at which a fuse element will melt, which is the asymptotic value of current shown by the time/current characteristic. (refer Fig. 6.30) A conventional current rating is normally used under classification of fuses which are reproducible under standard conditions. The service rating is used for special type of fuselink which are to perform unusual duties. These types of fuses must be used with the advice of the manufacturer. The current rating is the rating less than the minimum fusing current, stated by the manufacturer. This is the current that the fuselink will carry continuously without deterioration. Fusion factor is the ratio of minimum fusing current to that of the current rating.

128

6.2

POWER SYSTEM PROTECTION AND COMMUNICATIONS

CATEGORIES OF FUSES

Fuses can be classified into three categories: (i) high voltage (ii) low voltage (iii) miniature. The distinction between the high voltage and the low voltage occurs at 1 kV and the miniature designation is associated with physical dimension. Fuses are produced in four constructional forms: (a) cartridge (b) semi-enclosed (c) liquid (d) expulsion.

6.2.1 Cartridge Type of Fuses The cartridge type of fuse can be of all the three categories: (a) low voltage cartridge fuse (b) high voltage cartridge fuse (c) miniature type. A typical construction of the low voltage type is shown in Fig. 6.1. The powder filled cartridge category of fuses have the most advanced type of fuselink. Normally, fillers like sand which is pure and free of iron or quartz is used and both are functions of silicon dioxide. When the fuse blows, it creates a tube of melted sand around it which withdraws energy from the arc and extinguishes it. If fine or coarse filler is used it causes excessive pressure, however, intermediate grain produces optimum cooling. It is desired to reduce the volume of metal in an element as a result reducing the pressure on the cartridge.

FIGURE 6.1 Low voltage cartridge fuse

The advantages of filler is that heat is conducted away from the element more rapidly than in air. Hence smaller element can melt at a larger

129

FUSES

minimum fusing current. Thus a thinner wire may be used for a given current rating. When the wire is flattered into a tape the heat dissipation is much faster. If the width at sectors along its length is increased, the heat dissipation from the constriction is still faster. By such means the crosssectional area of the constrictions can be considerably reduced for a given rated current which makes the fuse operate much faster than on a uniform element as shown in Fig. 6.2. g

Closing angle

Supply voltage

Voltage zero

Cut-off current Prospective current 5,000 A

22x 5000 A

Current

Recovery voltage

Approx. 1000 V

Volts across fuse terminals

5,000 kW

Sand melted is proportional to this area Power dissipated in fuse cartridge

Pre-arcing 2 it

2

Total i t (limits heating of conductors etc.)

ò i2dt Joule integral

Actual pre-arcing time

Actual arcing time

Element heating up to melting point at constrictions during pre-arcing time

FIGURE 6.2 Representation of a sand-filled cartridge fuse with typical oscillogram for the operation on short circuit (Approx. 100 A rating)

The dissipation of heat is further improved by using a number of thinner elements in parallel instead of one thicker element. This gives further advantages, firstly, the arc is distributed uniformly and secondly, it improves performance of fuses on small over current. However, parallel element may/may not blow out simultaneously.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Melting time of fuse element may be further adjusted by means of special techniques of time delay. 1. M-effect (Metcalf or Melting point effect): This method can be achieved by the addition of low melting point alloy to the surface, where it will dissolve the element material when it melts. This has the effect of opening the element at the point where the dissolution takes place at a chosen point along the length of the element. As this process takes longer time to complete than the melting of the unmodified element of smaller cross-section, in spite of the fusing current to be the same in both cross-section, the use of M-effect can produce a time delay in the small to medium over current region and thus prevent unnecessary blowing of fuses by surges of current in normal service (Fig. 6.3). 2. Heat sink effect: In this process by inserting a large fusible metal in the element a more extended time delay can be obtained. Because of the large thermal capacity of the insert it acts as a “heat sink”. Larger the volume of the fusible metal, longer is the time taken to melt. Hence longer the time delay. Tape Wire Low melting point high thermal capacity insert. Melts on small overcurrent if sustained

Dual element time tag M-effect additions (fuse on small overcurrent if sustained) Region which melts on high overcurrent

FIGURE 6.3 Techniques of time delay on a section of a fuse element

Besides the time delay provision, both the above methods have other advantages. It reduces the temperature at which the element opens the circuit. Therefore, it reduces the temperature of the ‘blown’ cartridge immediately after clearing a fault at small overcurrent. Under high over current conditions, the fuse will melt at the most constricted points and by designing these carefully and manufacturing them to high precision, the pre-arcing time can be controlled.

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FUSES

The high voltage powder-filled cartridge type (rating >1 kV) is of current limiting type and uses similar basic principles as to its low voltage counter part. However, it is further refined to produce special characteristic and additional features. The length of fuse element and the number of constrictions is roughly proportional to its voltage rating. Therefore, fuse may tend to become quite long and difficult to use. Thus it is wound in the form of a helix on a star core in a barrel, as shown in Fig. 6.4. However, such construction requires great care, precision and careful design in order to ensure that the arc from one turn does not merge with the arcs from the next turn or sustained arcing may cause entire destruction. During productions manufacturers perform non-destructive testing. If used within prescribed rating and breaking capacity it can be a safe and reliable product. Striker coil Outer cap

Starcore

Body

Striker assembly Silver elements

Sand filter

FIGURE 6.4 Construction of typical hv fuselink

The miniature cartridge type of fuselink may be of two types (i) filled and (ii) unfilled type. They are basically small in size and used for the protection of electric appliances, electronic equipment and component parts, normally intended for use indoors. Many such varieties are available as shown in Fig. 6.5. Powder is used as filler for the filled type and it has high breaking capacity (in order of 1500 A). However, in the unfilled type the element is supported in air inside the glass cartridge. It has low breaking capacity (in order of 35 A). It is also possible to enclose huge variety of element shapes, time delay springs, thermal sinks etc. in the glass cartridge. The categories of speed of operation are signified by internationally accepted letters that are marked on the fuselink bodies, viz., FF = super quick acting F = quick acting M = medium time lag T = time lag or anti surge TT = super time lag.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

FIGURE 6.5 Selection of miniature fuselink

Fig. 6.6 provides an illustration of the different operating speeds of various miniature categories. 1000

100

10

F M T

TT

Time

FF

1

0.1

0.01 1

2

3 4 Current

5 6 7 8 910

FIGURE 6.6 Time/current characteristics of miniature fuselinks

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FUSES

The quick acting type of fuselinks are F and FF. The F type have single wire construction e.g., silver, copper and its alloy, nickel and nickel chromium. The FF type is similar to the F type except that the elements have a restricted section in them. The time lagging types are M, T and TT. These are all of low-breaking capacity type and have glass bodies and of the unfilled type.

6.2.2 The Semi-Enclosed Type of Fuse Fig. 6.7 illustrates the semi-enclosed type of fuse. This type is very widely used and they are in the low voltage category. The re-wirable fuse consists of a base, a carrier, the fuse element and an arc resistant tube (to limit the expulsion of flame). The element material is tinned copper, which has a melting point of 1083°C, but it cannot be run for any length of time at temperatures approaching the melting point and rapid oxidation takes place above 250°C. Hence, the semi-enclosed fuse requires a large overcurrent to blow it. The fusing factor is about 1.75. The performance depends on how the fuse is wired (may/may not touch the tube sides) and on the state of the tube. Care should also be taken as to ensure that it is free of kink and the correct size of fuse wire should be used. Fuse carrier

Fixed terminal

Fixed contact

Fuse element Fuse contact

Arc resistant tube

Fuse base

Cable socket

FIGURE 6.7 Semi-enclosed fuse

A lower fusing factor with reduced time-lag can be achieved by using a wire of silver, which is used in many cartridge fuses. The higher temperature at which the wire would have to run might, however, cause over-heating at rated current. There may be some form of emission of flame from the tube, in particular with larger fault currents, however, careful screening is necessary to avoid flashover to adjacent metal work or to other fuses. When a number of fuse wires are used in parallel in a re-wireable fuse, the resultant rating is less than the arithmetical sum of ratings of the individual wires. Its effective value is influenced by the type of design of fuse carrier being used, hence this practice is discouraged.

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6.2.3 European Categorisation of Semi-Enclosed Fuses The three systems used are described in terms of contact arrangements of the fuselinks and these are (a) Blade contact — NH type (b) End contact/screw type — D type (c) Cylindrical cap contact — B type The blade contact type referred to as NH fuses, where NH is the abbreviation of Niederspannungs Hochleitungs which is German for low voltage with high breaking capacity. They find applications in factory distribution systems and also in distribution cabinets of the electric supply industry. Fig. 6.8 shows a range of such type of fuses. The fuse elements are generally made of copper strip and the body is made of ceramic but in recent years high-temperature thermosetting plastic materials have gained popularity. Their bodies have a rectangular outside cross-section with a circular longitudinal hole through them, and end plates complete with the blade contacts are attached to the body with screws. To allow the fuselinks to be mounted in close proximity to each other, even in the absence of insulating separators, the end plates are normally confined within the outside dimension of the fuselink body. The blade contact surface are usually silver plated to assist in obtaining low-resistance connections even when the forces applied by the spring contacts into which they fit are relatively low. Some fuselinks are provided with cylindrical bodies and these are allowed in the standard specification provided they meet the dimensional requirements.

FIGURE 6.8 NH fuselinks

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FUSES

FIGURE 6.9 NH feeder pillar showing use of handles

FIGURE 6.10 NH fuse switch

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The NH fuselinks are inserted into their fuselinks by a detachable handle which is made of plastic, a particular example is shown in Fig. 6.9. Alternatively, in a widely used simple design of fuse-switch, the cover of the switch acts as the fuse handle, the fuse links replacing the normal switch blades and being withdrawn when the cover is opened or removed. This arrangement is shown in Fig. 6.10. The end contact or screw-type fuses are a very old fuse system. The abbreviation D standing for Diazed type. It is also called ‘bottle’ type due to the shape of the fuselinks (Fig. 6.11). The ‘D’ type also indicates that they are for domestic use. They have reached wide acceptance and it is being continuously used as replacement. Even new domestic FIGURE 6.11 ‘D’ type fuselink installations tend to use such types of fuses. The fuselink contain strip elements of copper or silver plated copper and are filled with granular quartz. The bodies are made of ceramic material. Each fuselink is fitted at the ends with cylindrical contacts made of brass, usually nickel-plated and are often of two different diameters. They are usually provided with grooves at ends to ensure good contacts when they are fitted in the carrier. The fuselinks are fitted with indicators which have a button head form and is pushed out through the end contact by a weak spring when the Plan 'xx' fine wire device in parallel with the main X X element melts and no longer provides restraint. The button head is visible through glass window in the fuse socket cap. Fig. 6.12 shows a standard holder. A range of gauge rings with various internal diameters and coloured ends to indicate the maximum ratings of fuselinks which will fit into them, is available. The appropriate ring is placed into a fuse socket to ensure that a fuselink of too great a rating for the circuit being protected may not be installed. The fuselink is inserted before the fuse socket cap is screwed to the fuse socket which produces forces between the fuselink end contacts and the spring contacts FIGURE 6.12 Holder for in the fuse socket and fuse socket cap. ‘D’ type fuselink

137

FUSES

The cylindrical cap contact or ‘B’ type fuses are widely used in France for both domestic and industrial applications. The fuselinks have copper wire or wire elements and are filled with quartz and have ceramic bodies. These fuselinks are available with visual operational indicators, if required. For domestic applications, the fuselinks are produced in a range of diameters and lengths, each rating having its own unique dimensions to prevent incorrect replacement after operation. Fuse switch units having ‘B’ type fuselinks are available for industrial use. Strikers, operating in a similar way to operation indicators may be incorporated in these fuselinks. When a fuselink melts, the striker moves out through the end cap and actuates a micro-switch which may initiate an alarm.

6.2.4 North American Fuses The various fuses are divided into classes, the main one being: Class K — up to 600 A, 250 V and 600 V Class H — up to 600 A, 250 V and 600 V Class J — up to 600 A, 600 V Class L — above 600 A and up to 6000 A, 600 V. Fuselinks with current ratings up to 60 A are generally fitted with cylindrical end contacts as illustrated in Fig. 6.13. Fuselinks for higher ratings are provided with either blade-type terminations for mounting in spring contact or blade terminations containing holes or slots which allow bolted connections to be made (Fig. 6.14).

FIGURE 6.13 North American cylindrical fuses

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FIGURE 6.14 North American tag type fuses

The Class K are cartridge fuselinks having a high breaking capacity typically about 200 kA. The fuselinks are made of organic materials viz., fibre to glass cloth impregnated with resin. The Class K is the most popular industrial fuse in USA. The fuselink operates slowly at currents in a range above the minimum fusing level but clears rapidly when carrying large currents. The way this is achieved is by splitting the fuse element into three different sections. The two outer sections use conventional strip and are surrounded by arc-quenching material such as quartz or calcium sulphate. It is these sections which operate when high short-circuit currents flow. The elements are generally made of copper but silver is sometimes used. The centre section is unusual as it has two metal portions of large thermal mass connected together with low melting-point solder (Fig. 6.15). Granular quartz

Short circuit elements

Body

Thermal cut-out element

End cap

FIGURE 6.15 Dual-element fuselink

At currents above the minimum fusing level the solder melts, its temperature rise being slowed by the adjacent masses of the metal. To provide an adequate break, the two metal parts are pulled away from each other by springs when the solder melts. The centre section does not contain

139

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filling material as this would prevent movement of the metal parts and it is not required for arc-quenching purposes at that current levels. Other types of Class K fuselink use the M-effect principle. The Class H fuselinks have a low breaking capacity (about 10 kA). They employ cylindrical fuse bodies in the high-breaking capacity fuselinks and the connection arrangements and dimensions are also interchangeable. There are two types of Class H fuselinks being non renewable and renewable. The former uses copper elements and fillers whereas the latter do not contain filling and use replaceable zinc elements with restricted section. The end cap of the renewable type are removable (Fig. 6.16) so as to allow the elements to be replaced when necessary. Screw on end cap Inner cap

Body

Element

FIGURE 6.16 Renewable fuselinks

Both the Class K and H fuselinks are mounted in simple unshrouded bases as illustrated in Fig. 6.17. As both classes are interchangeable, care should be taken to ensure that the two fuselinks are never interchanged as one has a lower breaking capacity than the other. Hence in order to distinguish between them, Class K type of fuse have recently been replaced

FIGURE 6.17 North American fuse bases

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by Class R fuselink. The Class R type of fuselink is shown in Fig. 6.18 and they contain features which prevents the insertion of Class H or Class K fuselinks.

FIGURE 6.18 Rejection features in class ‘R’ fuselinks

The Class J fuselinks are more compact than both the Classes K and H. They have a breaking capacity of 200 kA and a high speed operation under higher fault levels. Recently Class J has been replaced by Class T fuselinks which has smaller dimensions. The Class L fuselinks are used for all applications for current ratings above 600 A. They have a breaking capacity of 200 kA. In North America for domestic, commercial and light industrial distribution applications Class G fuses are available. They have a rating of 300 V up to 60 A with a breaking capacity of 100 kA. In domestic premises, the fuses are incorporated in the sockets from which the supplies are obtained. As the fuselinks are screwed or plugged into their holders they are known as ‘plug’ fuses. They generally have ratings up to 36 A and operate at 125 V. Three types of such plug fuses are used: (i) the ordinary (ii) the dual type (iii) the S type. The ordinary plug type is as shown in Fig. 6.19 and contains an element either in strip or wire form. The element can be seen through a mica window set in the end of the body. The body has no filling material and is made of glass. It has a metal contact in one end and a threaded brass section around it which acts as a second contact and a means for screwing the fuselinks into its base or holder. The fuselink can be replaced after operation but there are some which allow replacement of the element. Mica cover

Edison screw base

Contact Fuse element

FIGURE 6.19 Plug fuse

FUSES

141

The dual element plug fuse has the same basic construction as the ordinary plug fuse except that it contains two copper strips of which each have one of their ends soldered to the other. A spring is incorporated to separate the strips when the solder has melted as a result of the passage of overloads. The operation is not produced by high transitory surge currents but rapid clearance is obtained in the event of very high currents flowing during the short circuits. Both the plug type of fuse is fitted into standard Edison screw fuses (Fig. 6.19). It is possible for users to make contact with live parts when the fuselink is removed and a fuselink of any rating may be fitted into the base. The type S plug fuse is similar to the dual-element fuse but it is designed for use with an adaptor which performs a role similar to the gauge rings as mentioned earlier with the D type fuses. The adaptor has an external screw thread which will mate with Diaphragm the internal thread of a standard Edison screw fuses and when fully secured it can be locked. The adaptors are produced with several different internal threads, one for each fuse rating, hence the insertion of an incorrect Element fuselink is prevented.

6.2.5 Liquid Type of Fuse The liquid fuses are used for high voltage application and utilises spring tension to assist with arc extinction and to provide an adequate physical break in the circuit to withstand the Arc extinguishing service voltage after operation. It consists of liquid a toughened glass tube with metal end caps, to the upper of which is secured by the short Spring element (Fig. 6.20). This element has a high tensile strain wire in parallel with the silver fuse wire, as the latter is not strong enough to Glass tube withstand the tension of the spring securing the bottom of contact of the element to the lower end cap. The wires are enclosed in a fibre tube and the bottom contact of the element also carries a conical liquid director. The body of the fuse is filled with non inflammable insulating liquid such as carbon FIGURE 6.20 Sectional view of a liquid fuse tetrachloride to a level just below the element.

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When the element melts, the bottom contact is retracted downwards by the spring and the liquid director forces a stream of liquid into the arc path. The vapour pressure generated de-ionises the arc path and is then vented to the atmosphere by the rupture of a thin aluminium diaphragm in the top-end cap. The element and liquid may be replaced after operation and the fuse returned to service. Liquid quenched fuses are in wide use on overhead line networks. They are basically used outdoors and provision is made for removing from and replacing the fuselinks into their mountings by pole operation from the ground, a bayonet-fixing arrangement being utilised. They are mostly used for the protection of 11 and 33 kV pole or pad-mounted transformers on rural system and also for spurs feeding a number of transformers. In new installations such types of fuses are not being recommended and it is being replaced by the expulsion type of fuses. They have given and are till now giving good/satisfactory service. However, problems have been experienced with metal to glass seals which fail and cause leakage of the liquid. A subsequent fault clearance results in the disintegration of the tube.

6.2.6 Expulsion type Fuses Expulsion fuses consists of a tube of insulating material into which the fuse element is inserted, in some cases one end of the tube is closed and in other both ends are open. (Fig. 6.21). When element melts and arcing takes place the resultant gas pressure causes the arc to be blown out of the ends of the tube and extinguish. In certain designs the process is assisted by lining the interior of the tube with material such as boric acid, which produce gas when heated by the arc. In order to accelerate the process of arc extinction, the element is held under spring tension and when the element melts the spring rapidly separates the two sections. The disadvantages of the system is the clearing of low overcurrents. This is due to small pressure generated but it is overcome by using a small inner fibre tube to enclose within the main tube. The operation of expulsion fuse is violent, in particular with large fault currents and it is usually pole mounted out-of-doors, increased phase spacing is employed to avoid flashovers. Walls of tube may be contaminated by carbon and other arc products after blowing and in order to prevent leakage along this path the tube is arranged to be isolated from the circuit contacts after operation. This is achieved by utilising the spring normally holding the element under tension effectively to shorten the length of the fuse carrier when released. Also, it allows the carrier tube to disengage

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from the upper contact and to fall, under the influence of gravity, about the lower hinged contact. Screwed terminal cap Upper contact

Eye for operating rod

Element Inner tube

S.R.B.P. tube Standard flexible lead

Lower contact

Pivot pin Hinge pin Spring loaded quadrant

FIGURE 6.21 Expulsion fuse

The expulsion fuse is not manufactured for 415 V or other low voltages. It is essentially high voltage fuse use on system up to 33 kV. It is also used for the protection of overhead line network. Hence both fast and slow blowing elements are available. Also a number of automatic reclosing units have been designed, so arranged that if one blows it is automatically replaced after an interval of a few seconds. A cross-section through a typical fuselink is shown in Fig. 6.22(a) and three popular physical connection arrangements are illustrated in Fig. 6.22(b). These are designated: (i) button head (ii) double tail (iii) universal.

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Fibre sleeve

Flex

Copper sleeve

Solder Strain tape

Copper sleeve

Tin or copper element Copper button head rivet

Washer

(a) Sectional view of expulsion fuselinks

T-slow

T-slow

K-fast

(b) Terminations of expulsion fuselinks FIGURE 6.22

It can be seen that all of them have braid at the lower end, the only difference being the upper termination. The fuse carrier has pins at the lower end which act as a hinge when it is mounted on the lower contact of the fuse unit. In the service position the fuse carrier is tilted from the vertical as seen in Fig. 6.23. The main advantage of expulsion fuses is that they are cheap and in most cases can be reused by fitting replacement links. In addition, as they interrupt at current zero, they do not chop and do not produce excessive switching voltages. Their disadvantages are that they do not have the high breaking capacities of powder filled fuses and are not current limiting.

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Terminal Mounting bracket

Expendable cap (often cap only)

Fuse element Fusible section (enclosing tube often omitted) Fuse link (includes fusible section and tails) Fuse base Fuse-base contact

Fuse-carrier contact

Fuse-carrier

FIGURE 6.23 Schematic arrangement of an expulsion fuse

In some applications they have been known to cause fires due to the expulsion of incandescent particles during operation.

6.3

FUSE OPERATING OSCILLOGRAMS

Typical oscillograms of operation of fuses under small overcurrent and large overcurrent conditions are shown in Fig. 6.24. Current passed by fuse substantially equal to prospective current

Cut-off current

Prospective current

Current zero Peak arc voltage

Relatively long Pre-arcing time Voltage zero

Arc voltage

Recovery voltage

Recovery voltage Voltage zero

a

b

c a

c b d.c. a—Initiation of current; b—Initiation of arcing; c—Final clearance d.c.

(a)

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Current passed by fuse substantially equal to prospective current Current zero

Cut-off current Prospective current Current zero

Peak arc voltage Voltage zero

Recovery voltage

Voltage zero

Relatively long

Arc voltage Recovery c votage b a.c.

Pre-arcing time

a

a

b

c

a.c. (b) (a) Small overcurrent; (b) Large overcurrent

FIGURE 6.24 Typical oscillograms of fuse operation

6.3.1 Peak Arc Voltage It was a characteristic of certain early types of filled cartridge fuse that the voltage rise when clearing large fault currents was considerable, most fuse specifications now prescribe a limit to this voltage which, if exceeded, constitutes a disqualification. A simple wire fuse breaks up into globules along its length, with an arc between each globule and the next, thus producing a chain of arcs, which add up to produce a voltage proportional to the length of the element consumed and which may rise to several kilovolts. Modern fuses employ elements with constrictions. This results effectually in a number of short fuse elements in series, each so short that the overvoltage is limited. Problems do not arise until the fuse is operated very close to its breaking capacity and above its rated voltage, where the excessive burn-back of the element can produce conditions leading to very high voltages, as the wider parts of the element break up into molten globules. This is seen to be a further reason why fuses should never be used in a circuit above their rated voltage.

6.3.2 Fulgurite (Roping) These are terms normally used for the residues of sand in the fuse which were melted by the arc during clearance. These residues give much evidence of the processes which caused the fuse to blow. For example, the arc energy in the fuse may be calculated by weighing the fulgurite. If the weight of the fulgurite is w, then the arc energy was E = 2100 w Joules (w in grams)

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It is also possible to tell whether the fuse operated on a small or a large overcurrent by breaking open the blown fuse and studying the fulgurite. (Fig. 6.25.) Before

After Large overcurrent

Small overcurrent

FIGURE 6.25 Fulgurite structure-fuse without M-effect (with M-effect the fuse will operate at the M-effect on small overcurrent)

Maximum arc voltage

Peak arc voltage is dependent upon the number of constrictions in an element, because of the arcs in series. This gives a minimum value of peak arc voltage irrespective of the applied voltage up to a certain point. When this point is exceeded, the extra applied voltage can force the arcing to persist and produce burn-back and other effects which may increase with each incremental voltage, thus causing a larger peak arc voltage. This is illustrated in Fig. 6.26.

1000 V 500 V 250 V

Voltage rating Applied voltage

FIGURE 6.26 Arc voltage characteristic

It is, therefore, clear that a fuse of higher voltage rating should not be used to replace a blown fuse of lower voltage rating unless due cognisance is taken of the fact that its peak arc voltage will be greater. Peak arc voltage must not exceed the dielectric withstand of the system in which the fuse is placed. Fuses for 11 kV use are frequently designed to produce low arc voltages, in order that they may also be used on 6.6 kV systems. It should not be assumed that this is the case without first consulting the manufacturer on this point.

148

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

TIME vs CURRENT CHARACTERISTIC

Fuses operate by resistance heating of the fuse element. The heat dissipated t

in time t is equal to

z

i 2 R dt , where R is the resistance of the fuse element.

0

Further, at sometime t1 the element will reach the boiling point of the t1

material and for large currents the total heat generated will be

z

i 2 R dt

0

from this it can be deduced that, for a given element, under adiabatic conditions, the total amount of heating required to fuse the element can be t1

precisely determined, i.e.,

z

i 2 R dt is a constant. This quantity is known as

0

the Joule-integral and is denoted by I2t, where t is the virtual time defined as the value I2t divided by the square of the breaking current. Joule-integral can be used to accurately predict the cut off current for a given prospective short-circuit current. The pre-arcing I 2t of a fuse element is directly proportional to the square of its smallest cross-sectional area. Consider the section of a fuse element shown in Fig. 6.27 of length l and cross-sectional area A; carrying a current i. Mass m Temperature q°C Specific Heat s joules/gm Resistivity r0 ohm mm at 0°C Temperature coefficient of resistance = a per degree centigrade

Current i

I Resistance R

FIGURE 6.27 Section of fuse element heated by current

The heat produced in time dt is i2R dt =

i 2 ρ0 (I + αθ)l dt A

where ρ0 α σ θ

is the resistivity in ohm-mm at 0°C is the temperature coefficient of resistance in per °C is the specific heat in joules/gram is the temperature in °C

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As this quantity of heat will raise the temperature by dθ if no heat is lost to surroundings and from the knowledge of thermodynamics this quantity of heat is the product of mass, specific heat and the temperature i2 R dt = m σ dθ Also by definition density is the ratio of mass to volume. Hence, m=DAl 3 where D = density (kg/m ) and m = mass (kg) A × l = volume (m3) i 2 ρ 0 (I + αθ)l dt = DAl.σ dθ A

i2 dt = A2

or

Dσ dθ ρ0 α (θ + 1 / α)

On integrating both sides

z

2 i 2 dt = A

F GH

(θ 2 + 1/α ) Dσ ln ρ0 α (θ 1 + 1/α )

I JK

where θ2 = melting point of the element and

θ1 = 20 °C

z

i 2 dt = KA2

where K is the constant of the metal and can be directly calculated from the known values. For typical metal like silver and copper, normally used as fuse elements, the pre-arcing I2t is 6.6 × 106 A2 (Amp2 sec) and 9 × 104 A2 (Amp2 sec ) respectively, where A is the cross-sectional area of the conductor at narrowest point in mm2. Silver is very commonly used as a fuse element due to its non-deteriorating, low oxidation properties. It also has good M-effect with tin and its alloy. The usefulness of virtual time is shown in Fig. 6.28 which represents a typical fuse. It will be seen that the time less than about 5 × 10–1 s, there is a spread in the normal current-time curve (shown shaded) and with the larger currents there is considerable variation in the time, the ratio of the largest to the smallest being about 5. There is however, no spread in the curves of virtual time, and discrimination will be achieved between two fuses provided that the curve of virtual total operating time of the minor fuse lines below the curve of virtual pre-arcing time of the major fuse.

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Hence it is common practise for checking the discrimination between fuses to use I2t characteristics. 1000 500 100 50 10 5 1 –1

Time (sec)

5 × 10

Limits of actual pre-arcing time

–1

10 –2 5 × 10

–2

10 –3 5 × 10

–3

10 –4 5 × 10

Virtual pre-arcing time Virtual total operating time

–4

10 –5 5 × 10 –5

10

50000 40000 30000

20000

10000

5000 4000 3000

2000

1000

500 400 300

200

100

50

Prospective symetrical r.m.s. current (amp)

FIGURE 6.28 Vertical time curves

I2t characteristics are extremely useful to protection engineers who require rapid assessment of the degree of protection against short-circuits in a fuse protected network. The total operating time is greater than the time shown on the fore-arcing time/current characteristic, because the fuse element continues to arc between the melted ends until the current is reduced to zero. Hence Total operating time = Pre-arcing time + Arcing time The pre-arcing time is the time between commencement of a current large enough to cause melting of the fuse element and the instant when the arcing is initiated. Total operating times cannot be shown with accuracy

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151

since the arcing time varies with the power factor and transient characteristic of the circuit, the supply voltage, the electrical angle at which arcing commences and other factors. When operated within the voltage limits prescribed by the manufacturer, the arcing time is only significant for large overcurrents, where there are short operating times. The current usually plotted on the time/current characteristic is the prospective current i.e., the current which would flow in the test circuit if the fuse were replaced by a link of negligible impedance. The time for short-circuit operation is usually the virtual time, because of the variation of actual time with the point on the voltage wave and other variables. On small over currents, however, where the pre-arcing time is long and the arcing time negligible by comparison, the times shown can be taken as the total operating times at the currents shown. A fuselink which is to protect Supply Connecting a particular piece of equipment or cable cable A circuit should ideally satisfy a Item of equipment number of criteria. This is illustrated B by considering a simple example based on the circuit shown in FIGURE 6.29 Circuit protected by a fuse Fig. 6.29. Firstly, the minimum fusing current of the fuse should be slightly below the current which the cables and item of equipment are able to carry continuously. The item of equipment will usually be able to carry overload currents for limited periods, and the fuse should operate at these current levels in times slightly shorter than the corresponding equipment time ratings. Clearly, the cables should also be able to cope with this duty without suffering damage. Higher currents may flow as a result of faults within the item of equipment and in these circumstances the primary requirement is that consequential damage to the remainder of the circuit should be prevented. The extreme case will occur in the event of a short-circuit between the line and neutral terminals of the equipment. Clearance must then be effected before damage is caused to the cables. A further possibility is a short-circuit between the conductors of the connecting cable. The most severe situation would arise if the fault was at the input end, i.e., between points A and B and in these circumstances the fuse would have to interrupt the circuit before the source and supply cables could suffer damage.

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Time, (sec)

To achieve the criteria, fuselinks should have time/current characteristics which lie close to the withstand curves of their associated circuits as shown in Fig. 6.30. Clearly the operating time of the fuse should always be less, at any current level, than the period for which the circuit can withstand the condition. This seems to be self-evident but in practice there are a number of less obvious limitations and factors which must be taken into account.

Withstand curve of protected circuit Fuselink characteristic

Current

FIGURE 6.30 Time/current characteristics of circuit and fuse

A very important factor which must be recognised is that the operating times referred to above are the total clearance times, i.e., the sum of the pre-arcing and arcing times. Now ideally, a fuselink should be capable of carrying a current just below the minimum fusing level indefinitely and also of carrying a current just below the minimum fusing level indefinitely and also of carrying any higher current for just less than the corresponding operating time and thereafter be in its original condition. In practice, these conditions cannot be achieved because there are changes of state before operation occurs. Once arcing has commenced it is clearly impossible for an element to return to its original form and even in the molten state, an element may distort and not return to its initial shape on cooling. Furthermore, unacceptable changes may occur in fuses with low melting point materials on the elements, if overcurrents continue long enough to initiate the ‘M’ effect diffusion process. There is thus a head band below the time/current characteristic in which a fuse should, if possible, not be called upon to perform. The likelihood of high current flowing through a fuselink for just less than its operating time is small, but if it should happen, the probable result, which must be accepted, is that the fuse will operate more quickly than expected on a future occasion. Difficulties would certainly arise if a fuselink carried currents near its minimum fusing level for long periods, and, to avoid this situation, a fuselink is assigned a rated current somewhat below the

FUSES

153

minimum fusing value. The ratio of the minimum fusing current to the rated value, which is defined as the fusing factor, usually has values in the range 1.2–2. The significance of this factor is that protected circuits must be able to operate continuously at levels appreciably above the rated current of the fuse in the first criterion above, namely that the circuit continuous rating must exceed the minimum fusing current is to be satisfied. This is an uneconomic situation which arises with many protective arrangements, because it is necessary to have current settings above the full-load value of the circuit unless discrimination is achieved by differential methods. It is clear that it is particularly desirable to use fuselinks of low fusing factor when the cost of the protected circuit and equipment rises significantly with its current-carrying capacity. Another factor which must be borne in mind is that many fuselinks do not provide full-range protection, i.e., they will not operate satisfactorily, at all current levels from their rated breaking capacities down to the minimum fusing values. As stated earlier, satisfactory arc extinction may not be achieved in some fuselinks at relatively low over currents. Care must always be taken to see that such fuselinks are only used in applications where currents of these magnitudes will not be experienced or, if this cannot be guaranteed, then an associated protective scheme must be provided to interrupt these currents before the fuse can operate.

6.4.1 Published Time/Current Characteristics The data required for producing these characteristics are obtained by testing fuselinks which are at ambient temperature (15–20 °C) when current flow through them is initiated. The curves published by the fuse manufacturers usually show the relationship of the virtual pre-arcing time to prospective current. It will be appreciated that the effects of factors such as current limiting, the instant of fault occurrence and the current wave shapes do not significantly affect the performance at the lower current levels where the operating times are long and of course, the arcing periods are negligible compared with the pre-arcing times. As a consequence, the variations in operating times are insignificant at these levels and there is therefore only one time/current curve for each fuselink. In practice the passage of load current prior to the overcurrent condition of a high temperature environment causes operation to be slightly faster than shown on the characteristic. There is also an associated reduction of the times for which the protected circuit can withstand given overcurrents if it is in an environment of relatively high temperature or if load currents

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Pre-arcing time, (sec)

have been flowing in it. The two effects will not usually be equal but they nevertheless reduce the significance of this factor. 5000 1000 100 10

100A 40A 16A

1 0.1 0.01

100 1000 10,000 50,000 Prospective current in amps [r.m.s. Symmetrical]

10

FIGURE 6.31 Time/current characteristics

It is common to indicate the approximate minimum-breaking current on the characteristics by using a full line above this level and a dotted line below it. This is illustrated in the typical characteristics shown in Fig. 6.31.

6.4.2 Cut-Off Characteristics

or sh ric al et m ym

Characteristics for different rated currents

As

Peak current

tc

irc

ui

t

These show the highest possible instantaneous values of current which a given current-limiting fuselink will pass under fault conditions for varying values of prospective current. They are of use in calculating the peak mechanical forces which the equipment in protected circuits must be able to withstand. A typical characteristic is illustrated in Fig. 6.32.

Prospective currents r.m.s

FIGURE 6.32 Cut-off characteristic

FUSES

155

6.4.3 Operating Frequency The characteristics of fuselinks normally relate to operation at frequencies of 50 or 60 Hz and there is little difference between the behaviours obtained at these frequencies. Certainly a fuselink tested at a frequency of 50 Hz will be entirely suitable for use at 60 Hz. Even higher power frequencies would present little difficulty for the fuselink. Lower frequencies do, however, need careful consideration since extension of the duration of the half cycles of the source voltage wave causes the total operating times at very high current levels to be increased. As a result higher arc energies are released in the fuselink. For frequencies below 50 Hz some de-rating in terms of rated operating voltage is therefore necessary. In the extreme case of dc applications the voltage rating may be only half that allowable at a frequency of 50 Hz and high values of circuit inductance may necessitate further voltage de-rating.

6.5

DISCRIMINATION

Most circuits contain several protective devices and some of these are effectively in series. They must all be coordinated so that correct discrimination is achieved under all fault conditions and only the minimum of interruption should occur to clear any fault condition.

6.5.1 Discrimination between Fuse Links In domestic, and in many industrial installations, it is usual for the supply authority to provide the main fuses, and consumers’ branch circuits are protected by fuses of smaller rating. In the event of a fault in a branch circuit the branch-circuit fuse should blow but not the supply authority’s fuse, that is to say there should be discrimination. It is usual to call the fuses the major fuse and the minor fuse, respectively. If there were no arcing, and the fuses were of the same design, the minor fuse could be 90% of the rating of the major fuse and there would still be perfect discrimination. In practice, however, it is possible for a fuse to pass more I2t during arcing than is passed during melting (termed more correctly, the pre-arcing period), especially with large overcurrents in inductive circuits. If the major fuse is to remain intact its pre-arcing I2t must not be exceeded: Hence to achieve discrimination the pre-arcing plus the arcing I2t of the minor fuse must not exceed, and preferably should be less than, the pre-arcing I2t of the major fuse. This usually means that the rating of the major should be not less than twice that of the minor fuse. For convenience in ensuring discrimination between fuses, manufacturers publish I2t characteristics similar to those shown in Fig. 6.33.

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In these curves the minimum pre-arcing I2t is measured for every fuselink at high prospective current, and the maximum total let-through I2t, prearcing and arcing, will often occur at the condition of maximum arc energy. To select a minor fuselink which will discriminate with a major fuselink under all conditions, following two examples show the use of these curves. 7

10

Total operating 2

I t (at 415 V) 6

10

Total operating 2

I t (at 240 V)

2

2

I t (Amp sec)

5

10

4

10

2

Pre-arcing I t

3

10

10 12 16 20 25 32 40 50 63 80 100 125 160 200 250 315 400 500 630 800

2

10

Rated current (A)

FIGURE 6.33 Typical I2t characteristic

Example 1. Let a 160 A fuselink be the major fuselink in a system. It can be seen from the curves (Fig. 6.33) that the minimum pre-arcing I2t of this fuselink is 8 × 104 A2s. In the example, this is seen to be equal to the let-through I2t of a 100 A fuselink at 415 V. Theoretically this would be just

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too large a current rating for the minor fuse, because the element of the major fuse would just melt with the maximum let-through of the minor fuse. In practice, discrimination would probably not be lost, because the condition of maximum arc energy is very unlikely. To be sure that no deterioration of the major fuse can take place, the 2 : 1 ratio is to be preferred. We see that for the 80 A fuselink the I2t let-through is only 4.5 × 104 A2s, giving such a wide margin that the major fuse cannot suffer any permanent effect. It is evident from the foregoing that, if the rating of the major fuse is not too close to that of the minor, discrimination will be assured, provided that the fuses are of the same design. If the supply authority fits cartridge fuses at the incoming feeder and the user installs semi-enclosed fuses in the branch circuits, a larger ratio than two may be necessary to ensure that the major fuse will not blow in the event of a fault in the branch circuit. Circumstances can occur in which the major fuse is at approximately its working temperature when a fault occurs in a sub-circuit containing an unloaded minor fuse. Obviously the pre-arcing I2t of a hot fuse is less than that of a cold one, but if the minimum ratio of two is maintained the major fuse would not normally be more than 50% loaded and the corresponding reduction in I2t would be insignificant. Tests have shown that even if a cartridge fuse is preheated for a considerable time by a current not sufficient to melt the element, the reduction in I2t is usually small, in the context of discrimination. Example 2. It is very common to employ the radial system as shown in Fig. 6.34 which may contain a number of fuses which must be chosen to discriminate or alternatively a fuse may have to operate in series with a circuit which is tripped by a protective relay.

PD 4

PD 1

Load 1

PD 2

Load 2

PD 3

Load 3

Supply

FIGURE 6.34 Simple network

Here the major fuse in the supply connection (PD4) and minor fuses in the individual load circuits (PD1, 2 and 3). Clearly each minor fuse must have the time/current characteristic needed to protect its load circuit and a fault on a particular load should only cause its associated minor fuse to operate. The major fuse (PD4) will also carry the fault current but it must not operate or be impaired.

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Time, (sec)

For faults which cause relatively small currents to flow, the arcing times, as proportions of the pre-arcing times, are small and consequently discrimination can be predicted by comparing the time/current curves of the major and minor fuses. Provided that the curves for the minor fuses are to the left of that for the major fuse, that is the minor fuses operate more quickly, then discrimination should be obtained. A significant margin should nevertheless be allowed for fuse tolerances and because the major fuselink may be carrying currents fed to healthy circuits as well as the fault current. If these load currents may be large, then calculations should be done to determine the possible currents in the major fuselink for given fault currents and adequate time differences should still be present between the operating times of the fuses concerned. This situation is illustrated in Fig. 6.35.

b tb a

ta

Ia

Ib

Current

a = Minor fuselink b = Major fuselink Ib = Current in major fuselink when fault current Ia flows in minor fuselink tb = Must exceed ta characteristic

FIGURE 6.35 Fuselink characteristics

At higher fault-current levels which will result in melting the minor fuse in less than 100 ms, the arcing time of the minor fuse must be taken into account. This is done, not by considering the actual values of time, but by using the I2t values. The requirement is that the pre-arcing I2t of the major fuse shall exceed the total operating I2t of the minor fuse by a reasonable margin (say 40%). It will be appreciated that load currents flowing in healthy circuits while a fault exists, have negligible effects on the operation of the fuses when the fault current is very great. Pre-fault conditions are important, however, and the I2t margin suggested above should be increased if it is known that before a fault, the minor fuse is likely to be much less loaded, as a proportion of its rated current than the

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major fuse. This is because the minor fuse will be operating at lower temperatures than the major fuse at the instant of fault occurrence. A suggested rough, but general guide, for the extreme case of the minor fuse being on no load and the major fuse on full load when the fault occurs, is that the rating of the major fuse should be increased by a further 25%.

6.5.2 Networks Protected by Fuses and Devices of other Types Here the general requirement is similar to that for discrimination between two fuselinks, in that only the minor device is required to operate. It is the latter device which has to be chosen first, because its time/current characteristic must provide the necessary protection for its associated circuit. Thereafter, the major device must have a characteristic which will ensure discrimination. In practice two alternative arrangements are encountered, one in which the major device may be a fuse whilst the minor devices may be small or miniature circuit breakers incorporating overcurrent protective features, and the other in which a major circuit breaker and minor fuses are used. The characteristics associated with these two situations are shown in Fig. 6.36. d f

u

a = Minor device u = Major device f = Fuselink

Time, (sec)

1000 100 a

10 1 0.1

Current

FIGURE 6.36 Discrimination between a current limiting fuselink and other protective devices

With the first arrangement, there is always an actual or potential upper limit to the fault current at which discrimination can be obtained. This is because the circuit breaker or other minor device always has a definite minimum-operating time resulting from the delays in the overcurrent detection equipment and the circuit breaker itself plus its own arcing time, of which the latter is not likely to be less than the duration of one half-cycle. The operating time of the major fuse on the other hand, decreases continually with increase in current and the upper-current limit

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at which discrimination can be achieved is at the intersection of curves d and f in Fig. 6.36. With the second arrangement, the curves f and u in Fig. 6.36 are relevant. It will be seen that they approach each other most closely at times of the order of 1–3 s where the influence of arcing time is negligible and there is usually little difficulty in choosing characteristics which enable full discrimination to be obtained.

6.5.3 Coordination between a Current Limiting Fuse and a Directly Associated Device of Lower Breaking Capacity It has already been stressed that some current-limiting fuselinks are unable to clear currents in a range above the minimum fusing level and that an associated device of limited-breaking capacity is needed to interrupt these currents. In these circumstances the requirements are quite different from the preceding two cases. The current limiting fuse is used as a back-up for the other device. Thus in the event of heavy faults only the current-limiting fuse is required to operate while the associated device is required to operate in the event of overloads or small faults. This is achieved by choosing characteristics for the fuselink and other device so that they produce a composite characteristic of the form shown in Fig. 6.37, and this clearly must give sufficiently rapid clearance at all current levels to adequately protect the associated circuit. The other criteria which must be satisfied are as follows:

Time, (sec)

1000

a

100 Max breaking current of expulsion fuse

10 1 A

b

0.1

Current a—Expulsion fuse characteristic b—Current-limiting fuse characteristic

FIGURE 6.37 Coordination of a fuse and a directly associated device

(a) The take-over point (A) at which the curves intersect must be at a current level below the breaking capacity of the other device and above the minimum value which the current-limiting fuse

FUSES

161

link can interrupt, unless it is fitted with a striker which operates the other device. (b) To deal with cases where the current-limiting fuses clears the circuit, the other device must be able to safely carry the maximum fault current and, where it may have to close on to a fault, a making capacity adequate for the cut-off and I2t let-through values of the fuselink.

6.6

TESTING OF FUSES

Fuselinks, unlike most other equipment, cannot be subjected to extensive routine proving tests at the end of the production process because if they are operated they cannot be used again. The behaviour of individual designs must therefore be determined by very rigorous type tests and then the subsequent component parts must be produced to within very close limits of those used in the type-tested fuselinks. In addition, inspection and quality assurance systems must be employed to ensure that the volumeproduction output corresponds closely with the initial devices. In service, the conditions encountered by fuselinks may be very variable and, of course, their performances may be affected thereby. To ensure uniformity between manufacturers, tests must be done in specified and standardised conditions. The tests are conducted in laboratories and because of the control which is available, the limits set on parameters such as ambient temperature are much smaller than those specified in the standard conditions of service. Because the performances of fuselinks may be significantly affected by factors, such as the impedances of the test circuits, the size and disposition of attachments (including the cables) and, the proximity of supports or enclosures, the standards specify the test arrangements in great detail and this is particularly so for the time/current and short-circuit breaking-capacity tests. In general the following checks and tests are done on a number of pre-production fuselinks.

6.6.1 Construction and Dimensions Each fuselink which is to be used during type testing must be carefully examined during manufacture to ensure that there is nothing abnormal in its construction and the dimensions of the component parts are measured accurately to see that they are within close tolerances of the values to be used in the subsequent volume production.

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6.6.2 Electrical Resistance This value is measured for each fuselink to be type-tested. It must be done at an ambient temperature, typically in the range 20–25°C.

6.6.3 Power Dissipation Normally low-voltage fuselinks must be tested in a standard rig, as stated earlier. The power dissipated by each fuselink must be measured at rated current and the temperature rises of contacts or terminals are measured by thermocouples. Similar tests are done on high-voltage fuselinks but the power input need not be measured and when miniature fuselinks are tested only the voltage drop at rated current needs to be recorded.

6.6.4 Power Acceptance of Fuse Holders This test which is only applied to low-voltage fuses is performed by taking the fuselink found to have the highest power dissipation in the above test and inserting it into a fuse holder. Rated current is then passed through it again and the temperature rises at various points are measured by thermocouples.

6.6.5 Insulation Levels Extensive tests must be done on high-voltage fuses because of the vulnerable positions in which they may be used. They are subjected to impulse voltages viz., 1/50 is waves) between parts which will, in service, be live and earthed respectively. They are also subjected to power-frequency over-voltages under both wet and dry conditions. Low voltage fuselinks in their fuse holders are mounted on a metal panel and a power-frequency supply of 2.5 kV is connected for one minute between the panel and normally-live fuse parts.

6.6.6 Conventional Fusing Currents The terms ‘conventional fusing current’ and ‘conventional non-fusing current’ have been introduced into standard low-voltage fuse specifications to replace the term, minimum-fusing current, which has been in use for many years. The latter current is strictly the one which will cause a fuse link to operate in an infinite time and therefore its determination is impractical. The minimum-fusing current is defined as that current which causes operation in four hours, but even the determination of this value is very time consuming. To simplify the situation, the standard specifications require that all of a number of fuse links mounted in a standard type-test rig should operate in less than the conventional time when they are carrying the conventional non-fusing current. The conventional time, which may

163

FUSES

vary between values of one and four hours, depending on the current rating, is specified in the standards. The concept of conventional currents has been used on the continent for several years and it is likely that the present usage of the term ‘minimum-fusing current’ will be phased out.

6.6.7 Breaking Capacity Because fuses are usually the ultimate back-up protection in the circuits in which they are included they must be capable of operating under the most onerous conditions which may arise. For this reason the tests at maximum breaking capacity are done under specified conditions in low-power factor (typically less than 0.2 for low-voltage fuses), single-phase, inductive circuits arranged as shown in Fig. 6.38. Equipment is included to enable the test circuit to be closed at any desired point in the voltage cycle so that conditions of varying severity may be produced. The fuselinks are mounted in standard rigs of the form shown in Fig. 6.39. The tests determine not only breaking capacity but parameters such as I2t let through arc voltage and cut-off current and when the latter is being found, the circuit is switched so that arcing commences just prior to an instant when the system voltage Circuit Make breaker switch

Source of voltage

Variable impedors

Fuse under test

FIGURE 6.38 Test circuit

FIGURE 6.39 Standard test rig

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is at its peak value. To cater for three-phase applications the appropriate source voltage is used in the test circuit, that is 87% of the rated voltage in the case of high-voltage fuselinks or 10% more than the rated line voltage when low-voltage cartridge fuselinks are being tested. In all breakingcapacity tests the full recovery voltage is maintained for at least 30 s and in the case of high-voltage fuses it is maintained for 60 s. In addition to the above tests, the specifications require manufacturers to do type tests at lower current levels, and for these, the power factors of the test circuits are generally higher than those used at the maximum currents. This represents the situation which tends to arise in service, proportionally more resistance being present at the lower fault levels. This is also recognised in the standard specifications which allow power factors of 0.3 to 0.5 for low-voltage fuselinks. Minimum breaking capacities are not usually quoted by manufacturers for miniature fuselinks and for the majority of low-voltage, general-purpose fuses, but a number of type tests are done at different currents to ensure that they will operate satisfactorily at somewhat arbitrarily chosen multiples of the rated currents. The minimum breaking capacities of high-voltage cartridge fuselinks are not specified in the standard documents, but it is nevertheless an important parameter which is usually quoted by the individual manufacturers after conducting tests in the standard manner. To conduct the maximum breaking capacity tests it is required that the fuse be tested for breaking capacity at least three levels of current. Test 1 is at the maximum prospective current. Current-limiting fuses are capable of breaking extremely high prospective currents because by their current limiting action they prevent the current from reaching the peak of the prospective current. In fact, the cut-off current only increases proportionally to the cube root of the prospective current. The point on the voltage wave is very important in testing fuses. For example, the conditions of the breaking capacity test are specified not only in terms of the current, voltage and power factor at which the test must be made, but also the instant of initiation of arcing within the fuse after the element has melted after voltage zero as follows: For one test arcing must commence between 40° and 65° (this is the condition represented in Fig. 6.40 by the curve a1, b1, c1). This condition is considered to correspond to the maximum thermal stress on the fuselink. For two further tests, arcing must commence between 65° and 90° (this is the condition represented in Fig. 6.40 by the curve a2, b2, c2). This

165

FUSES

condition is considered to correspond to the maximum electromagnetic stress on the fuselink. If the fuse is capable of breaking its maximum prospective current under these conditions, it should be capable of breaking it under any other breaking angle. Voltage & current

Circuit voltage Limits of arcing angle 40° 65° 90°

b1

b2 c2

a2 0

30

Same prospective r.m.s. ‘current’ but different closing angles, resulting in different degrees of asymmetry

60

90

120 150 180 210 240 270 300 330 360 Circuit closing angle g (degress)

a—Initiation of current; b—Initiation of arcing; c—Final clearance

FIGURE 6.40 Fuses blowing on high current, low power factor within prescribed limits for breaking capacity. Test No. 1 at maximum breaking capacity

Test 2 is at the maximum arc energy condition for a current-limiting fuselink. It is made at a current, chosen such that it produces a cut-off current approximately equal to the r.m.s. value of the prospective current, when the circuit is closed at an angle of between 0° and 20° after voltage zero. The condition of maximum arc energy usually corresponds to an inductive current equal to 3–4 times the current corresponding to a prearcing time of 0.01 s. Tests 3, 4 and 5 are made in order to verify that the fuselinks will not fail when breaking a small overcurrent. It has been explained earlier that fuses have special difficulties in this region, and may be unable to extinguish a low current arc, resulting in overheating, burning through the end caps, or even explosion. Tests 3, 4 and 5 ensure that this does not happen, under the specified conditions. In all tests, 1–5, it is essential that, after the fuse has interrupted the circuit, it can withstand the recovery voltage which appears at its terminals, and should not restrike or produce dangerous leakage currents. For this reason the recovery voltage is left on for a specified period after tests (as long as 5 min if the fuselink contains any organic materials), and the insulation is tested within 3 min of completion of the test to ensure that it is better than a specified level.

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6.6.8 Other Parameters Tested Apart from the afore-mentioned tests, fuses are tested at independent testing stations for the following parameters: (a) dielectric properties (b) temperature rise and power loss (c) accuracy of time/current characteristic (d) oil tightness (if intended to be used under oil) (e) weather proofness and thermal shock (if intended to be used outdoors) (f) effectiveness of strikers (if fitted) (g) accuracy of cut-off characteristics and I2t characteristics (when required) All these factors are recorded in the type test reports, in which the data are assembled to prove compliance with a standard. This is intended to ensure that every fuse made of identical manufacture to the fuse tested will be safe and suitable for the application corresponding to the tests.

6.7

FUTURE DEVELOPMENTS

Modern fuselinks are available in greater range than ever before. Special fuses for semiconductor protection have very fast operation, and carefully controlled over-voltages. Motor circuit protection fuses have characteristics specially designed for short-circuit protection without spurious operation on sustained starting currents, in compact dimensions and with special characteristics designed for discrimination with motor starters. Special back up fuses are also available. New developments are the dual-mode expulsion fuse and the permanent power fuse. The dual mode expulsion fuse employs a saturating transformer to produce a shape of time/current characteristic which gives closer discrimination with an IDMT relay, permitting lower settings. The permanent power fuse is a Japanese self-healing device using a column of sodium as a fuse element. This is contained in a ceramic capillary attached to an arc chamber, and the liquid sodium is forced to flow back into this space when the arc extinguishes after the circuit has cleared. The device is intended to back up circuit-breakers of limited breaking capacity. New ideas still to be developed include the vacuum fuse and the oil-filled fuse (not oil immersed).

CHAPTER

7 Distance/Impedance Protection

7.1

OVERVIEW OF DISTANCE PROTECTION

The extra high voltage systems form usually a tightly interconnected network with no radial feeders. The fault currents in the network depend more on the operating conditions of the whole system than on the fault location along the line. The requirements of protection operating speed and selectivity cannot be satisfied by grading by the current magnitude or by current and time. For a great majority of transmission and subtransmission lines the overcurrent protection systems are, therefore, not adequate. Due to economical and technical restrictions, mentioned in the chapter of “Transmission Protection” the application of differential schemes is also limited, especially for longer lines. The most common protection of transmission and subtransmission lines is distance protection. Comprehensive explanation of distance protection theory is readily available from the literature [references in bibliography]. Some features of this theory are discussed in the following paragraphs. A good brief description of the basics is provided in the textbook by Kothari and Nagrath. Subsequent paragraph offers only a concise overview theory and application of distance relays.

7.2

PRINCIPLE OF DISTANCE PROTECTION

A distance protection system is a non-unit system and as such it operates on information obtained from instrument transformers at only one end of the protected line. In principle the relay discriminates between faults on the protected line, which should cause fast disconnection of the line at the

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relay end, and the faults on the adjacent plant which should be left to the protection of that plant to clear. This discrimination is achieved by measurement of the distance from the relay location to the fault location. This distance, when compared with the length of the protected line, should, ideally, determine whether the fault location is nearer than or beyond the other end of the line.

7.2.1 Zones Using voltages supplied from the voltage transformers and currents from the current transformers, the distance relay measures the impedance of the line section from its location, at A, (Fig. 7.1), to the fault at K1. This impedance is proportional to the fault distance A-K1. The distance relay trips the circuit breaker at A instantaneously if the impedance measured is less than a reference impedance e.g., the known impedance of line A-B . Such a measurement cannot discriminate between the faults K2 just before the busbar B in the station at the other end of the line, and those on or beyond the busbars, like at K3 and K4 respectively, because the distance from A to these points is practically the same. The protection engineer has to make sure that the relay does not over-reach i.e., does not trip at A for a fault on or beyond bus B even if the measurement of the impedance is laden with some error. To prevent over-reaching, the reference impedance for the instantaneous tripping is selected so that it corresponds only to 80% of the line length with a 20% safety margin left for all possible errors. This creates a zone of 80% of the line, such that faults in that zone are isolated instantaneously from end A. This zone is called Zone 1 of relay A and the reference setting which determines the length of that zone is called Zone 1 setting. B A K1

Ct G Vt

K4

C

K4

D

K2

Distance relay

FIGURE 7.1 Fault locations in zones 1 and 2 of distance relay

The isolation from A of faults in the remaining 20% section of the line is not instantaneous. To isolate these faults the relay at A also compares the impedance measurement with another reference, Zone 2 setting, greater than the impedance of the whole line A-B. The relay is designed to trip at A for faults in Zone 2 with a predetermined delay, usually 0.4–0.5 second. This delay allows for instantaneous isolation at B of faults K3, K4 and K5 by

169

DISTANCE/IMPEDANCE PROTECTION

operation of bus B protection or the protection of line B-C or line B-D, respectively, without unnecessary tripping at A. To make sure that all faults on line A-B are isolated at A not later than with Zone 2 delay, the Zone 2 setting is greater than the impedance of line A-B by a margin of at least 20%, often 50% or more, so that the Zone 2 reach extends well into the lines outgoing from bus B. Most distance relays have also a Zone 3 with even longer reach than that of Zone 2 and a longer delay in operation. Zone 3 is often useful for back-up protection for a remote circuit breaker or protection failure. Distance relays are usually installed at both ends of a transmission line and isolate any fault at both ends. Faults in the central 60% of the line are isolated instantaneously by both relays while faults close to the line terminals are isolated instantaneously at the end close to the fault and with a delay of about 0.5 second at the remote end. All zones of protection systems of various plant items have to be coordinated to ensure their discrimination. Fig. 7.2 shows coordination of distance schemes on adjacent lines. The operating time of relay C is shown inverted for clarity. Time Zone 2 > 120%

Zone 1 = 80%

Zone 1 = 80% Zone 1

Distance

60% Stat. A

Stat. B

Stat. C

Time at C

FIGURE 7.2 Time/distance characteristic

7.2.2 Selection of Measurands The measurement of the impedance to the fault in distance relays is carried out by comparison of selected voltages and currents. For a particular fault only one pair of voltage and current is suitable for that measurement. For example, the correct measurement of the impedance for a phase-to phase fault a-b is by determining the ratio: Vab / (Ia – Ib). For a phase to ground fault b-n the phase to ground voltage Vbn and a combination of phase b and neutral current (Ib+ KIn) have to be used. To respond to all phase to

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phase and phase to ground faults as many as six voltage/current pairs have to be monitored and a three zone relay has to make 18 comparisons of the measurement results with the reference values (settings). The fast and expensive distance relays for E.H.V. transmission lines have therefore 18 comparators continuously monitoring all possible fault loops. This is necessary for the required speed and communication with the other end as discussed later. Such as 18 element relay is called ‘full-scheme’ or ‘non-switched’ distance relay. The relays for subtransmission lines usually do not have to be so fast and do not have to use signalling links. Their construction is made more economical by switching the same comparator to different loops and using it consecutively for comparison in all zones. The switching is controlled by simple separate starting elements that only have to recognise the type of the fault and by the timer controlling the zones. This system is called a ‘switched distance’ scheme. Traditionally switched schemes used to be far cheaper than full schemes but this difference is much less significant in the digital construction of relays. It is expected that the switched schemes will be phased out in the future.

7.2.3 Polar Characteristics The ratio of the voltage and current supplied to a comparator of a relay represents a vector of impedance which can be shown in the impedance plane Z (R, X), Fig. 7.3. This impedance is often referred to as ‘seen’ by the relay. The angle of an impedances seen during direct faults on the protected line, e.g., Zd, is equal to the angle of the line impedance, usually 70° to 89° for transmission lines and in the order of 60° for lower voltage lines. If the fault involves an object of some resistance like a tree branch, or just an electric arc then the impedance seen by the relay has a horizontal resistive component Ra and its resultant angle is smaller. Faults beyond the end of the line are seen to have a greater magnitude, say Z4. jX

C B Zd

Z4 Ra

Za

30°

Line angle

Load impedance area

A

R

M

FIGURE 7.3 Impedance plane

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DISTANCE/IMPEDANCE PROTECTION

The polar characteristic of a distance relay determines the area of the impedance plane which contains all impedances causing operation of the relay if seen by the comparator. Fig. 7.4 shows characteristics of Zones 1, 2 and 3 of a typical relay. The relay operates instantaneously if the impedance seen by a Zone 1 comparator of the relay appears inside the smallest circle. A Zone 2 delayed operation will result from seeing the measured impedance at point K2.

7.2.4 Directionality Change of the current direction with respect to voltage reflects in the impedance plane as a change of the angle of the impedance seen. Faults behind the relay, e.g., M in Fig. 7.1, fed via the protected line, correspond to points in the third quadrant of the plane. Zones 1 and 2 in Fig. 7.4 are directional because no point of the third quadrant is inside Zone 1 or 2 characteristics. A circular characteristic passing through the origin like those of Zones 1 and 2 in Fig. 7.4, is known as a ‘mho’ characteristic. jX

2

Zo ne 3

C

1

Zo

ne

B

Zo

ne

K2 O

A

R

FIGURE 7.4 Three zone distance relay

7.2.5 Stability on Load During normal service of the line the comparators of the full scheme continuously monitor impedances made of the normal voltages and the load currents of the line. For a phase-to-phase element a-b the ‘impedance seen’ is: Zl =

Va − Vb Va = I a − Ib Ia

The magnitude of this impedance is usually much greater than that of any fault on the line. The angle of the load impedance Zl is that of power factor of the transmitted load and varies between –30° and +30° for

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transmission from A to B. A transmission in the opposite direction is seen as an impedance with an angle between 150° and 210°. The characteristics must be so selected that no load impedance is seen inside any of the characteristics otherwise the relay will trip the healthy line on load. The shape of the characteristics may be circular, oblong e.g., lens, quadrilateral or more sophisticated. Fig. 7.5 shows some typical characteristics of distance relays. The variety of available shapes enables separation of all impedances seen under no fault conditions from those faulty conditions that require a reliable positive operation of the scheme. The application of a particular relay is decided by its characteristics and other factors like accuracy, operating time, burden, method of setting adjustment, etc. Above all the relay must be reliable. jX

jX

jX

R

R

R

Impedance

mho

Offset mho jX

jX

R R Lens

Quadrilateral

FIGURE 7.5 Distance relay measuring characteristics

7.2.6 Methods of Impedance Measurement Determination whether the fault impedance (impedance of the line between the relay and the fault point) fits within the characteristic of the relay may be done by analogue comparison of signals derived from voltages and currents or by numerical computation of the fault inductance and resistance from the voltage and current samples taken at regular intervals in every cycle. The methods based on analogue comparison used in more traditional relays have already achieved high performance development levels of

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DISTANCE/IMPEDANCE PROTECTION

reliability and speed. The numerical methods are used in digital relays which, have already won enough confidence in the market to be exclusively purchased by more and more utilities who appreciate the additional benefits of digital technology.

7.3

ANALOG AMPLITUDE AND PHASE COMPARISON

A protection relay in general is expected to sense the change between healthy and faulted conditions and send a signal when fault occurs. This, in analog relays, is achieved by comparing two quantities either in amplitude, or in phase. The amplitude or phase relation depends on the system conditions and for a predetermined value of this relation, indicative of a particular type and location of fault, the relay operates. Except in relays such as overcurrent relays, where only one electrical quantity overcomes a mechanical quantity such as the restraint from a spring, it is usual to compare two electrical quantities. As such the device performing the comparison part is the heart of a protective relay and is known as a comparator. It decides the operating characteristics of the relay. Taking a very general case to cover the complete range of conventional relay characteristics, let S1 and S2 be the two input signals such that when the phase relationship or magnitude relationship obeys predetermined threshold conditions, tripping is initiated. The input signals are derived from the primary power system via current and voltage transformers. These signals may be derived from primary voltage or current or from both, the latter necessitating some form of mixing device such as a current voltage transactor as shown in Fig. 7.6. v

K1

K3

v

K4

I

S1 Comparator S2

I

K2

FIGURE 7.6 Comparison of mixed signals

S 1 = K1 V + K 2 I

...(1)

S 2 = K3 V + K 4 I where K1 and K3 are scalar constants and K2 and K4 vector constants with angles θ2 and θ4 respectively. Taking V as the reference vector and vector I to lag V by an angle φ equation (1) reduce to

S1 = K1|V| + K2|I|{cos(θ2 – φ) + j sin(θ2 – φ)} S2 = K3|V| + K4|I|{cos(θ4 – φ) + j sin(θ4 – φ)}

...(2)

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

7.3.1 Analysis for Amplitude Comparator If the criteria for operation is given by | S1 | ≥ | S2 | , then at the threshold of operation | S1 | = | S2 |, equating the moduli of expression (2) {K1|V| + K2|I|cos(θ2 – φ)}2 + {K2|I|sin(θ2 – φ)}2

...(3)

{K3|V| + K4|I|cos(θ4 – φ)}2 + {K4|I|sin(θ4 – φ)}2 Rearranging the terms (K12 – K32)|V|2 + 2|V||I|{K1 K2 cos (θ2 – φ) – K3K4 cos(θ4 – φ)} + K22|I|2 cos2 (θ2 – φ) – K42|I|2 cos2 (θ4 – φ) + |I|2 {K22 sin2 (θ2 – φ) – K42 sin2 (θ4 – φ)}= 0 or

(K12 – K32)|V|2 + 2|V||I|{K1K2 cos (θ2 – φ) – K3K4 cos (θ4 – φ)} + (K22 – K42)|I|2 = 0 Dividing by

(K22

–

...(4)

K42)|V|2

| I | (K 1K 2 cos θ 2 − K 3 K 4 cos θ 4 ) cos φ | I |2 +2 2 |V| K 22 − K 24 |V| +

(K 1K 2 sin θ 2 − K 3 K 4 cos θ 4 ) cos φ K 12 − K 23 + 2 =0 K 2 − K 24 K 22 − K 24 | I |2 +2 V

or

...(5)

|I| {x cos φ + y sin φ} + z = 0 |V|

where x = (K1K2 cos θ2 – K3K4 cos θ4)/(K22 – K42) y = (K1K2 sin θ2 – K3K4 sin θ4)/(K22 – K42) z=

K 12 − K 23 K 22 − K 24

Equation (5) represents the equation of a circle on the β-plane having |I/V|cos φ and j|I/V| sin φ as coordinates represented as |I V|p + j|I V|q. This circle as shown in Fig. 7.7 has radius r=

and

d=

{K 12 K 24 + K 22 K 23 − 2K 1K 2 K 3 K 4 cos (θ 2 − θ 4 )} K 22 − K 24 {K 12 K 22 + K 23 K 24 − 2K 1K 2 K 3 K 4 cos (θ 2 − θ 4 )} K 22 − K 24

DISTANCE/IMPEDANCE PROTECTION

175

Similarly equation (4) can be plotted in the α-plane by dividing it by (K12 – K22)|I|2.

7.3.2 Analysis for Phase Comparator The two quantities to be compared are S 1 and S 2. If α is the phase angle of input S 1 and β that of S 2, the relay operates when the product of S 1 and S 2 is positive. The product is maximum when the two quantities are in phase. All the conventional characteristics of relays can be obtained with a symmetrical phase comparator with (α – β) = ± 90°. Therefore, the threshold condition is tan (α – β) = ± α

tan α − tan β =±α 1 + tan α tan β

or i.e.,

when 1 + tan α tan β = 0 1+

K 2|I|sin (θ 2 − φ) K 4|I|sin (θ 4 − φ) × =0 K 1|V|+ K 2|I|cos (θ 2 − φ) K 3|V|+ K 4|I|cos (θ 4 − φ)

K1K3|V|2 + {K1K4cos (θ4 – φ) + K2K3cos (θ2 – φ)}|V||I|

...(6) + K2K4 |I|2 cos (θ2 + θ4) = 0 This equation is again similar to equation (4) and can be plotted on the β-plane. Dividing Equation (6) throughout by K2 K4 |V|2 cos (θ2 – θ4), we get

K K cos (θ 2 − φ) | I | {K 1K 4 cos(θ 4 − φ) | I |2 + 2 3 + | V | K 2 K 4 cos (θ 2 − θ 4 ) K 2 K 4 cos (θ 2 − θ 4 ) V +

K 1K 3 =0 K 2 K 4 cos (θ 2 − θ 4 )

| I | {(K 1K 4 cos θ 4 + K 2 K 3 cos θ 2 ) cos φ | I |2 + K 2 K 4 cos (θ 2 − θ 4 ) V |V| +

or

(K 1K 4 sin θ 4 + K 2 K 3 sin θ 2 ) sin φ} + K 1K 3 = 0 ...(7) K 2 K 4 cos (θ 2 − θ 4 )

| I |2 |I| + {x cos φ + y sin φ| + z = 0 V |V|

where x=

K 1K 4 cos θ 4 + K 2 K 3 cos θ 2 K 2 K 4 cos (θ 2 − θ 4 )

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

y=

K 1K 4 sin θ 4 + K 2 K 3 sin θ 2 K 2 K 4 cos (θ 2 − θ 4 )

z=

K1 K 3 K 2 K 4 cos (θ 2 − θ 4 )

The circle has Radius r = and

c=

{K 12 K 24 + K 22 K 23 − 2 K 1K 2 K 3 K 4 cos (θ 2 − θ 4 )} 2 K 2 K 4 cos (θ 2 − θ 4 )

{K 12 K 24 + K 22 K 23 − 2 K 1K 2 K 3 K 4 cos (θ 2 − θ 4 )} 2 K 2 K 4 cos (θ 2 − θ 4 )

Values of r and c for plot on the α-plane can be obtained, similarly. In most relays at least one of the constants K (i.e., K1, K2, K3, K4) is zero and two of them are often equal. Also the angle of the two vector constants is usually the same. This makes the practical case relatively simple. If θ2 = θ4 the values of r and c in the two cases are tabulated as shown in Table 1. TABLE 1: Comparative values of r and c for amplitude and phase comparators (Fig. 7. 7) Quantity

7.4

Amplitude comparator

Phase comparator

r

K 1K 4 − K 2 K 3 K 22 − K 24

K 1K 4 − K 2 K 3 2 K 2K 4

c

K 1K 2 − K 2 K 4 K 22 − K 24

K 1K 4 + K 2 K 3 2 K 2K 4

RELAY TYPES AND THEIR APPLICATION

Using specifically selected constant vectors (K1, K2, K3 and K4), various types of distance relay characteristics may be obtained. The principal types of distance relays are: (i) impedance (ii) reactance (iii) admittance (mho) (iv) ohm (v) offset mho. The common types compare two input quantities either in magnitude or in phase. Any of the relay characteristics can be obtained either by an amplitude comparator or by a phase comparator as explained earlier.

177

DISTANCE/IMPEDANCE PROTECTION

7.4.1 Impedance Relay This is a device which measures distance by comparing the fault current I with the voltage V across the fault loop. It is usual in this case to have an amplitude comparator and the balanced beam type structure is most common. The equation for the amplitude comparator at threshold as derived already in equation (4) is I V

q

r c f

I V

p

FIGURE 7.7 Threshold characteristics of a comparator

(K12 – K32)|V|2 + 2|V||I|{K1K2 cos (θ2 – φ) – K3 K4 cos (θ2 – φ) + (K22 – K42)|I|2 = 0 If the constants are so adjusted that the input signals are S 1 = K1 |V|

and i.e.,

S 2 = K4 |I|

K2 = K3 = 0 Substituting these conditions in the above equation, we get K12 |V| 2 = K42 |I| 2

or i.e.,

| V | K4 = K1 |I|

...(8)

Z = constant K

The characteristics when plotted on the R-X plane is shown in Fig. 7.8 which is a circle with origin as its centre; signifying that a simple impedance relay would operate for any value of impedance lying within the circle. The characteristic also depicts that the relay is not directional and it is essential to provide a directional relay along with an impedance relay. The combined

Z=X

R

FIGURE 7.8 Characteristics of impedance relay

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

characteristics of an impedance and directional relay are shown in Fig. 7.9, where DD′ represents the directional relay characteristic and the operating region is the shaded portion. X

D R D¢

FIGURE 7.9 Characteristics of impedance with directional relay

7.4.2 Reactance Relay All other relays except the impedance relay are conveniently obtained by a phase comparator. The basic equation for a phase comparator already derived in equation (6) at threshold is: K1K3|V|2 + {K1K4 cos (θ4 – φ) + K2K3 cos (θ2 – φ)|V||I| + K2K4 |I|2 cos (θ2 – θ4) = 0 Using the input signals in the following manner S1 = – KV + K’I ∠ (θ – φ) S2 = K’ I ∠ (θ – φ) i.e.,

K1 = – K K 1 = K 4 = K’ ∠ θ

and

K3 = 0. Substituting these conditions in the above equation, we have – K K’ cos (θ – φ) |V| |I| + K’2 |I|2 = 0

or

Z cos (θ – φ) =

K’ K

...(9)

Now if θ is ∠π/2 the above equation reduces to the reactance form, i.e., or

Z sin φ =

K’ K

X=

K’ K

...(10)

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DISTANCE/IMPEDANCE PROTECTION

When plotted on the R-X diagram, the characteristic is represented by a straight line parallel to the horizontal axis R as in Fig. 7.10. X

X = K¢ K O

R

FIGURE 7.10 Characteristics of reactance relay

With some predetermined setting of value X, the relay will measure any value of reactance below the setting. A reactance relay responds only to the reactive component of system impedance; consequently it is unaffected by fault arc resistance. However, when fault resistance is such a high value that load and fault current magnitudes are comparable the reach of the relay is modified by the value of the load and its power factor and may either overreach or underreach. Voltage-restrained starting relays are used in a reactance measuring scheme to give directional response and to prevent operation on load. The reactance relay as seen by equation 10 is a particular case of an ohm relay, in which the angle of compensation θ is 90°.

7.4.3 Admittance (Mho) Relay If the signals S1 and S2 given to the phase comparator are: S1 = – K |V| + K’ |I| (θ – φ) and

S2 = K |V|

i.e.,

K1 = – K K2 = K’ ∠ θ K3 = K K4 = 0 Substituting these conditions in equation (6), we have – K2 |V|2 + KK’ cos (θ – φ) |V||I| = 0

or or

...(11)

I K cos (θ – φ) = V K’

Y cos (θ – φ) =

K K’

...(12)

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

This represents the admittance or the mho characteristic and when plotted on the R-X diagram is a circle passing through the origin and when plotted on the G-B diagram is a straight line as illustrated in Fig. 7.11. X

B

Stable

Stable K¢ K

Trip

q

G Trip

K¢ K

q R (b) G-B plane

(a) R-X plane

FIGURE 7.11 Characteristics of mho relay

The circle passing through the origin makes it inherently directional. With such a characteristic the relay measures distances in one direction only. From the expression (11) it is evident that the relay is inoperative if the voltage falls to zero, because both terms contain V. A memory circuit may be used to prevent the immediate decay of voltage applied to the relay terminals when a close-up three-phase short-circuit occurs. This enables high speed mho protection to operate correctly on close-up faults, provided that the protected circuit is energised before the short-circuit is applied.

7.4.4 Ohm Relay As explained earlier a reactance relay is a particular case of an ohm relay. Its characteristic is represented by equation (9) when plotted on the R-X plane is a straight line (Fig. 7.12). The ohm relay is used as a supplementary element to modify the operating region of the other types of measuring elements.

X

K¢ K

Trip q

R

FIGURE 7.12 Ohm relay characteristics

7.4.5 Offset Mho Relay Let the signals S1 and S2 given to the phase comparator be S1 = K |V| + K2 |I| ∠ (θ – φ) S2 = K |V| + K4 |I| ∠ (θ – φ)

181

DISTANCE/IMPEDANCE PROTECTION

i.e.,

K1 = – K K2 = K2 ∠ θ K3 = K K 4 = K4 ∠ θ

Substituting these conditions, we have – K2 |V| 2 + {– K1K4 cos (θ – φ) + K2K cos (θ – φ)} |V| |I| + K2K4 |I| 2 = 0 Let

V be Z I

and we get – K2Z2 + K2K4 + KZ (K2 – K4) cos (θ – φ) = 0 Z2 = R2 + X2

Also, as Therefore,

R2 + X2 or

R–

K 2 K 4 (K 2 − K 4 ) (R cos θ + sin θ) = 0 K K2

(K 2 − K 4 ) cos 2 θ ( K 2 − K 4 ) sin 2 θ (K 2 + K 4 ) 2 × ≤ 2K 2K 2K

This equation represents a circle, with centre at (K2 – K4)/2K∠ θ on the R-X plane, the radius being of magnitude (K2 + K4)/2K. The offset threshold characteristic is shown in Fig. 7.13. X K2 Ðq K

q K1 Ðq K

O

R

FIGURE 7.13 Offset mho relay characteristics

An offset form is extensively used to provide a measure of back up protection in respect of faults behind the relay.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

7.4.6 Some Other Forms of Relay The reactance characteristic is often used in combination with the mho characteristic to provide extra coverage in respect of fault arc resistance on lines of un-earthed construction (particularly, but not exclusively distribution feeds). Such a set up produces a resultant characteristic as shown in Fig. 7.14. x Faults are coverage

R

FIGURE 7.14 Mho reactance relay characteristics

Extra fault arc coverage may be obtained by means of an offset mho/ reactance/directional characteristic as shown in Fig. 7.15. X

R

FIGURE 7.15 Offset mho/reactance/directional relay characteristics

When protecting long lines, the reach of the polar characteristic along the resistive axis can be many orders greater than the maximum fault arc resistance. Even under normal conditions, when the line is transferring power, some impedance is measured by the relay and this is generally resistive but outside the characteristic. However, for long lines and heavy circuit loading, healthy circuit tripping may occur, and it is necessary to restrict the characteristic as shown in Fig. 7.16.

183

DISTANCE/IMPEDANCE PROTECTION

Blind

er

X

Typical load impedance area R

FIGURE 7.16 Restricted characteristics for long line application

7.5

DERIVATION OF SIGNALS FOR DISTANCE PROTECTION

We have seen that distance relays make use of the voltage and current at the relaying point. In practice we have to cater for several different types of fault, i.e. 3-phase-earth faults (a – e, b – e, c – e) and 3-phase-phase faults (a – b, b – c, c – a), and care has to be taken in the choice of the voltages and currents to cover each type of fault. Consider a single phase-earth fault in phase a of a feeder fed from one end only, as shown in Fig. 7.17. a

z

b

z

c

z

e

zg

FIGURE 7.17 Single phase to earth fault representation

If we feed the relay with a voltage Va – e and Ia it will measure an impedance Z + Zg. However, when we consider a line fed from both ends (which is the usual case), the current in the earth return path incorporating Zg is usually different from that in the faulty conductor (i.e., there are sound phasecurrents). Under these conditions Va = IaZ + IgZg, and the relay measures Va/Ia = Z + (Ig/Ia)Zg. Now Ig depends on the pre-fault loading and the

184

POWER SYSTEM PROTECTION AND COMMUNICATIONS

method of earthing at either end of the feeder, and we cannot use just Va and Ia to cover this fault. In practice we feed the relay with a current Ia + KIg (Ig = residual current = Ia + Ib + Ic) and so the relay measures an impedance.

I a Z + I g Z g Z(I a + I g Z g/z ) Va = = I a + KI g I a + KI g I a + KI g Now the ratio Zg/Z does not vary with the position of the fault, and if we make the residual compensating factor K = Zg/Z the relay always measures the line impedance to the point of fault irrespective of the current actually flowing in the earth return. Likewise care has to be taken in the relaying qualities used in respect of phase-faults, as shown in Fig. 7.18. Ia Vab

z

z Ib z

zg

FIGURE 7.18 Phase faults representation

Here we see Vab = IaZ – IbZ, and provided we feed a voltage Vab and Ia – Ib to the relay the impedance measured is again the impedance Z to the point of fault. The various voltages and currents used in distance protection are thus: For Earth faults

For Phase faults

a–e

Va

→

Ia

+

KIg

b–e

Vb

→

Ib

+

KIg

c–e

Vc

→

Ic

+

KIg

a–b

Vab

→

Ia

–

Ib

b–c

Vbc

→

Ib

–

Ic

c–a

Vca

→

Ic

–

Ia

In schematic form the signals are derived from the system as shown in Fig. 7.19.

185

DISTANCE/IMPEDANCE PROTECTION

CT VT

CT VT

CT Trip

VT Relaying signals Replica impedance

Mixing circuits

Comparators

FIGURE 7.19 Signals derivation

7.6

METHODS OF REALISING COMPARATORS

Before considering circuit details, it is important to note the duality between pure phase and pure amplitude comparators. Consider a phase-comparator in block form as shown in Fig. 7.20 which trips when β ≤ S1/S2 ≤ α Likewise consider a pure amplitude comparator as shown in Fig. 7.21. S1 S2

Phase comparator

Output

FIGURE 7.20 Block diagram of phase comparator

S1 S2

Amplitude comparator

Output

FIGURE 7.21 Block diagram of amplitude comparator

Here we get an output if |S1| ≥ |S2|. Suppose we feed a signal S1 + S2 and S1 – S2 to our phase comparator, and take signal S1 as a reference. Let S1 = A, S2 = B + jC and we get an output from the phase comparator if β ≤ (S1 + S2)/(S1 – S2) ≤ α

186

POWER SYSTEM PROTECTION AND COMMUNICATIONS

But

(S1 + S2) = (A + B) + jC (S1 – S2) = (A – B) – jC

Thus ∠

S1 + S 2 = ∠(A2 – B2 – C2 + jAC) = α at the limiting conditions. S1 − S 2 tan α =

Thus

AC A − B2 − C 2 2

S1 = A1, S2 = (B2 + C2)1/2

but

(|S1|2 – |S2|2) tan α = |S1| C If α – φ = π/2 we see that tan α and since |S1|, C are generally finite, there is an output if |S1| ≥ |S2| i.e., |S1| = |S2| is the limiting condition. Thus by feeding S1 + S2, S1 – S2 to a pure phase comparator (over the limits +/– π/2) we effectively compare S1 and S2 in amplitude. The same clearly applies in reverse i.e., by feeding S1 + S2, S1 – S2 to an amplitude comparator there is an output if – π/2 ≤ S2/S1 ≤ π/2 i.e., we may effectively compare S2 and S1 in phase by means of an amplitude comparator. Fig. 7.22 summarises the situation where a phase-comparator is used to compare the amplitude of signals S1/S2. Inherent phase comparator S1-S2

Inherent phase comparator

S1-S2

S1

S2

S2 S1

FIGURE 7.22 Equivalent comparator relationship

7.6.1 Amplitude Comparators A very common form of amplitude comparator is the back to back bridge arrangement as shown in Fig. 7.23(a). Here the signals are in the form of currents, and the action may be seen in the following Fig. 7.23(b).

187

DISTANCE/IMPEDANCE PROTECTION

The output voltage = (I1 – I2)R and the average volts are seen to be positive if |I1| > |I2| , where the average is taken by means of integrator circuit. Note: That the operating criterion is independent of the phase of S1 and S2. I2

I1

S1

S2 (a) Back to back amplitude comparator + S1

+

–

–

I1 I2 S2

(b) Waveforms

FIGURE 7.23

There is another comparator as illustrated in Fig. 7.24 which is often taken to be a pure phase-comparator, but which is really an amplitude comparator having inputs (S1 + S2) and (S1 – S2). S1 + S2 S2 1 : 1 To integrator Va trips when ò Va dt is + Ve S1 – S2 2S1 1:2

S1

FIGURE 7.24 Another form of amplitude comparator

188

POWER SYSTEM PROTECTION AND COMMUNICATIONS

It can be seen that the average output volts are positive (i.e. trip) when –π/2 < S2/S1 < + π/2 but the transformer arrangements are really a crafty way of providing the signals (S1 + S2), (S1 – S2) which are compared in amplitude therefore. Some proposed methods of providing inherent amplitude comparators using transistors have been made, but with reference to high speed methods problems clearly arise. It is necessary to locate the maxima of the signals and compare, and this makes the circuitry involved quite complex. Also as we shall see later there is a large dynamic range of relay signals, and this aggravates the situation. We will not therefore consider amplitude comparators further.

7.6.2 Phase Comparators The measurement of phase is fundamentally easier than amplitude, since zero-crossings are easy to detect and in theory independent of the magnitude of the signals being compared. There are many methods (some practical others less so) of performing phase-comparison using transistorised circuits, and now using integrated circuits. Because of their importance we shall consider some of the methods in detail in order of practicability.

7.6.3 Pulse Type Phase Comparator Here a short duration pulse produced at the maximum of one relaying signal is compared with one half cycle of the other signal. Thus a short duration pulse appears at the output (E) provided –π/2 < ∠ S2S1 < π. The principle is illustrated in Fig. 7.25. S1

Sine/square conversion

A

AND Gate B S2

p/2 Phase shift

C Sine/square conversion

D Differentiator

(a)

E

189

DISTANCE/IMPEDANCE PROTECTION v

S2 S1 t

v t

A

v t

B

v C

t

v D

t

v E

t

(b)

FIGURE 7.25 Principle of pulse type phase comparator

7.6.4 Fixed Time Reference Comparator Here the coincidence period between the two signals is compared with a pulse generated therefrom. The diagram in Fig. 7.26 illustrates the principle and shows that tripping is obtained if – (π – ωT) < ∠ S2/S1 < (π – ωT). Notice that the limits of comparison are symmetrical about the condition of in phase relaying signals and that by making ωT = π/2 the comparator may be used to produce the common mho and offset mho characteristics.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

S1 S2

AND gate

Time delay (T)

A

B

AND gate

C

(a) v

v

S2 S1

S1

S2

t

t

v

v

A

t

t

A

v

v

B

t

t

B

w 0T = d

w0T = d

v

v

C

t

t

C

S1/S2 £(p – w0T)

S1/S2 £(p – w0T)

(Trip)

(Block) (b)

FIGURE 7.26 Circuit action of fixed time reference phase comparator

7.6.5 Block-Average Comparator In this device the coincidence period between two signals is fed to a linear integrator, so that the output voltage increases for all phase angles between the signals in the range –π/2 < S2/S1 < π/2. The schematic in Fig. 7.27 shows the principle of operation. Such comparators have an inverse type of time response i.e., the operating time increases as the relaying signals approach threshold (± π/2). Thus for faults near the boundary of a characteristic the device takes longer to operate. This feature increases the immunity of such devices to measurement errors caused by transients in the relaying signals. In practice

191

DISTANCE/IMPEDANCE PROTECTION

the characteristic boundaries may be preserved provided the pick up/drop S1 S2

Coincidence A detector

Integrator

B

Level detector

C

(a) v

v

v

t

v

t

v

v

t

A

v

t

v

B

VR VS

VR VS

t

v

C

t

B

VR VS

t

v

t

Inside threshold (b)

A

v

t

v

t

t

C

Near threshold (c)

t

Outside threshold (d)

FIGURE 7.27 Block average arrangement

off ratio of the level detector exceeds about 2.5 (theoretically two is a transient exists in only one signal). This comparator is extensively used due to its desirable response. Its only disadvantage is that it is rather inflexible from in that it is only possible to produce simple shapes of characteristic (e.g., mho) which nevertheless are satisfactory for the majority of lines. Other more flexible methods to cater for the requirements of long and very important lines have been developed. Block Average Arrangement The relaying signals compared in a block average comparator arrangement to produce the polarised mho characteristics are of the well-known form of equation (14). S1 = IZr – V

...(13)

S2 = V + Vp

...(14)

where I, V are the relaying current at CT secondaries and the relaying voltage at the VT secondaries respectively. Vp is the sound phase polarising voltage and Zr is the replica impedance, the former is obtained using the

192

POWER SYSTEM PROTECTION AND COMMUNICATIONS

polarising circuit and the latter is associated with a transformer-reactor arrangement. The signal S1 is of a standard form and varies according to the type of fault, e.g., for an ‘a’-earth fault, is of the form as shown in equation (15). S1a = (Ia + KI res) Zr – Va

...(15)

where Ires is the zero sequence current and K is the residual compensating factor, as given by equation (16). K=

F GH

I JK

1 | Z LO | −1 3 | Z LI |

...(16)

where ZLO and ZLI are the z.p.s. and p.p.s. line impedances. It is common practice to place replica impedances in the secondary of the current transformers in order to generate the relaying signal S1 as given by equations (14) and (15). The transactor which is basically a transformer with a core having air gaps and is extensively used in protection equipment using the block average comparator arrangement and has a circuit as shown in Fig. 7.28(a). Rb is a burden resistance so that neglecting the secondary winding reactance (which is relatively low because of the air gap) yields the equivalent circuit of Fig. 7.28(b) referred to the primary. With reference to Fig. 7.28(b) it can be shown that the magnitude of the Zr the replica impedance referred to the primary of the transactor, is given by equation (17). IP¢

I

I : nt R1

Lm

Va

(a) Actual circuit I

Vi

Xm

Rb n2t

= Rb¢

Va = Va¢ nt

(b) Equivalent circuit referred to primary

FIGURE 7.28 Transformer-reactor arrangement

DISTANCE/IMPEDANCE PROTECTION

Zr =

Vo′ Xm = I [1 + cot 2 φ T ]

193

...(1)

where φT = tan–1 (Rb/nt2 Xm). The relaying signal produced by the transactor (e.g., for an ‘e’-earth fault) is therefore S = I Zr – Va or in the transduced form, it can be shown that: S1′ = nt2

nc Z I – Va′ nv r

where nc, nv are the turns ratio of the CT and VT respectively, which are typically 1200/1 and 500/0.11 (for a 500 kV system) respectively. nt is normally taken as 1/1. It can thus be seen that the Zr′ replica impedance referred to the secondary is given by equation (18). Zr′ =

7.7

nv Z nc r

...(18)

SIGNAL S2

As regards signal S2, there are essentially three basic types: (a) self-polarised (b) fully cross-polarised (c) using the memory circuit.

7.7.1 Self-Polarised Type In this case, the polarising signal is obtained from the same faulted phase and is not very satisfactory, mainly because for close-up earth faults the faulted phase voltage is close to zero, which gives unsatisfactory S2 signal. However, it can have certain advantages for other fault positions. For an ‘a’-earth fault, for example, the S2 signal is given by equation (19). S2a = Va + kp Va

...(19)

where kp is a constant.

7.7.2 Fully Cross-Polarised Type The fully cross-polarised type is the most commonly used. In this case, the polarising signal is obtained from the healthy phases and for an ‘a’ earth fault, for example, it is given by equation (20). ...(20) S2a = Va + kp Vbc where kp is the polarising constant and is equal to kp ∠ 90°.

194

POWER SYSTEM PROTECTION AND COMMUNICATIONS

7.7.3 Using the Memory Circuit It has been found that the signal S2 obtained using the memory circuit can have certain advantages. In this type a mixture of the faulted and/or healthy phase voltage with a voltage from a memory circuit is used as the polarising signal. As, for example, for ‘a’ earth fault, the signal is as expressed in equation (21). S2a = Ea or

S2a = Ea + kp Vbc

...(21)

where Ea is the prefault steady state component of voltage and kp is the polarised voltage constant which is equal to kp ∠ 90°.

7.8

PRE-FILTERS USED IN POWER SYSTEM PROTECTIVE RELAYING

Second order low pass filter pre-conditions the S1 and S2 signals. A low-pass filter is a device which passes signals of low frequencies and suppressed or attenuates those of high frequencies. Its performance may be illustrated by its amplitude response, which is a plot of the amplitude H(jω) of its transfer function H(s) versus frequency ω, where ω = 2πf. In all cases H = vo/vi, where vo and vi are the output and input voltages. Transactor CVT Phase shift circuit Missing circuit Second order filter

S1 S2

To comparator

FIGURE 7.29 Pre-filtering circuits used before entering comparator

It is common practice to prefilter the signals S1 and S2 in a second order filter before going to a comparator. A second order approximation to an ideal low pass filter is achieved by the transfer function. vo K1 = 2 vi p + ap + b

...(22)

where ‘a’ and ‘b’ are properly chosen constants and K1 is a constant. The term ‘second order’ refers to the degree of the denominator polynomial.

195

DISTANCE/IMPEDANCE PROTECTION

The gain of the low pass filter is the value of its transfer function at p = 0 and is given in the case of equation (22) by gain = K1/b. There are a number of ways of obtaining low pass filters using active devices instead of inductors. The method commonly used is that of Sallen and Kelly, in which the active device is an operational amplifier (op-amp). Vc(t) +

R1

R2

Cf

+

+

– V(t) C1

Vi(t)

R3

V¢(t)

Va(t)

R4

– (a) Actual circuitary Vc(t)

i2(t) +

R2

R1

Cf

i1(t)

+

– C1

Vi(t)

+

V(t)

Va(t)

(b) Equivalent circuit

FIGURE 7.30 Sallen and Kelly second order low pass filter

A Sallen and Kelly second order low pass filter is shown in Fig. 7.30(a), where the resistors and capacitors are properly chosen to realise given values of ‘a’ and ‘b’ in equation (22). The op-amp, together with the resistor R1 and R2, constitutes a voltage-controlled voltage source (VCVS) and hence the Sallen and Key network is of the VCVS type. The value of the constants are as follows:

µ × 10 6 R 1 R 2 C 1C f

K1 = a= b=

1 1 1 (1 − µ ) + + R 2 C1 R 1C f R 2 C f

1 R 1 R 2 C f C1

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

The quantity l = 1 + R4/R3 is the gain of the VCVS and is also the gain of the filter since K1/b = µ There are many types of low pass filter, but the two most commonly used are the Butterworth and Chebyshev types.

7.9

EFFECT OF THE RATIO SOURCE IMPEDANCE TO LINE IMPEDANCE (ZS/ZL)

Any system could be represented by a single line diagram shown in Fig. 7.31 representing the source and the line to be protected, R being the relay location. This simple impedance loop has a voltage V applied to it which actually depends on the type of fault whether phase fault of ground fault. ZS and ZL are the source impedance and the line impedance respectively. ZS is a measure of fault MVA at the relaying point, and for faults involving earth, is also dependent on the method of system earthing behind the relaying point. ZL is a measure of the line impedance of the protected section. IR and VR are respectively the current and voltage applied to the relay. The voltage VR applied to the relay is thus IR ZL for a fault at the reach point, and this may be alternatively expressed in terms of ZS /ZL ratio as R

Source

Line

FIGURE 7.31 Power system arrangement

VR = IR ZL where Ir =

V ZS + ZL

Thus

Vr =

ZL V ZS + ZL

Vr =

1 V ( Z S /Z L ) + 1

...(23)

Equation (23) is true for all types of faults with the following rule being observed: 1. For phase-faults V is the delta voltage and ZS/ZL is the positive sequence source impedance/positive sequence line impedance, i.e.,

VR =

V∆ (Z S1/Z L1 ) + 1

...(24)

197

DISTANCE/IMPEDANCE PROTECTION

2. With earth-faults V is the star voltage and ZS/ZL is a composite ratio involving positive and zero sequence impedance, i.e., VR = where

VY (Z S /Z L ) + 1

ZS = 2ZS + ZS 1

0

1

0

ZL = 2ZL + ZL

and of course VY = V∆ / 3 . Fig. 7.32 illustrates the effect of ZS/ZL ratio on the voltage at relay position R. Three fault locations are shown: Fault outside the zone of protection, fault at setting distance, and fault in the protected zone. The ordinate at R represents the voltage applied to the relay VR for various fault locations, for the relay to restrain VR should be greater than the preset value of VR = IR ZL and for operation V should be less than the preset value of VR = IRZL. VS

VL = VR R

ZS

V

IR ZL

VR

FIGURE 7.32 Relation between source, line and relay voltage

7.10 TIME GRADING OF DISTANCE RELAYS A typical distance relay has stepped characteristics in three stages (as shown in Fig. 7.2). Zone 1 of the relay provides instantaneous tripping for any fault within a predetermined distance from the relay (generally 80% of the protected feeder). Zone 2 operates with a time delay and covers the remainder of the protected feeder and backs up the protection on the next feeder for a part of that feeder. After a further time delay the range of the distance relays is further extended to Zone 3, which is used as backup protection only. The time delay between the various zones is chosen according to stepped principle (usual value of time delay step is 0.5 s). Because of this only high-speed distance relays are widely used in practice. Such relays can be arranged for measuring impedance or reactance and are normally provided with built-in directional feature. Hence the basic features involved in such a relay are: (i) impedance or reactance measurement, (ii) direction and (iii) timing.

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For finding the pickup value of the impedance in section n let us say Zone 1 is 80% of the protected section. (n) Z(n) pickup (1) = 0.8 ZL

where Z(n) pickup (1) = Setting value of pickup impedance of the Zone 1 impedance element. ZL(n) = Line impedance of the protected section n Therefore, any phase-fault for which the impedance seen by the relay is less than the setting value of pickup impedance for Zone 1 will belong to Zone 1 and is cleared instantaneously. The Zone 2 includes the whole length of protected section plus up to 40% of the next adjacent section. The clearing time for the Zone 2 is taken as t2 = t1 + ∆t where t1 = Clearing time of Zone 1 ∆t = 0.5 (time delay step) t2 = Clearing time of Zone 2.

Analog input Sample hold control signal

CLOCK MPX address

Input transformer

3 ch

n ch

Filter

SH

Filter

SH

Filter

SH

Filter

SH

Setting DI

ROM A/D

2 ch 1 ch n ch 1 2 ch n ch ch 10

11

DMA

RAM

1 ch 2 ch 1 1 0 0 0 0 1 1

n ch 1 0 0 1 12 bit

0 0 1 1 10

FIGURE 7.33 Principle of digital relay

Parallel

condition Trip DO output

0 1

t

1 ch Data 2 ch Data

10

2 ch

CPU M U L T I P L E X E R

n ch Data 1 ch Data 2 ch Data

11

1 ch

Microprocessor

199

DISTANCE/IMPEDANCE PROTECTION

To ensure the reliability of relay operation for faults close to the remote end of the line and discrimination with the protection of the adjacent feeders the pick up impedance for Zone 2 should meet the requirements: (n)

(n)

(n)

(n + 1)

kdZL 〈 Z pickup (2) ≤ ZL + 0.4 ZL (n)

where Z pickup (2) = Setting value of pickup impedance for Zone 2 impedance element (n) ZL = Line impedance of protected section n (n + 1)

ZL

= Line impedance of the next adjacent section (n + 1) to the protected section n

kd = Dependability factor of at least 1.2, preferably 1.5. Zone 1 reach is limited, because of the indeterminate nature of the fault resistance which may disturb the selective operation for faults at the end of the protected section and at the beginning of the next section. This is why Zone 1 is kept nearly 80% of the protected section and Zone 2 protects only a little portion nearly 20% of the protected section, but this provision helps in selective operation.

7.11 REQUIREMENTS OF DEFINITE-DISTANCE SCHEMES Two feeders BO and OA are represented on the complex plane in Fig. 7.34 considered from the point of view of relays at O. The length OA is thus proportional to the impedance of feeder OA and θ is the impedance angle of the feeder. X¢ A P

P¢

q O

O¢

R

B

FIGURE 7.34 Ideal tripping area

Zone 1 of the protection at O is required to reach up to say P. The relays at O therefore must operate for all faults between O and P only. The effect of fault arc resistance is also shown in Fig. 7.34. The fault resistance increases slightly for faults towards the remote end of the feeder because less of the total fault current flows through the relay. The shaded

200

POWER SYSTEM PROTECTION AND COMMUNICATIONS

area OPP’O’ is known as fault area. The impedance seen for differing fault positions will lie inside the shaded area. To protect against all faults the relay must operate if the measured impedance lies within the fault area. Hence relays at O with characteristics which completely enclose the fault area are suitable for protection of feeder OA. Fault Resistance Fault resistance consists of two components, the resistance of the arc and the resistance of earth. The second component is present only when it involves an earth-fault. In such a case the resistance of earth would mean the resistance of fault path through the tower, tower footing resistance and earth return. An approximate value of arc resistance is to be obtained by empirical relations. Warrington gives the expression Rarc = 2.9 × 104 L /I1.4 ohms where L = length of arc in metres in still air I = fault current in amperes The arc resistance formula developed in Russia is:

L ohms I L will initially be equal to conductor spacing in the case of phasefaults and distance from conductor to tower in case of earth faults. With cross wind, when there is a time delay in fault clearance such as in Zones 2 and 3, the arc is extended considerably, and the resistance is increased. For Zone 1 where the tripping is instantaneous, the effect of arc resistance is small and may be neglected except on very short feeders; but for Zones 2 or 3 high velocity winds may cause the relay to underreach seriously. When both wind and time are involved, Warrington’s formula for arc resistance is: Rarc = 1050

50 (VL + 47 vt) ohms I where VL = nominal system interphase voltage, kV v = wind velocity in km per hour t = time in second I = fault current in amperes Rarc =

7.12 REACH OF DISTANCE RELAY A distance relay is set to operate up to a particular value of impedance; for an impedance greater than this set value the relay should not operate. This impedance, or the corresponding distance is known as the reach of the relay.

201

DISTANCE/IMPEDANCE PROTECTION

To convert primary impedance (impedance of the line referred to the line voltage and current) to a secondary value (line impedance referred to the relay side) for use in adjusting a distance relay the following relation is used: Zsec = Zprim × CT ratio/VT ratio where the CT ratio is the ratio of the HV phase current to the relay phase current, and the VT ratio is the ratio of the HV phase-to-phase voltage to the relay phase-to-phase voltage all under balanced conditions. The tendency of a distance relay to operate at impedances larger than its setting value is known as overreach and similarly the tendency to restrain at the set value of impedance or impedances lower than the set value is known as underreach. An important reason for overreach is the presence of d.c. offset in the fault current wave, as the offset current has a higher peak value than that of a symmetrical wave for which the relay is set. The transient overreach is defined as: Per cent transient overreach =

Z os − Z sy Z sy

× 100

where Zos = The maximum impedance for which the relay will operate with an offset current wave, for a given adjustment. Zsy = The maximum impedance for which the relay will operate for symmetrical currents for the same adjustment as for Zos.

Overreach (per cent)

The transient overreach increases as the system angle tan–1 X/R increases. Fig. 7.35 shows the variation of overreach with system angle.

20 10

10 20 30 40 50 60 70 80 90 System angle degrees

FIGURE 7.35 Overreach characteristics

A distance relay may underreach because of the introduction of fault resistance as illustrated in Fig. 7.36. Relay at O is set for protection up to P. Now if a fault at P occurs such that fault resistance (PP’) is high and by adding this resistance the impedance seen by the relay is OP’ such that P’ lies outside the operating region of the relay, then the relay does not operate.

202

POWER SYSTEM PROTECTION AND COMMUNICATIONS X¢ A P

O

O¢

P¢ R

FIGURE 7.36 Underreach of distance relay

Occasionally a fault may occur in the Zone 1 and the relay may begin to operate. If the fault impedance now increases due to the arc resistance the total impedance seen by the relay will be the sum of the line impedance up to the fault and the arc impedance. This sum may be more than the impedance setting of the relay in which case the first stage operation will stop and the fault will be cleared as if it is located in the second or third zone. In order to prevent this, impedance relays are locked once they begin to operate on the basis of the true impedance up to the fault. Any increase in impedance due to arc will not affect the relay once it is locked.

7.13 DIGITAL COMPUTATION BY A MICROPROCESSOR Digital distance relays estimate the location of a fault using instantaneous values of the voltage and current simultaneously measured (sampled) at fixed time intervals. The sampling is done several times per cycle. The sampling rates of various relays may be different, the practical range being from 4 to 40 samples per cycle. The most typical sampling rate, 12 samples per cycle, corresponds to the electrical angle of 30° and , for 50 Hz systems, the time interval of 1.67 ms. At this rate the sampling frequency is 600 per second. A variety of algorithms have been proposed for processing samples of current and voltage and several are utilised in the digital relays offered by the major relay manufacturers. Some algorithms used in distance relays calculate the fault impedance from the magnitudes and angles of the fundamental frequency components of input voltage and current. These fundamental frequency component values are estimated from several samples of the pre-filtered input voltage and current. If the measured signal is purely sinusoidal it is enough to have just two samples taken at a known time interval (other than half a cycle or its multiple) to be able to find the magnitude and the phase angle of the signal. However, the practical voltage and current signals available at the relay

DISTANCE/IMPEDANCE PROTECTION

203

location during faults are often heavily distorted and laden with high frequency noise. Filtering of the signals and mathematical processing of a greater number of samples are, normally, necessary to make sufficiently accurate estimate of the fault distance. The error signals superimposed on the input quantities come from several sources and are only partly predictable. DC and low frequency transients are produced by instrument transformers and free oscillations between system inductances and capacitances, higher harmonics are generated in transformers , generators, static VAR compensators and nonlinear loads, non-harmonic high frequency random noise is produced by multiple reflections of travelling waves initiated by faults and switching operations. On top of these primary distortions there are also non-linearities of the instrument transformers and interferences generated in the secondary systems. The ability of the relay to extract the fundamental frequency components from the noisy signals greatly increases with the time available for filtering and the number of samples available for mathematical processing. The rule known from application of all previous technologies that the high accuracy and the high operating speed are conflicting requirements applies also to digital technology and the practical solutions are always results of compromises between these requirements. In all practical digital relays the input quantity signals, voltage and current, are passed through analog filters to eliminate any components of frequencies higher than half of the sampling frequency to prevent errors called aliasing. After the anti-aliasing filters the signals are sampled and converted to digital form. A simplified block diagram of a digital relay is shown in Fig. 7.33. The sampling is controlled by a clock. The sampled values are held constant for a short-time by sample-hold modules in order to provide for calculation the voltage and current values corresponding nearly to the same instant although the sampling takes place at a slightly different time. Sampling exactly at the same time is possible but requires multiplication of A/D (Analog to Digital) converters which is more expensive than using one converter fed from multiplexed inputs as shown in the diagram. Further processing of the digital values representing voltage and current at the sampling instants may lead to estimation of magnitudes and angles (vectors) of their fundamental frequency components and subsequently, to determination of the fault impedance from these components. These methods may utilise fast but less accurate algorithms based on a short data window e.g., three samples, or more accurate longer window algorithms. Some relays have both fast and slow algorithms running in parallel to increase the speed for faults deep within Zone 1 and to provide accurate borders between the zones.

204

POWER SYSTEM PROTECTION AND COMMUNICATIONS

A simple way of determination of the distance to the fault from three samples may be illustrated in Mann-Morrison algorithm as follows: For any sinusoidal wave-form the peak value can be determined from two instantaneous values measured at 90° interval. Assume the period of sinusoid v(t) to be T = 20 ms and that three samples v(t – ∆t), v(t) and v (t + ∆t) have been taken at short intervals ∆t, say ∆t = 1.67 ms. v(t) = Vp sin (ωt + φ)

If then

v (t + T/4) = Vp sin (ωt + φ + 90°) = Vp cos (ωt + φ) Vp2 = [Vp sin (ωt + φ)]2 + [Vp cos (ωt + φ)]2

and

= [v(t)]2 + [v(t + T/4)]2 Note, however, that the second component (t + T/4) can be estimated from the samples v(t – ∆t) and v(t + ∆t) measured, respectively, just before and just after the instant t. These samples may be used for calculation of derivative of function v(t): v’(t) = ω × Vp cos (ωt + φ) = ω × v (t + T/4) which, using trapezoidal rule, can be estimated as v’(t) = [v(t + Dt) – v(t – Dt)]/(2 × Dt) and may be used for finding v (t + T/4) = Vp cos (ωt + φ) = v’(t)/ω Eventually the peak value can be determined as: 2 2 Vp = [ Vp sin(ωt + φ)] + [Vp cos (ωt + φ )] 2 2 = [ V (t )] + [v’(t )/ω ]

where v’(t) =

[v (t + ∆t) − v(t − ∆(t)] . 2 × ∆t

The phase angle of the sinusoid at instant t is: ωt + φ = arc tan

Vp sin (ωt + φ) Vp cos (ωt + φ)

=

v’(t) × ω v(t)

It can be seen from the above that, without excessive calculations, the magnitude Vp and angle ωt + φ of the signal V can be determined within time interval of (t + ∆t) – (t – ∆t) = 2 × ∆t, in this case 2 ∆t = 3.34 ms provided the signal can be assumed to be undistorted and sinusoidal. Calculating the square root for voltage and current separately is not necessary if the impedance is the required result. Having evaluated the

205

DISTANCE/IMPEDANCE PROTECTION

squares of voltage and current magnitudes one can calculate the square of impedance magnitude by division: Vp2

Z2 =

I 2p

=

v(t )2 + [v’(t)/ω]2 i(t )2 + [i’(t)/ω ]2

The impedance phase angle can be found from the formula: φ = arc tan [ω × i(t)/i’(t)] – arc tan [ω × v(t)/v’(t)]. The above algorithm is very sensitive to distortion of the wave-form and its use would require thorough filtering. Off course a determination of the magnitude and angle from just two samples would be much more inaccurate.

7.13.1 Full Cycle Fourier Algorithm Some of the popular algorithms of higher accuracy are based on Fourier Filters. The Full Cycle Fourier Algorithm correlates the fault voltage and current signals with sine and cosine weighting factors. This technique generates two orthogonal components for each input voltage and current signal. Note that for any harmonic In sin (nωt + φn) = Inr cos (nωt) + Inx sin (nωt) 2 2 where In = ( Inr + I nx ) ; tan φn = Inr/Inx ; ω = 2πf = 2π/T;

nω = ωn = 2π/Tn where n = the order of the harmonic, for n = 1 (the fundamental frequency of 50 Hz) T = 20 ms, for n = 2 (second harmonic) Tn= 10 ms etc. The coefficients Ir and Ix can be calculated from the following formulas: Fundamental frequency: Ir = 2/T Ix = 2/T The nth harmonics:

Inr = 2/T Inx = 2/T

T

z z z z

t=0 T

t=0

T

t=0 T

t=0

i(t ) cos (ωt) dt i(t ) sin (ωt) dt

i(t ) cos (nωt) dt i(t ) sin (nωt) dt

206

POWER SYSTEM PROTECTION AND COMMUNICATIONS

The digital approximation of the integrals for the fundamental frequency above may be: K

Ir = 2/K

∑ i(k) cos (2πk/K) k=1 K

Ix = 2/K

∑ i(k ) sin (2πk/K) k =1

where K is the number of samples per cycle. It can be shown that these components can be combined in each phase according to the following equations to yield estimates of the resistance and reactance to the fault location. R = (Vr × Ir + Vx × Ix ) / (Ir2 + Ix2) X = (Vr × Ir – Vx × Ix ) / (Ir2 + Ix2) where R is the line resistance to the fault point X is the line reactance to the fault point Vr is the real voltage component Vx is the imaginary voltage component Ir is the real current component Ix is the imaginary current component This algorithm is evaluated after each new sample i.e. the data window slides along the input data stream producing a new estimate of R and L for each new set of input samples. This algorithm is insensitive to any harmonic content of the input signals and to the d.c. component of the signals. This ‘rejection‘ of all harmonics is only obtained if, at least, one whole cycle of the fundamental frequency is included in the sample data window. It may be noted that a noise of high frequency which is not an integer multiple of the fundamental frequency is not rejected by Fourier algorithm and may cause error in distance estimation.

7.13.2 Differential-Equation Algorithms This group of algorithms is based on a single phase model of the faulted line. The differential equation relating the voltage and current to the line parameters is: v(t) = Ri(t) + L[di(t)/dt] Solving this type of equation would produce the required resistance R and inductance L which are both proportional to the distance to the fault.

207

DISTANCE/IMPEDANCE PROTECTION

McInnes and Morrison propose solving the equation by integrating the voltage over two consecutive intervals : t0 – t1 and t1 – t2

z z

t1

t0 t2

t1

v(t) dt = R v(t) dt = R

z z

t1

t0 t2

t1

i(t) dt + L[i(t1) – i(t0)] i(t) dt + L[i(t2) – i(t1)]

The integrals above may be estimated from the samples taken at instants t0, t1, t2 using the trapezoidal rule of integration:

z

t1

t0

v(t) dt = ∆t/2[v(t1) + v(t0)]

For the samples of voltage and current taken at any three consecutive instants k, k + 1, k + 2 the line equations may be written as:

LM ∆t (i N ∆t (i

+ ik )/2 (i k + 1 − i k ) + i k + 1 )/2 (ik + 2 − ik + 1 )

k+1

k+2

OP LR O = LM ∆t (v Q MNL PQ N∆t (v

+ v k )/2 + v k + 1 )/2

k +1

k+2

OP Q

The fault resistance and inductance from the above equations are: R=

L=

( v k + 1 + v k ) (i k + 2 − i k + 1 ) − ( v k + 2 + v k + 1 ) (i k + 1 − i k ) (i k + 1 + i k ) (i k + 2 − i k + 1 ) − (i k + 2 + i k + 1 ) ( i k + 1 − i k ) ∆t (ik + 1 + ik ) ( vk + 2 + vk + 1 ) − (ik + 2 + ik + 1 ) (vk + 1 + vk ) × (ik + 1 + ik ) (ik + 2 − ik + 1 ) − (ik + 2 + ik + 1 ) (ik + 1 − ik ) 2

Similar formulas for R and L can be obtained in terms of the signal values and their first order derivatives or in terms of the first and second derivatives of the signals. For example, if the values of signals v1 and i1 and their derivatives v1′ and i1′ at instant t1, and also values v2 and i2 and their derivatives at instant t2 are available then the resistance and inductance are: v . i ′ − v2 . i1′ R= 1 2 i1 . i2′ − i2 . i2′

v2 . i1′ − v1 . i2′ i1 . i2′ − i2 . i1′ With use of the first and second order derivatives the formulas become: v . i ′′− v2 . i1′′ R= 1 2 i1 . i 2′′− i2′ . i1′′ L=

L=

v2 ’. i1′ − v1′ . i 2′ i1 ’. i2′′− i 2′ . i1′′

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

The derivatives of the signal used in the above equation may be determined from three or more samples. The method of this determination affects the frequency response of the relay. The differential equation algorithms reject the d.c. components of the input signals and can be made reject a particular frequency but, generally, higher frequency distortion may cause considerable errors in their measurement. The use of second order derivative method makes the relay more tolerant to lower frequency interference which, together with the low pass antialiasing filters makes the sensitivity window of the relay reasonably small. Protection design engineer should be aware of the performance characteristics and sensitivity of the relays resulting from their principal signal processing method and should use it to the advantage of the protection scheme. The characteristics of a practical relay result from the combination of the analog and digital filters, impedance algorithms and the operating criteria programs. This combination may mask to a degree the generic performance characteristics of the algorithms but it has been confirmed by numerous simulation tests in the laboratory that the knowledge of the relay algorithms makes protection operation a lot more predictable.

CHAPTER

8 Differential Protection

8.1

INTRODUCTION

Differential protection is a unit type protection scheme that uses a comparison between the current entering the protected zone and the current leaving the protected zone, to determine if there is a fault. The comparison can be made on the magnitude of the difference between the currents, the phase difference or a combination of both. Differential protection, in its various forms, is widely used in protection systems for generators, transformers, busbars and lines. The objective of this chapter is to examine the operating principles and design of the various schemes. The principle forms to be discussed are: • circulating current differential protection (low impedance), • biased differential protection, • high impedance current differential, • pilot wire, and • phase comparison.

8.2

CIRCULATING CURRENT DIFFERENTIAL (LOW IMPEDANCE)

The low impedance circulating current scheme is the basic form of differential protection. It is applied widely in subtransmission systems and to a lesser extent in transmission systems as busbar protection.

210

POWER SYSTEM PROTECTION AND COMMUNICATIONS

The scheme is simply a summation, on a per phase basis, of the current transformers associated with each item of plant in the protected zone. An overcurrent relay is connected across the CT summation junction and is set to operate when an internal fault results in current flowing in the relay circuit. Fig. 8.1 shows current flows in the CT and relay circuits for an internal and external fault. It can be seen that, for normal load currents or an external fault, currents in the CT secondary circuits ‘circulate’ around the secondary loop and summate to zero at the junction. For an internal fault, currents will flow into the fault from the primary sources and the secondary currents will add to flow through the relay. Note the polarity marks shown for the CTs and the connections to give the correct summation of the currents.

R

R

R

(a) External fault

(b) Internal fault

FIGURE 8.1 Low impedance current differential

For the scheme to operate satisfactorily, it is necessary to ensure that any errors that cause unbalance of the CT secondary summation, for an

211

DIFFERENTIAL PROTECTION

external fault, will not result in operation of the relay. All current transformers must be connected on the same ratio, have similar performance specifications and similar lead burdens between the CT and the secondary summation point. To achieve the latter, it is usual to make the CT summation as close to the primary plant as possible (e.g., in the switchyard close the CBs). The summation is then cabled to the protection panel. In practice, there will always be some ‘spill’ current under external fault conditions, particularly during the sub-transient and transient periods of the fault. The precise level of these currents is difficult to predict so it is usual to introduce a time delay into the relay and ensure that the minimum operating level is not too sensitive. An inverse overcurrent relay, set on a Short Time Multiplier Setting, gives a satisfactory performance. Even with the use of an inverse overcurrent relay, the operating times that can be achieved with this protection are far superior to what would be the case if remote overcurrent or distance protections were relied upon to clear the fault. One difficulty that can arise with the application of low impedance schemes is CT saturation. The most likely situation where this will occur is where one of the primary circuits in the protected zone contributes a higher level of current to an external fault than other circuits in the zone. If saturation does occur, the CT will not contribute to the summation and the magnetising impedance will appear as a zero impedance. As a result, the circuit containing the saturated CT (including its cabling) will appear as a resistance across the summation, in parallel with the relay. The summated current from the unsaturated CTs will divide between the relay and the saturated CT circuit according to the relative resistances of the relay circuit and the saturated CT circuit i.e., spill current will flow through the relay and most likely cause incorrect operation. Referring to Fig. 8.2, it can be seen that the current through the relay can be represented by: IRelay =

I sec (Rlb + Rctb) R Relay

From this formula, it can be seen that if RRelay is small compared with (Rlb + Rctb) incorrect operation is likely to occur . One technique to overcome the problem is to connect a ‘stabilising’ resistor series with the relay. In the extreme, this approaches the high impedance scheme described in section 8.4 and is not frequently seen in Australian practice; the preference being to use the high impedance scheme.

212

POWER SYSTEM PROTECTION AND COMMUNICATIONS

a

b Rcta

Rla

Rlb

Rctb

Relay

FIGURE 8.2 Circulating current scheme (one CT saturated)

In making the decision between low impedance and high impedance schemes, however, it must be remembered that the high impedance scheme requires dedicated CTs and these are not always available, particularly in a subtransmission system.

8.3

BIASED DIFFERENTIAL PROTECTION

To improve the stability of a differential scheme to unbalances in CT secondary currents that can occur under external fault conditions, and to allow the operating time delay to be reduced, the concept of ‘bias’ is introduced. Biased differential protection, in it’s usual form, is designed for two or three inputs and is most commonly used for transformer protection. The bias feature overcomes the difficulty with power transformers of achieving a good match between CTs on the different voltage levels and the spill currents in the differential circuit that arise from tap changing. There are also some forms of proprietary biased schemes available for bus bar protection. I2

I1

Bias

Bias

Operate

(a) Biased differential relay

213

DIFFERENTIAL PROTECTION

es

8 n

io

o

ot

Pr

6 Current, I1

t ec

t ra pe

ea

e tiv

ar

ra

pe

o In

4

es

t ra

on

e op

cti

2

e ot

Pr

0

2

4

6

8

Current, I2 (% rated secondary current) (b) Typical biased characteristic relay

FIGURE 8.3 Biased differential protection

The concept of the biased relay is as shown in Fig. 8.3(a). This form, known as percentage bias, operates on the principle that if the two currents entering and leaving the protected zone are I1 and I2, then: The operating quantity = K1 (I1 – I2) The biasing quantity

= K2 (I1 + I2)

Suitable choice of constants K1 and K2 ensures stability for external fault conditions despite measurement errors, while still retaining adequate sensitivity for operation on internal faults. Fig. 8.3(b) shows a typical characteristic. In electromechanical terms the relay can be thought of as having bias coils in the circulating current path that exert a restraining torque on relay operation and on coil in the operating leg that produces an operating torque. Where the protection is used on transformers, the CTs associated with star connected windings are usually connected in delta and those for delta connected windings in star. This corrects the power transformer line current phase shift and eliminates the zero sequence currents on the star side which might otherwise upset the stability due to the lack of a corresponding zero sequence component on the delta side. Bias settings are chosen to ensure that the relay will remain stable with the transformer at the extremes of the tapping range.

8.4

HIGH IMPEDANCE CURRENT DIFFERENTIAL

With the low impedance circulating current scheme, described in section 8.3, it was seen that it is not practical to maintain stability under external

214

POWER SYSTEM PROTECTION AND COMMUNICATIONS

fault conditions, if CT saturation occurs. High impedance current differential protection was developed to overcome this problem and to achieve high speed operation is required for internal faults. In principle, the scheme involves increasing the stabilising resistor to a value that results in the operating voltage having a margin over the voltage developed across the circuit with the saturated CT. High impedance schemes are widely used for busbar protection and zone protections (e.g., the connections to a power transformer) on EHV and subtransmission systems and for generator differential protection. The scheme makes use of the principle, described earlier, that the secondary winding of a saturated CT will not contribute to the CT summation and its secondary winding will represent a resistance connected in parallel with the CT summation and the differential relay A voltage measuring relay (usually an instantaneous overcurrent relay with a series resistor) is connected across the CT summation point. To ensure stability for external faults, the relay is set to operate at a voltage approximately 1.1 times the voltage that will appear across the summation with one of the CTs which is saturated under external fault conditions. The setting calculation is performed on the highest CT + lead resistance, connected to the summation i.e., the CT furthest from the summation point. On an internal, fault, the summation will see the relay impedance and CTs will develop a voltage across the differential relay. The operating voltage is usually set to 0.5 Vk , to ensure definite operation. Under internal fault, conditions, the conditions in the CT secondary circuit is similar to that of an open circuit operation and results in the potential for very high secondary voltages to be developed. The voltage waveform will be distorted but the peak value may be many times the nominal saturation value. A guide to the possible peak voltage can be obtained from the following formulae: Vk ( Vf − Vk )

Vp = 2 2

...(1)

where Vp = peak voltage developed Vk = saturation voltage (knee point voltage) Vf = prospective voltage in the absence of saturation Vp = 2

If I ek

Vk

...(2)

DIFFERENTIAL PROTECTION

215

where If = fault current Iek = exciting current at knee point voltage Vk = knee point voltage Equation (1) applies when there is a finite burden resistance (although high) but it does not hold for the open circuit condition. Equation (2) applies for the open circuit secondary condition. Any burden across the secondary will reduce the voltage. It is usual to limit the voltage across the relay circuit with the connection of a non-linear resistor. A ceramic resistor (commonly referred to by the trade name (Metrosil) having a characteristic V = Clβ is used, where C is a constant depending on the dimensions and β is a constant in the range 0.2–0.25. Because of the risk of high voltages appearing on the secondary circuits it is necessary to ensure that the secondary wiring and isolation equipment has sufficient insulation and that procedures are in place to ensure that staff access to the equipment for testing and maintenance is safe.

8.5

PILOT WIRE PROTECTION

The limit to the application of the differential schemes described above is the length of cabling required to summate the CT secondary currents. In practice, this limits the application of these schemes to plant and connections within stations. To remove this limitation pilot wire protection schemes were developed, where the CT secondary currents are transformed to a level that can be transmitted over telecommunications cables. Comparison of the phase and magnitude of quantities representing the local and the remote currents are then made at each terminal, i.e., comparisons are made at each end of the protected zone in contrast to the direct comparison of the current differential schemes described earlier. Bias is included in the scheme design to provide stability for differences in CT characteristics. Insulation, current carrying limitations and capacitance of telecommunications cables, limit the length of cable that can be used to around 30 km. As a result, this form of protection is usually used for short transmission and subtransmission lines. These schemes are well suited to this application as they provide a high speed unit type scheme compared with the alternative of distance or overcurrent protections which can be difficult to apply to short lines and have longer operating time.

216

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Two basic schemes are generally used: • Circulating current Fig. 8.4(a), where current circulates in the pilot circuit under load or external fault conditions and through the operating circuits of the relays at each end of the protected zone for internal faults. • Balanced voltage scheme Fig. 8.4(b), where the voltage on the pilot circuits are opposed, under load or external fault conditions, resulting in zero current in the pilot circuit and relay operating circuits. An internal fault results in a phase reversal in the voltage at one end of the pilot circuit with the result that current flows in the pilots and the operating circuit of the relay. It will be noted that the schemes shown in Fig. 8.4 use one pilot circuit to cover all fault conditions. A summation transformer, Fig. 8.4(c), is used to combine the three phases into a single quantity for the comparison. This is done to minimise the use of pilot cable circuits, as they are relatively expensive to provide. Line

Summation transformer

R

V

I

I

R

Pilots V Relay

Summation transformer

Relay

(a) Circulating current scheme

Line

I Summation transformer

V

R I Relay

I

I Pilots

V

R I Relay

(b) Balanced voltage sheme

Summation transformer

217

DIFFERENTIAL PROTECTION A T1

B C

T2 N (c) Summation transformer

FIGURE 8.4 Pilot wire protection

The interphase sections of the winding A-B and B-C are often given equal numbers of turns, the neutral end of the winding C-N will generally have a greater number of turns. Unbalanced fault currents will then energise different number of turns according to which phase is faulted. This leads to relay settings which are in inverse ratio to the number of turns involved. If the relay has a setting of 100% for an A-B fault, the following proportionate phase settings will apply. Phase A-C

100%

Phase A-C

50%

Phase A-B

100%

Three phase

58%

The earth fault settings will depend on the relative number of turns in section C-N but will also depend on which phase is faulted.

8.6

PHASE COMPARISON PROTECTION

Phase comparison is a term used to describe a differential scheme that compares the phase relationship of the currents at each end of the protected zone and initiates tripping when the phase difference exceeds the tripping criteria. These schemes were principally designed to use high frequency bearers such as power line carrier on longer transmission lines. The carrier signal is modulated to represent the power system current and transmitted to the remote end where the phase relationship is compared with the local current. The schemes were used only to a limited extent in Australia because of their relative complexity and difficulties with maintaining reliable performance compared with distance schemes. As shown in Fig. 8.5, modulation is of the all or nothing type giving half-cycle pulses of carrier signal interspersed with half periods of zero signal.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

With an external fault, the transmission from one end fills in the gaps at the other end resulting in a continuous signal on the line, when observed by the measuring equipment at one end. Signal attenuation does not affect the measurement. The continuous signal blocks operation. For an internal, fault the resultant signal on the line has half-period gaps during which the tripping function is initiated. Time delay circuits are included in the protection to compensate for the transmission time of the carrier (0.33 milliseconds or 6 electrical degrees per 100 km of line for power line carrier). Starting relays using current level, rate of change of current or impedance measurement are used to initiate the comparison (telecommunications regulations usually do not allow continuous transmission of power line carrier) and to interlock the tripping circuit. The tripping function is set so that operation will not occur until the gap corresponds to a specific phase difference between the currents at each end of the zone - usually in the range 18°–30°. As with pilot wire schemes, separate comparison for each phase is usually uneconomical and some arrangement for combining the phase currents are made. Modern developments, with the advent of digital transmission systems and particularly the availability of fibre optic transmission systems on transmission lines, has generated a renewed interest and there are schemes available on the market. Through fault

Internal fault 30° tripping angle

Fault current at station A Effect of squaring circuit Hf signal transmission at A Fault current at station B Hf signal transmission at B Combined hf signals on line at station A Blocking voltage from detector stage Current in trip relay

FIGURE 8.5 Phase comparison protection

Internal fault 180° tripping angle

CHAPTER

9 Unit, Remote and Back Up Protection 9.1

UNIT AND NON-UNIT PROTECTION SCHEMES

Protection schemes fall into two basic categories, these are the ‘Unit Schemes’ and the ‘Non-Unit Schemes’. The basic features of the two categories are as follows: ♦ Unit Schemes — These schemes are used to protect a defined/discrete zone, usually their boundaries are defined by the Current Transformers. Advantages: No grading is required with adjacent protections nor with the load current, they are fast operating and sensitive. Disadvantages: Do not provide back up to adjoining protection zones, therefore duplication of protections is generally necessary. ♦ Non-Unit Schemes— These schemes do not protect discrete zones but they overlap with other protection zones. As a result, they need to discriminate with other protections and distinguish between the load current and the fault current. Advantages: Ability to discriminate over other relay groups allows back up to be provided to the relay nearest the fault if that relay has failed to operate.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Disadvantages: Time/current/impedance grading required to allow for discrimination with other protections, therefore slowest fault clearing times are going to be at the highest fault level locations. The following compares in more detail some of the main features of the two: Feature

Unit Protection Scheme

1. Principle of operation

Operates if the input and output quantities of the protected zone are not equal (e.g., a differential type protection, etc).

4. Speed of operation

Generally can be made very fast and basically is an inherent property of the scheme itself. Operating times of 20–30 milliseconds are common.

Non-Unit Protection Scheme

Operates if a measured quantity (volts, amperes, ohms, etc.) is over/under or departs from a set level (e.g., under/over voltage overcurrent, impedance protection, etc.). 2. Sensitivity to The magnitude of the differ- In the case of simple overshort circuits ence between the input/ current protection the sensibetween output quantities required tivity is limited by maximum conductors for operation can be less load, i.e., the fault which can (i.e., Multithan the maximum load be detected is greater than phase faults) current (i.e., good sensitivity load current. Impedance or is possible). distance protections do allow sensitivities which are better than maximum load current. 3. Sensitivity to Virtually only limited As for the Unit Scheme short circuits by the sensitivity which between can be built into the conductors and scheme—therefore good ground (i.e., sensitivity is possible. Phase-to-Earth faults)

5. Facility for By its nature it cannot providing back- provide back up for up for other failure of protective

Generally to obtain discrimination with other protective devices it is necessary for time delays to be introduced. Operating times greater than about 0.5 second are usually appropriate. Back up to protective equipment at other locations is possible

UNIT, REMOTE AND BACK UP PROTECTION

protection elements

221

equipment at other locations.

within the constraints imposed by loading, system interconnection and earthing.

6. Cost

Generally somewhat higher than for non-unit schemes but can be significantly higher if interstation signalling is necessary.

This varies with the sophistication of the device, from being relatively cheap for a single quantity device (e.g., overcurrent and overvoltage) to quite costly for a complex distance relay.

7. Range of application

May find application at all system levels but mostly at the main transmission level. (For some types, the cost may be difficult to justify at the lower voltage levels).

The simpler types of equipment or schemes would not generally be found on the main transmission system but the complex schemes (e.g., distance relays) are found at both main and subtransmission voltage levels.

From the above comparison, it can be seen that each category has its advantages/ disadvantages for particular applications but overall cost is generally the biggest factor in applying unit-type schemes, particularly where it becomes necessary to provide interstation signalling. Distance protection does overcome to a large extent one of the main disadvantages of non-unit schemes (i.e., limited sensitivity) and therefore it is becoming the most common choice for the protection of lines in the sub-transmission system along with almost universal use, with associated signalling, at the main transmission level for which it was originally developed. The typical application of Unit and Non-Unit type Schemes are demonstrated in Figs. 9.1 and 9.2. The typical type of schemes used are as follows: Unit Type Schemes • Pilot wire • Transformer differential • Bus protection (high impedance, medium impedance, low impedance) • Phase comparison • Distance protection with associated signalling • Directional comparison • Restricted earth fault etc.

222

POWER SYSTEM PROTECTION AND COMMUNICATIONS N

220 kV Bus

Microwave PLC optic fiber

66 kV Bus

Pilot wire Unit schemes Non-unit schemes

FIGURE 9.1 Unit and non-unit schemes

223

UNIT, REMOTE AND BACK UP PROTECTION

G GEN Transformer protection zone

GEN TR High impedence protection zone

No. 1 Bus

BUSBAR protection LINE zones protection zone

No. 2 Bus LINE

FIGURE 9.2 Unit protection type schemes

Non-Unit Schemes Feeder Overcurrent Transformer H.T. Overcurrent Bus Overload Earth Leakage Protection Distance Protection without Associated Signalling Fuses etc.

224

9.2

POWER SYSTEM PROTECTION AND COMMUNICATIONS

REMOTE AND LOCAL BACK UP PROTECTION

With any protection system it is generally accepted that any device other than a fuse can fail to operate. To reduce the risk of a fault not being cleared, it is common practice to provide protection systems that cater (as a minimum requirement) for the failure of at least one element and still ensure that the fault is cleared. On a world wide basis, this has proved to be a satisfactory assumption. As a consequence back up protection is applied primarily to cover for the: • failure of the circuit breaker associated with the primary protection zone, • ‘blind spots’ of the system which are not included in any zone of the main protection because of the location of the current or voltage transformers and, • failure of the main protection systems including the measuring current transformers and voltage transformers. On simple radial systems, each circuit breaker and its associated protective relays provide back up for the failure of the circuit breaker or the main protection at the next station. The failure could result from the relay being defective, the station battery being flat, or the circuit breaker being unable to interrupt the fault. This type of arrangement is termed remote back up and is provided by time-graded protections (current or impedance). Remote back up protection has the advantage that it provides back up protection for both relays and circuit breakers. However, remote back up has the following disadvantages: — The protection providing the remote back up can be very slow to operate since it is required to discriminate with other protections. — It may not be possible to set the back up protection so that it can detect the fault condition at the remote location. For example: • the load currents could be greater than the fault currents. • in a power system with interconnections, parallel circuits and infeeds from intermediate current sources could affect the performance of time-graded type protections, (e.g., increasing or decreasing the reach of the relays). In these cases, it may again not be practical for the protection to be set to detect the fault at the remote location. Obviously remote back up may not be practical for some applications, for such situations another form of back up has been developed and this is termed local back up.

UNIT, REMOTE AND BACK UP PROTECTION

225

Local back up is provided in two parts: • Back up to cover Protection Scheme Failure — provision of two independent protections (In general local back up is not duplicated, however, this is dependent on the philosophy/practice of the relevant organisation). — provision of independent current transformers, circuit breaker trip coils, d.c. supplies, voltage transformer supplies (generally by segregating the circuit near the voltage transformer). • Back up to cover circuit breaker failure or provision of ‘Blind Spot’ protection. Local back up for circuit breaker failure or ‘blind spot’ protection, is provided by determining that a circuit breaker has failed to trip or isolate a fault, and then in turn initiate tripping of all circuit breakers that are adjacent to the failed circuit breaker to clear the fault. Briefly the advantages and disadvantages of the remote and local back up are as follows: Remote Back up Advantages • inexpensive • backs up all elements including battery • simple

Local Back up Advantages • faster clearance • more sensitive • easier to set • minimum system interrupted

Disadvantages • slow • less sensitive • difficult to set with infeeds and coordination with other protections • entire station tripped Disadvantages • more expensive • more complex maintenance • two independent primary protections are required • incorrect operation can shut down other plant

Remote Back up Remote back up as indicated previously can be provided by time discrimination protections, i.e., overcurrent and distance are two typical protections that are used for this function. Remote back up is generally applied in radial systems. A simple example of remote back up is demonstrated by the system shown in Fig. 9.3. In this example, the protection at ‘B’ provides the back up for ‘C’ and ‘A’ provides the back up to ‘B’.

226

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Clearance time

Dt

Dt A

B

C

I R1

I R2

I R3

Overcurrent protection Clearance time

0.5 S

Dt

Dt Zone 1

Zone 1

Zone 1

0 A

B Z

C Z

Z

Distance protection Dt-discrimination margin

FIGURE 9.3 Remote back up

Local Back up Back up to Protection Scheme Failure The back up scheme to be provided must ensure, as a minimum, that the performance and reliability of the overall protection system to clear a fault is maintained for the failure of any single element. To achieve the above requirement, the practice of organisations is, in general, to have a philosophy similar to the following: • Provision of two independent protection relay equipments on all protection zones (e.g., lines, busbars, transformers etc.). • Where possible, duplicated primary protections on a plant item should use, equipment operating on different measuring principles and/or design. The exception being duplicate electromechanical protection schemes where in-service experience has shown that such relays have displayed a high level of stability and reliability. • Provision of independent inter-station signalling links, where required, preferably on different routes for the two independent protection schemes.

UNIT, REMOTE AND BACK UP PROTECTION

227

• Provision of independent d.c. supplies to the two independent protections. • Provision of independent current transformers to the two independent protections. • Provision of independent voltage supplies to the two independent protections. • Relay and other protective equipment performance requirements required to comply with British, IEC or Australian Standards or other as appropriate. • Regular maintenance and testing of equipment. Typical examples of design practices to provide back up for the failure of protection are shown in Figs. 9.4 and 9.5. Backup to Circuit Breaker Failure In the case of circuit breaker failure, it is not economically viable to provide duplicate high voltage circuit breakers for back up. Even with the provision of duplicate trip coils on circuit breakers, electrical or mechanical failure with the circuit breaker can prevent the clearance of a fault. To ensure the clearance of the fault in the event of circuit breaker failure, local back up is provided. Although there may be differences with the specific circuit breaker fail schemes logics used from organisation to organisation and from country to country, the principle of operation is in general similar in all cases. It is normal practice to utilise the main protection in conjunction with a current check relay (or in some applications the use of the circuit breaker auxiliary contact) to detect the failure of the circuit breaker and initiate a timing relay. If the fault is not cleared by the primary scheme before the timing relay times out, then all the adjacent circuit breakers are tripped to clear the fault. The current check relay used to detect the failure of the circuit breaker is an instantaneous type overcurrent relay. To ensure that the circuit breaker scheme functions correctly, it is essential that the current check relay sensitivity selected (setting) is below the minimum level of fault current. Generally, two arrangements of incorporating circuit breaker failure relays are used, these are: • Arrangement ‘One’ (Refer to Fig. 9.6(a) for typical logic). With this arrangement, the circuit breaker failure scheme is not enabled until the primary protection, that initiates the trip of that circuit breaker, has operated.

228

Battery

Comm

Seal in relay X line protection

Line protection CTs

X Y

Trip relay

Seal in relay

Seal in relay Y line protection

CB fail protection Trip relay

Trip relay CB fail initiate aux RLY

CB fail (back up)

CB fail initiate aux RLY

X CB CB ‘A’ SW trip coil Y CB CB ‘A’ SW trip coil

Initiate tirp of bus via X bus prot. Trip relay

Initiate trip of adjacent CB for 1.5 CB arrangement via X trip coil

X protection

Y protection

Circuit breaker fail

Bus

FIGURE 9.4 Design practice providing back up for failure of protection-partial duplication

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Bus protection CTs CB fail

Y Trip To other X prots

If applicable

To other X prots

X

X Y

Y Relay

X Trip

X Relay

Y

Comm

Line

Comm

If applicable X line protection

Seal in relay

If applicable

Y line protection

X CB fail

Seal in relay

Seal in relay

Y CB fail

Trip relay

Trip relay Trip relay

Trip relay

X Prot & X CB fail

X CB CB ‘A’ SW trip coil Y CB CB ‘A’ SW trip coil

Note: CB fail logic not included for failure of CB for: ‘X’ bus protection operation Recieve X back up trip from remote end of line.

If applicable

Y Prot & Y CB fail If applicable

Line protection CTs

Bus protection CTs CB fail

Seal in relay

Comm

To other X prots

X

Y Trip

Y Relay To other Y prots

X Trip

X Relay

Y

X Y

Y Battery

Initiate trip of bus via X bus prot. Trip relay

Initiate trip of adjacent CB for 1.5 CB arrangement via X trip coil

Note: CB fail logic not included for failure of CB for: ‘Y’ bus protection operation Recieve Y back up trip from remote end of line.

UNIT, REMOTE AND BACK UP PROTECTION

X Battery Line

Initiate trip of bus via Y bus prot. Trip relay

Initiate trip of adjacent CB for 1.5 CB arrangement via Y trip coil

Bus

229

FIGURE 9.5 Design practice providing back up for failure of protection-full duplication

230

POWER SYSTEM PROTECTION AND COMMUNICATIONS

DC supply +

– Timer

Protection Current check

Trip A relay Preferred circuit DC supply + Protection

–

Current check

Trip appropriate CBs or send remote trip

Timer

Trip A relay Alternative circuit

Trip appropriate CBs or send remote trip

FIGURE 9.6 (a) Circuit breaker failure scheme arrangement ‘one’

The advantage of this scheme is that the circuit breaker failure relay settings can be below load current without impacting on the security of the system. However, the disadvantage of this arrangement is that the circuit breaker failure scheme remains in a de-energised state until a protection operation has occurred. The reliability of the scheme could be an unknown quantity. • Arrangement ‘Two’ [Refer to Fig. 9.6(b) for typical logic] With the arrangement, the circuit breaker failure scheme is always in an energised state. In this case, the operation of the overcurrent check relay feature is independent of the primary protection. The disadvantage of this arrangement is that the circuit breaker failure relay settings usually need to be set above load current for system security reasons. As a consequence it may become difficult to set the relay to cover some contingencies for circuit breaker failure, in particular if the fault current is less than the load current.

231

UNIT, REMOTE AND BACK UP PROTECTION

DC supply +

–

Current check Timer

Protection Trip A relay Trip appropriate CBs or send remote trip

FIGURE 9.6 (b) Circuit breaker failure scheme arrangment ‘two’

Where the fault current is less than the load current, different arrangements may be necessary, these would include the use of high set current checks with other sensitive fault detectors interlocked by low set overcurrent check relays. In these applications the high set current check is set above the load and would cover the high level faults, the low set current check arrangement would cover low level fault conditions. Typical examples of local back up protection used on EHV systems refer to Fig. 9.7. Local back up EHV lines (Three pole trip) Line prot

HOC

R

RWB

AND

Timer Trip all bus CBs

OR

B LOC

N AND

Bus prot

Timer

RWB

(a)

Trip adjacent CBs initiate remote trip as required

232

POWER SYSTEM PROTECTION AND COMMUNICATIONS Local back up EHV lines (Initial three pole trip future provision for single pole trip) AND R Line prot

OR

Timer

W

Trip all bus CBs

S OR R HOC W OR

S Deleted when single pole trip required LOC N

Bus prot

AND

Timer

RWB

Trip adjacent CBs initiate remote trip as required

(b) Local back up EHV lines (Single pole trip-line prot, three pole trip-reactor prot) Reactor prot

RWS

AND

OR

OR

AND

Line prot

Timer Trip all bus CBs

R OR W B OR R HOC

W B AND R

LOC

OR

W S

NEG SEQ Bus prot

AND RWS (c)

Timer

Trip adjacent CBs initiate remote trip as required

233

UNIT, REMOTE AND BACK UP PROTECTION

Auto-Transformer (Three pole trip) Reactor prot

RWS AND R

Line prot

OR

Timer Trip all bus CBs

OR

W B R

LOC

OR

AND

W B

NEG SEQ Bus prot

AND

Timer

RWS

Trip adjacent CBs

(d)

Local current check logic utilising remote signalling Remote receive remote sensitive current check

AND

R W

Local low set current check

B (e)

Remote trip receive interlock logics Timer

Timer

Remote trip receive

AND

Under voltage 3f impedance Zero sequence Negative sequence Trip appropriate CBs (f)

FIGURE 9.7 Typical examples of back up protection on EHV systems

A typical example of local back up protection is demonstrated in Fig. 9.8. In this example, the protections at E (P1 or P2), apart from their prime function of tripping the circuit breaker E for a fault at F, also in conjunction with the current check relay CC, detect the failure of the circuit breaker to trip. The timing relay, set to say 200 milliseconds, depending on

234

POWER SYSTEM PROTECTION AND COMMUNICATIONS

the circuit breakers and relays involved, will then initiate the trip of the circuit breakers A, B, and C if the protection does not reset in that time, indicating that the circuit breaker has failed to trip.

A E

G F

CC B

P1

P2

C

D

(a) Schematic X+

Y+ P1

B/U+

P2

+ CC Trip relays

–

+

–

C.B. ‘E’ X trip coils

–

Time – delay relay

Y

X–

Y– Trip c.bs. A, B, C

–

(b) D.C. circuit

FIGURE 9.8 Examples of typical back up scheme

235

UNIT, REMOTE AND BACK UP PROTECTION

Provision of ‘Blind Spot’ Protection utilising Local Back up Protection The term ‘Blind Spot’ as applied to protection schemes indicates that if a fault occurs in this area it will not be cleared by the primary protection unless some special protection is provided. These ‘Blind Spots’ are created because of the current transformer arrangements. To reduce costs it is normal practice to have current transformers located on one side of the circuit breaker only, this arrangement leads to a blind spot being created. If one considers the example shown in Fig. 9.9, the current transformer in this case is located on the line side of the circuit breaker with overlapping line and busbar protection zones. However, if a fault were to occur between the circuit breaker and the current transformer, the fault would be detected by the busbar protection only, the fault would not be detected by the line protection since it is outside its protection zone. As a consequence the busbar circuit breakers would be tripped, however the infeed from the other end of the line would remain unless some other form of protection was provided. It is normal practice to utilise the circuit breaker failure protection for this purpose. Bus

Dead zone Or Blind zone Line

Circuit breaker

Fault Line protection

Y X

CBF CBF Y X

1. X and Y protection operates and trips CBF isolating bus from fault is outside line protection zone and line protection will not operate. 2. After a time delay the X and Y CBF protection in conjunction with the bus initiates a trip to clear the breaker at the remote end of the line.

236

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Current check Bus protection

Line protection

AND

OR

BU TMR

Remote trip

CB Trip

FIGURE 9.9 ‘Blind spot’ or ‘Dead zone’ protection

In this case, the busbar protection (which would remain in an operated state until the fault had been cleared) would initiate the circuit breaker failure protection. The overcurrent check of the circuit breaker failure protection would also have operated and would remain operated until the fault had been cleared. The operation of both the busbar protection and the overcurrent check would cause the timing relay of the circuit breaker failure scheme to operate, this in turn would initiate the trip of the circuit breaker at the other end of the line, thus clearing the fault. Generally the protections for ‘Blind spot’ are not provided with two independent protections, because the probability of a fault in this area is considered so low that duplication of protections to cover for this contingency is, in general, not considered necessary. However, there are instances where the ‘Blind Spot’ exposure is significant to justify the provision of two independent protections. Each protection system needs to be considered on its merits. Circuit Breaker Failure Scheme Timer Settings Whether arrangement ‘One’ or ‘Two’ is applied, is dependent on the preferences and philosophies of the relevant organisation. In both arrangements, the time delay that is set on the circuit breaker failure scheme should include allowance for the following times: • total circuit breaker operating time (from initiation of trip to fault clearance), • reset time of the current check relay (the reset time of some relays could be affected by the performance of the current transformers), • timing relay error, and • safety margin. The timer setting in some instances can be reduced by using a circuit breaker auxiliary contact to de-energise the timing relay circuit. However, this type of scheme has a number of disadvantages and, in general, the use of auxiliary contacts should not be used as they are considered to be

UNIT, REMOTE AND BACK UP PROTECTION

237

insecure. The disadvantages of using circuit breaker auxiliary contacts are as follows: ♦ cabling is required to the circuit breaker and this could be a source of problems ♦ the circuit breaker mechanism could operate (and hence the auxiliary contact) but the circuit breaker may not have interrupted the fault current. ♦ erroneous initiation during testing/commissioning of the circuit breaker. Circuit Breaker Failure Scheme Current Settings Whether arrangement ‘One’ or ‘Two’ is applied, the circuit breaker failure schemes are required to operate for minimum fault conditions. The setting should be set to less than half the minimum fault level to ensure the reliability of the scheme. Typically the current sensing portion of available relays have a continuous rating of twice rated nominal current. In the case of arrangement ‘Two’ the current setting should also be greater than or equal to 120% of the maximum load for normal system conditions. In the event that the two setting constraints of fault current and load current cannot be satisfied then an alternative design may need to be considered arrangement ‘One’ may need to be used or alternatively it may be possible to use high set current checks with other sensitive fault detectors interlocked by low set overcurrent check relays as indicated previously.

9.3

EXAMPLE DEMONSTRATING A METHOD TO DETERMINE CURRENT SETTINGS OF CIRCUIT BREAKER FAILURE SCHEMES

The system that is detailed in Fig. 9.10, will be used to demonstrate a typical approach when determining the required settings of a circuit breaker failure scheme. The logic assumed for the scheme is in accordance with arrangement ‘Two’ as detailed in earlier section. The supply system consists of: • two radially fed 220 kV/66 kV YY∆ transformers without 220 kV bus, • 220 kV circuit breakers located on the 220 kV incoming lines, and • 66 kV circuit breakers located on the 66 kV side of the transformers, 66 kV bus tie and 66 kV feeders.

238

POWER SYSTEM PROTECTION AND COMMUNICATIONS 220 kV source Terminal station

220 kV lines

220 kV Buses

Terminal station

F2

F1

C/C

C/C

C/C current check

66 kV feeders

FIGURE 9.10 System used to demonstrate the method of determining circuit breaker failure settings

The failure of the 66 kV transformer circuit breaker is to be considered for this example. Assume that the most onerous contingency to be considered for the failure of this circuit breaker is a fault occurring either on the 220 kV side of the transformer or on the tertiary of one of the 220 kV/66 kV transformers. Assume that the circuit breaker failure protection scheme proposed at this stage is as follows: • high set current check with two phase elements and a neutral element, • proposed settings of 2100 A for the phase elements and 525 A for the neutral elements. The exercise will be to verify that the proposed arrangement is satisfactory. The other conditions that have been supplied are as follows: • the maximum load expected to be taken by the transformers is 1200 A.

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239

• the available phase settings for the relay are 1000 A, 1600 A, 2100 A and 3000 A. • the available neutral settings for the relay are 250 A, 400 A, 525 A and 750 A. • Equivalent fault currents seen by the back up protection (with safety margins) for faults on the 220 kV bus or on the tertiary of the transformer are as follows: Fault Location 220 kV Bus

Transformer Tertiary

Fault Level

Safety Margin

3Φ = 3648A (R,Y, B) Φ-Φ = 0A (R ) 3158A (Y) 3158A (B) Φ-g = 3657A (R) 595A (Y) 595A (B) 2467A (N) 3Φ = 3884A (R,Y, B) Φ-Φ = 1942A (R ) 3884A (Y) 1942A (B) Φ-g = Not Applicable

3648/2100 = 1.74 – 1.5 1.5 1.74 – – 4.7 1.85 – 1.85 –

From the data provided above, the following conclusions can be reached: • the setting of 2100A for the transformer 66 kV circuit breaker current check is too high to cater for this example of back fed transformer faults. (A safety margin of greater than 1.8 must be achieved. This condition is not met for the 220 kV faults). • to cater for the phase-to-phase faults on the transformer tertiary, a current check with three individual phase elements is required. • based on the maximum transformer load of 1200 A, the current check phase element can be set on 1600 A. By selecting a current check with three individual phase elements with settings of 1600 A, the required safety margins and the required performance would be achieved for the operating conditions considered.

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PART B

POWER SYTSEM COMMUNICATIONS

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CHAPTER

1 Introduction

1.1

INTERNATIONAL ELECTROTECHNICAL COMMITTEE (IEC) TECHNICAL COMMITTEE (TC) 57

The International Electrotechnical Committee (IEC) Technical Committee (TC) 57 was established in 1964 because of an urgent need to produce international standards in the field of communications between the equipment and systems for the electric power process, including telecontrol, teleprotection and all other telecommunications to control the electric power system. IEC did not only consider equipment aspects, but more and more system parameters. This scope was modified to prepare standards for power system control equipment and control systems, including supervisory control and data acquisition (SCADA), energy management system (EMS), distribution management system (DMS), distribution automation (DA), teleprotection and associated communications. The technical experts of twenty-two (22) participating countries have recognized that the increasing competition among electric utilities is due to the deregulation of energy markets. The integration of equipment and systems for controlling the electric power process into integrated system solutions is needed to support the utilities ‘core processes’. Equipment and systems have to be interoperable, and interfaces, protocols and data models must be compatible to reach this goal.

1.2

ELECTRIC POWER RESEARCH INSTITUTE (EPRI)

The Electric Power Research Institute (EPRI) was in existence since the 1970s to develop technologies for the benefit of electric utilities. It manages

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research and development projects with funds supplied by those utilities as group and other sources. Since the 1980s EPRI has recognized the potential benefits of a unified scheme of data communications for all operating purposes across the entire utility enterprise. They focussed on the ease of combining a broad range of devices and systems; and the resultant sharing of management and control information among all departments of the utility organization. EPRI commissioned the North American Utility Communication Architecture (UCA) project, which identified the requirements, the overall structure and the specific communications technologies and layers to implement the scheme. The UCA initiative works under similar charter and recommends for implementation of interfaces, protocols and data models. It is expected that upon completion, the IEC TC 57 will adopt these recommendations and make them a subset of the IEC 61850 standard. The key to standardization is interoperability between vendors and systems. Of particular interest to all are on-going discussions of functional interoperability, hardware and software interfaces, protocols, data models and interchangeability.

1.3

INNOVATIVE INTEGRATION DEVELOPMENTS (IEDs)

Innovative integration developments (IEDs) within multifunction microprocessor based relays and other electronic devices have created new ways of collecting and reacting to data and using these data to create useful information. Power providers are facing demands to increase productivity and make electric power safer, more reliable and more economical. This can be done when electric manufactures provide innovative, simple to use, robust technologies to protect, automate, control, monitor and analyse power systems. An essential element of this strategy is the development of important communications technologies and protocols. When integrated together, relays and IEDs become a powerful, economical and streamlined Instrumental and Control (I&C) systems, capable of supporting all aspects of electric power protection, automation, control, monitoring and analysis. Communications processors, RTUs and PLCs are used as integration and automation controllers all over the world. The number of Utility Communication Architecture (UCA) based IEDs for protection and control available on the market is continuously growing and they are starting to appear in installations around the world. There are some significant differences between UCA based IEDs and conventional microprocessor based protective relays. This requires good understanding of the fundamentals of communications based substation protection devices and at the same time the availability of proper

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245

configuration tools that will make it easy for the user to adopt the relay for its application in the substation. This is especially important for peer-topeer communications based protection and control functions. The material is organized in seven chapters. After Introduction of the International Electrotechnical Committee and its objectives, the initiatives taken by the Electric Power Research Institute are identified followed by development of Intelligent Electronic Devices and the development of Multifunction Microprocessor based relays. A separate chapter is dedicated to communication principles where various terminologies and architectures are identified. Numerous terminologies are described so that the student or power network operator can have an Engineering book that is easily understandable and which can be referred to easily. Various architectures are considered that may very well be appropriate for different scenarios. A separate chapter is included on Protocols. In this chapter issues such as how communications processors communicate to each other within the entire power network are identified in detail. The application part of this book covers design and implementation of Universal Middleware to support real-time communication services over substation communication networks. Intended to link various power networks via LAN & WAN communication and information embedded power networks, this book is authored from both university and power network operator’s perspective. This book is aimed at the audience of application, design and Research & Development Engineers in Power System Communications as well as university graduate and continuous education students.

CHAPTER

2 Communication Principle

2.1

TERMINOLOGIES

2.1.1 System Automation and System Integration System automation is the control of power system apparatus operations to take the place of the human functions of observation, decision and action. Substation automation refers to using Intelligent Electronic Device (IED) data within the substation and control commands from remote users to control the power system devices within the substation. System integration is the act of communicating data to and from or between IEDs in the Instrumentation and Control (I & C) system and remote users. Substation integration refers to combining data from the IEDs that are local to a substation so there is a single point of contact in the substation for all the I & C data. This single point of contact then mediates remote and local substation control. Since true substation automation relies on substation integration, the terms are often used interchangeably. There is often a need for multiple single points of contact to serve multiple user connections or provide redundancy. The single point of contact is an I&C device acting as a client/server, programmable logic platform, gateway, router, dial-out device, communication switch, time synchronization broadcaster, or a combination of these.

2.1.2 Substation Controller Products from many industries are used to perform substation automation. RTUs, port switches, meters, bay modules, and protocol gateways from the Supervisory Control and Data Acquisition (SCADA) industry; PLCs from the process control industry, relays and communication processors from the protection industry, and PCs from the office environment.

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247

Substation controller and bay controller are the terms commonly used to refer devices that perform data acquisition and control of IEDs and contain local Input/Output (I/O). The communications processor is the only substation controller that can perform all the substation automation tasks. The communications processor is also the only device that is designed to meet the harsh environmental conditions as the relays themselves. SCADA and process control industry products are not designed to meet these environmental standards.

2.1.3 Client/Server for Dynamic Data The communications industry uses the term client/server for a device that acts as a master or client, retrieving data from some devices and then acts as a slave, or server, sending this data to other devices. The client/server for dynamic data collects and forwards data frequently based on master poll rate or by exception. These data include protection data, metering data, automation data, control data and supervisory data.

2.1.4 Client/Server for Archived Data A substation archive client/server collects and archives historical data from several devices. These data include system profiles, event reports, Sequential Events Recorder (SER) reports, power quality reports and protection quality reports; they provide a clear picture of system performance. The user retrieves data when it is convenient to do so.

2.1.5 Data Concentrator A data concentrator creates a substation database by collecting and concentrating dynamic data from several devices. In this fashion, essential subsets of data from many IEDs are forwarded to a master through one data transfer. The data concentrator database passes data from one IED to another when they are not connected peer-to-peer.

2.1.6 Message Broker A message broker collects and stores entire messages from several sources. Rather than extract and concentrate only a subset of the data, the message broker collects the entire message including header, content and error check terminator. The message broker then acts as an agent for the message by negotiating where and when to send the message. In this fashion, an entire message can be exchanged between two devices that cannot be directly or transparently connected.

2.1.7 Programmable Logic Platform A programmable logic platform executes custom automation logic equations. RTUs and PLCs have little or no default automation capability.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Therefore, RTUs and PLCs support flexible programmability so the end user can create necessary automation from the ground up.

2.1.8 Protocol Gateway A gateway converts conversations from one protocol or communication language to another. Often RTUs or PLCs are used for the sole purpose of acting as a gateway between substation data and a legacy SCADA or energy management system (EMS) protocol.

2.1.9 Hubs A hub is a relative simple multi-port device that rebroadcasts all data that it receives on each port to all remaining ports. It operates at the physical layer of the Open System Interconnection (OSI) network model (Fig. 2.1), so it does not use any of the data to remaining routing actions. The International Standards Organisation (ISO) created the OSI [1-3]. Application Presentation Session Transport Network Data link Physical

FIGURE 2.1 ISO OSI model

Layer Levels • Application—Provides a set of interfaces for applications to use to gain access to networked services. • Presentation—Converts application data into a generic format for network transmission and vice versa. • Session—Enables two parties to hold ongoing communications, called sessions, across a network. • Transport—Manages the transmission of data across a network. • Network—Handles addressing message for delivery, as well as translates logical network addresses and names into their physical counterparts. • Data Link—Handles special data frames between the network layer and the physical layer.

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249

• Physical—Converts bits into signals for outgoing messages and converts signals into bits for incoming messages.

2.1.10 Switches A switch is an intelligent multiplexing device that monitors the data link layer of the OSI network model (Fig. 2.1). If a data packet is incomplete or indecipherable, the switch ignores it and does not broadcast it. If a data packet is intact, the switch rebroadcasts it to another port, based on the addressing data included in the packet and the addresses associated with each port of the switch. New switches can operate on the Network (Layer 3) or Transport (Layer 4) packet information.

2.1.11 Router A router is an intelligent device used to connect two networks together. It can be a complex model, with many features. It operates at the Network layer of the OSI network model (Fig. 2.1). In another term, as used in the communications industry it refers to a device that routes data in transit between source and destination. The router intelligently transmits messages received on one communications port to another communications port. The destination port for the message is dynamically determined via the content of the message. This is used to efficiently route SER and other messages through multiple substation controllers without affecting substation automation.

2.1.12 Servers A server collects data from all of the local devices and creates a substation database. Often a local human machine interface graphics package uses data from this database. Servers function at the Application layer of the OSI model (Fig. 2.1).

2.1.13 Dial-out A dial-out device initiates conversations or triggers paging from the substation to a remote user. Use for dial-out include ensuring connection security, eliminating the need for a dedicated communications connection, and performing unsolicited indication of a disturbance with fault location.

2.1.14 Communications Switch A communications switch is the single point of contact for remote users to dial in and make a direct connection to all substations IEDs individually. A single communications connection form inside or outside the substation is switched between several IEDs. The user initiates a dynamic conversation with specific IED and the port switch merely ‘passes through’ the conversation.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

2.1.15 Time Synchronization Broadcast In order to synchronize IED clocks, a device in the substation needs to generate, or acquire from an external source, a time value and then broadcast it to the IEDs. Millisecond accuracy and repetitive synchronization are necessary.

2.1.16 Local I/O Substation controllers often make use of the I/O within connected IEDs. They also support local I/O terminated at the substation controller for automation and alarm functions.

2.1.17 Eavesdrop Communications Eavesdrop communications refers to monitoring a conversation between two devices in the I & C system, for capturing and storing the transferred data. This is useful for extracting the information without influencing the flow of data between devices that may not be available.

2.1.18 Emulate Protocol Messaging with Settings When choosing the best new and in-service devices a successful I & C system, it is often necessary to select from multiple vendors and also multiple vintages or generations of products. Many of these devices employ proprietary communications and interfaces. Most substation controllers must have embedded software written specifically to communicate via proprietary interfaces.

2.1.19 Autoconfiguration Some substation controllers simplify implementation through autoconfiguration. This process automatically determines the proper baud rate to communicate with the connected IED as well as start-up parameters, device type and capabilities.

2.1.20 Device-Level SER A device-level SER application creates and stores event data with a time stamp. Predefined input contacts and logic elements are monitored as the source of event records. The SER associates a time of occurrence with each event and stores these data in a buffer. It forwards these data in the order of event occurrence in an unsolicited fashion and/or in response to a request.

2.1.21 Station-Level SER A station-level SER application creates and stores event data with a time stamp for local inputs. It also collects and stores SER messages from other IEDs in the station in an unsolicited fashion and/or in response to a request. The local SER messages and the SER messages from the other IEDs are

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251

stored in a buffer and organised in order of occurrence. The station SER are also forwarded in order of event occurrence in an unsolicited fashion and/or in response to a request.

2.1.22 Tier-to-Tier/Peer-to-Peer Some substation controllers accommodate substations of varying size as well as redundant designs by supporting peer-to-peer and tier-to-tier functionality. Peer-to-peer refers to the direct transfer of data between devices functioning in a similar capacity. Tier-to-tier refers to devices that can transfer data while connected in such a way that one is the client and the other the server.

2.1.23 Substation Hardened The inverse of the failure rate of a device, or mean time between failure (MTBF) compares reliability of devices. Most devices that were traditionally used for automation in the past, such as RTUs and PLCs were designed to be operated in controlled environments like control rooms and generation facilities. The average MTBF or RTUs and PLCs is 11 and 17 years respectively. This low MTBF reflects a design philosophy based on frequent replacement and maintenance. Protection devices are designed to be more reliable, fail less frequently, be in service longer, and cost less to maintain than PLCs and RTUs. The device MTBF can be used to predict how available an automation system will be and how frequently the maintenance staff will be replacing failed devices [1-2].

2.2 ARCHITECTURES 2.2.1 Types of Connections Direct connect and multidrop are two types of data link connections available to create networks. In a direct connection, there are only two devices connected via network media, which can be metallic, wireless or fiber. Each interface consists of a separate transmit and receive connection at each device. Since there are only two devices, each of them can constantly control the connection on which they are transmitting and both can know implicitly to which other device they are connected. Several individual direct connections to many IEDs would allow each of them to communicate simultaneously. Many direct connections originating from one device is called a star network topology (Fig. 2.2).

252

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Network controller

Relays/IEDs

FIGURE 2.2 Star topology

Any protocol, including those designed for multidrop applications, can be used for direct connections in a star topology. Star network designs support a wide range of IED capabilities. Simple, slow communicating devices can coexist with more complex fast communicating relays. Devices from different manufacturers with different protocols can coexist in the same star network because each has a dedicated direct connection. Open architecture is a term that refers to networks that are interoperable between hardware and software interfaces and therefore among vendors. The star topology is the only design that is truly open architecture and will accommodate multiple protocols, baud rates and network interfaces. The most common communication architecture used today is the multidrop network. In a multidrop network topology, several devices can be physically connected in a bus or ring network and control of the transmit and receive connection must be negotiated. Figs. 2.3 and 2.4 illustrate relays connected in a bus and ring topology respectively. A multidrop connection requires only one device to communicate at a time. There are often additional components for terminations and network drop connections, which are vertically down to the individual relays or IEDs. Because all IED/relay share the cable, communications are usually controlled by the network master or a token passing scheme in which IEDs/relays have permission to communicate when they receive the virtual token and then pass the token on when they are done. Peer-to-peer messaging may or may not be available. Sequential polling of each IED/relay usually performs data retrieval by the master [3-4]. Network controller

Relays/IEDs

FIGURE 2.3 Bus topology

253

COMMUNICATION PRINCIPLE

Network controller

Relays

FIGURE 2.4 Ring topology

Software and hardware are used to determine which device has permission to transmit so that data does not collide on the conductor. Since several devices are connected, addressing is necessary within the protocol to identify the source and destination of the data being communicated. This addressing adds overhead in the form of processing time and amount of information that needs to be transmitted thus reducing the data transfer rate. Devices compensate this by increasing the speed at which they communicate and increasing the amount of communications processing that they perform. Troubleshooting communication problems on a multidrop network is difficult. Messages from many sources must be captured and deciphered. Direct connections are quickly and easily verified using simple LED indication. Relays have varying memory and computational capacities and, therefore varying protocol support capabilities. Interactions on a multidrop network must be done at the lowest common denominator and all devices must support the same baud rate and physical connection. It is important to note that if the mediation of control of data transmission should fail, none of the multidropped devices can communicate. This can be caused by relay communications hardware failing to release control, relay communications software failing to process mediation schemes correctly, or corruption of the network [2-4].

2.2.2 Long-term Trend of Networks The future trend is away from multidrop network and towards star network, e.g., Ethernet. Originally this was conceived as a multidrop network using expensive coaxial cable, however widespread use has shown that a star network is far superior. Today all Ethernet networks are built using hubs. A hub acts as a very short bus, which allows one to wire from the hub using inexpensive cable in a star configuration. With network traffic and use continuing to rise, smarter devices like switches are replacing hubs. A switch can store and forward information making the logical network a star also. Multiple nodes can transmit or

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

receive messages from the switch at the same time. Ethernet has now completed the transformation both electrically and logically in a star network architecture.

2.2.3 Peer-to-Peer Network Architecture Protection data, for the purpose of security, reliability and speed are highest priority and should be transferred via a single purpose conversation on a channel dedicated to this purpose along (Fig. 2.5). These functions perform optimally if this data can be transferred every device processing interval, between 1-12 ms.

Relays/IEDs

FIGURE 2.5 Peer-to-Peer direct connection

2.2.4 Typical Integrated Digital Protection and Control System A simplified diagram of a typical Integrated Substation Protection and Control System is shown on Fig. 2.6. It consists of a series of devices interconnected through an Ethernet network. Such a system has a hierarchical structure with distributed intelligence and different level of complexity. The hierarchy however is only functional, as well at the same time it can be flat from the communications point of view, i.e., all IEDs are connected to the same Ethernet network. For large substations with several voltage levels and multiple buses the number of hubs will increase and depending on the requirements for protection performance the hubs can be replaced by switches in order to limit the traffic on the different segments of the substation network. The primary functions of the IEDs is to protect different substation and power system elements viz. transformers, buses, capacitor banks, motors, lines etc. IEDs perform this basic function only under fault conditions, which is a event with very low probability. However, they need to have sufficient processing power and intelligence. Hence at lower hierarchical level it allows their use for data acquisition, control, monitoring and fault recording system. At the next level the Bay Controller IEDs provide additional digital and analogue interface with the substation environment and at the same time provide protection and control functions.

255

COMMUNICATION PRINCIPLE

At the top level the Substation Controller IED or the substation computer it provides integrated protection and control. It provides substation protection and control functions based on the exchanged highspeed peer-to-peer communications messages and over the substation LAN. It also provides the Human Machine Interface (HMI) functionality with the different IEDs in the substation. It supports alarm and event reporting, data archiving, analysis, monitoring etc., functions. In Fig. 2.6 the architecture uses the Ethernet network with the required Ethernet hub and a router connecting it to the utility Wide Area Network (WAN) [2-4]. Engineering station

SCADA master

RS232

Ethernet HUB Route

WAN

Terminal server

Terminal server Substation HMI

UCA gateway

RS485

Ethernet IED

Legacy IED RS485

RS485 Back 2

Ethernet IED RS485 Back 2

RS232 Front

Laptop computer

Data concentrator

FIGURE 2.6 Communication processor centric hybrid network

2.2.5 Hybrid Network Architecture Using the communication processor as the substation controller, a hybrid system, as shown in Fig. 2.7, can be created to perform control, monitoring, automation, protection, analysis, tests, maintenance and operation of the power system.

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Host and/or network connections

Noninstrusive eavesdrop data link

Communication processor Expert nodes

Metering master Met

Multidrop subnetwork Subsystem

Peer-to-Peer connections

FIGURE 2.7 Communication processor centric hybrid network

2.2.6 LAN Design Consideration A station LAN with all IEDs on one segment and a multiple segment process LAN design is shown in Fig. 2.8. A merged station and process LAN is shown in Fig. 2.9. The example LAN designs in Figs. 2.8 and 2.9 are two of many different ways to configure the network. Other design methods improve reliability, speed and maintainability. Optimising reliability and speed create conflicting substation LAN designs. Speed is important for sophisticated distributed protection, synchro-check and time synchronisation of IED clocks. Peer-to-peer speed is fastest when all IEDs are connected on a single LAN segment but communication functions are more reliable when systems are redundant and without a single point of failure. The peer-to-peer communications are based on what is defined as a GOOSE i.e., Generic Object Oriented Substation Event and it is based on a multicast asynchronous reporting of an IEDs digital outputs status to other peer devices enrolled to receive the configuration of the substation integration process (Fig. 2.10). It is important to note that if the mediation of data transmission control fails, none of the devices on a LAN segment could communicate. This can be caused by the IED communications interface failing in such a way as to corrupt the network.

257

COMMUNICATION PRINCIPLE Distributed controller

HMI Ethernet switch

Primary protection

Back up protection

Primary protection

Back up protection

Feeder 1

Feeder 1

Feeder 2

Feeder 2

Ethernet switch

Process LAN

Ethernet switch

Disconnect switch

Circuit breaker

Merging unit

Disconnect switch

Circuit breaker

Merging unit

Feeder 1

Feeder 1

Feeder 1

Feeder 2

Feeder 2

Feeder 2

FIGURE 2.8 Station LAN and multiple segment process LAN design Station LAN

Distributed controller

HMI Ethernet switch

Primary protection

Back up protection

Primary protection

Back up protection

Feeder 1

Feeder 1

Feeder 2

Feeder 2

Process LAN

Ethernet switch

Ethernet switch

Disconnect switch

Circuit breaker

Merging unit

Disconnect switch

Circuit breaker

Merging unit

Feeder 1

Feeder 1

Feeder 1

Feeder 2

Feeder 2

Feeder 2

FIGURE 2.9 Merged station and process LAN design

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

Ethernet HUB

IED

Sending IED

Receiving IED GOOSE Receiving IED

IED

FIGURE 2.10 Sending and receiving IED on an ethernet LAN

The designer has to ultimately balance the needs to create isolated LAN segments for security, redundant systems for reliability, and monolithic and single segment LANs for high speed. The value of each need will be compared against the cost in dollars and additional processor burden within devices.

2.2.7 External Substation Connections The IT products in the substation facilitate easy connection to other corporate systems through WAN or Internet connections. These connections possibilities highlight the importance of securing connections into the substation LAN. Fig. 2.11 shows a previous substation network with the addition of external connections [3-4]. Distributed controller

HMI

To Internet To WAN

Ethernet switch

Router Primary protection

Back up protection

Primary protection

Back up protection

Feeder 1

Feeder 1

Feeder 2

Feeder 2

Ethernet switch

Ethernet switch

Disconnect switch

Circuit breaker

Merging unit

Disconnect switch

Circuit breaker

Merging unit

Feeder 1

Feeder 1

Feeder 1

Feeder 2

Feeder 2

Feeder 2

FIGURE 2.11 External connections to substation communication network

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259

A three-pronged third-party interface development approach can be: • connect relays as an RTU, PLC or HMI slave, by sharing interleave protocol specifications with SCADA vendors and system integrators, and through the communications processor. • connect directly to substation networks as a Modbus slave in the Communications Processors or as a Modbus Plus® slave in the Communications Processors. • for the long-term, use a local high-speed network in the substation and this will be the method of choice for the third-party interconnection such as an application protocol running on ethernet [1-4].

CHAPTER

3 Protocols

A modern power system is one of the largest complexes constructed and operated both in terms of geographical distances as well as generated and transmitted power. Such a system needs precise and high quality control with protection functions as primary due to the top priority safety reasons. Traditionally protective relays have been electro mechanical devices whose purpose was only to protect electrical power systems against system failures. Application of microprocessors to power system relaying has increased the functionality of protective relays and brought new concepts, which considers control, protection and monitoring functions integrated together. In the past decade, new communications schemes have been designed and retrofitted into the substations by the utilities to integrate data from relays and Intelligent Electronic Devices (IEDs) and capitalize on the protection, control, metering, fault recording, communication functions available in digital devices. This chapter describes substation communications and the ongoing communication standardization efforts discussing the IEC 61850 and the Utility Communications Architecture (UCA) standards.

3.1

INTRODUCTION TO POWER SYSTEM COMMUNICATION

Many of today’s electric utility substations include digital relays and other Intelligent Electronic Devices (IEDs) that record and store a variety of data about their control interface, internal operation and performance, and about the power system they monitor, control and protect. Nowadays, digital relays are widely replacing the aging electromechanical and solid-state

261

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electronic component—type relays and relay systems. Fig. (3.1) shows a digital relay with its target interfaces. Digital relay’s popularity comes from their price, reliability, functionality and flexibility. However, the most important feature that separates the digital relay from previous devices is its capability of collecting and reacting to data and then using this data to create information. Such information includes: [5, 6] • Fault location and fault type • Prefault, fault and post-fault currents and voltages • Relay internal element status • Relay control input and output status • Instantaneous and demand metering • Breaker operation data • Relay operation data • Diagnostic and historical data. CT

VT

Digital rela y

FIGURE 3.1 Digital relay with target interface

Instrumentation and Control devices, which are built using microprocessors, are commonly referred to as Intelligent Electronic Devices (IEDs). Microprocessors are single chip computers that can process data, accept commands, and communicate information like a computer. IEDs can also run automatic processes, and communications are handled through a serial port like the communications ports on a computer. Some examples [8] of IEDs used in a power system are: • Instrument transformers • Transducers • Remote terminal unit (RTU) • Communications port switch • Meter

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POWER SYSTEM PROTECTION AND COMMUNICATIONS

• Digital fault recorder • Protocol gateway.

3.1.1 Power System Communications Initiatives Communication systems have been used for decades to enhance the performance of power systems. Without the use of a proper communication channel, power system protection suffers from a major disadvantage of not being able to accurately discriminate faults [27]. When voltages and currents are analysed only from one terminal, it cannot be concluded whether a fault near the far end terminal is internal or external to the protected line segment. This requires delayed tripping for such faults, which can endanger system stability or increase damage. At the far end terminal, the decision whether the fault is internal or external is obvious, not from a distance measurement but from knowledge of the direction of the fault. This information can be transmitted to the other terminal with the use of a proper communication channel enabling it to decide whether to trip or not to trip [9, 10, 11, 36]. Power providers are focussed on increasing productivity and making electric power safer, more reliable and more economical by providing innovative, simple to use, robust technologies for power system protection, automation, control and monitoring. Development of appropriate communications technologies and protocols is at the heart of this strategy. When relays and IEDs are integrated together, they form a powerful, economical Instrumentation and Control (I&C) system to support all aspects of electric power protection, automation, control, monitoring and analysis [8]. Figure 3.2 shows how IEDs and relays can be interconnected together to form protection schemes for power systems. Such a system also supports the substation in terms of the monitoring, analysis and automation aspects. The relaying and measurement tasks have been well understood and standardized. On the other hand, the technical methods and operating impact of data communications continue to evolve dramatically. There is a wide variety of incompatible communications approaches and systems in the marketplace. Competing manufacturers have been following unique approaches when designing the communications interface circuits. Other IED makers designed networks, which make it possible to connect a number of devices in one substation to a single local host that could dynamically address requests for data to any unit. However, the user could not directly interconnect competing products since the protocol remained unique for each system. Whilst the use of products from competing vendors offers

263

PROTOCOLS

SCADA master

Engineering station RS232

Ethernet HUB

UCA gateway

RS485

WAN

Ethernet IED RS485 Back 2

Terminal server Terminal server

Substation HMI

RS485 Legacy IED

Router

Ethernet RS232 Front RS485 Back 2

IED

Laptop computer

Data concentrator

FIGURE 3.2 Typical integrated substation protection and control system [28]

users a variety of protection and monitoring capabilities [12, 13], the variations in the communications system, and the need for a different system for each vendor, has often frustrated users. Nowadays, the desire and the need to merge the communications capabilities of all the relays and IEDs in a substation into a standard that is capable of providing data gathering and setting capability as well as remote control, is clearly recognized. Furthermore, multiple IEDs can share data or control commands at high speed to perform new distributed protection and control functions [14]. In addition to standardization efforts within the substations, the development of several powerline communication protocols such as CEBus has also renewed the interest in powerline communications, which has existed for use in the home as a networking medium for many years now [37, 38]. The emergence of new devices with the recent technological developments have enabled utilities to utilize the powerline to send and receive control signals with some degree of reliability offering broadband services. Powerline Communication (PLC) is the transmission of data along the utility powerline network, which eliminates the need to rewire houses and buildings with separate communication links. Although other options such as satellite communications exist, the high cost and the unavailability of these technologies in rural and suburban areas have also increased the importance of powerline communications. The main advantage of powerline communications is the fact that the physical network is already installed over a wide area [38].

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As mentioned earlier, some forms of PLC have been in use for quite long time now. However, a new perspective has been formed in the recent years with the proliferation of companies developing low-cost chipsets, which enable new high-speed short-distance applications. In addition, companies have high hopes for developing ways of communicating Broadband Internet connections over long distances using the utility powerline network. There are many existing and evolving high-speed PLC technologies with further research work proceeding aggressively. However, the fact that powerlines are inherently limited to transmission at the highest 400 Hz brings some concerns [37]. In addition, the high electronically contaminated structure of the powerline and the high signal attenuation at the frequencies of interest makes it challenging to achieve dependable results. Hence, there is still a long way to go!

3.2

PROTOCOLS IN GENERAL

A protocol is basically a set of rules that must be obeyed for orderly communication between two or more communicating parties. Communication between data processing systems from different manufacturers has often been particularly difficult due to the fact that there has been separate development of data processing and data communications techniques, often resulting in complex and expensive interfaces. With the International Standards Organization (ISO) model, which is commonly known as the Open Systems Interconnection (OSI), the communications process has been divided into seven basic layers as shown in Fig. 3.3. These layers define how data flows from one end of a communications network to another end and vice versa. Two devices can only communicate if each layer in the model at the sending device matches with each layer in the model at the receiving device [15, 16, 17]. Application layer Presentation layer Session layer

Application layer Information processing functions

Transport layer Network layer Data Link layer Physical layer

Presentation layer Session layer Transport layer

Communication functions

Network layer Data Link layer Physical layer

THE PHYSICAL MEDIA OF THE OSI

FIGURE 3.3 The OSI reference model

PROTOCOLS

265

The user can quite often make choices in any given layer. The ensemble of choices made to implement a protocol is termed a profile. The rules designed by a protocol profile are designed to organize operating issues in the following areas: • Framing • Error control • Sequence control • Transparency • Line control • Time-out control • Start-up control. There are literally thousands of combinations of protocol agreements that can be created with the large domain of existing pieces. The main protocols that have found widespread use in the substation environments are [18, 10]: • MODBUS: A popular master-slave protocol with industrial users, which has also become popular in substations. It issues simple READ/WRITE commands to addresses inside an IED. • Distributed Network Protocol (DNP): An increasingly popular master-slave protocol mainly in North America. DNP can run over multiple media, such as RS-232 and RS-485 and can issue multiple types of READ/WRITE messages to an IED. • IEC-870-5-101: It is considered as the European partner to DNP. It differentiates itself from DNP with its slightly different messaging structure and the ability to access object information from the IED. • UCA: It is the Utility Communications Architecture designed to satisfy every possible requirement in substation equipment.

3.3

EXPAND ON DNP

DNP (Disturbed Network Protocol)-1 and DNP-2 which can be used to construct parallel structures for simulating large Scale Neural (NN) models [39].

3.3.1 Introduction to DNP The DNP-1 was implemented in 1991, and the DNP-2 was implemented by the VLSI chip of single-chip multiprocessor having four DNPs. The DNP-2 has the performance 50 MCPS (Million Connections Per Second) at 50 MHz and the microprocessor (E-MIND/2) having 2D mesh structure of 1024 DNP-2’s accomplishes maximum 40 GCPS (Giga Connections Per Second) [39].

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3.3.2 The Structure of DNP A processing element, the DNP-l is a 8-bit microprocessor devised with instructions and data paths for efficient neural computation: a weighted sum, a non-linear function etc. The DNP-1 consists of three block units: an arithmetic unit, a control unit and a communication unit [39]. The DNP-2 is a 16 bit microprocessor and its architecture is similar to DNP-1 exclusive of parallel arithmetic constructs and two pipeline functions. The DNP-2 also consists of three units: An arithmetic unit, a control unit and a communication unit [39].

3.3.3 Size/Speed Comparison of DNP It is necessary to compare performance of the DNP-1 with the DNP-2. Table 3.1 clearly indicates how one can obtain the results that the function (an arithmetic pipeline of an arithmetic unit and an instruction pipeline of a control unit) and the parallel constructs of DNP-2 are cost efficient for neural network emulation [39]. Table 3.1: Cost/Performance comparisons using AT of two processors (AU: Arithmetic Unit; CU: Control Unit) Data Model

DNP-l

DNP-2

AU (l6 bits)

CU (l6 bits)

Processor (l6 bits)

AU

CU

Processor

Number of gate

491(950)

456(456)

94(1306)

6646

1682

8328

Number of SC

9(17)

4(4)

13(21)

1

1

1

AT

4419 (16150)

1824 (1824)

12311 (27426)

6646

1682

8329

3.3.4 Implementation and Performance We make the DNP-2 as a processing element of large scale parallel neurocomputer, and fabricate four DNP-2’s into one chip to increase the density of system integration. The DNP-2 is implemented in 0.8 µm CMOS process, with a target of 50 MHz clock rate. This chip features 299 pins and a power dissipation of 2 watts at 50 MHz. The silicon size measures 11.5 × 11.5 mm2 and integrates 60,000 gates excluding on chip memory of DNP-2. The DNP has a peak performance of around 50 MCPS [MCPS].

PROTOCOLS

3.4

267

STANDARDISATION DEVELOPMENTS

Study committee B5 (previously 34) of CIGRE comprises of advisory groups, working groups and task forces covering Power System Protection and Automation in terms of the principles, design, applications, coordination, performance and asset management of: 1. system protection, 2. substation control and automation, 3. remote control systems and equipment, and 4. metering systems and equipment. The working group 07 of the study commitee B5 is the one mainly concerned with substation control and automation reporting on aspects such as: • substation control and automation, • possible architecture of automated systems, and • state of art in communication standards and applications. The WG 07 reports that the power system industry is in a fast competition to have an optimal management of the power system network in all system levels. With the privatisation of the power system industry, a new electricity market has been formed differing in all aspects from the traditional old market. Therefore automating the existing substations is very important for the utilities, who want to meet the existing challenges of the future market and reliability of the existing equipment [19, 20]. Nowadays, most of the substation automation systems have similar architectures usually including a central computer connected to decentralized computers and protection relays, and also synchronization and communication components. A few major alternatives to the architecture that is usually a central computer and the database is distributed. Protection and control can be combined in a single IED or protection in a physical device separate from control. The WG 07 reports that recent developments in technology have brought new concepts requiring IEDs to function on a much broader level, such as measurement devices or control devices. It also requires IEDs to communicate with each other using a common software environment involving standardized protocols and standardized object models for each IED. The UCA 2.0 was the first attempt to meet such requirements. The WG 07 report states that the IEC 61850 project has evolved further incorporating the UCA 2.0 works and extending it towards the process level[21, 22]. The harmonisation of data models between UCA 2.0 and the IEC 61850 will eventually be an important step towards a worldwide-

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accepted standard [19, 20]. IEC 61850 is a super subset of UCA 2.0 while offering some additional features. IEC 61850 was published as standard around the year 2003[23]. The following sections will detail the work done by the IEC and EPRI groups towards standardization.

3.4.1 The UCA Substation Communication Project The introduction of higher-level protocols in IEDs has only enabled communications between like devices or in other words communications between devices from the same manufacturer. In order to communicate a variety of devices from different vendors, which enables the utilities with a variety of protection, monitoring and automation capabilities, there is a need to use protocol converters or gateways. Furthermore, the IED protocols are also limited in capability including speed, functionality and services making engineering harder, and increasing operation and maintenance costs. Worldwide, electric utility deregulation is expanding and creating demands to integrate, consolidate and disseminate real-time information quickly and accurately within and with substations [25]. The Electric Power Research Institute (EPRI) has existed since 1970s to develop technologies for the benefit of electric utilities. It manages research and development projects with funds supplied by those utilities as a group and other sources. The Utility Communications Architecture (UCA) was commissioned by the EPRI, which identified the requirements, the overall structure, and the specific communications technologies and layers to implement the standardization scheme. UCA aims to dramatically improve device data integration into the information and automation technology in order to reduce the engineering, monitoring, operation and maintenance costs increasing the agility of the whole life cycle of a substation [14, 26]. Many relay and IED manufacturing companies and progressive utilities showed their interest in UCA work and joined in the effort to define and demonstrate a communications network stack. The approach adopted defines the technical requirements for a system to control and monitor substations of any size. With the use of the substation Local Area Network (LAN), the mass of the dedicated wiring among the IEDs and power apparatus is ultimately reduced or replaced. With continued EPRI support, a long list of relay, meter, and IED vendors have built UCA-compliant versions of products. The elaborate specification for a communications protocol, which handles all the data

269

PROTOCOLS

collection and high-speed control functions, has been evolving quite rapidly. The equipment makers continue to modify and update the implementations in each of the products. Many US and overseas utilities have signed up to demonstrate UCA substation systems. The users can see an impressive and elaborate demonstration of interoperability among a broad variety of equipment from competing manufacturers in meetings held several times a year by the UCA Substation Initiative Project. The importance of achieving interoperable communications has forced collegial cooperation among competitors, who see the individual-product features and performance as the proper ground for competition [12, 19]. The layers of the seven-layer stack are logically separated to ease troubleshooting and to allow levels to be replaced without affecting neighbouring levels. The more sophisticated Application Layer provides the services necessary to perform data acquisition and control in the substation and also allows data sharing. This layer is expensive to develop and needs to be maintained longer than the quickly changing Physical Layer. The Physical Layer describes the signal transmission media independent of the communications protocols. The middle five OSI layers are often referred to as the Protocol Stack. The Protocol Stack describes a combination of protocols that work together to achieve network communications. Three common stack combinations are the OSI protocol stack, the combination of the Transmission Control Protocol (TCP) and Internet Protocol (IP), and the combination of the User Datagram Protocol (UDP) and IP. The relationship of these protocol stacks within the Application and Physical Layers is shown in Fig. (3.4) [26]. Possibilities: · IEC 870-5 · DNP · Profibus · Other

Application layer

Protocol stacks

FTP

Telnet

MMS

UDP

TCP

Other

OSI

IP Physical layer

Physical connection

FIGURE 3.4 Parallel protocol stacks [8,20]

270

POWER SYSTEM PROTECTION AND COMMUNICATIONS

UCA’s main difference from the previously designed and used protocols is its use of object models of devices and device components. The common data formats; identifiers and controls for substation and feeder devices can be defined with the use of object models of devices and device components. The models specify standardised behaviour for the most common device functions, and allow for significant vendor specialisation for future innovation [19, 26]. The three levels of UCA are shown in Fig. 3.5. Device Data objects

Service interface

Communication profiles Data

How to describe data/devices How to access?

Communication channels

Data Data on the wire

FIGURE 3.5 The three levels of UCA [22]

As shown in Fig. 3.5, the UCA comprises the data object models (forming the highest level), the service interfaces to these models (defining, retrieving, reporting and logging of process data, controlling devices, file transfer) and the communication profiles. The direct data acquisition and control of field devices is an area, which has been undergoing significant transition. Traditionally, the end field devices were directly connected to Remote Terminal Units (RTUs), which provided a network interface and performed initial processing of the acquired data. The introduction of the microprocessor technology has allowed for the direct network access to the devices as well as more processing being performed at the end device by leading to the development of Intelligent Electronic Devices (IEDs). The cost of integrating the end devices has been increasing rapidly since the end devices (IEDs) became more and more complex in time due to the advancements in the technology. Within the UCA framework, the device object model is referred to the definition of the data and control functions made available by the device, along with the associated algorithms and capabilities [19, 26, 27]. Number of efforts has been initiated to develop detailed object models of common field devices, including definitions of their associated

PROTOCOLS

271

algorithms and communications behaviour visible through the communication system. Modelling efforts within the customer interface area are also in progress. These efforts include metering and interfaces to residential and commercial customer devices. There has been active industry participation in the customer interface modelling efforts. Significant work has been accomplished as part of several UCA pilot projects and preliminary results are available in draft form. The device models developed within the UCA 2.0 effort describe the communications behaviour of the devices by making use of a common set of services. The detailed interoperable structure for utility field devices can be fully specified by mapping these services onto the UCA Application Layer Protocol (ALP) when used in conjunction with the device models. The services and mapping to MMS are defined in UCA Common Application Service Models (CASM). An added benefit is that CASM simplifies the integration efforts across functional areas of the utility. Moreover, device models can be specified independent of the underlying protocol. Active participation of groups outside the UCA activities has been encouraged due to this feature of protocol independence, which also simplifies migration through the construction of gateways to older existing protocols [19, 26, 27]. Vendors of utility field devices begin with their existing Vendor Product Specification, which defines the functionality that the device performs as shown in Fig. 3.6. The appropriate model of the field device can be chosen from the various UCA Utility Standard Device Models, such as Generic Object Models for Substation and Feeder Equipment (GOMSFE). The vendor arrives at a product model by selecting from the optional model components, adding their specialization to their existing product specification. The product model defines the communications behaviour of the vendor products in terms of the common application service models. The mechanisms for representing the application services in the underlying UCA application layer protocol is described by the UCA Common Application Service Models (CASM) document. Next step is to produce an application layer, which completely specifies the application layer communications software required to support the product as a UCA compliant device, by the specific mapping of objects and services into the application layer protocol. Finally, the user selects the appropriate UCA profiles to be supported from the UCA Profile Specification, Version 2.0 and determines the lower protocol layers by taking the expected operating evironment of the device into consideration. The selected profiles, combined with the Application Definition, forms the final Product Design. The Fig. 3.6

272

POWER SYSTEM PROTECTION AND COMMUNICATIONS

illustrates how the UCA Version 2.0 is implemented for field [27]. A device is conformant to the UCA specifications only if it incorporates the following three distinct specifications: • The appropriate UCA object mode • One or more UCA profiles • The appropriate mapping of the Common Application Serivces used in the Object Model to the application layer protocol. UCA documents Vendor documents Vendor product information, user requirements

TASE.2 Services supported

Specific TASE.2 data objects

Software implementation

Vendor product specification

TASE.2 Service interface

Application definition

Selection of TASE.2 building blocks

Specific mapping of objects

Selection of profiles

IEC 870-6-503: TASE.2 services and protocol

Standardized services, mapping to application layer

IEC 870-802: TASE.2 object models

Specific object types to be supported

UCA version 2.0 profile specification

UCA Version 2.0

Product design

FIGURE 3.6 Definition of UCA field devices [23]

The number of UCA based IEDs for protection and control available on the market is continuously growing and they are starting to appear in installations around the world. However, the significant amount of conventional microprocessor based protective relays installed earlier in the substations need to be considered. There are some significant differences between the UCA based IEDs and conventional microprocessor based protective relays. This requires good understanding of the fundamentals of communications based substation protection devices and at the same time the availability of proper configuration tools that will make it easy for the user to adapt the relay for its application in the substation [28].

3.4.2 lEC 61850 Project IEC 61850 is based on the need and the opportunity for developing standard communication protocols [30] to permit interoperability of IEDs from

273

PROTOCOLS

different manufacturers. Utilities also require IED interchangeability, which is the ability to replace a device supplied by one manufacturer with a device supplied by another manufacturer, without making changes to other elements in the system. IEC 61850 makes use of existing standards and commonly accepted communication principles, which allows for the free exchange of information between IEDs. It considers the operational requirements since any communication standard must consider the substation operations functions. However, the communication protocol standard IEC 61850 focuses on neither standardising the functions involved in substation operation nor their allocation within the substation automation systems which are used to define the impact of the operational functions on the communication protocol requirements. Substation automation systems normally incorporate functions, which can be assigned to three levels: the station level (level 20), the bay level (level 1) and the process level (level 0), for control, supervision, protection and monitoring of the high voltage equipment and the grid. The physical mapping of logical interfaces forms the communications between these levels as shown in Fig. 3.7 and forms the basis for the IEC 61850 standard series [25]. Remote control Station level

Technical services

FCT.A

FCT.B

Bay level

Bay unit

Prot.

Cont.

Remote protection

HV equipment

Prot.

Remote protection

Cont.

HV equipment

FIGURE 3.7 Logical interferences in a substation [31]

IEC 61850 identifies all the known functions in a substation automation system and splits them into sub-functions or so-called logical nodes. A logical node is a sub-function located in a physical node, which exchanges data [29] with other separate logical entities. In IEC 61850, all logical nodes have been grouped according to their most common application area, a short textual description of the functionality, a device function number if applicable and the relationship between logical nodes

274

POWER SYSTEM PROTECTION AND COMMUNICATIONS

and functions [25]. IEC 61850 decouples applications to design them independent from communication so they are able to communicate by use of different communication protocols. This is due to the fact that the vendors and utilities have maintained application functions that are optimised to meet specific requirements and that have reached a high degree of maturity and quality. Therefore, IEC 61850 provides a neutral interface between application objects and the related application services allowing a compatible exchange of data among components of a substation automation system. Fig. 3.8 shows the basic reference model [28]. One of the most important features of IEC 61850 is that it covers not only communication, but also qualitative properties of engineering tools, measures for quality management and configuration management. This is necessary since when the utilities are planning to build a substation automation system with the intention of combining IEDs from different vendors, they expect not only interoperability of functions and devices, but also a homogenous system handling. Application

Neutral interface

SCSM 1

AL 1

SCSM 2

AL 2

SCSM n

AL n

ACSI Abstract communication service interface

‘‘Specific communication service mapping’’ Specific interfaces Application layer 7 Layers 1.6

Communication stacks

FIGURE 3.8 The basic reference model [25]

Quality assurance for system life cycles is one of the important aspects covered by the IEC 61850, which defines the responsibilities of utilities and vendors [29, 31, 32]. Guidelines for environmental conditions and auxiliary services with recommendations of the relevance of specific requirements from other standards and specifications are also defined [25].

275

PROTOCOLS

Application view

Object dictionary of a device contains all accessible information

Data objects

Data objects

Data objects

Data objects

Objects According to 7-4 and 7-3

Communication view

Binding

Logical node obejct

Process

For a long time, one of the major problems faced by protection engineers to use IEDs to their full extent was the proprietary nature of the communication interfaces. It was quite impossible to connect multiple IEDs from multiple vendors without the use of special gateways and converters, which tend to limit the functionality of the overall system. The concept of logical nodes with a standardization of data contained within a logical node in so-called data objects allows interoperability between IEDs or in other words plug and play capability of IEDs in order to share information and commands on a single network. Fig. 3.9 illustrates the relationship between the process and the communication interface [25].

Services by which the information can be accessed or manipulated Communication objects and services according to 7-2 mapped to a SCSM

Network

FIGURE 3.9 Relation process and communication interface [25]

Applications can be defined using the standardized data without knowledge about the actual device. This is because with the use of standardized objects, the data contained in a device and the data available on the network for further use is know up front and the naming of data is independent of the actual device. As long as the logical nodes, data classes, data object and data elements are implemented as specified in the standard, we know up front where data will be present from a communication point of view. The plug and play becomes possible after we add the capability of self-description of logical nodes and therefore those of the devices. Manufacturers need to provide devices containing extensions of functions

276

POWER SYSTEM PROTECTION AND COMMUNICATIONS

that are not yet modelled in IEC 61850. With the rules contained in EIC 61850 on how to model extensions, the data contained in these specific extensions can be made available over the communication network in a predefined way assuring interoperability [25]. With the plug and play capabilities embedded in the standard and the immediate prove of concept in pilot projects, IEC 61850 promises to be a great step forward in the development and acceptance of substation automation systems world-wide. This will finally bring the real benefits of automation and integration to utilities that were originally promised years ago [25]. A non-proprietary, standard, high-speed protocol offering sufficient services was required to enable a robust, integrated substation communications network without protocol converters. The introduction of IEC 61850 and the Utility Communications Architecture has made it possible and justifiable to integrate station IEDs through standardization. Using the standardized high-speed communications between IEDs, the utility engineers can eliminate, many expensive stand-alone devices and use the sophisticated functionality and the available data to their full extend [25, 35].

3.4.3 DNP-3[153] DNP-3 (Distributed Network Protocol) is a set of communications protocols. It plays an important role in SCADA (Super Control and Data Acquisition) system, where it is used for communications between system components. The protocol was specifically developed for facilitating communication between data acquisition and control devices. DNP3 is an open, intelligent, robust, and efficient modern SCADA protocol. It can: • request and respond with multiple data types in single messages, • segment message into multiple frames to ensure excellent error detection and recovery, • include only changed data in response message, • assign priorities to data items and request data items periodically based on their priority. • respond without request (unsolicited), • support time synchronization and a standard time format, • allow multiple masters and peer-to-peer operations, and • allow user definable objects including file transfer. DNP-3 Provides Multiplexing, Data Fragmentation and More: • DNP-3 is a layer 2 protocol. This means that it provides for multiplexing, data fragmentation, error checking, link control, and

PROTOCOLS

277

prioritization. It also provides layer 2 addressing services for user data. • DNP-3 enables the various devices in process automation system to communicate. The DNP-3 protocol is widely used in the electrical and water industries by utility companies. It is also possible for DNP-3 to be utilize in other areas, through it is not as common. DNP-3 Protocol Facilitates SCADA Communications: • SCADA system use the DNP-3 protocol for communications between various system components. The DNP-3 protocol for communication between the SCADA system master, the system’s RTU’s (Remote Terminal Units), and IED’s (Intelligent Electronic Devices). • DNP-3 was developed to meet the need for a standard communications protocol that would allow for communication between SCADA system components developed by differing vendors. Using IEC 60870-5 as a base, DNP-3 was created as an open protocol for use in these situations. This protocol was available for immediate implementation within SCAD networks, and catered to the specifications laid out by North American organizations. DNP-3 Provides Communication Reliability for Utilities: • DNP-3 ensures the reliability of communications within the harsh environments of electrical and water utilities. The protocol is able to avoid being distorted by EMI, legacy system components, and poor transmission due to DNP-3’s specifically designed communications format. Although the protocol was created with reliability in mind, DNP-3 is not secured, an important consideration during SCADA planning. • One can protect important DNP-3 communications and SCADA system with a network alarm monitoring system. The most advanced alarm masters can monitor in the alarms in a single, convenient browser window. Sending one’s alarm notification via email or page, the alarm master will inform instantly if there is a problem with operation. 3.4.3.1 Typical Australian Practice (viz. SP Ausnet) of Connecting Between IEDs and RTU The most common connection is RS485 and RS422 (multi-drop) with protocol. Each IED has an unique DNP3 address. Master sends massage

278

POWER SYSTEM PROTECTION AND COMMUNICATIONS

with destination address. All IEDs on the bus receive the message but only the matching address IED responses. In SPAusNet, only a handful of analogue circuits is used for SCADA communication between RTU and Control Centre. SP AusNet Digital Network SDH/PDH (circuit switch) is used to provide all communications requirements for Protection, Controls and SCADA. It also builds a separate Ethernet GigaBit network (where possible) to provide corporate, engineering access to IEDs at Terminal and Zone substations. Future development will be Operational IP network to provide SCADA on IP.

CHAPTER

4 Middleware

4.1

INTRODUCTION

Power system utilities have to increase the efficiency and effectiveness of their communications and control systems to become faster, flexible and more productive. The best solution to achieve this is to make more efficient use of the information and telecommunication systems. The progressing deregulation of the sector has been possessing new demands to integrate, consolidate and disseminate real-time information quickly and accurately within all kinds of company systems. Therefore, there is a further need to utilise the data provided by the Substation Automation (SA) system to extend it by enhancing information processing and management on system level. Furthermore, coordination of the SA and network control levels is also crucial. Over the last years, there have been significant standardization efforts in order to prepare standards for power system control equipments and control systems. Interoperability between vendors and systems is the key for standardization. The new IEC standard IEC 61850 is expected to solve some of the problems. However, the existing standard remote control protocols are not well suited for transmitting between the substations and system control system. Hence, there is a need for improving the coordination of communication protocols at station level and for remote control, which will improve the vertical integration, and the cost benefit of SA. Heterogenous software systems, computing and communication components form the basis of future computing platforms, which are also

280

POWER SYSTEM PROTECTION AND COMMUNICATIONS

subject to dynamic changes in resource availability. Distributed applications such as the SA system applications have dynamic behaviours with respect to their computation and communication needs. There is a need to create software abstractions, tools and methods for building efficient componentbased applications for such feature platforms [40-43].

4.2

AUTOMATION SYSTEMS AND COMMUNICATION NEEDS

Nowadays, the majority of the automation systems developed by manufacturers have a similar architecture, except for a few differences. A central computer is usually connected to decentralised computers and protection relays as well as the synchronisation and communication components. A Local Area Network is used, for system operation, with a Human-Machine Interface (HMI) in order to control and monitor the system and the processes. Such architecture is shown in Fig. 4.1, which shows the architecture of substations in Europe. There are four different architecture alternatives that could be chosen. The first two architectures differentiate themselves from each other by means of a central computer. The former has a central computer where the latter has no central computer and the database is distributed. This section aims to investigate the specific points of the communication networks in automation system. Communication networks used in automation substation systems can be used for adapting automation systems to the SCADA protocol and HMI and storing data

Gateway OI

Substation network Lead Master Controller (optional) Substation bus Protection unit Bay controller

Bay 1

Electrical Process

Bay 2

Bay 3

FIGURE 4.1 Common substation architecture in Europe

281

MIDDLEWARE

to the various IED communication protocols. Nowadays, the communication network developments are mainly concerned with standards used and particularly the interoperability between automation systems and the equipments connected to them. Although some projects provide interoperability that is far more extensive than that concerning IEDs, it is commercially impossible for a central computer from a given manufacturer to cohabit with the decentralised modules of another.

4.2.1 Types of Architectures In general, the term ‘power system’ describes the collection of devices that make up the physical systems that generate, transmit and distribute power. The term ‘instrumentation and control (I & C) system’ refers to the collection of devices that monitors, controls, and protects the power system [40-44]. 4.2.1.1 Four Levels of the Instrumentation and Control System The I & C system is composed of four levels as shown in Fig. 4.2. They are: 1. Process bus: The lowest level of I & C devices considered as the process level, are physically connected to power system and are sensing their current status. These include Current Transformers (CTs) to sense current, Voltage Transformers (VTs) to sense voltage and Resistance Thermal Detectors (RTDs) to sense temperature as well as various sensors. Transducers are also the process level devices that convert the sensor output of the above devices from one level to another. 2. Bay level: The next level is the bay level composed of IEDs that collect the sensor data in order to create information from it and react to it. PC

To network control centre

Station level

Interbay bus Integrated control and protection

Bay control, feeder protection

Additional products

Bay level

Process bus CD drive

CTS/PTS

Power transformers

FIGURE 4.2 Modern substation

Process level

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A bay refers to an area where a power system device such as feeder breaker, and all of the I & C devices associated with it are located. These power system IEDs include protective relays, meters, fault recorders, load tap changers, VAR controllers, Remote Terminal Units (RTUs) and Programmable Logic Controllers (PLCs). 3. Station level: Substation controller refers to devices that perform data acquisition and control of IEDs and contain local I/O. They contain data for the entire station. RTUs, PLCs, bay controllers, and Human Machine Interface (HMI) software running on a personal computer are all possible substation controllers. 4. Enterprise level: This is a generic term for all of the end users, or clients of power system data inside and outside of the substation. These applications acquire data from station level and unit-level devices. For example, the three-fold purpose of a utility’s system integration task can be summarised as follows. Transfer sensor measurements and information created from this data among IEDs, between IEDs and a substation controller and to end user clients directly from the IEDs and the substation controller. 4.2.1.2 Example Communication Architectures of Power Systems The communications architecture needs to be capable of data acquisition and control to and from each IED in the substation. The following sections detail the types of architectures used in substations. 4.2.1.2.1 Multidrop Network Architecture The most common communication architecture used today is the multidrop network or bus network shown in Fig. 4.3. As it can be seen from Fig. 4.2, all devices are connected to the same physical wiring bus. Network master is responsible for controlling the communications by issuing permission commands to IEDs sharing the cable. An IED can only communicate when it receives the virtual token and then passes the token when it is finished. The most important advantage concerned with this kind of architecture is that simple and fast peer-to-peer connections are possible. However, there are major disadvantages as well such as the fact Substation

FIGURE 4.3 Relays connected in the bus topology

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that it does not allow simultaneous data polling of IEDs. The long-term trend is away from multidrop networks and towards star networks. 4.2.1.2.2 Star Network Architecture Many direct connections originating from one device is called a star network topology as shown in Fig. 4.4. Any protocol, including those designed for multidrop applications, can be used for direct communications in a star topology. In this architecture, slow communicating devices can coexist with more complex fast communication relays. Therefore star network supports a wide range of IED capabilities.

Communications

FIGURE 4.4 Relays connected in the star topology

4.2.2 Wide Area Network Structures in Substation Automation Wide area functions are used for the execution of protection and/or control functions within a substation, which needs to make use of the information coming from a more extensive area covered by the substation itself to perform correctly. In the last decade, we have seen common incorporation of LAN and WAN technologies in the Automation and Control of electric power networks with devices and protocols within and outside the substations being adapted to the use of Local and Wide Area Networks. Ethernet, a famous computer network, is used, for communication between IEDs offering high speed, high transfer capacity and versatility. However, certain factors, nowadays still prevent the practical implementation of such functions. These factors are mainly security, availability, communication speed and response time. The performance required is measured by the load imposed on the communication medium, speed and functionality limitations imposed on communication by the protocols and the suitability of the software applications in the devices to make full use of the communication capabilities. Many applications aimed at in wide area functions require on-line information at a speed only feasible with very strict limitations and conditions of the communication network [41-44].

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When the conditions as mentioned are considered, it will be clear that the incorporation of computer networks in power network automation, control and protection represents a huge potential for new and more efficient methods to be implemented with a huge potential of reducing costs and increasing efficiency. Applications can only be automated on a substation level when the need for human interface is excluded or at least minimised, the reason being the ongoing trend for unmanned substations. The exchange of data requires the information to be made available to the network by IEDs connected to the network and a data model to enable the processing of these data in the desired applications. Recent developments aim not only at control devices such as relays but on a broader range of IEDs such as measurement devices and primary equipment. The feasibility of wide-area applications will depend heavily on the realisation of standard communication and standardized modelling of IEDs. The UCATM 2.0 initiative in the USA is an attempt to meet these requirements. IEC61850 takes these efforts one-step further; incorporating the UCATM 2.0 works, and extending it towards the process level. The harmonisation of data models between UCATM 2.0 and IEC 61850 will eventually be an important step towards a worldwide-accepted standard. Timing and performance together with the security and availability factors are the important factors determining the feasibility of wide-area automation, control and protection functions. Since the IEC 61850 is still in the process of becoming a standard and the incorporation in devices is not yet available in commercial products. The UCATM 2.0 concept has been widely accepted in the USA with a number of prototypes being introduced or planned to be introduced tested extensively by the Utility Initiative, which is a consortium of utilities and vendors.

4.2.3 Communication Standards and Applications The strong technological development of large-scale integrated circuits leading to the present availability of advanced, fast and powerful microprocessors making substation automation possible, which resulted in an evolution of substation secondary equipment. The evolution of substation secondary equipment, in turn, has made it possible to implement decentralised substation automation systems, using several IEDs to perform the required functions such as remote monitoring and control. As a result, the need arose for efficient communication among the IEDs, especially for a standard protocol.

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The vendor specific and hardware oriented structure of the market has lead to a number of protocols for communication making communication between IEDs of different manufacturers impossible or only with disproportionate expenditure. The advancement of the connectivity and interoperability of systems is only possible with standardization since a reduction of variety in a relatively small market is extremely beneficial for both the vendors and users. The deregulation of the energy market has increased the importance of data and a lot more data is necessary. Thus open and standardised communication interfaces are needed. This fact is expected to have enormous influence on rebuilding and renewing substations, especially of control components and of the way the process bus is connected to the control system. In the future, the primary equipment must also be equipped with serial communication interfaces. The expected changes are listed below: • The importance of standardised hardware and software is increasing. • A maximum integration of functions within multi-function devices is targeted since the experiences have pointed out that the maximum allowed degree of integration has not yet been fully realised. Therefore, considerable scope still exists for further integration of functions up to the maximum allowed levels. • The medium term target in substation automation will be towards the combination of functionality’s to reduce the number of hardware units and the achievement of an information system. Implementation of interfacing modules between a particular manufacturer process bus and legacy IEDs is seen to be the intermediate step for the solution of problems in the short-term. In the longer term, this is not advised since it adds further installation costs. Besides, the possibility of a wireless substation structure in the long-term means that the bay level devices will be able to communicate directly with the primary plant by means of a process bus [45-46].

4.3

MIDDLEWARE REQUIREMENTS FOR PROTECTION APPLICATIONS

The need to integrate protection, control and data acquisition on the substation Local Area Network (LAN) using a standardised communication protocol has been recognised since the early 90s and many attempts have been made since then to define the standardized communication protocol.

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Many communities such as IEC, CIGRE and IEEE have focussed on developing the specifications for peer-to-peer communication between IEDs. In order to achieve interoperability between IEDs of different vendors, i.e., to be able to communicate between IEDs built by different vendors, the communication protocol must be constraint. This section reviews the important constraints when choosing a protocol offering an option for implementing more than one protocol within the substation. There are three basic sets of requirements when choosing a communication protocol. They are: 1. Performance: The most important performance requirement is the protection commands over the LAN between IED applications within 4ms. This requirement then defines both a peer-to-peer communication protocol and either a 100Mbps shared or 10Mbps-switched ethernet implementation. The 4ms requirement between a sending application in one slave IED and the receiving application in another slave IED cannot be met with a framework implementing a master-slave communication protocol or with a taken passing protocol since the latter has to wait for the token to pass the data packet. 2. Interoperability: When the communication over the substation LAN, which is used for control and monitoring only, is considered then interoperability clearly becomes the dominant selection criteria. In cases where protection does not need to be integrated with control and monitoring over the substation LAN, then the selection of the communication protocol does not strongly depend on the time required to communicate a message from the sending IED application to the receiving IED application. However multicast is still required for interlocking and other control functions. Interoperability is only achieved when the information exchanged between IEDs is fully understood and unambiguous, which requires a welldefined data model that specifies both the syntax and semantics of the information exchanged. In other words, the protocol specification must define the rules and building blocks for developing extensible objects that will be communicated between IEDs. The interoperability requirement has to be implemented in all future substations including the new ones as well as the retrofitted ones. The protocol, which includes a well-defined set of rules for implementing the data model, has to be selected with a project notebook imposed on all vendors to ensure that every nuance of the build out of the data model is understood and documented. The project notebook will be governing document for defining the ‘as-built’ specification. Therefore, future changes to the substation automation system should then be based on the project notebook [43-46].

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3. Maturity: The most important criteria mitigating cost and schedule risk for depolying selected communication architecture is maturity with the most important input to the maturity analysis being the clarity of the utility’s vision for substation automation. By comparing installed user bases for a candidate protocol, maturity can be easily measured. However, care must be taken since technology is rapidly changing and each installed user base used in the comparison must be restricted to one version of protocol specifications. The one version should include all the capabilities needed for a specific utility’s vision of substation automation. The solution is not to choose someone, who has built-in bias for a particular technology or solution, for performing the maturity analysis. The person selected needs to have a high degree of knowledge in the following areas: • A good understanding of the candidate communication technologies under consideration, which is best measured by current participation in venues that are developing these technologies. • Modelling tools that can be used to develop a baseline, without which the comparative analysis will be terribly confused and useless to the decision-maker, from the utility’s vision for substation automation. • It is technically possible to implement more than one protocol in substations by providing gateways for needed protocol conversion, a technique that will always increase cost and reduce performance and reliability of the communication architecture. However, gateways are unavoidable in situations where the required functional capabilities of substations can only be achieved with the use of gateways. Gateways are unavoidable when: — IEDs within the substation operate with a different communication protocol than those IEDs outside the substation (external substation IEDs) or on the EMS/DMS nodes. — Substation LAN segments operate with different protocol, which will probably be the case when migrating from legacy systems to the communication protocol of choice. — Communication segments, streaming data from the substation yard into the substation control house, use different protocols for their operation. If a ‘Process Bus’ as described in IEC 61850 is implemented, this could be the case since the process bus is used to stream data from the yard and is not burdened with substation LAN protocol overhead.

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Provided that the LAN internal to the substation has sufficient bandwidth, then more than one protocol can exist. However, it is crucial to ensure that all required peer-to-peer communication operates correctly. The best approach is performing integrated system testing under moderate loads to determine the behaviour of each IED when it receives a message communicated using a foreign protocol specified in the message header [43-46].

4.4

MIDDLEWARE ARCHITECTURES

A new class of software, called middleware, has risen to address the challenge of interoperability. Middleware software is a layer between the networking code and the application code provided by the communication processor. The function of the middleware is to insulate the application programmer from the raw networking code thus providing an easier way to communicate. In this section we will discuss middleware requirements for remote monitoring, protection and control applications. The requirements that are not largely and sufficiently supported by present middleware platforms are only outlined below. The key requirements identified are as follows: 1. Event notification 2. Fine grained time synchronisation 3. Security 4. Naming and directory services 5. Mediation services 6. Unit and time conversation 7. Distribution configuration management 8. Dynamic substitution of computers 9. Debugging support for distributed systems 10. Real-time object request brokers 11. Performance enhancements in general. The above requirements can be classified into more general categories as follows: • Basic services • Security • Distribution system management • Performance.

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4.4.1 Types of Middleware Architectures The use of the appropriate middleware is crucial for achieving success in substation automation. There are three main types of middleware architectures, which are: 1. Point-to-point architectures. 2. Client-server architectures. 3. Publish-subscribe architectures. 4.4.1.1 Point-to-Point Architectures This is simplest form of communication. The communication between the Intelligent Electronic Devices (IED) within the substation is perhaps the most familiar example of point-to-point communication. It can only be used when the initiating IED or in other words the calling IED, knows the address of the responding IED. They can have a two-way communication dialog as soon as the connection between them has been established. However, this type of connection is not useful in large substations where one IED needs to be able to talk to several IEDs simultaneously. So it is only designed to support one-to-one communications. 4.4.1.2 Client-Server Architectures Client-Server architecture has a many-to-one architecture in which one special ‘server’ node can connect simultaneously to many client nodes. Client-server architectures are useful when all the nodes on the network need to access centralised information. However, this type of architecture is inefficient since they require all information, which is being generated at multiple IEDs, to be sent to the server before it comes accessible to the clients. Another disadvantage concerned with this type of architecture is the unknown delay being added to the system since the receiving client does not know when new information has been added to the server. Substation database of configuration parameters and transaction processing between two relay IEDs are two common examples of this type of architecture [45-48]. 4.4.1.3 Publish-Subscribe Architectures With Publish-Subscribe architecture, an IED can perform two main tasks enabling direct message exchange between the communicating IEDs. An IED will either. • Subscribe to data that it needs or • Publish information that it produces. Any authorised IED may add itself as a subscriber to a particular publisher’s list. That subscribing IED will then receive the publications directly from that publisher IED, as they become available. PublishSubscribe systems are useful since:

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• They are good are quick distributors of large quantities of timecritical information even when unreliable delivery mechanisms are present. • They can handle very complex data flow patterns. One of the important properties of the publish-subscribe middleware is that the application software in data sources and data sinks are kept independent of each other. The most important of all is that it (middleware layer) handles connections, failures and changes in the network eliminating the need to handle exceptions. Middleware only delivers the data that has been requested by the application software.

4.4.2 Real-Time Substation Applications and Requirements Distributed real-time communications in the substation environment can well be realised using the publish-subscribe architectures. Publish-subscribe architectures make the most efficient use of the networking resources since: • There is no need to request data. • The data transfers are done directly between the publisher and the subscriber. In addition to making full use of the network resources, publishsubscribe architectures also provide low latency delivery since the data can be sent from the publisher to the subscriber as soon as it becomes available. Moreover, they can take advantage of the new multicast capabilities of modern communication networks. Continuous sampled data from instrument transformers, group communication of state changes (the famous GOOSE message) and reliable status updates are the data transfer requirements of distributed real-time systems that can be supported by the publish-subscribe architectures when they are configured properly . However real-time systems have other needs, which cannot be met by the publish-subscribe architectures. Some of these are: • The ability to trade off delivery reliability against delivery delay. • The need for communications processors to handle the unique behaviour of the real-time communication protocols. 4.4.2.1 Delivery Delay against Delivery Reliability When communication protocols are designed for guaranteed delivery but a less-than-reliable medium, then an important problem arises in the case of failed transmissions. What happens is that the communication protocol would be struck trying to transmit the failed transmissions wasting time and destroying the timing determinism. For example, the process of

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trading-off reliability of delivery for greater determinism is crucial for multicasting GOOSE state change messages. Sending the most recent GOOSE message is much more important than resending old updates, which would probably be out-of-date when they are delivered anyway. In this case, the best policy would be to send the latest update disregarding the earlier updates [46-51]. In contrast, when a sequence of device operation commands is required then a communications processor has to receive every step in the command sequence properly, which can only be quarantined with reliable delivery. In some situations, protection applications require some intermediate action, which is unfortunately not specified by any of the current networking protocols. For example, Transaction and Control Protocol (TCP) refuses to accept any subsequent packets for several minutes until a dropped packet has successfully been delivered to the TCP. Hence, TCP cannot provide deterministic timing such as retrying for 100 ms and then moving on. 4.4.2.2 Synchronisation In Electric Control and Protection applications, there is a need for a synchronisation time of 10 ms. There is such a stringent requirement for time synchronisation across the distributed system particularly due to the phase differences among generators. An adaptive source rate control mechanism can be developed to handle the changes in the effective synchronization scheme, which can be used to compensate for long-term delay variation caused by large-scale fading. Hence the synchronisation will be maintained keeping the end-to-end delay in low values. 4.4.2.3 Event Notification Services In any remote monitoring, protection and control systems, there is a clear mechanism of one type for the notification of interesting events, when remote sites notify the monitoring sites. Ideally, important events (such as power system faults) need to be pre-defined so that the system can listen for specific types of events to produce a synchronous, persistent and multicast event notifications. In a distributed system such as power system control and protection system where system components (CVTs, relays, IEDs) can fail or in some cases become unreachable, then we might need substantial technical requirements for implementing such services. There are low-level eventdelivery protocols defined in Common Object Request Broker Architecture, but however high-level event service behaviour still depends on the vendorspecific products. What we need is to: • To define and implement event service reliability and delivery persistence capabilities.

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• To identify and describe a significant subset of high level event service functionality sufficiently well-described to allow multiple implementations that exhibit interoperable behaviour. 4.4.2.4 Data Push Architectures Data push architectures, when combined with publish-subscribe architectures, enables users to distribute data to a large and variable set of remote applications. The most important feature of publish-subscribe architectures is that multiple applications, local to the publisher or at some remote Internet site, can subscribe to data published by a single platform. The most appropriate network protocol can be easily identified and used for the network topology between the publisher and subscriber. There are, however, problems when matching the pure, synchronous, remote object method invocation model found in most ORBs to the push model found in data push architectures. Individual data sources and control objects are ideally mapped onto single software objects. When remote applications are reading data out of the data sources, they make use of a method called ‘remote method invocation’ on the data source’s software object. Such a method is not really appropriate since the data push architectures can only push data out at their own pace by performing object method invocations at their own investigation. Another disadvantage is that when data is collected from a variety of objects, it will be pushed out as a single message ending up being treated in various special, ad hoc ways. It has become necessary to bridge the gap between these two models. If the data publishing protocol is formalised by making specific reference to ORB interface repository entries that would tie elements of the data message to specific method invocations on specific objects, then this problem can be solved. When the elements of the data message are received, they could easily be unmarshalled in accordance with interface repository information [49–52]. 4.4.2.5 Security Requirements When monitoring and operating devices over the Internet, there are strict security measures required for several reasons: 1. The monitored data can be stolen, corrupted and intentionally falsified. 2. The devices can be used maliciously by impersonators. 3. The device can be used without unauthorisation. 4. The privacy of monitoring data has to be preserved for commercial and national security.

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Then there is clearly a need for new middleware functions in order to enforce the security requirements detailed above. They are: • Server authentication: It is needed to ensure operation on the intended site. • Client authentication: It is needed to ensure that an authorised client/operator is operating the equipment. • Confidentiality: It is needed for transferring data items in the encrypted format preventing malicious and false operation and eavesdropping. • Non-repudiation of control operations to guarantee liability [48-51].

4.4.3 New Features Required for Communication Protocols There are many challenges, such as the ones outlined above, which need to be solved. There is a clear need to design a real-time communication protocol to run with a communication processor, which needs to have features such as: • Pre-emptive thread schedulers. • Fixed memory managers. • Predictable response times. The required networking software can be effective running on the communication processor only if it is capable of: • Managing priorities. • Control memory usage and timing. • Restrict access to system resources. For example, the networking software running on the communication processor must be completely event driven avoiding the latencies and the inefficiencies of polling. Hence, it should not pause the execution of a high-priority task just because that task issues a publication request. Another important feature required is the re-entrancy of the software, which allows for simultaneous accessing to networking devices due to the possibility of many threads running at different priority levels.

4.4.4 Needed Communication Model Clearly, there is a need to develop a formal communication model satisfying the following features: • It models time and timestamps each transaction.

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• It allows the application software to trade-off timing against reliable delivery. • It controls and specifies memory usage. • It allows for a adaptive synchronization scheme. • It allows for event notification. • It allows for the functions required to meet with the security measures. • It works in a real-time communication processor environment. Only when the above conditions are met, then we can successfully use publish-subscribe architecture in real time for protection applications. Furthermore, each node in the network has to be able maintain a record of its own internal subscribers and publication to which each subscribes; and, its own internal publishers and the list of subscribers to which each sends issues. TCP/IP protocol allows for the easy implementation of non-realtime applications running over it. However, in order to implement real time applications running over UDP/IP, the utilities require a network data delivery service with small size and fast speed. UDP and IP are quite simple and are reasonably fast. The network data delivery service middleware, which needs to be implemented, should add only minimal overhead to the underlying network communication stack and should be much more efficient that TCP, DCOM, or CORBA. This distributed approach not only simplifies the system configuration but also provides for graceful degradation meaning that if any particular node is lost in the network, this will not stop data transmission between unaffected nodes in the rest of the system [41–46].

4.5

PUBLISH/SUBSCRIBE MIDDLEWARE

A Publish/Subscribe system, shown in Fig. 4.5, is a middleware communication service supporting an asynchronous style of many-to-many communication in contrast to the request/response type of synchronous approach of object invocation. It relies on the preferences expressed by the subscribers to deliver messages from one publisher to one or many subscribers instead of the publisher relying on specific destination addresses [41]. A publisher can also be referred as a producer, or sender. Similarly, subscribers are most often referred to as consumers or receivers.

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Publisher 1

Event service

Subscriber 1

Subscribe ( ) Publisher 2

Subscriber 2 Publish

Publisher 3

Unsubscribe ( ) Push event ( )

Subscriber 3

FIGURE 4.5 Publish/subscribe communication model

Consumers make subscriptions using definitions of the information they are particularly interested in. Producers create instances of information, which will be forwarded to the subscribers of this information.

4.5.1 Different Subscription Mechanisms There are three types of subscription mechanisms that consumers can generally make us of when subscribing to information [41]. They are:

4.5.2 Channel-Based Subscription This is the simplest form of subscriptions. Consumers can either subscribe or listen to a channel. Channels will be sent copies of events in the occurrence of new events, which in turn will be delivered to all subscribers listening to that channel [41].

4.5.3 Subject-Based Subscriptions This is the form of subscription mechanism where the idea of a channel subscription has been extended with a more flexible addressing scheme. The notification message include two different parts, which are: • The subject attribute that determines the address. • Followed by the event data. The advantage of subject-based subscriptions is that consumers can express interest in many channels or more than one subject. The subject of the subscription will be assessed against the subject of the event message, and those consumers with matching subscriptions will be forwarded with relative events [41].

4.5.4 Context-based Subscriptions The context-based subscription are an extended version of the subject-based ones, where a consumer cannot only express interest in the subject of the notification but also within the content of the notification. The main advantage of the context-based subscriptions is that fact that the delivery of uninteresting messages can be minimised or even avoided due to the fact that the consumers’ capability of clearly expressing his interest has been increased [41].

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4.5.5 Routing Problem The primary component of a Publish/Subscribe network is a routing engine, which aims to make sure that each message will be delivered to its potential subscribers, i.e. the consumers that have already notified the Publish/Subscribe system of their interest [47]. The first dilemma when facing the routing problem is to choose the most appropriate type of messaging concept. There are three main messaging concepts, which are: 4.5.5.1 Unicast Messaging Unicast messaging, shown in Fig. 4.6, requires the sender to send one individual copy to each subscriber, which limits the number of available subscribers as a result of the bandwidth limitations of the sender. Unicast messaging is the least suitable concept when trying to achieve real-time goals since it consumes bandwidth resources by creating a heavy load when trying to achieve a number of point-to-point links. In addition, it is the messaging concept in which message delivery delay is the least predictable [48].

Sending host

Ethernet hub

Receiving device

Receiving device

Receiving device

FIGURE 4.6 Unicast transmission

4.5.5.2 Multicast Messaging Multicast messaging allows the sender to send a single copy to the data stream, which will then be replicated and forwarded to the consumers, which signaled their interest earlier on, by the network architecture.

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Another subnet

Sending host

Another subnet Ethernet hub

Receiver not interested in the multicast does not receive it

Receiving device

Receiving device

Receiving device

FIGURE 4.7 Multicast transmission

Therefore, instead of sending thousands of copies, the sender sends a single copy directed by the routers on the network to the consumers that have indicated their interest in the message. Consumers usually indicate their interest by joining a particular multicast session group. Thus, multicast messaging reduces the amount to traffic over the network yielding an increased efficiency for both the sender and the network with a number of other performance improvements [48, 49, 50]. 4.5.5.3 Broadcast Messaging Broadcast messaging uses the concept of sending one copy of the message to all nodes on the network (Fig. 4.8). With broadcast messaging, every consumer on the network needs to process the message regardless of whether or not the consumer is interested with the message. The main problem concerned with this is the fact that many consumers might actually be not interested with every message they receive increasing CPU usage, which in turn reduces efficiency [48, 49, 50]. The problem of choosing the appropriate messaging for successful routing is in general followed by the need to tackle the filtering problem, which requires making sure that any subscriber does not receive more message than what it has subscribed for. In the cases, where each publisher is fully aware of its subscribers, then there is no need for filtering. This is usually the case for multicast messaging. However, with broadcast messaging where every consumer receives one copy of all messages, some sort of filtering must take place in order to implement the Publish/Subscribe model.

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Another subnet Sending host

Another subnet

Receiver not interested in the broadcast however still receives it

Receiving device

Receiving device

Receiving device

FIGURE 4.8 Broadcast transmission

4.5.6 Filtering and Binding Filtering is simply the decoding of the message against the subscriptions in order to find out the relative subscribers that have shown interest in that message. Therefore, the type of filtering mechanism to be chosen depends on the subscription mechanism. For instance, when the concept of context-based subscriptions is used where subscribers can express their interest for the message contents, then the filtering mechanism needs to evaluate the complete contents of each message, which adds a non-predictable overhead on each node [47]. The relative overhead decreases when subject based subscription concept is used. In this case, the message is usually tagged with its subject, which has to be evaluated by the filtering process. The complexity of the filtering will be reduced since the filter only needs to evaluate the subject tag rather than all the message contents. A solution in Reformance [47] has been proposed in order to make subject based addressing scheme more efficient and usable in real time systems. In Reformance [47], this is achieved by putting the subject in the address of the message instead of the message contents, which is claimed to increase the efficiency of the filtering to a great extent. Once the filtering problem has been tackled, the task of binding has to be considered. Binding allows the system to find out the relative addresses that it needs to use when forwarding messages. For context base subscriptions, there is no need for any binding. However, for channel-based and subject based subscription systems, some sort of binding needs to be implemented. Binding problem is easily overcome in the event channel based publish-subscribe systems such as CORBA event channel since binding takes place when nodes are connecting to the event channel [47].

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4.5.7 Publish-Subscribe and QoS Although Publish-Subscribe communication model has many advantages such as offering a weak coupling among the communication parties [51], it also has a number of drawbacks such as the lack of support for the negotiation or enforcement of Quality of Service (QoS) [51]. This is a significant drawback because QoS features are nowadays very important components of real time applications. However, lately some significant research has been carried out in order to incorporate the use of QoS features and techniques into publishsubscribe systems [51, 52]. The subsection 4.5.7.1 aims to give reader some background information about QoS features and techniques, while the subsection 4.5.8 discusses some of the research work that has been done with the intention of integrating QoS features and techniques into PublishSubscribe systems. 4.5.7.1 QoS Features and Techniques Applications require certain network services to be delivered to at a certain minimum performance level to be usable [53]. QoS refers to a network system’s ability to sustain a given service at or above its required minimum performance level [54]. Fig. 4.9 shows QoS architecture and components. QoS techniques improves network performance level [55] by Desired QoS parameters delay, bandwidth, reliability, etc.

QoS signalling

Host

Host QoS techniques signalling queuing, etc.

FIGURE 4.9 QoS architecture and components

Client

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• Supporting dedicated bandwidth • Improving reliability characteristics • Avoiding and managing network congestion by controlling jitter and latency • Setting traffic priorities across the network • Shaping network traffic. Delay is the time it takes a packet to travel from sender through the network to receiver. As delay increases, the transport protocol becomes less efficient. Jitter is the variation in the total end-to-end delay values of different packets on the network. A high level of jitter is also undesirable since it leads to the inefficiency of the transport protocol while at the same time causing signal distortion. Bandwidth is the maximal data transfer rate that can be sustained between two end points. Reliability can be referred to as the average error rate of the medium. Poor reliability can result in the transmission of packet in an order different than that of the original transmission or even the loss of packets. Therefore, this situation needs to be avoided [55]. When a network receives more packets than it can handle exceeding its limitations, then congestion occurs, which results in a complete network collapse where data packets are not transmitted at all [55]. Therefore, this has to be avoided. Management tools help for providing QoS within a single network element. The most popular congestion management techniques are queuing, scheduling and traffic shaping and signaling. When packets arrive at the transmitter interface faster than the transmitter can transmit them, they will be queued until the interfaces are free to transmit them. They will be scheduled for transmission according to their assigned priority (Fig. 4.10) an end the type of the queuing algorithm configured for the interface. Queuing and scheduling schemes together provide predictable network service by Low and medium priority dispense only when high priority is empty

Low priority

Medium priority

High priority dispenses until empty

High priority

FIGURE 4.10 Priority queuing

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providing dedicated bandwidth, controlled jitter and latency and improved packet loss characteristics [55]. The basic idea is to pre-allocate resources (e.g., processor and buffer space) for sensitive data. Each of the following schemes require customized configuration of output interface queues: 1. Priority Queuing (PQ) assures that during congestion lower priority traffic does not delay the highest priority data. However, as it can be seen from Fig. 4.10, lower priority traffic can experience significant delays. PQ is designed for environments that focus on mission critical data, excluding or delaying less critical traffic during periods of congestion [55]. 2. Custom Queuing (CQ) assigns a certain percentage of the bandwidth to each queue to assure predictable output for other queues. It is designed for environments that need to guarantee a minimal level of service of all traffic [55]. 3. Weighted Fair Queuing (WFQ) allocates a percentage of the output bandwidth equal to the relative weight of each traffic class during periods of congestion [55]. In addition to managing congestion, it is also important to try to prevent congestion. Weighted Random Early Detection (WRED) algorithm and is a congestion avoidance algorithm, which starts to drop low priority packets to ensure the delivery of all mission critical traffic. This happens only if WRED detects the possibility of future network congestion (Fig. 4.11). Therefore, it is very suitable for real time mission critical applications (55). 4. Committed Access Rate mechanism (CAR) is a traffic shaping mechanism, which defines a traffic contract in routed networks. CAR can classify and set policies for handling traffic that exceeds a certain bandwidth allocation. CAR can be also used to set IP precedence based on application, incoming interface and type of service (TOS). It allows considerable flexibility for precedence assignment [55].

4.5.8 Resource Reservation Protocol (RSVP) Signaling is a form of network communication that enables network elements to signal requests to its neighbours. Coordination between traffic management and policing tools can be handled with the use of QoS signaling. Reservation Protocol (RSVP) is a very complex signalling protocol, which provides reservation set-up and control going far beyond standard ‘best effort’ IP service to provide highest level to QoS in terms of [55, 57]: 1. Service guarantees 2. Granularity of a resource allocation 3. Detail of feedback to QoS-enabled applications.

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When the outgoing connection is congested, RED discards lower priority and non-RSVP packets randomly

FIGURE 4.11 Weighted random early detection [16]

RSVP can be summarized with a simple description [55]: • Each sender defines the characteristics of traffic specification (TSpeck) in term of upper and lower bounds of bandwidth, jitter, and delay. The path (PATH) message originating from the sender is sent to the receiver taking the traffic specification into consideration is every step along the network. • The reservation request (RESV) message from receiver to sender not only specifies traffic. • Each router receiving the RESV message allocates the needed resources. • The last router sends confirmation back to the receiver once it receives the RESV message.

4.6

CORBA AND ITS FEATURES

The introduction of IEC 61850 and the Utility Communications Architecture (UCA) has made it possible and justifiable to integrate station IEDs through standardization. However, more advances are needed in order to establish an open and standard working environment allowing for more and more functions to be developed. The new forthcoming ideas need to follow the

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path opened by the IEC 61850 in order to provide advanced complements to this basic architecture. One of today’s most popular open and standardworking environments is Common Object Request Broker Architecture (CORBA) middleware with set of services, which also allows for heterogeneous implementation of distribution applications. CORBA is an object-oriented standard for distributed object systems, which is implemented using the Object Request Broker (ORB) specification of the Object Management Architecture (OMA). CORBA architecture consists a client object, a server object, an Interface Definition Language (IDL) Stub, an IDL Skeleton and an ORB. CORBA middleware makes the communication between these various components possible through the use of a method involving twelve steps of invocations. The main emphasis in this section is the use of CORBA middleware communications for power system communications. The section discusses the advantages and disadvantages of the CORBA middleware architecture for its use in substations and also the need for its harmonization with UCA. The section aims to example how the standard CORBA middleware can be exended to form an effective platform performance sensitive real-time power system operations. It also deals with implementing the UCA protocol over the newly designed CORBA application thus showing how the interoperability requirements can be met while providing an effective platform for performance sensitive substation automation applications.

4.6.1 Substation Automation Systems The collection of devices that make up the physical systems that generate, transmit and distribute power is usually referred to as the Power System. Substation Automation (SA) is the use of the IED data within the substation and control commands from remote users to control the power system devices within the substation. A SA system is a distributed system dedicated to the monitoring and protection of the primary equipment of such a substation and its associated feeders [41]. When relays and IEDs are integrated together, they form a powerful, economical Instrumentation and Control (I&C) system to support all aspects of electric power protection, automation, control, monitoring and analysis. Nowadays, the desire and the need to merge the communication capabilities of all the relays and IEDs in a substation is clearly recognized, which is capable of providing not only data gathering and setting capability, but also remote control. Worldwide, electric utility deregulation is expanding and creating demands to integrate, consolidate and disseminate real-time information quickly and accurately within and with substations. All these factors have lead to a strong customer drive for standardized solutions [42].

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The Utility Communications Architecture (UCA) specifies a suite of internationally recognized open communication protocols, which meet the requirements of the utilities industry, including electric, gas and water. UCA should rather be regarded as an architecture than a simple protocol. Although the specific object and operational models can be specific to any one of the utilities mentioned above, the architecture remains applicable to all with roughly the similar constraints. Generic Object Models for Substation and Feeder Equipment (GOMSFE) defines a set of object models for use within the UCA architecture across a broad range of typical utility devices [43, 44]. The UCA Common Applications Service Models (CASM) provides a common set of communications functions such as data access, data reporting, data logging, and control functions, which are found in most real-time utility field devices [43, 44]. Although CASM allows discrete devices to share data and services, it is only an abstract application layer protocol without any real procedure for sending and receiving data. It can only be usable when it is mapped, as shown in Fig. 4.11, to a specific communication service such as Manufacturing Message Specification (MMS) protocol, Distributed Component Object Model (DCOM) or Common Object Request Broker Architecture (CORBA) [43, 44]. At the application layer of this model, the MMS application layer protocol is specified to provide the necessary messaging services for devices in these environments. In addition, the UCA Station Management Protocol is specified, which provides support for UCA Time Synchronization services. However, in this book, we propose the use of CORBA to provide the necessary communication services [43, 44]. CORBA is complementary to UCA since CORBA is concerned with standard APIs while UCA focuses on the communications infrastructure. Both worlds require the use of objects so they need to be harmonized. This book investigates the mapping of CORBA services to CASM. The main advantage of the use of CORBA comes from the fact that we can replace MMS objects such as MMS-Events, Domains Download/Upload and Semaphores while adding value to the communication system, e.g., Security, Time Synchronization and Transaction.

4.6.2 CORBA Middleware CORBA, shown in Fig. 4.12, is an object-oriented standard for distributed object systems, which is implemented using the Object Request Broker (ORB) specification of the Object Management Architecture (OMA). CORBA aims at providing a uniform communication infrastructure for building distributed applications. It provides the user with unifying mechanisms capable of interoperating software components, operating on various

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software platforms, and running under different operating systems implemented in different programming languages [45]. In addition to all of these, CORBA is capable of supporting heterogeneous, robust, transparent real-time applications. Therefore, it is also quite suitable for real-time substation communication and automation systems. Client object

Server object

IDL stub

IDL skeleton

ORB

ORB

Network TCP/IP

TCP/IP

FIGURE 4.12 Elements of CORBA

In addition to all these, CORBA services, add to the basic capabilities of ORB. The most important of all is the Naming Service, which enables CORBA objects to register themselves so that they can be located by name. On the other hand, the security service describes how an ORB provides secure communications and defines the different levels of security that can be provided [46].

4.6.3 Mapping UCA Over CORBA The use of CASM services within all UCA device models allows for the expansion of the UCA protocol suite to other application protocols such as CORBA reason being the fact that device models to be specified are independent of the underlying protocol [44].

4.6.4 Basic UCA Models Object Oriented Modelling (OOM) techniques are used to define the UCA device models. UCA device models represent the behaviour of real devices by defining standard classes and objects inherited and aggregated from the basic class definitions. Objects accessible by clients often reside in remote servers. CASM objects, which inherit from the CASM classes LogicalDevice, DataObject and DataSet, usually reside within the Server and they are directly accessible by the client through the network. CASM objects can easily be translated into CORBA objects by giving them object references. This is a straightforward process since both techniques use the OOM approach as mentioned earlier.

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4.6.5 CASM Communications The communications mechanisms of the UCA also match with those of the CORBA. There are four main communication mechanisms used in CASM. They are [48]: • Request/response • Request/No response • GOOSE message • Sampled value. For the first-two mechanisms, CORBA’s 12-step communication mode, shown in Fig. 4.13, is used, which was implemented and described earlier on by the previous chapter [49]. For more details, refer to the references figure and other figures. For the remaining two mechanisms, the developers are still in the process of designing a new Publish/Subscribe CORBA Architecture, which will make it possible to transfer GOOSE state change messages and sampled values over the network easily and with high determinism.

4.6.6 Further Needs UCA includes a definition for the relay-to-relay communication of binary state data known as GOOSE, which has the packet format shown in Fig. 4.14. Client 1. Issue request

12. Return

2. Marshall arguments

11. Unmarshall results

3. Send request

10.Receive reply

TCP/IP 9. Send reply

4. Receive request 5. Unmarshall arguments 6. Up-call

8. Marshall 7. Return

Server

FIGURE 4.13 Twelve steps of CORBA

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Multicast (1bit)

Relay name (32 bits)

Server name (32 bits)

Time of event (32 bits)

Destination (32 bits)

Next goose (32 bits)

Req/res (1 bit)

Dynamic network announcement (64 bits)

Data (12800 bits)

FIGURE 4.14 ‘GOOSE’ format

GOOSE messages are transferred over the network by a communication mechanism called Publish-Subscribe architecture with which, any IED can either [46] subscribe to data that it needs, or publish information that it produces. Publish-subscribe architectures make the most efficient use of the networking resources. However, real-time systems have other needs, which cannot be met by the publish-subscribe architectures. One of this is the ability to trade-off delivery reliability against delivery delay [47]. The process of trading-off reliability of delivery for greater determinism is crucial for multicasting GOOSE state change messages [47]. Sending the most recent GOOSE message is much more important than resending old updates, which would probably be out-of-date when they are delivered anyway. In contrast, when a sequence of device operation commands is required then a communication processor has to receive every step in the command sequence properly, which can only be quarantined with reliable delivery. In some situations, protection applications require some intermediate action, which is unfortunately not specified by any of the current networking protocols. The developers are currently working on a new publish-subscribe architecture in order to solve this problem that exists within the substations. The simulation section further illustrates the need for such an architecture.

4.6.7 Simulations We will be running simulations on a point-to-point architecture to measure the packet-end-to-end delay for two different configurations. The first configuration uses TCP/IP as the transport protocol whereas the second configuration uses UDP to transfer packets between the CORBA Client object and the CORBA Server object over the network. The network model

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used to simulate the point-to-point network architecture is shown in Fig. 4.15. APPL

APPL

APPLICATION DEFINITION

PROFILES DEFINITION

Applicants

Profiles

Atlantic Ocean

In Corba_server

IED1

FIGURE 4.15 Point-to-point network architecture

Fig. 4.16 shows the two components of the system reaction time for the case when UDP is used as the transport protocol:

Realtime OS

Communication control

Management interface

Communication protocol stack

Diagnostics and test

Application framework

Data transport control

Board support package

Software

Communication protocol hardware

Microprocessor peripheral hardware

FIGURE 4.16 Embedded communication device software architecture

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• The end-to-end delay of a packet to travel from the IED to the server, and • The end-to-end delay of a control packet to travel from the server back to the IED. The transmission of trip signals including short but time-critical data packets has a 4 ms-performance requirement, which is the most crucial requirement. Under normal conditions such as this scenario, the delay going from controller to IED is about 0.3 ms and the delay going in the opposite path is about 0.35 ms. The sum of the delays in both directions gives us the total end-to-end delay for a packet as 0.75 ms, which is well-below the 4 ms performance requirement. However in the case of long and reliability-critical signals, TCP needs to be used so that there will not be any loss of packets. In this case, 4 msperformance requirement cannot be met. We can clearly see from Fig. 4.15 that in the case of TCP transport protocol being used, the end-to-end packet delay will be about 9 ms. Substation Automation systems, responsible for operating equipment in Electrical Substations, are prime examples of distributed command and control systems. They were traditionally built as turnkey systems based on proprietary technology but with the recent developments in automation and networking, a new wave of interoperability requirements has started. Standardization is a key issue offering interoperability across vendor boundaries [57-60]. The IEC 61850 standard protocol, which will be a published standard since year 2003, specifies a collection of elementary services such as breaker operation, monitorization, reporting, etc. Different types of technologies can be used for implementing these services, sometimes referred to as logical nodes in the substation and then they can be distributed over a network including various processors such as IEDS, RTUs and station computers. Furthermore, such services can be bundled together to form the global system behaviour. For example, a global synchronised switching function can be implemented by integrating several logical nodes such as synchronised switching, HMI and breaker control. The ACSI interface designed by the IEC TC-57 group is used as the common abstract interface, which supports interoperability. This abstract interface is mapped to standardized communication protocols that provide the real substrate for the implementation. This section mainly deals with implementing the IEC 61850 over a CORBA based middleware. This is not unique in the sense of implementing the IEC 61850 standard over the CORBA middleware since some initial

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work has already been carried out in this field since 1999. However, the project can become unique in the sense that the IEC 61850 is not to be implemented over a standard CORBA middleware but over an extended version of the standard CORBA middleware. In other words, the main phase of research comes in when the standard CORBA middleware is extended to form an effective platform for performance sensitive real-time power system operations. The main emphasis is on satisfying the middleware requirements such as the ones detailed in Section 4.3. Next step is to implement the IEC 61850 on the newly designed middleware. Such an implementation is necessary since the designed middleware will not deal with specific object functionality but with how interfaces are specified, used and managed across the substation automation network. Thus, we can provide an effective platform for performance sensitive substation automation applications while also meeting the interoperability requirements. Last step of the work can be programming a programmable communications processor with the overall code. The programmed communication processor can be referred to as Universal Communications Processor (UCP) and FPGA technology could well be used for this purpose [55-60]. CORBA enables running application analysis, monitorization and simplifies system evolution. CORBA, nowadays, is the best suitable platform for distributed systems construction due to its ability: • To provide a good mixture of performance • To provide resource consumption • To provide a good support in the early phases of systems engineering life cycles. The research aims for making a standard middleware for substation automation system by extending the standard CORBA middleware to meet certain requirements as detailed earlier on. Thus, while keeping some of the benefits it provides, the developers have tries to enhance it to end up with a middleware platform speficifically designed to meet the requirements of a substation automation network. Hence, the designed communications processor is of universal type since it can include a universal middle ware and the IEC 61850 universal standard.

4.7

COMMON ARCHITECTURES FOR COMMUNICATION DEVICES

Many embedded communication devices have architectures with variations on the same theme, containing a surprisingly similar set of key elements, inspite of the variety of forms and diversity of functions. This section examines those common architectural elements in some detail and touches

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on the implementation of these elements. There are many developers of embedded communication device architectures leading to many variations. However, a common set of elements tends to appear in a great many architectures. The basic software architecture of a hypothetical embedded communication device is shown in Fig. 4.16, where usually only a couple of elements in the architecture are more or less unique to each other while the rest show very similar properties, form and fashion [58-60].

4.7.1 Communication Protocol Stack The communication protocol stack is the heart of any communication device. All types of communication are subject to some form of protocol. A device can communicate with any other entity only if it knows at least one communication protocol and if the targeted entity knows the same protocol. Most standardized communication protocols roughly suit some portion of the Open Systems Interconnect (OSI) model shown in Fig. 4.17. Some portion of layers 2 and 3 are usually provided in software Transaction and Control Protocol (TCP) of layer 4 is offering higher-level functionality. Layer 7

Application

Layer 6

Presentation

Layer 5

Session

Layer 4

Transport

Layer 3

Network

Layer 2

Data link

Layer 1

Physical

Typical embedded protocol layers

FIGURE 4.17 The OSI model

Physical layer is usually implemented in hardware due to prohibitive processing and electrical signalling requirements. However in many cases, we can see software and hardware interactions in layering. Some special communication processors can perform physical layer functions in software, while upper-layer functions can be performed in hardware [59-60]. For example, it is common for a Digital Signal Processor (DSP) to perform some physical layer functions in software. On the other hand, a Network Processing Unit (NPU) may perform portions of all seven layers in hardware.

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The lower layers in a protocol stack are primarily used to establish and maintain a physical, logical or virtual connection suitable for reliable transmission of the information in the upper layers. Whereas the primary function of the upper layers is to transport information relevant to the application of the transporting entity. Various communication-oriented activities can occur at any layer. These are mainly activities such as flow control, error detection and security checking and etc. An important implementation strategy of the protocol layers is to use event-driven state machines since in many cases a protocol layer require some event to occur in order to proceed to the next state in the protocol. Fig. 4.18 shows an extremely simple layer two state machine [56-60]. Idle

Layer 3 Correct request

Resources pending

Layer 1 Release confirm

Layer 1 Failure indicate

Layer 1 Resource confirm Layer 1 Failure indicate Link pending Layer 1 Link confirm

Release pending Layer 1 Release indicate

Link established

Layer 1 Release request

Layer 3 Data request

FIGURE 4.18 A simple layer two state machine

The state machine, shown in Fig. 4.18 is used for: • Establishing a connection • Forwarding data • Releasing the connection based on indicators and directives from layers 1 and 3, respectively. The state machine approach is seen to be an effective way of implementing the protocol behaviour based on the sequential nature of the control protocol shown in the Fig. 4.18.

4.7.2 Communication Control The application or control functionality of the communication device is contained in the control element. It may be

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• An intelligent application, which uses the protocol stack to communicate with a peer entity on another device. • A bridge between the protocol stack and another protocol stack. • An interface between the protocol stack and another application or device. The communication control element is effectively the top-most layer of the protocol stack, a service provider to the control element, regardless of its function. Similarly, event-driven state machine approach can be used for implementing a communication control element.

4.7.3 Data Transport Control Any communication device is responsible for transforming information to and from peer devices. In some cases, the volume of information allows the software to construct every bit of the information sent and to analyse every bit of the information received. On the other hand, in most cases, devices must transfer massive quantities of information in real-time. General-purpose microprocessors are typically ill equipped to handle the raw processing requirements associated with such high data rates. The solution for accommodating the need for additional data bandwidth is to perform most of the protocol functions in communication-specific hardware, where maximum output can be attained. The use of communication-specific processors, which are specially equipped to handle the activities of a protocol or a family of protocols, is also one of the solutions. Therefore, the task of the communication devices software is to control the data transport hardware logic, rather than performing the data transport directly. This task usually includes setting up (programming) the hardware to transport data, and having the hardware to notify the software when something of interest occurs. The appearance of an important piece of data such as a device address, the occurrence of an error and the crossing of a threshold are among those that might be considered as interesting information. Thus, this ‘set-up-and-notify’ approach enables the communication device to transport massive volumes of data with minimal intervention from the software. The data transport is typically initiated and controlled by the protocol stack as it walks through its various states. It is quite common to implement the data transport control as a hardware device driver since the data transport is generally hardware assisted. The driver provides hardware access functions as well as hardware interrupt service routines [40, 58-60]. Fig. 4.19 shows a general driver model, where the access functions are used for programming and controlling the data transport hardware, such as:

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• Configuring the hardware to perform data transport in a specific way • Setting up interrupts • Initiating the flow of data. Protocol stack

Access function

Interrupt service routine

Access function

Interrupt service routine

Hardware

FIGURE 4.19 A general driver model

The interrupts from the data transport hardware are processed by the interrupt service routines, such as those indicating the receipt of interesting data or the occurrence of error conditions or threshold crossings.

4.7.4 Management Application Interface The ability to adjust system characteristics of a device in response to changing conditions is often ignored in the world of embedded communication devices. There is a clear need for a management interface, which would allow a device to be adjusted in response to changing system conditions. Some of the typical management activities are: • Configuration-setting device parameters that affect the device’s run-time behaviour. • Performance monitoring-collecting information concerning the performance of the device, which may prompt reconfiguration. • Usage monitoring-collecting information concerning the usage of the device. • Fault monitoring-collecting information concerning the faults, errors, and warnings related to device operation. • Diagnostic and test-prompting the device to perform selfdiagnostic and tests, and reporting the information to the management source. The management interface can be implemented as a group of sub-elements as shown in Fig. 4.20.

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Protocol stack

Management protocol access

Configuration manager

Diag. and test manager

Performance monitor

Usage monitor

Fault monitor

Objects and/or Data stores

Diag./Test application

FIGURE 4.20 Management interface

The sub-elements of the management interface are: 1. Management protocol agent: A management protocol has to be executed so that the management interface communicates with the external management system. The function of this sub-element is to act as the protocol agent for the other management sub-elements hiding the details of the management protocol from them. The eventdriven state machine approach can well be used when implementing the management protocol agent. 2. Configuration manager: This sub-element maintains the configuration data in a data store and/or passes the data to the appropriate elements of the communication device. 3. Performance monitor, usage monitor and fault monitor: These subelements access information from other elements of the communication device reporting this information through the management protocol agent to the external management system [40, 57-60]. The elements can usually be implemented as functions or methods. However, in cases of high complexity of their interactions with other elements in the communication device, state machine behaviour may be needed.

CHAPTER

5 Information Embedded Power Systems

5.1

OVERVIEW OF COMMUNICATION NETWORKING REQUIREMENTS

In every parts of the world, society has entered into a new era of economics and social experience driven by digitally based technologies. Our world is more interconnected than at any time in history, utterly dependent on the integrity of complex networks including the internet, telecommunication and electric power system. Existing information management systems could not satisfy the new challenges as the demand for more and faster information increase by many players either in developed or developing countries. An equal step should be taken by developing countries in par with the developed ones to upgrade the power system communications infrastructure. The rapid developments of the internet and distributed computing have opened the door for feasible and cost-effective solutions. In this chapter, an overview of communication networking requirements is discussed briefly. An emerging power system communication technology to be used in the future electric utility industry called IEPS-LAN/WAN is presented. The benefits of employing the IPES-LAN/WAN have also been discussed. In recent years, telecommunication systems have undergone radical changes prompted mainly by the desire to increase system performance. New technologies are providing huge increases in performance at lower unit cost. At the same time, deregulation and privatisation of the electricity industry coupled with the liberalization of the telecommunication market have imposed new requirements on the electrical power communication network. Key drivers for change of traditional SCADA networking to a

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common communication networking (LAN/WAN) include: cheaper availability of optical fiber installations, efficient transport control protocol over internet protocol (TCP/IP) networking and emergence of quality of service (QoS) over LAN/WAN technology [61, 62]. Traditional SCADA networking is based on fixed voice grade circuits and modem thus making sure that a communication path is there when required and that transmission delay and variations are very small. This technology is becoming obsolete and unsuited to the increasing demands of today’s power system operations.

5.2

INFORMATION EMBEDDED POWER SYSTEM VIA LAN/WAN

Information embedded power system is an extension of traditional power systems with added monitoring, control and telecommunication capabilities. A simplified illustration of an information embedded power system is shown in Fig. 5.1. This system consists of: (i) power system hardware, (ii) the measurement system (RTUs), (iii) the communication system and (iv) the electric utility control centre. In this system, the RTU computers record power system measurements and send them in real time over a computer network (LAN/WAN) to the power control centre. NAT

REG

REG

REG

PROV

RTU

NAT

RTU

PROV

RTU

RTU

PROV

RTU

RTU

REG

PROV

RTU

PROV

RTU

RTU

RTU

RTU = Remote terminal unit, PROV = Provincial control centres REG = Regional control centres, NAT = National control centres

FIGURE 5.1 Computer network controlling the electric network with a tree topology

Data communications have always played a great role in the operation and control of power utility systems. Applications of data

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communications in power systems range from relay-communications to ‘inter-control centre’ data sharing with direct link computer networks used to deliver real-time measurements from RTU computers to an energy control centre as well as other business data. Popular communication network protocols employed in IEPS are direct link networks and end-toend network. Detailed information on power system hardware, communication system, the measurement system and the electric utility control centre can be found in references [61, 63, 64, 65, 66].

5.2.1 Deregulated Power Deregulation has served to complicate the operation of power systems. In the new deregulated environment, the pattern of power flows in the network is less predictable than it is in the vertically integrated systems, in view of the new possibilities associated with open access and the operation of the transmission network under energy market rules. The goal of modern power utilities, in the presence of new competitive markets, is to provide services to customers aiming at high reliability with the lowest cost. Before the days of deregulation, utilities performed both power network and marketing functions but were not motivated to use tools that required accurate real-time network models such as optimal power flows and available transfer capability determination. These practices are starting to change in the emerging competitive environment. Worldwide, electric utility deregulation is expanding and creating demands to integrate, consolidate and disseminate information quickly and accurately between and within utilities. Utilities spend an ever-increasing amount - estimated $ 2 billion to $ 5 billion dollars a year in the USA only-for voice and data communication. There are strong ways to find ways of reducing operating costs to improve utility earnings. In the deregulated power industry, it is necessary to have global vision of the network situation. That is, the measurements acquired locally in the RTUs should be transmitted to a provincial control centre. The information from these provisional control centres is transmitted to a control centre of higher level such as regional in which a more global vision of electric network can be obtained. In a similar way, the information from the regional control centres can be transmitted to a national control centres in which one obtains a general vision of the network. This results in a hierarchy of control centres with several levels, from the RTU until the general (national) network control centre. In addition, information is frequently exchanged among control centres of the same hierarchical level or different levels as shown in Fig. 5.1. The

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increasing incorporation of digital devices throughout the utility enterprise as well as the forces of deregulation are driving utility communication into new realms with new requirements and paradigms. Deregulation place new requirement on the communication of data and information throughout the utility enterprise. With the current advancement in Information Technology (IT), utility can meet the present data sharing in broader perspective. The time has come to fully employ WAN technology in the power system industry.

5.2.2 LAN/WAN 5.2.2.1 Migration to WAN Conventional SCADA network designs rely on the predictable nature of connection-oriented services using fixed audio bandwidth links, analogue modems and specific protocols. Setting up and maintaining these networks require specialised skills. Reconfigurations involve hardware rewiring, are time consuming and costly. Bandwidth is limited to 3 kHz, which is adequate for current RTUs but potentially limiting business move towards the use of substation automation and remote management. As the world moves to digital communications, the support of analogue modems is becoming increasingly difficult [67-69, 72]. Changing to utilitizing WAN technology will enable the management of SCADA networks to be integrated into a system common to the corporate data network. Reconfigurations will be simplified to keyboard commands rather than rewiring at multiple points. Bandwidth can be allocated as required and RTUs themselves remotely managed. In addition, the advantages of WAN networking include: worldwide adoption, very well developed hardware and software market, simplicity and choice of application layer protocols, inherent resilience of the IP routing concept and strong network management, including remote control and monitoring. Furthermore, WAN presents the opportunity to migrate to a single network for both operational and non-operational requirements [70-72]. Applications will include SCADA data, business data and video monitoring, which are integrated with Network Integrated System (NIS), Energy Management System (EMS) and Human machine Interface (HMI) as shown in Fig. 5.2.

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RTU management & provisioning

PBX

EMS

GW Host Site

NIS

Video Monitoring

Wide Area Network

Video

VOIP NIS HMI

RTUs

Video

VOIP NIS HMI

Alarms

RTUs

Video

VOIP NIS HMI

Alarms

RTUs

Alarms

FIGURE 5.2 Integrated WAN communication network

5.2.2.2 Information Embedded Power Systems via WAN (IEPS-W) Due to significant changes in the power system industry, Information Embedded Power System via Wide Area Network (IEPS-W) is essential to accurately and effectively monitor, control and use telecommunication facilities in a broader perspective. Therefore, a wider flexible system is desired so that RTU computers can record power system measurements and send them in real time over Wide Area Network (WAN) to the power control centre efficiently together with other non-SCADA data. An IEPS-W is an extension of traditional power systems with added monitoring, control and telecommunication capabilities. A simplified illustration of an IEPS-W is shown in Fig. 5.3. This system consists of: (i) power system hardware; (ii) the measurement system (represented by three remote terminal computers – RTUs); (iii) the communication system (WNA) and (iv) the electric utility control center. In this system, the RTU computers record power system measurements and send them in real time over a Wide Area Network (WAN) to the power control centre. Control centres are also capable of sending messages back to the RTUs to perform control actions such as opening/closing breakers, transformer tap changing, generation control, etc.

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INFORMATION EMBEDDED POWER SYSTEMS Power utility control centre

Power system RTU 1

RTU 2

I2 V1 Wide area network

Measurement data

P3

Display Mainframe

RTU 3

FIGURE 5.3 Illustration of information embedded power system

This IEPS-W model should be based on high speed monitoring of measurement points, ‘concentration’ of these measurement, and generation of displays based on these measurements. By constantly monitoring conditions throughout a wide-area-network, IEPS-W can detect abnormal system conditions as they arise. Expansion of this capability is crucial for implementation of an integrated wholesale power market. Reliable, realtime gathering of a range of power system parameters will enable power delivery system operators to detect and counteract abnormality over a wide geographic area, thus enabling the power delivery system to operate safely to its inherent limits. Broader implementation of IEPS-W like system will provide the real-time information needed for integrated control of a large highly interconnected transmission networks. Obviously, this will add intelligent components to conventional controls to learn and make decisions quickly, process imprecise information, provide high level of adaptation. One of the challenges will be to meet human resources needed (technical as well business skill). It will require well-trained personal, highly skilled and well-informed people [62, 67-69].

5.3

THE BENEFITS OF USING IEPS-LAN/WAN TECHNOLOGY

IEPS-W looks very promising as shown in Fig. 5.2 integrating all required parameters for the modern power system communication. However, an extensive research is required to study how the random characteristics of the computer network can affect the accuracy of the measurements sent from the RTUs to the control centre especially when data are transmitted via WAN environment when other data will be sharing the same network

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as well. Large amount of computer network traffic may result in large measurement errors and temporarily render parts of the power system unobservable. To maintain power system observability, the computer network must meet two main criteria: bounded time delay and guaranteed transmission; that is, a measurement should be transmitted successfully within a bounded time delay (4 ms). Unsuccessfully transmitted or large time-delay messages from the RTUs to the control centre may cause several buses in the power system to become unobservable. In addition, it is crucial to study the random characteristics of the computer network as the traditional power system observability methods does not consider measurement errors due to delays in delivering the measurement. In other words, traditional power system monitoring methods assume that the state of the power system remains unchanged during the time it takes to deliver a newly recorded set of measurements to a control centre. In this new proposed model, delay could be higher when data are transmitted via WAN and further research is required to minimize the system delay since data are very sensitive for utility industry. The characteristics of the measurement delays associated with these types of networks will be much more complex due to the added complexities of routing and switching. Before employing this sophisticated and realistic IEPS-W model, utility must ensure through experimental analysis that this model meets the communication delay acceptable by electrical power industry [71-72].

CHAPTER

6 Fiber Optic Network Infrastructure as Next Generation Power System Communications

6.1

BACKGROUND

Power system communication has from high-speed substation control and protection data communication to wide area power system monitoring and measurement data transmission, the increasing incorporation of computer network throughout the utility as well as the forces of deregulation are compelling power system communications into new realms with new requirements and challenges. Expanding network services such as real time wide area control and Flexible AC Transmission System (FACTS) device coordination are also driving the need for evermore bandwidth in the network backbone. These need will grow further as new real-time service, protection and control applications become more feasible and pervasive. Electric utilities often employ several types of communication media for different functions. With more and more bandwidth required by the power system data communication, the current transmission media cannot meet all the high capacity and quality of service requirement. This chapter reviews current power system communication media and discusses fiber optic network infrastructure for the next generation power system communications. The power system is using several media for its protection, control, and information sharing function. The most common ones include: Power Line Carrier (PLC), microwave, pilot wire and wireless. PLC operates by transmitting radio band of frequency signals between 10 kHz to 490 kHz over the transmission lines. PLC with power

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output of order 150 W can be used up to 240 km. Normally, PLC carriers only one channel of 4 kHz bandwidth. The frequency range is limited by government regulations. The PLC is the most common communication media used in the USA. However, it has some disadvantage such as bandwidth limit. It is subject to lightening switching surges, and networks reconfiguration. Another media is microwave. Microwave operates in the 150 MHz to 20 GHz frequency range. This bandwidth can carry a lot of communication channels for a variety of information. The disadvantages of microwave is that the transmission length is limited to sight path between antennas. Microwave is subject to atmospheric attenuation and distortion. The combined latency using modem plus analog microwave is around 100 milliseconds between two adjacent antennas. Pilot wire is normally a telephone wire either owned by utility companies or leased from telephone companies. This type of communication has a bandwidth from 0-4 kHz. Overhead lines may experience interference from power lines while the underground is subject to damages for many obvious reasons. Wireless is one of the modern methods of communication. Low orbit satellite communication system provides an existing option to transmit information covering a very large range. The delay is a problem, which depends on the distance. For example, the latency for low orbit satellite at 10 km above the earth is about 300 ms one-way. Another disadvantage is the cost of installation. All the above media may be using different communication networks such as circuit-switched networks, packet-switched networks, and cellswitched networks [73–80].

6.2

CURRENT POWER SYSTEM DATA COMMUNICATION MEDIA

Real time monitoring is an expanding network service that drives the need in the network backbone for ever wider bandwidth. As new remote real time protection and control applications become more flexible and pervasive these needs go further for increased bandwith. Conventionally electric utilities made avail of several types of communication media for different functions. [81–86]. Extensively used communication media in the power system are highlighted in following sections. Fibre Optic will be the ideal choice for future communication infrastructure, with more and more bandwidth required.

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6.2.1 Power Line Carrier Power Line Carrier (PLC) [81] [85] [100] does not offer a reliable solution for wide area data transmission. Communication with remote sites cannot be maintained during a disturbance. Therefore, PLC’s effectiveness for wide area data transmission is limited.

6.2.2 Dedicated Links In order to communicate between Control centre and substation RTUs; dedicated links [81] [85] [86] [87] are employed by many SCADA systems. However, capability to provide high data rates is the foremost advantage of dedicated links. The main disadvantage in dedicated links occurs in remote areas, due to lack of connectivity. Dedicated links have no practical application for controlling medium voltage grids.

6.2.3 Radio Systems Wide area data transmission can facilitate Conventional Radio (CR), Trunked Radio (TR) or Spread Spectrum Radio (SSR). CR, TR or SSR are based on licensed channels or over non-licensed frequencies. Many countries have limited frequencies in the VHF/UHF bands (Very High Frequency/Ultra High Frequency) bands. Overutilisation of unlicensed frequencies by mass consumer applications causes questions in the reliability of VHF/UHF for commercial and industrial use. Poor utilization of air time and unreliable communication resulted when using line protocols over radio.

6.2.4 Microwave The radio signal operating in the 150 MHz to 20 GHz frequency range is Microwave [81] [85] [87] [93]. The main disadvantage of the microwave is that the transmission length is limited to a line of sight path between antennas, is subject to distortion and atmospheric attenuation. Using modem plus analogue microwave, the combined latency is around 100 millisecond between two adjacent antennas. From Table 6.1, it is evident that none of the above currently used transmission media in the power system, can meet the real time measurement requirement. Time latency requirements by fast control and protection function cannot be met by transmission media in Table 6.1. Therefore, the above media in Table 6.1 is not suitable to meet ‘Quality of Service’ requirements.

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Table 6.1 Currently used transmission media in the power system Transmission Media

Data Rate

T1

1 Mbps. Effective bandwidth considering network traffic, data collision etc 125 kbps

Frame Relay

280 kbps

ISDN

140 kbps

T1 Fractional

62.5 kbps

56k leased line

56 kbps (Effective bandwidth lower than this)

Internet

Effective rate 40 kbps depends on network traffic

Radio Frequency

9.6 kbps

Power Line Carrier

1.2 kbps

6.3 NETWORKS AND INFORMATION TECHNOLOGY The problems mentioned in the previous sections pose the challenge of making use of more advanced technology for future power system communications infrastructure design.

6.3.1 Fiber Optic and its Enabling Technologies Fiber optic system [81] [131] is the most suitable data transmission medium for power system control, protection and monitoring function. The particular characteristics [81] [132] [133] of the optical fibers that make them so useful are: low attenuation; high bandwidth; electromagnetic interface immunity and security. Low attenuation: The wavelength of the light signal in use has a direct effect in the attenuation of the Optical Fiber. Attenuation of 0.35 and 0.2 dB/km are achieved by Wavelength of 1300 nm and 1550 nm. 0.2 dB/km attenuation value allows 100 km between repeaters or amplifiers; given that the achievable net loss is 20 dB. High bandwidth: Potential bandwidth of 20Tbps which could accommodate 312 million voice channels (64 kbps) can be facilitated by a single optic fibre operating at 1300 nm or 1500 nm of wavelength. Electro Optic devices and receivers or the Electronic interface to these devices, mostly determine, the bandwidth limits of fiber Optic transmission. Small physical cross-section: Small physical cross-section, is an advantage provided by Fiber Optic Systems. By merely installing Wavelength Division Multiplexing (WDM) or higher Speed Electronics the Optic Fiber can be upgraded for more capability.

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Electromagnetic interface immunity: High powered transmitter or very sensitive receivers are unable to cause interference in the form of noise or cross talk on optic fibers, making them immune to Electro Magnetic Interface Interference. Security: It is impossible to non-invasively eavesdrop of the signal, as optic fibers radiate no energy. The advancement in key component technologies [81, 131–136] such as fiber, amplifiers, lasers, filters and switching devices has driven to the rise of optical networking such as WDM. Switching components and Optical linking components are the two classifications of Fiber Optical linking components. WDM Multiplexers/ DeMultiplexers and WDM passive star couplers form the make up of optical linking components. OADMs/OXCs and tunable transmitter/receivers are the make up of switching components. The following features are seen widely used optic fibers: 1. OADMs: Programmable devices configured to add or drop different wavelengths. 2. Amplifier technology: Act as wavelength routers or wavelength cross connects. 3. Transmitters: Which send the optical signal to fibers. Fibers are two types—Tunable or fixed. 4. Amplifier technology: Advances in amplifier technology have increased the distance between signal generators. 5. Amplifiers: Two basic amplifiers have been proposed. Semiconductor Optical Amplifier (SOA) can be integrated with other silicon components for improved packaging. Erbium Doped Fiber Amplifier (EDFA) design can typically achieve high gain. 6. Optical packet switches: These are nodes that have optical buffering capability and perform the packet header processing function required of packet switches. [81, 91–103].

6.3.2 IP Over Optic Network Topology WDM employments are point-to-point at present. In order to interface to higher layer of protocol stacks, WDM uses SDH/SONET as the standard layer. Different protocol stacks provide different functionality in terms of bandwidth overhead, rate scalability, traffic management and Q.O.S. (quality of service). Segmentation and reassembly of data with class of service and setting up of connections from source to destination is the function of the ATM layer. The function of SONET/SDH layer are interfaces with the electrical to optical layer, delivers highly reliable ring based topologies, performing

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mapping of Time Division Multiplexing (TDM) slots from digital hierarchial levels. The Wave Division Multiplexing layer multiplexes electrical signals onto specific wavelengths in a point-to-point topology and constructs the power system communication backbone. [81, 104–115]. The multi-layer topology as shown in Fig. 6.1 forms the basis of current optic fiber networks. Time delay and function overlay are problems with multi-layer topology. IP over WDM will be the better combination [81, 116–135] based on results of studies conducted, because of the studies conducted. IP/ATM/SONET layering IP/MPLS

Packet Over SONET layering

ATM

IP/MPLS

IP Over WDM layering

SONET/SDH

SONET/SDH

IP/MPLS

Optical WDM

FIGURE 6.1 IP over optic network technology

Each wavelength can be considered as a dedicated connection, as IP over WDM architecture brings in the property of virtual fibers. For performing control operations, the signals need not to be converted onto an electrical domain. The Latency in the IP/WDM system is smaller compared to that encountered in the SONET system. By using IP over WDM, the transport capabilities of SONET/SDH are being absorbed by the optical layer and the ATM function of traffic engineering is being absorbed into IP. Therefore, the multiplayer architecture converges to two layers.

6.3.3 The Need of Information Management Methodology IT will play an increasingly important role to cater for the great needs of information exchange in power system. By the redesign of the system for information exchange, integration, utilities have progressed from their initial efforts to re-consider their information needs. A methodology for efficient information consolation, exchange and sharing is required. As the volume of information holding increases, this need will become increasingly more critical [81, 137]. In different application such as information accessing and sharing [81, 138, 139] IT technology has been employed in power systems. Issues such as multiple data formats, compatibility problem and lack of metadata standardization complicate the exchange of data among different users. Although many standards have been developed already for information management, they are often incompatible with one another,

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as they tend to overlap. Isolation between power system applications also hinders the development of a universal information infrastructure in power system utilities. A great waste of resources has resulted because of the lack of standards among the disparate systems. The development of a universal information infrastructure in power system utilities has hindered the isolation between power system applications. Future power industry may benefit from the use of universal information architectures, such as a standard data exchange model and communication network that can support the different data requirements, transfer rates and qualities of data flow among various systems. To address the critical need of a universal data interchange problem, the more recent XML technology can be used. For easy information exchange between disparate power systems and application, XML technology is used. Information exchange can be accomplished with minimum modifications necessary on existing applications, using XML. While still being able to exchange power system data with other applications, utilities can continue to use their respective proprietary data formats internally XML [142] has been widely used in networking [143], earth science [145], e-commerce [144], simulation [146] for data exchange. XML has also been introduced and discussed in power systems for power market and information exchange [149] with the development of power industry deregulation [81].

6.4

WIDE AREA COMMUNICATION INFRASTRUCTURE

IP over WDM network design for future power system is proposed through the above discussion. One of the key advantages of WDM is that it offers support for multi-protocols, allowing multiple independent network protocols to coexist on the same filter network. It is extremely important to cooperate with the existing multi-protocol network in power systems. Increasing operational costs are required to deploy fiber rings with physical topologies. There is a great desire to deploy WDM technology and further optimize this with wavelength routing, as shown in Fig. 6.2. The overall fiber optic network will be mesh architecture [81] [147] [149]. The key nodes will be the big utilities or control centres. Together they set up the core optical network. Data transmission will set up on this network over IP protocol.

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FIGURE 6.2 IP over WDM fiber optic network

Fiber optic technologies have developed rapidly over the last 15-20 years. All-Optical cross connects and All-Optical Add-drop multiplexers enable the evolution from simple point-to-point WDM links to full networks. Fig. 6.3 shows detailed fiber optic network architecture. Consisting of N-full duplex ports, where each of which can connect to any other device, an OXC is a large photonic switch. An OADM is a 2 × 2 degenerate form of the NN × OXC. An OADM extracts and reinserts certain light paths for local use and routes the others through. End user OXC Router

OXC OXC Long distance mesh network (100s–100s km)

OXC OEO OXC

OXC OXC

Metro distance network (10s–100s km)

OXC OXC

Local area network (1s–10s km)

End user

Router

End user

OXC

Router

OXC OADM

OADM GigE

GigE GigE

Local area network

Router

End user

FIGURE 6.3 Detailed fiber optic network architecture

Physical Layer The layer at which signals are exchanged is known as the physical layer. Based on fiber optic along the distribution feeders or single mode fiber installed in the substation, is the feature of the physical layer. While bit rates can be OC-48 (2.5 Gbs)/OC–192 (10 Gbps) or higher, transmitting options are based on laser.

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Data Link Layer Responsible for delimiting data fields, the link layer, above the network layer, makes acknowledgement of receipt of data and error control and the capabilities. Receipt of information that passes the error check is acknowledged to the sending station, in most of the communication systems. When two devices of different speeds try to communicate; the data link layer, may communicate; the data containing a flow control mechanism. By using flow control mechanism, message first time transmitted, can be ensured to all traffic in fiber optic network. In combination with the antibody algorithm, fiber optic network can help guarantee minimum network congestion. Application Layer The application layer will be allocated to power system communication. For information exchange between utilities and substations, the wide area fiber optic network can be used. Information such as rate schedules, operating constraints, available transmission capacity can be shared between different users of power system.

6.5

LOCAL AREA SUBSTATION NETWORK DESIGN

Due to implementation of advanced computer and network technologies, at present, substation automation tends to be more complicated. For the proper protection and control operations, real time information acquired by IED must be transmitted under few milliseconds. Real time, high speed communication links between station unit is in demand. A large number of power equipment, supported by an efficient communication system, is required for this type of substation system. The optic fiber choice as transmission medium, guarantee the robustness against EMI (Electrical Magnetic Interference).

6.5.1 Substation Communication Network Requirement The automation system has the following needs: • Data acquisition: Analog and digital information are included in the data, from the equipment in the substation. With the provisioning of consolidated metering, alarm and status information, local operations are facilitated. • Control and monitoring: A monitoring system is needed for substation level control. Between the control centre, local substation and IEDs a control hierarchy can be implemented. • High availability and redundancy: The “no single point of failure” communication criterion, system, must be guaranteed.

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• Capability for future expansion: Easy future communication expansion, should be allowed by the system.

6.5.2 Substation Communication Network Architecture As shown in Fig. 6.4, the proposed all-fiber substation communication network architecture can be divided into three levels. IEDs or PLCs (Programmable Logic Controllers) connected to substation equipment is incorporated in level 1. These PLCs or IEDs are classified either as control or protection IEDs. The purpose of protection IEDs is to report the equipment status information and implement the protection algorithms. The purpose of control IEDs are to act as gateway between substation server and protection IED. Substation server makes up level 2. All control and monitoring operations can be performed anytime. Communication between substation server and control centre server takes place, for information exchange. The utility control server makes up level 3. The entire substation system is monitored and controlled by the utility control server. Various LAN topologies such as FDDI (Fiber Distributed Data Interface) or Giga Byte Ethernet, can be used for substation automation system design.

Scada server

Scada server

Scada server

Level 3 Control centre

Switch

Substation server

Level 2 Substation

Switch Control IED Control IED

Protection IED

Protection IED

Control IED

Level 1 Substation

Protection IED

FIGURE 6.4 Substation communication network

6.6

TIME DATA COMMUNICATION AND EXCHANGE

Applications based on the suite of transmission control protocol/user diagram protocol/ real time protocol/internet protocol/HTTP (TCP/UDP/ RTP/IP/HTTP) protocols [81] [148] [150] [151], or commonly referred to

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as IP protocol form the largest segment of traffic. IP protocol is clearly the convergence layer in today’s data communication network. In the new future, it is no doubt, that IP protocols, will expand its service to multiservice networks. Transportability over a broad variety of data link layer protocols and underlying network frequencies, is a features of IP based data. For real time information transmission through the network an IP based protocol such as TCP/IP can be used.

6.6.1 ISO-OSI Network Architecture The four-layered internet architecture is commonly used instead of the generic seven layered model and has been illustrated in Fig. 6.5. [81] [148] [150] • Network layer: Raw data transmission is performed in this layer. This layer is implemented by a combination of hardware (NICNetwork Interface Card) and software (NIC driver). FDDI Ethernet are commonly used networks defined in this layer. • IP layer: Internet Protocol fits within the content of the IP layer. IP supports multiple interconnected networks into one logical network. • TCP/UDP: In-order to provide logical channels to application programs TCP and UDP are utilized. Both IP/TCP are most commonly used IP based protocols. • Application layer: User defined applications are supported by application layer.

User application

SMTP/FTP...

TFTP/NFS...

User application

UDP

TCP Internet protocol Network layer

FIGURE 6.5 Internet architecture

6.6.2 IP, TCP and UDP Operating as a network layer protocol, Internet Protocol (IP) [81] [148] [150] [151] is responsible for routing addressing and package delivery. Internet Protocol (IP) does not handle assured delivery, package division, sequencing or error correction.

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UDP [146] [148] [149] does not add much service to the underlying IP. A mechanism of sending packets called datagrams is simply provided by IP. The arrival of data neither the order of arrival nor important are guaranteed. For large volume and non-critical data transmission like stream audio and video UDP is normally used. The TCP [146] [148] [149] offers connection-oriented byte-stream service to the data transmission. The features are very important for power system data transmission, since when data sent to the control centre or a command is issued through the network, each bit will be very critical for the correct information interpretation. Reliability facilities to the IP protocol such as error detection and correction, flow control, resequencing and duplicated segments management, are added by TCP [146] [148] [149].

CHAPTER

7 Conclusions

CONCLUSION TO CHAPTER THREE ON PROTOCOLS Substation communications and ongoing communication standardization are addressed in this chapter. Substation Integration and Automation are becoming the tools that can help utility to achieve reduced installation, maintenance and operation costs. This is possible because of the integration of microprocessor based IEDs/relays into Substation or even Power System Integration Systems. In this chapter, the IEC61850 and the Utility Communications Architecture (UCA) protocols have been discussed. By providing innovative, simple to use, robust technologies for power system protection, automation, control and monitoring; power providers are focussed on increasing productivity and making electric power safer, more reliable and more economical. The transmission of data along the utility powerline network is called Powerline Communication. Powerline Communication eliminates the need to rewire houses and buildings with separate communication links. The fact that the physical network is already installed over a wide area is the main advantage of powerline communications. In substation environments the following main protocols have been found widespread. The MODBUS, Distributed Network Protocol (DNP), IEC-870-5-101 and UCA in particular have extensive use. The DNP-2 protocol is implemented in 0.8 µm CMOS process, with a target of 50 MHz clock rate. This chip features a power dissipation of 2 Watts at 50 MHz and has 299 pins. The silicon size measures 11.5 × 11.5 mm2

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and integrates 60,000 gates excluding on chip memory of DNP-2. The DNP has a peak performance of around 50 MCPS. Its use of object models of devices and device components is the main difference in UCA from the previously designed and used protocols. The common data formats; identifiers, controls for substation and feeder devices can be defined with the use of object models of devices and device components. The models specify standardized behaviour for most common device functions and allow for significant vendor specialization for future innovation. The IEC 61850 protocol identifies all the known functions in a substation automation system and splits them into sub-functions or so-called logical nodes. A logical node is a sub-function located in a physical node, which exchanges data with other separate logical entities. In IEC 61850, all logical nodes have been grouped according to their most common applications area, a short textual description of the functionally, a device function number if applicable and the relationship between logical nodes and functions. The introduction of UCA and IEC61850 has made it justifiable and possible to integrate station IEDs through standardization. Utility Engineers can eliminate, many expensive stand-alone devices and use the sophisticated functionality and the available data to their full extent, using the standardized high-speed communications between IEDs.

OVERALL CONCLUSION TO IEC61850 AND DNP-3 Recent developments with communication media and protocols, networking technology, computing devices and substation equipment have presented major new opportunities for utilities to improve their electric systems, operations, and business process automations. One area of significant development is with applications that can involve communications to substations such as: • SCADA • Interfacing to a power line carrier AMR and/or load management system • Video (for physical security or equipment observation) • Mobile data hotspots • Voice over IP • Relay, control, and meter configuration-related functions • Retrieval of disturbance information • Communication network management • Physical access security such as card readers

CONCLUSIONS

337

• Communications link to down-line devices for distribution automation and, • Remote access from the substation to central application servers. Each of these applications impact the communications network, cyber security needs, plans and designs for substation equipment, and head-end software applications. There are numerous details that go into navigating this new technology “landscape”. The focus of this presentation is to look at the communication protocol situation for substations given this wide range of applications. It was not that long ago when the applications using communications at the substation might have been limited to SCADA, AMR data backhaul, and a dial-up phone for voice communication or possible ad hoc data retrieval from a meter or set of relays. In terms of protocol choice, the major question might have been what to user for SCADA. Today, a substation can have numerous communication protocols supporting a wide variety of applications. This situation developed partly as a result to the board acceptance and support of IP-based communications to substations. This support comes in the form of numerous substation devices supporting TCP/IP communications and perhaps hundreds of different wireless communication products. In addition, through small on a percentage basis, there are a growing number of substations with access to fiber optics for communications. Communication messages for an application typically involve multiple layered protocols such as a file transfer application using FTP, connection application using TCP/IP, or a connection less application using UDP/IP, all over Ethernet. Modern communication networks to substations will often have multiple application layer protocols running ‘‘on top of’’ TCP/IP and the lower-level data link and physical layer protocols. Some examples of water communications to a substation could involve today include: • TCP, UDP (user datagram protocol), IP, Ethernet • DNP3 and DNP3 over IP • IEC 61850-compliant standards • XML • SNMP • FTP • COMTRADE file formats (with protocol having file transport capability) • HTTP

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• Vendor-specific protocols to run their intelligent electronic device (IED) software packages remotely • Radio diagnostic protocols • Video protocols • VoIP • Security card reader protocols and, • Mobile application protocols. For cyber security purposes, there may be more than one IP network or the set of applications supported may be limited to the most critical substations. The bottom line is that today’s technology allows utilities to run multiple protocols. Two important communication standards that have unique positions in the industry are IEC 61850 and DNP3. Some utilities have already jumped into implementing IEC 61850. Give the continual expectation and move to improve information technology to achieve better results, it seems reasonable to assume that, in time, most all utilities will move to an object-oriented, standardized approach to substation automation and other application area that can benefit from the same technology. The different question is probably more when it will make sense for a particular utility’s situation give the state of their existing systems, their objective and the state of technology that might meet the needs. While IEC 61850 has gained some momentum with completion of the standard and the availability of more vendor products, other technology and standard as well as IEC 61850 will continue to evolve, much like DNP3’s move to incorporate some of the IEC 61850 self-description capability. There is still no silver bullet answer or solution, but there are great new opportunities. When moving to take advantage of opportunities, it will continue to be important for any utility to understand the quality and interoperability of the technology they are looking at regardless of the standards it adheres to. Due diligence with requirements definition, design and implementation will continue to be essential for a successful project.

CONCLUSION TO CHAPTER FOUR ON MIDDLEWARE Open standardized communication interfaces are needed as deregulation of the energy market has increased the importance of data, in a scenario where a lot more data has been necessary. Since the early 90s many attempts have been made to define the standardized communication protocol and the need to integrate protection, control and data acquisition on the substation Local Area Network (LAN).

CONCLUSIONS

339

The three basic sets of requirements when choosing a communication protocol are performance, interoperability and maturity. In order to address the challenge of interoperability, a new class of software middleware has risen. Provided by the communications processor, middleware software, is a layer between the networking code and the application code. The function of the middleware is to insulate the application programmer from the raw networking code thus providing an easier way to communicate. In this chapter, middleware requirements for remote monitoring, protection and control applications have been discussed. For achieving success in substation automation, the use of the appropriate middleware is crucial. The three main types of middleware architectures, namely, Point-to-Point Architectures, Client-Server Architectures and Publish-Subscribe Architectures have each played a key role in substation automation. Distributed-real-time communications in the substation environment can be realized using the publish-subscribe architectures. The process of trading-off reliability of delivery for greater determinism is crucial for multicasting GOOSE state change message. Sending the most recent GOOSE message is much more important than resending old updates, which would probably be out-of-date when they are delivered anyway. When communication protocols are designed for guaranteed delivery but less-than-reliable medium, than an important problem arises in the case of failed transmissions. What happens is that the communication protocol would be stuck trying to transmit the failed tranmissions wasting time and destroying the timing determinism. In this case, the best policy would be to send the latest update disregarding the earlier updates. In electric Control and Protection applications, there is a need for a synchronisation time of 10ms. There is such a stringent requirement for time synchronization across the distributed system, particularly due to the phase differences among generators. In any remote monitoring, protection and control systems, there is a clear mechanism of one type for the notification of interesting events, when remote sites notify the monitoring sites. Ideally, important events (such as power system faults) need to be pre-defined so that the system can listen to specific types of events to produce asynchronous, persistant and multicast event notification. When combined with publish-subscribe architectures, data push architectures, enables users to distribute data to a large and variable set of remote applications.

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There is clearly a need for new middleware functions in order to enforce the security requirements of server authentication, client authentication, confidentiality and non-repudation. Only if it is capable of managing priorities, controlling memory usage and restricted access to system resources can the effective running on the communication processor and the network software be effective on the communications processor. The needed communication model time stamps each transaction, allows the application software to trade-off timing against reliable delivery, controls and specifies memory usage, allows for adaptive synchronization scheme, event notification and the functions required to meet with the security measures and works in a real-time communications processor environment. The three types of subscription mechanisms that consumers can generally make use of when subscribing to information are channel-based subscription, subject-based subscriptions and context-based subscriptions. There are three messaging concepts which are Unicast messaging, Multicast messaging and Broadcast messaging. CORBA aims at providing uniform communication infrastructure for building distributed applications. CORBA enables running application analysis, monitorization and simplifies system evolution. CORBA, nowadays, is the best suitable platform for distributed systems construction due to its ability to provide good mixture of performance, resource consumption and good support in the early phases of system engineering life cycles.

CONCLUSION TO CHAPTER FIVE ON INFORMATION EMBEDDED POWER SYSTEM Information embedded power system is an extension of traditional power systems. When a traditional power system has added monitoring, control and telecommunication capabilities, then it is known as an information embedded power system. The system consists of power system hardware, the measurement system (RTUs), the communication system and the electric utility control centre. In this system, the RTU computers record power system measurements and send them in real time over a computer network (LAN/ WAN) to the power control centre. Demands to integrate, consolidate and disseminate information quickly and accurately between and within utilities is expanding and creating electric utility deregulation. It is necessary to have a global vision

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341

of the network situation in the deregulated power industry. That means, the measures acquired locally in the RTUs should be transmitted to a provincial control centre. The information from these provisional control centres is transmitted to a control centre of higher level such as regional, in which a more global vision of electric network can be obtained. World-wide adoption and very well developed hardware are some of the main advantages of WAN networking. The simplicity and choice of application layer protocols, inherent resilience of the IP routing concept and strong network management, including remote control and management have been very well developed. For both operational and non-operational requirements, WAN represents the opportunity to migrate to a single network. Reliable, real time gathering of a range of power system parameters will enable power delivery system operators to detect and counteract abnormal over a wide georgraphical area, thus enabling the power delivery system to operate safely to its inherent limits. Real-time information needed for integrated control of a large highly interconnected transmission network, will be provided, by a broader implementation of IEPS-W like system. Integrating all required parameters for the modern power system communication, looks very promising and is known as IEPS-W. Temporarily rendering parts of the power system unobservable, large amounts of computer network traffic may result in large measurement errors. Bounded time delay and guaranteed transmission are two main criteria, that must be met by computer networks. Several buses in the power system will become unobservable, because of unsuccessfully transmitted large time-delay messages from the RTUs to control centre. Traditional power system monitoring methods assume that the state of the power system remains unchanged during the time it takes to deliver a newly recorded set of measurements to a control centre. Before employing sophisticated and realistic IEPS-W model, utility must ensure through experimental analysis that this model meets the communication delay acceptable be electrical power industry.

CONCLUSION TO CHAPTER SIX ON FIBER OPTIC NETWORK INFRASTRUCTURE AS NEXT GENERATION POWER SYSTEM COMMUNICATIONS In this chapter, Fiber Optic Network Infrastructure has been discussed. Fiber Optics is the next generation power system communication medium.

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For protection, control and information sharing functions Power Line Carrier (PLC), microwave, pilot wire and wireless are some of the different media that have been used. The most common media in the U.S.A. is PLC. Limitations in bandwidth is a disadvantage of PLC. PLC is subject to lightening, switching surges and network reconfiguration. Microwave has disadvantages such as transmission length being limited to sight path between antennas, atmospheric attenuation and distortion. Pilot wire overhead lines may experience interference from power lines while the underground is subject to damages. Wireless communication has to deal with delays in propotion to distance and the cost of installation. With more and more bandwidth required, Fiber Optic will be the ideal choice for future communications infrastructure. Fiber Optic system is the most suitable data transmission medium for power system control, protection and monitoring functions. The particular characteristics of the optic fibers that contribute to its advantages are: low attenuation, high bandwidth, electromagnetic interface immunity and security. Widely used features in optic fibers are OADMs, Amplifier technology, Transmitters, Amplifier Technology, Amplifiers and Optical packet switches. The multi-layer topology forms the basis of current optic fiber networks. Without the need of an information management methodology and wide area communication architecture, fiber optics will not effectively contribute to power system communication. To facilitate an effective substation communication network, the automation system has the following needs of data acquisition, control and monitoring, high availability and redundancy as well as capability for future expansion. For substation automation system design, various LAN topologies such FDDI (Fiber Distributed Data Interface) or Giga Byte Ethernet, can be used. For the purpose of supporting the Fiber network infrastructure, a four (4) layered internet architecture has been adopted instead of the seven (7) layered model and has been both illustrated and discussed in the network, layer, IP layer, TCP/UDP and Application layer. A functional discussion, IP, TCP and UDP have been made. In this chapter, the vital features of Chapter 3 on Protocols, Chapter 4 on Middleware, Chapter 5 on Information Embedded Power Systems and Chapter 6 on Fiber Optic Network Infrastructure as Next Generation Power Systems Communications has been discussed succinctly.

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143. Pokorny, J., “XML Functionally”, Database Engineering and Applications Symposium, 2000, pp. 266–74. 144. Rollins, S., Sundaresan, N., “A Framework for Creating Customized Multi-modal Interfaces for XML Documents”, IEEE International Conference on Multimedia and Expo, Vol. 2, 2000, pp. 933–36. 145. Suresh, R., Shukla, P., Schwenke, G., “XML-based Data Systems for Earth Science Applications”, IEEE 2000 International Symposium on Geosciences and Remote Sensing (IGRASS) Proceedings, Vol. 3, 2000, pp. 1214–16. 146. Buchner, A.G., Baumgarten, M., “Data Mining and XML: Current and Future Issues”, Web Information Systems Engineering, Vol. 2, 2000, pp. 131–35. 147. Harold Kirkham, Alan, Johnson, R., “Design Consideration for a Fiber Optic Communications Network for Power Systems”, IEEE Transaction on Power Delivery, Vol. 9, No. 1, January 1994, pp. 510–18. 148. Sabir, S., Mahoney, H., “Building a Backbone for Integrated Business Communications”, IEEE Computer Applications in Power, Vol. 9, Issue 1, February 1996, pp. 38–41. 149. Washburn, K., Evans, J.T., “TCP/IP – Running Successful Network”, Addison-Wesley Publishing Company, 1998. 150. Larry, L. Peterson and Bruce, S.D., Computer Network: A System Approach, Morgan Kaufmann, 2000. 151. IEEE Communication Protocol Tutorial, February 1995. 152. Mohammad Shahidepur, Yaoyu Wang, “Communication and Control in Electric Power Systems” IEEE Press, Wiley Interscience, A. John Wiley & Sons, Inc., Publication, 2003. 153. Kothari, D.P., and Nagrath, I.J., “Modern Power System Analysis”, McGraw-Hill, New York, 2006. 154. Kothari, D.P. and Nagrath, I.J., “Power System Engineering”, 2nd edn. Tata McGraw-Hill, New Delhi, 2007. 155. Triangle Micro Works Inc, ‘‘DNP 3 Overview’’, 2002, [Online] Available: http://www.TriangleMicroWorks.com. 156. Lebakken, T.M. and Orlando, D.R., ‘‘Substation Automation and Communication Standard: IEC 61850 and DNP3’’, 2009.

Index

Aliasing

203 Amplitude and phase comparison 173 Amplitude comparator 176 Application layer 331 Average comparator 192

‘B’ type fuses

137 Back to back bridge 186 Back up relaying 14, 15 Balanced voltage scheme 216 Biased differential 212 Binding 298 Blind spot 224, 225 Block-average comparator 190 Breaking capacity 163 Broadcast messaging 297, 340

Capacitor divider

84 Channel-based 295 Circulating current 216 Client-server architectures 289, 339 Committed access rate mechanism 301 Common multiple earthed neutral 65 Communication protocol stack 311

Confidentiality 293 Context-based 295 Conventional fusing current 162 Conventional non-fusing current 162 CORBA 340 Core saturation 94 Current transformers 168 Custom queuing 301

‘D’ type fuselink

136 Data link layer 331 Data push architectures 292 Data transport control 313 Datagrams 334 Dedicated links 325 Derived burden 95 Dial-out 249 Differential protection 209 Digital relay 198 Directional relay 178 Discrimination 20 Distance relay 169 Distance protection 167 Distributed network protocol 265 Double switching 10

356

POWER SYSTEM PROTECTION AND COMMUNICATIONS

Duplicate primary relaying 16 Duplicated protection 75

Earth fault

183 Earth fault current limitation 65 Earth fault protection 122 Earth potential rise code 60 Eavesdrop communications 250 Erbium doped fiber amplifier 327 Expulsion fuses 142

Fault current paths

73 Fault resistance 200 FDDI 342 Ferro-resonance 83 Filtering 298 Fixed time reference comparator 189 Footing resistance 200 Fulgurite 146 Fully cross-polarised 193 Fuseholder 126 Fuselinks 134 Fusion factor 127

GOOSE

339 Grading by current 113 Grading margin 121

High fidelity CVT

83 Heat sink effect 130 High speed schemes 92 High voltage cartridge fuse 128

Impedance measurement

172 Impedance relay 177 Instrument transformers 167 Inter-control centre 318 Inverse definite minimum time 102 Inverse overcurrent relay 211 IP routing 341

Knee-point e.m.f.

87

Liquid fuse

141 Local back up 15, 225, 226 Low pass filter 195 Low speed schemes 92 Low voltage cartridge fuse 128

Magnetising impedance

211 Major fuse 157 Management application interface 314 Mann-Morrison algorithm 204 Master-slave communication 286 Maximum prospective current 164 Memory circuit 194 Metcalf 130 mho 171 Microwave 325 Middleware 288 Miniature type 128 Minimum fusing current 127, 151 Minor fuse 157 Multicast messaging 296, 340

Negative sequence impedances

31

Non Unit schemes 18, 219

OADMs

330, 342 Normal operation 3 Overcurrent protection 167 Overreach relay 179

Peak arc voltage

146 Peer-to-Peer direct connection 254 Phase comparator 176 Phase faults 184 Physical layer 330 Pilot wire 324 Plug fuse 140 Plug setting multiplier 103 Point-to-Point architectures 289, 339 Positive sequence impedances 31 Power line carrier 325

357

INDEX

Power transformer 213 Powerline communication 335 Pre-arcing time 150, 155 Prevention of electrical failure 3 Primary relaying 14 Priority queuing 301 Process bus 287 Prospective voltage 214 Protocol gateway 248 Publish-subscribe architectures 289, 339 Publish/Subscribe middleware 294 Pulse type phase comparator 188

Radio systems

325 Reactance relay 178 Remote back up 224 Remote monitoring 339 Remote terminal unit 261 Resistance 179 Resource reservation protocol 301 Restricted earth fault 221 Router 249 RTUs 340

Safety earthing

55 Safety margin 121 Sallen and Kelly 195 Self-polarised 193 Semi-enclosed fuse 133 Semiconductor optical amplifier 327 Servers 249 Single switching 9

Station earthing 58 Subject-based 295 Subtransient impedance 6 Summation transformer 216 Switched distance 170 Symmetrical components 31 Synchronisation 291 Synchronous impedance 6 System earthing 54 Time grading 197 Time multiplier setting 103 Time synchronization broadcast 250 Tower-footing resistance 4 Transactor 192 Transducers 84 Transient impedance 6

Underreach relay 179

Unicast messaging 296, 340 Unit protection 19 Unit schemes 219

Voltage transformers

168 Voltage-controlled voltage source (VCVS) 195

WAN

340 Warrington’s formula 200 Weighted fair queuing 301 Wide area communication 329

Zero sequence impedances

31