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Who is IDC Technologies?

IDC Technologies is a specialist in the field of industrial communications, telecommunications, automation and control and has been providing high quality training for more than six years on an international basis from offices around the world.

IDC consists of an enthusiastic team of professional engineers and support staff who are committed to providing the highest quality in their consulting and training services.

The Benefits to you of Technical Training Today

The technological world today presents tremendous challenges to engineers, scientists and technicians in keeping up to date and taking advantage of the latest developments in the key technology areas.

  • The immediate benefits of attending IDC workshops are:
  • Gain practical hands-on experience
  • Enhance your expertise and credibility
  • Save $$$s for your company
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  • Learn new approaches to troubleshooting
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The IDC Approach to Training

All workshops have been carefully structured to ensure that attendees gain maximum benefits. A combination of carefully designed training software, hardware and well written documentation, together with multimedia techniques ensure that the workshops are presented in an interesting, stimulating and logical fashion.

IDC has structured a number of workshops to cover the major areas of technology. These courses are presented by instructors who are experts in their fields, and have been attended by thousands of engineers, technicians and scientists world-wide (over 11,000 in the past two years), who have given excellent reviews. The IDC team of professional engineers is constantly reviewing the courses and talking to industry leaders in these fields, thus keeping the workshops topical and up to date.

Technical Training Workshops

IDC is continually developing high quality state of the art workshops aimed at assisting engineers, technicians and scientists. Current workshops include:

Instrumentation & Control

  • Practical Automation and Process Control using PLC’s
  • Practical Data Acquisition using Personal Computers and Standalone Systems
  • Practical On-line Analytical Instrumentation for Engineers and Technicians
  • Practical Flow Measurement for Engineers and Technicians
  • Practical Intrinsic Safety for Engineers and Technicians
  • Practical Safety Instrumentation and Shut-down Systems for Industry
  • Practical Process Control for Engineers and Technicians
  • Practical Programming for Industrial Control – using (IEC 1131-3;OPC)
  • Practical SCADA Systems for Industry
  • Practical Boiler Control and Instrumentation for Engineers and Technicians
  • Practical Process Instrumentation for Engineers and Technicians
  • Practical Motion Control for Engineers and Technicians
  • Practical Communications, SCADA & PLC’s for Managers


  • Practical Data Communications for Engineers and Technicians
  • Practical Essentials of SNMP Network Management
  • Practical Field Bus and Device Networks for Engineers and Technicians
  • Practical Industrial Communication Protocols
  • Practical Fibre Optics for Engineers and Technicians
  • Practical Industrial Networking for Engineers and Technicians
  • Practical TCP/IP & Ethernet Networking for Industry
  • Practical Telecommunications for Engineers and Technicians
  • Practical Radio & Telemetry Systems for Industry
  • Practical Local Area Networks for Engineers and Technicians
  • Practical Mobile Radio Systems for Industry


  • Practical Power Systems Protection for Engineers and Technicians
  • Practical High Voltage Safety Operating Procedures for Engineers & Technicians
  • Practical Solutions to Power Quality Problems for Engineers and Technicians
  • Practical Communications and Automation for Electrical Networks
  • Practical Power Distribution
  • Practical Variable Speed Drives for Instrumentation and Control Systems

Project & Financial Management

  • Practical Project Management for Engineers and Technicians
  • Practical Financial Management and Project Investment Analysis
  • How to Manage Consultants

Mechanical Engineering

  • Practical Boiler Plant Operation and Management for Engineers and Technicians
  • Practical Centrifugal Pumps – Efficient use for Safety & Reliability


  • Practical Digital Signal Processing Systems for Engineers and Technicians
  • Practical Industrial Electronics Workshop
  • Practical Image Processing and Applications
  • Practical EMC and EMI Control for Engineers and Technicians

Information Technology

  • Personal Computer & Network Security (Protect from Hackers, Crackers & Viruses)
  • Practical Guide to MCSE Certification
  • Practical Application Development for Web Based SCADA

Comprehensive Training Materials

Workshop Documentation

All IDC workshops are fully documented with complete reference materials including comprehensive manuals and practical reference guides.


Relevant software is supplied with most workshops. The software consists of demonstration programs which illustrate the basic theory as well as the more difficult concepts of the workshop.

Hands-On Approach to Training

The IDC engineers have developed the workshops based on the practical consulting expertise that has been built up over the years in various specialist areas. The objective of training today is to gain knowledge and experience in the latest developments in technology through cost effective methods. The investment in training made by companies and individuals is growing each year as the need to keep topical and up to date in the industry which they are operating is recognized. As a result, the IDC instructors place particular emphasis on the practical hands-on aspect of the workshops presented.

On-Site Workshops

In addition to the quality of workshops which IDC presents on a world-wide basis, all IDC courses are also available for on-site (in-house) presentation at our clients’ premises. On-site training is a cost effective method of training for companies with many delegates to train in a particular area. Organizations can save valuable training $$$’s by holding courses on-site, where costs are significantly less. Other benefits are IDC’s ability to focus on particular systems and equipment so that attendees obtain only the greatest benefits from the training.

All on-site workshops are tailored to meet with clients training requirements and courses can be presented at beginners, intermediate or advanced levels based on the knowledge and experience of delegates in attendance. Specific areas of interest to the client can also be covered in more detail. Our external workshops are planned well in advance and you should contact us as early as possible if you require on-site/customized training. While we will always endeavor to meet your timetable preferences, two to three month’s notice is preferable in order to successfully fulfil your requirements. Please don’t hesitate to contact us if you would like to discuss your training needs.

Customized Training

In addition to standard on-site training, IDC specializes in customized courses to meet client training specifications. IDC has the necessary engineering and training expertise and resources to work closely with clients in preparing and presenting specialized courses.

These courses may comprise a combination of all IDC courses along with additional topics and subjects that are required. The benefits to companies in using training are reflected in the increased efficiency of their operations and equipment.

Training Contracts

IDC also specializes in establishing training contracts with companies who require ongoing training for their employees. These contracts can be established over a given period of time and special fees are negotiated with clients based on their requirements. Where possible, IDC will also adapt courses to satisfy your training budget.

References from various international companies to whom IDC is contracted to provide on-going technical training are available on request.

Some of the thousands of Companies worldwide that have supported and benefited from IDC workshops are:

Alcoa, Allen-Bradley, Altona Petrochemical, Aluminum Company of America, AMC Mineral Sands, Amgen, Arco Oil and Gas, Argyle Diamond Mine, Associated Pulp and Paper Mill, Bailey Controls, Bechtel, BHP Engineering, Caltex Refining, Canon, Chevron, Coca-Cola, Colgate-Palmolive, Conoco Inc, Dow Chemical, ESKOM, Exxon, Ford, Gillette Company, Honda, Honeywell, Kodak, Lever Brothers, McDonnell Douglas, Mobil, Modicon, Monsanto, Motorola, Nabisco, NASA, National Instruments, National Semi-Conductor, Omron Electric, Pacific Power, Pirelli Cables, Proctor and Gamble, Robert Bosch Corp, Siemens, Smith Kline Beecham, Square D, Texaco, Varian, Warner Lambert, Woodside Offshore Petroleum, Zener Electric


Preface xi

Chapter 1 — Need for protection 1

1.1 Need for protective apparatus 1

1.2 Basic requirements of protection 2

1.3 Basic components of protection 2

1.4 Summary 3

Chapter 2 — Faults, types and effects 5

2.1 The development of simple distribution systems 5

2.2 Faults-types and their effects 7

Chapter 3 — Simple calculation of short circuit currents 13

3.1 Introduction 13

3.2 Revision of basic formulae 13

3.3 Calculation of short circuit MVA 18

3.4 Useful formulae 21

3.5 Cable information 26

Chapter 4 — System Grounding 29

4.1 Introduction 29

4.2 Grounding devices 30

4.3 Evaluation of grounding methods 33

4.4 Effect of electric shock on human beings 35

Chapter 5 — Fuses 39

5.1 Historical 39

5.2 Re-wireable type 39

5.3 Cartridge type 40

5.4 Operating characteristics 40

5.5 British standard 88:1952 41

5.6 Energy ‘let through’ 42

5.7 Application of selection of fuses 43

5.8 General ‘�rules of thumb’ 44

5.9 Special types 44

5.10 General 45

5.11 IS-limiter 46

Chapter 6 — Instrument transformers 51

6.1 Purpose 51

6.2 Basic theory of operation 51

6.3 Voltage transformers 52

6.4 Current transformers 62

6.5 Application of current transformers 76

6.6 Introducing relays 77

6.7 Inverse definite minimum time lag (IDMTL) relay 79

Chapter 7 — Circuit breakers 83

7.1 Introduction 83

7.2 Protective relay — circuit breaker combination 83

7.3 Purpose of circuit breakers (switchgear) 85

7.4 Behavior under fault conditions 86

7.5 Arc 87

7.6 Types of circuit breakers 88

7.7 Comparison of breaker types 97

Chapter 8 — Tripping batteries 109

8.1 Tripping batteries 109

8.2 Construction of battery chargers 115

8.3 Maintenance guide 116

8.4 Trip circuit supervision 120

8.5 Reasons why breakers and contactors fail to trip 121

8.6 Capacity storage trip units 122

Chapter 9 — Relays 125

9.1 Introduction 125

9.2 Principle of the construction and operation of the IDMTL relay 126

9.3 Factors influencing choice of plug setting 138

9.4 The new era in protection - microprocessor vs electronic vs traditional 139

9.5 Universal microprocessor overcurrent relay 147

9.6 Technical features of a modern microprocessor relay 148

9.7 Type testing of static relays 158

9.8 The future of protection for distribution systems 159

9.9 The era of the IED 161

9.10 Substation automation 164

9.11 Communication capability 167

Chapter 10 — Co-ordination by time grading 179

10.1 Introduction 180

10.2 What is coordination? 180

10.3 Over-current coordination 181

10.4 Protection design parameters on medium and low voltage networks 186

10.5 Sensitive ground fault protection 205

Chapter 11 — Low voltage network 207

11.1 Introduction 207

11.2 Air circuit breakers 207

11.3 Moulded case circuit breakers 209

11.4 Application and selective co-ordination 218

11.5 Ground leakage protection 223

Chapter 12 — Mine underground distribution protection 229

12.1 General 229

12.2 Ground leakage protection 230

12.3 Pilot wire monitor 233

12.4 Ground fault lockout 235

12.5 Neutral grounding resistor monitor (NERM) 235

Chapter 13 — Principles of unit protection 247

13.1 Protective relay systems 247

13.2 Main or unit protection 247

13.3 Back-up protection 248

13.4 Methods of obtaining selectivity 248

13.5 Differential protection 248

13.6 Transformer differential protection 251

13.7 Switchgear differential protection 252

13.8 Feeder pilot-wire protection 252

13.9 Time taken to clear faults 252

13.10 Recommended unit protection systems 253

13.11 Advantages of unit protection 253

Chapter 14 — Feeder protection cable feeders and overhead lines 255

14.1 Introduction 255

14.2 Translay 255

14.3 Solkor protection 256

14.4 Distance protection 260

Chapter 15 — Transformer protection 289

15.1 Winding polarity 289

15.2 Transformer connections 290

15.3 Transformer magnetizing characteristics 291

15.4 In-rush current 292

15.5 Neutral grounding 294

15.6 On-load tap changers 295

15.7 Mismatch of current transformers 296

15.8 Types of faults 296

15.9 Differential protection 299

15.10 Restricted ground fault 303

15.11 HV overcurrent 308

15.12 Protection by gas sensing and pressure detection 310

15.13 Overloading 312

Chapter 16 — Switchgear (busbar) protection 319

16.1 Importance of busbars 319

16.2 Busbar protection 320

16.3 The requirements for good protection 320

16.4 Busbar protection types 321

Chapter 17 — Motor protection relays 333

17.1 Introduction 333

17.2 Stalling of motors 343

17.3 Overcurrent/overload 346

17.4 Undervoltage/overvoltage 347

17.5 Underfrequency 348

17.6 Pole slip/out of step 348

17.7 Loss of excitation 349

17.8 Inadvertant energization 349

17.9 Overfluxing 349

17.10 Stall protection/acceleration time 350

17.11 Negative sequence events 352

17.12 Derating factors 354

17.13 Earth faults - core balance, residual stabilizing factors 355

17.14 Calculation of protective relay settings 356

17.15 Example 361

Chapter 18 — Generator protection 363

18.1 Introduction 363

18.2 Stator grounding and ground faults 364

18.3 Overload protection 366

18.4 Overcurrent protection 366

18.5 Overvoltage protection 367

18.6 Unbalanced loading 367

18.7 Rotor faults 367

18.8 Reverse power 370

18.9 Loss of excitation 370

18.10 Loss of synchronization 370

18.11 Field suppression 370

18.12 Industrial generator protection 370

18.13 Numerical relays 371

18.14 Parallel operation with grid 375

Chapter 19 — Cables and protection 377

19.1 Introduction 377

19.2 Advantages of cables over overhead transmission lines 379

19.3 Disadvantages of cables in power transmission 380

19.4 Types of cables 380

19.5 Cable jointing (splicing) accessories 381

19.6 Need for termination kits 382

19.7 Types of failures 383

19.8 Reasons for failure 384

19.9 Short circuit protection of underground cables 391

19.10 Cable protection applications 395

19.11 Fault location 399

19.12 Electrical tests for detection of cable faults 401

19.13 Analysis of failures 404

19.14 Documentation 408

Chapter 20 — Management of Protection 415

20.1 Management of protection 415

20.2 Schedule A 415

20.3 Schedule B 416

20.4 Test sheets 417

Appendix A — The Protection of Railway Traction Circuits 423

Appendix B — Typical Cable Data Sheets 433

Appendix C — Practical exercises on relay coordination 437

Appendix D — SIPROTEC4 7SA6 Distance Protection relay 443

Appendix E — SIPROTEC4 7SJ64 Feeder Management Relay 453

Appendix F — SIPROTEC4 7SD61 Line Differential Relay 463

Appendix G — SIPROTEC4 7SS60 Feeder Management Relay 473

Appendix H — SIPROTEC4 7UT6 Transformer Differential Relay 479

Appendix I — Arc Sensors 487

Appendix J — Integral Digital Protection Devices 495


This book has been designed to give plant operators, electricians, field technicians and engineers a better appreciation of the role played by power system protection systems. An understanding of power systems; along with correct management, will increase your plant efficiency and performance as well as increasing safety for all concerned. The book is designed to provide an excellent understanding on both a theoretical and practical level.

The book starts at a basic level, to ensure that you have a solid understanding of the fundamental concepts and also to refresh the more experienced readers in the essentials. The book then moves onto more detailed applications. It is most definitely not an advanced treatment of the topic and it is hoped the expert will forgive the simplifications that have been made to the material in order to get the concepts across in a practical useful manner.

The book features an introduction covering the need for protection, fault types and their effects, simple calculations of short circuit currents and system grounding. The book also refers to some practical work, such as simple fault calculations, relay settings and the checking of a current transformer magnetisation curve which are performed in the associated training workshop. You should be able to do these exercises and tasks yourself without too much difficulty based on the material covered in the book.

This is an intermediate level book – at the end of the book you will have an excellent knowledge of the principles of protection. You will also have a better understanding of the possible problems likely to arise and know where to look for answers.

In addition you are introduced to the most interesting and “fun” part of electrical engineering to make your job more rewarding. Even those who claim to be protection experts have admitted to improving their knowledge after studying this book; but this book will perhaps be an easy refresher on the topic enabling you to pass on knowledge to your less experienced colleagues.

We would hope that you will gain the following from this book:

  • The fundamentals of electrical power protection and applications
  • Knowledge of the different fault types
  • The ability to perform simple fault and design calculations
  • Practical knowledge of protection system components
  • Knowledge of how to perform simple relay settings
  • Increased job satisfaction through informed decision making
  • Know how to improve the safety of your site

Typical people who will find this book useful include:

  • Electrical Engineers
  • Project Engineers
  • Design Engineers
  • Instrumentation and
  • Engineers
  • Electrical Technicians
  • Field Technicians
  • Electricians
  • Plant Operators
  • Plant Operators

You should have a modicum of electrical knowledge and some exposure to electrical protection systems to derive maximum benefit from this book.

This book was put together by a few authors although initiated by the late Les Hewitson, who must be one of the finest instructors on the subject who presented this course in his own right in South Africa and throughout Europe/North America and Australia for IDC Technologies. It is to him that this book is dedicated.

Hambani Kahle (Zulu Farewell)
(Sources: Canciones de Nuestra Cabana (1980), Tent and Trail Songs (American Camping Association), Songs to Sing & Sing Again by Shelley Gordon)

Go well and safely.
Go well and safely.
Go well and safely.
The Lord be ever with you.

Stay well and safely.
Stay well and safely.
Stay well and safely.
The Lord be ever with you.

Hambani kahle.
Hambani kahle.
Hambani kahle.
The Lord be ever with you.


Steve Mackay
Series Editor FIE (Aust), CPEng, BSc(ElecEng), BSc(Hons), MBA


Need for protection

Important notes

  1. This book was originally written for UK and other European users and contains many references to the products and standards in those countries. We have made an effort to include IEEE/ANSI/NEMA references wherever possible. The general protection approach and theoretical principles are however universally applicable.
  2. The terms ‘earth’ as well as ‘ground’ have both been in general use to describe the common power/signal reference point interchangeably around the world in the Electro-technical terminology. While the USA and other North American countries favor the use of the term ‘ground’, European countries including UK and many other Eastern countries prefer the term ‘earth’. In this book, we will adopt the term ‘ground’ to denote the common electrical reference point. Our sincere apologies to those readers who would have preferred the use of ‘earth’ to the term ‘ground’.

1.1 Need for protective apparatus

A power system must be not only capable of meeting the present load but also requires the flexibility to meet the future demand. A power system is designed to generate electric power in sufficient quantity, to meet the present and estimated future demands of the users in a particular area, to transmit it to the areas where it will be used and then distribute it within that area, on a continuous basis.

To ensure the maximum return on the significant investment in the equipment, which goes to make up the power system, and to keep the users satisfied with reliable service, the whole system must be kept in operation continuously without major breakdowns.

This can be achieved in two ways:

  • The first option is to implement a system using components, which should not fail and which require minimal maintenance to maintain the continuity of service. However, implementing such a system is neither economical nor feasible, except for small systems.
  • The second option is to anticipate any possible effects or failures that may cause a long-term shutdown of a system, which in turn may take a longer time to bring the system back to its normal operation. The main idea is to restrict the disturbances during such failures to a limited area and maintain power distribution to the remaining areas. Special equipment is normally installed to detect such kind of failures (also called ‘faults’) that can possibly happen in various sections of a system, and to isolate faulty sections so that the interruption is limited to a localized area. The special equipment adopted to detect such possible faults is referred to as ‘Protective equipment or a protective relay’ and the system that uses such equipment is termed a ‘Protection system’.

A protective relay is the device, which gives instruction to disconnect a faulty part of the system. This action ensures that the remaining system is still fed with power, and protects the system from further damage due to the fault.

Hence, use of protective apparatus is very necessary in the electrical systems, which are expected to generate, transmit and distribute power with least interruptions and restoration time.

1.2 Basic requirements of protection

A protection system has three main functions/duties:

  • Safeguard the entire system to maintain continuity of supply.
  • Minimize damage and repair costs where it senses a fault.
  • Ensure safety of personnel.

These requirements are necessary, firstly for early detection and localization of faults and secondly, prompt removal of faulty equipment from service.

In order to carry out the above duties, protection must have the following qualities:

a) Selectivity: To detect and isolate the faulty item only.
b) Stability: To leave all healthy circuits intact to ensure continuity of supply.
c) Sensitivity: To detect even the smallest fault, current or system abnormalities and operate correctly at its setting before the fault causes irreparable damage.
d) Speed: To operate speedily when it is called upon to do so, thereby minimizing damage to the surroundings and ensuring safety to personnel.

To meet all of the above requirements, protection must be reliable which means it must be:

  • Dependable - it must trip when called upon to do so.
  • Secure - it must not trip when it is not supposed to.

1.3 Basic components of protection

The protection of any distribution system is a function of many elements and this section gives a brief outline of the various components that go into protecting a system. The following are the main components of a protection system.

  • A fuse self destructs and carries the currents in a power circuit continuously and sacrifices itself by blowing under abnormal conditions. These are normally independent OR stand-alone protective components in an electrical system unlike a circuit breaker, which necessarily requires the support of external components.
  • Accurate protection cannot be achieved without properly measuring the normal and abnormal conditions of a system. In electrical systems, voltage and current measurements give feedback on whether a system is healthy or not. Voltage transformers and current transformers measure these basic parameters and are capable of providing accurate measurement during fault conditions without failure.
  • The measured values are converted into analog and/or digital signals and are made to operate the relays, which in turn isolate the circuits by opening the faulty circuits. In most of the cases, the relays provide two functions viz., alarm and trip; once the abnormality is noticed. The relays in earlier times had very limited functions and were quite bulky. However, with the advancement in digital technology and use of microprocessors, relays monitor various parameters, which give a complete history of a system during both pre-fault and post-fault conditions.
  • The opening of faulty circuits requires some time, typically milliseconds. However, the circuit breakers, which are used to isolate the faulty circuits, are capable of carrying these fault currents until the fault currents are totally cleared. The circuit breakers are the main isolating devices in a distribution system, which can be said to directly protect the system.
  • The operation of relays and breakers require power sources, which shall not be affected by faults in the main distribution. Hence, the other component, which is vital in protective system, are batteries that are used to ensure uninterrupted power to relays and breaker coils.

The above items are extensively used in any protective system and their design requires careful study and selection for proper operation.

1.4 Summary

Power system protection-main functions
  1. To safeguard the entire system to maintain continuity of supply.
  2. To minimize damage and repair costs.
  3. To ensure safety of personnel.
Power system protection-basic requirements
  1. Selectivity: To detect and isolate the faulty item only.
  2. Stability: To leave all healthy circuits intact to ensure continuity of supply.
  3. Speed: To operate as fast as possible when called upon, to minimize damage, production downtime and ensure safety to personnel.
  4. Sensitivity: To detect even the smallest fault, current or system abnormalities and operate correctly at its setting.
Power system protection-speed is vital!!
The protective system should act fast to isolate faulty sections to prevent:
  • Increased damage at fault location. Fault energy = I2 × Rf × t, where t is time in seconds.
  • Danger to the operating personnel (flashes due to high fault energy sustaining for a long time).
  • Danger of igniting combustible gas in hazardous areas, such as methane in coal mines which could cause horrendous disaster.
  • Increased probability of ground faults spreading to healthy phases.
  • Higher mechanical and thermal stressing of all items of plant carrying the fault current, particularly transformers whose windings suffer progressive and cumulative deterioration because of the enormous electro-mechanical forces caused by multiphase faults proportional to the square of the fault current.
  • Sustained voltage dips resulting in motor (and generator), instability leading to extensive shutdown at the plant concerned and possibly other nearby plants connected to the system.
Power system protection-qualities
  1. Dependability: It MUST trip when called upon.
  2. Security: It must NOT trip when not supposed to.
Power system protection-basic components
  1. Voltage transformers and current transformers–To monitor and give accurate feedback about the healthiness of a system.
  2. Relays–To convert the signals from the monitoring devices, and give instructions to open a circuit under faulty conditions or to give alarms when the equipment being protected, is approaching towards possible destruction.
  3. Fuses–Self-destructing to save the downstream equipment being protected.
  4. Circuit breakers–These are used to make circuits carrying enormous currents, and also to break the circuit carrying the fault currents for a few cycles based on feedback from the relays.
  5. DC batteries–These give uninterrupted power source to the relays and breakers that is independent of the main power source being protected.


Faults, types and effects

2.1 The development of simple distribution systems

When a consumer requests electrical power from a supply authority, ideally all that is required is a cable and a transformer, shown physically as in Figure 2.1:

Figure 2.1
A simple distribution system

This is called a Radial system and can be shown schematically in the following manner (figure 2.2.)

Figure 2.2
A radial distribution system


If a fault occurs at T2 then only the protection on one leg connecting T2 is called into operation to isolate this leg. The other consumers are not affected.


If the conductor to T2 fails, then supply to this particular consumer is lost completely and cannot be restored until the conductor is replaced/repaired.

This disadvantage can be overcome by introducing additional / parallel feeders (Figure 2.3) connecting each of the consumers radially. However, this requires more cabling and is not always economical. The fault current also tends to increase due to use of two cables.

Figure 2.3
Radial distribution system with parallel feeders

The Ring main system, which is the most favored, then came into being (Figure 2.4). Here each consumer has two feeders but connected in different paths to ensure continuity of power, in case of conductor failure in any section.

Figure 2.4
A ring main distribution system


Essentially, meets the requirements of two alternative feeds to give 100% continuity of supply, whilst saving in cabling / copper compared to parallel feeders.


For faults at T1 fault current is fed into fault via two parallel paths effectively reducing the impedance from the source to the fault location, and hence the fault current is much higher compared to a radial path. The fault currents in particular could vary depending on the exact location of the fault.

Protection must therefore be fast and discriminate correctly, so that other consumers are not interrupted.

The above case basically covers feeder failure, since cables tend to be the most vulnerable component in the network. Not only are they likely to be hit by a pick or alternatively dug-up, or crushed by heavy machinery, but their joints are notoriously weak, being susceptible to moisture, ingress, etc. amongst other things.

Transformer faults are not so frequent, however they do occur as windings are often strained when carrying fault currents. Also, their insulation lifespan is very often reduced due to temporary or extended overloading leading to eventual failure. Hence interruption or restriction in the power being distributed cannot be avoided in case of transformer failures. As it takes a few months to manufacture a power transformer, it is a normal practice to install two units at a substation with sufficient spare capacity to provide continuity of supply in case of transformer failure.

Busbars on the other hand, are considered to be the most vital component on a distribution system. They form an electrical ‘node’ where many circuits come together, feeding in and sending out power.

On E.H.V. systems where mainly outdoor switchgear is used, it is relatively easy and economical to install duplicate busbar system to provide alternate power paths. But on medium voltage (11 kV, 6.6 kV and 3.3kV) and low voltage (1000 V and 500 V) systems, where indoor metal clad switchgear is extensively used, it is not practical or economical to provide standby or parallel switchboards. Further, duplicate busbar switchgear is not immune to the ravages of a busbar fault.

The loss of a busbar in a network can in fact be a catastrophic situation, and it is recommended that this component be given careful consideration from a protection viewpoint when designing the network, particularly for continuous process plants such as mineral processing.

2.2 Faults-types and their effects

It is not practical to design and build electrical equipment or networks to eliminate the possibility of failure in service.

Faults can be broadly classified into two main areas, which have been designated ‘Active’ and ‘Passive’.

2.2.1 Active faults

The ‘Active’ fault is when actual current flows from one phase conductor to another (phase-to-phase), or alternatively from one phase conductor to ground (phase-to-ground). This type of fault can also be further classified into two areas, namely the ‘solid’ fault and the ‘incipient’ fault.

The solid fault occurs as a result of an immediate complete breakdown of insulation as would happen if, say, a pick struck an underground cable, bridging conductors etc. or the cable was dug up by a bulldozer. In mining, a rockfall could crush a cable, as would a shuttle car. In these circumstances the fault current would be very high, resulting in an electrical explosion.

This type of fault must be cleared as quickly as possible, otherwise there will be:

  • Increased damage at fault location. Fault energy = I2 × Rf × t where t is time in seconds.
  • Danger to operating personnel (flashes due to high fault energy sustaining for a long time).
  • Danger of igniting combustible gas in hazardous areas, such as methane in coal mines which could cause horrendous disaster.
  • Increased probability of ground faults spreading to healthy phases.
  • Higher mechanical and thermal stressing of all items of plant carrying the fault current, particularly transformers whose windings suffer progressive and cumulative deterioration because of the enormous electro-mechanical forces caused by multiphase faults proportional to the square of the fault current.
  • Sustained voltage dips resulting in motor (and generator) instability leading to extensive shutdown at the plant concerned and possibly other nearby plants connected to the system.

The ‘incipient’ fault, on the other hand, is a fault that starts in a small way and develops into catastrophic failure. For example, partial discharge (excessive discharge activity is often referred to as a Corona) occurring in a void in the insulation over an extended period can burn away adjacent insulation, eventually spreading further and developing into a ‘solid’ fault.

Other causes can typically be a high-resistance joint or contact, alternatively pollution of insulators causing tracking across their surface. Once tracking occurs, any surrounding air will ionise which then behaves like a solid conductor consequently creating a ‘solid’ fault.

2.2.2 Passive faults

Passive faults are not real faults in the true sense of the word, but are rather conditions that are stressing the system beyond its design capacity, so that ultimately active faults will occur. Typical examples are:

  • Over loading leading to over heating of insulation (deteriorating quality, reduced life and ultimate failure)
  • Over voltage—Stressing the insulation beyond its withstand capacities
  • Under frequency—Causing plant to behave incorrectly
  • Power swings—Generators going out-of-step or out-of-synchronism with each other

It is therefore necessary to monitor these conditions to protect the system against these conditions.

2.2.3 Types of faults on a three-phase system

Largely, the power distribution is globally a three-phase distribution especially from power sources. The types of faults that can occur on a three-phase A.C. system are shown in Figure 2.5.

Figure 2.5
Types of faults on a three-phase system
(A) Phase-to-ground fault
(B) Phase-to-phase fault
(C) Phase-to-phase-to-ground fault
(D) Three-phase fault
(E) Three-phase-to-ground fault
(F) Phase-to-pilot fault*
(G) Pilot-to-ground fault*
  * In underground mining applications only

It will be noted that for a phase-to-phase fault, the currents will be high, because the fault current is only limited by the inherent (natural) series impedance of the power system up to the point of fault (Ohm’s law).

By design, this inherent series impedance in a power system is purposely chosen to be as low as possible in order to get maximum power transfer to the consumer so that unnecessary losses in the network are limited thereby increasing the distribution efficiency. Hence, the fault current cannot be decreased without a compromise on the distribution efficiency and further reduction cannot be substantial.

On the other hand, the magnitude of ground fault currents will be determined by the manner in which the system neutral is grounded. It is worth noting at this juncture that it is possible to control the level of ground fault current that can flow by the judicious choice of grounding arrangements for the neutral. Solid neutral grounding means high ground fault currents, being limited by the inherent ground fault (zero sequence) impedance of the system, whereas additional impedance introduced between neutral and ground can result in comparatively lower ground fault currents.

In other words, by the use of resistance or impedance in the neutral of the system, ground fault currents can be engineered to be at whatever level desired, and are therefore controllable. This cannot be achieved for phase faults.

2.2.4 Transient and permanent faults

Transient faults are faults, which do not damage the insulation permanently and allow the circuit to be safely re-energized after a short period.

A typical example would be an insulator flashover following a lightning strike, which would be successfully cleared on opening of the circuit breaker, which could then be automatically closed.

Transient faults occur mainly on outdoor equipment where air is the main insulating medium.

Permanent faults, as the name implies, are the result of permanent damage to the insulation. In this case, the equipment has to be repaired and recharging must not be entertained before repair/restoration.

2.2.5 Symmetrical and asymmetrical faults

A symmetrical fault is a balanced fault with the sinusoidal waves being equal about their axes, and represents a steady state condition.

An asymmetrical fault displays a D.C. offset, transient in nature and decaying to the steady state of the symmetrical fault after a period of time, as shown in Figure 2.6.

Figure 2.6
An asymmetrical fault

The amount of offset depends on the X/R (power factor) of the power system and the first peak can be as high as 2.55 times the steady state level (see Figure 2.7).

Figure 2.7
Total asymmetry factor chart


Simple calculation of short circuit currents

3.1 Introduction

Before selecting proper protective devices, it is necessary to determine the likely fault currents that may result in a system under various fault conditions. Depending upon the complexity of the system the calculations could also be too much involved. Accurate fault current calculations are normally carried out using an analysis method called symmetrical components. This method is used by design engineers and practicing protection engineers, as it involves the use of higher mathematics. It is based on the principle that any unbalanced set of vectors can be represented by a set of 3 balanced quantities, namely: positive, negative and zero sequence vectors.

However, for general practical purposes for operators, electricians and men-in-the-field it is possible to achieve a good approximation of three-phase short circuit currents using some very simple methods, which are discussed below. These simple methods are used to decide the equipment short circuit ratings and relay setting calculations in standard power distribution systems, which normally have limited power sources and interconnections. Even a complex system can be grouped into convenient parts and calculations can be made group-wise depending upon the location of the fault.

3.2 Revision of basic formulae

It is interesting to note that nearly all problems in electrical networks can be understood by the application of its most fundamental law viz., Ohm’s law, which stipulates,

For DC systems i.e.

For AC systems i.e.

3.2.1 Vectors

Vectors are a most useful tool in electrical engineering and are necessary for analyzing AC system components like voltage, current and power, which tends to vary in line with the variation in the system voltage being generated.

The vectors are instantaneous ‘snapshots’ of an AC sinusoidal wave, represented by a straight line and a direction. A sine wave starts from zero value at 0°, reaches its peak value at 90°, goes negative after 180° and again reaches back zero at 360°. Straight lines and relative angle positions, which are termed vectors, represent these values and positions. For a typical sine wave, the vector line will be horizontal at 0° of the reference point and will be vertical upwards at 90° and so on and again comes back to the horizontal position at 360° or at the start of the next cycle. Figure 3.1 gives one way of representing the vectors in a typical cycle.

Figure 3.1
Vectors and an AC wave

In an AC system, it is quite common to come across many voltages and currents depending on the number of sources and circuit connections. These are represented in form of vectors in relation to one another taking a common reference base. Then these can be added or subtracted depending on the nature of the circuits to find the resultant and provide a most convenient and simple way to analyze and solve problems, rather than having to draw numerous sinusoidal waves at different phase displacements.

3.2.2 Impedance

This is the AC equivalent of resistance in a DC system, and takes into account the additional effects of reactance. It is represented by the symbol Z and is the vector sum of resistance and reactance (see Figure 3.2).

Figure 3.2
Impedance relationship diagram

It is calculated by the formula:
Z = R + jX
R is resistance and X is reactance.

It is to be noted that X is positive for inductive circuits whereas it is negative in capacitive circuits. That means that the Z and X will be the mirror image with R as the base in the above diagram.

3.2.3 Reactance

Reactance is a phenomenon in AC systems brought about by inductance and capacitance effects of a system. Energy is required to overcome these components as they react to the source and effectively reduce the useful power available to a system. The energy, which is spent to overcome these components in a system is thus not available for use by the end user and is termed ‘useless’ energy though it still has to be generated by the source.

Inductance is represented by the symbol L and is a result of magnetic coupling which induces a back e.m.f. opposing that which is causing it. This ‘back-pressure’ has to be overcome and the energy expended is thus not available for use by the end user and is termed ‘useless’ energy, as it still has to be generated. L is normally measured in Henries.

The inductive reactance is represented using the formula:

Inductive reactance = 2π fL.

Capacitance is the electrostatic charge required when energizing the system. It is represented by the symbol C and is measured in farads.

To convert this to ohms,

Capacitive reactance =

f = supply frequency
L = system inductance
C = system capacitance.

Inductive reactance and capacitive reactance oppose each other vectorally, so to find the net reactance in a system, they must be arithmetically subtracted.

For example, in a system having resistance R, inductance L and capacitance C, its impedance;

Z = R + (j × 2π f L) – (j/ 2 π f C)

When a voltage is applied to a system, which has an impedance of Z, vectorally the voltage is in phase with the Z as per the above impedance diagram and the current is in phase with the resistive component. Accordingly, the current is said to be leading the voltage vector in a capacitive circuit and is said to be lagging the voltage vector in an inductive circuit.

3.2.4 Power and power factor

In a D.C. system, power dissipated in a system is the product of volts × amps and is measured in watts.
P = V × I

For AC systems, the power input is measured in volt amperes, due to the effect of reactance’s and the useful power is measured in watts. For a single-phase AC system, the VA is the direct multiplication of volt and amperes, whereas it is necessary to introduce a factor for a three-phase A.C. system. Hence VA power for the standard three-phase system is:


V is in kilovolts
I is in amps, or

V is in kV
and I is in kA.


From the impedance triangle below, it will be seen that the voltage will be in phase with Z, whereas the current will be in phase with resistance R (see Figure 3.3).

Figure 3.3
Impedance triangle

The cosine of the angle between the two is known as the Power factor.
Examples: When angle = 0°; cosine 0° = 1 (unity)
When angle = 90°; cosine 90° = 0

The useful kW power in a three-phase system taking into account the system reactive component is obtained by introducing the power factor cos φ as below:
P = × V × I × cos φ = kVA cos φ

It should be noted that the kW will be at a maximum when cos φ = 1 and will be zero when cos φ = 0. It means that the useful power is zero when cos φ = 0 and will tend to increase as the angle increases. The greater the power factor, the greater the useful power.

An alternative interpretation is that it is the factor applied to determine how much of the input power is effectively used in the system or simply it is a measure of the efficiency of the system.

The ‘Reactive power’ OR the so called ‘useless power’ is calculated using the formula

P’ = √ 3 × V × I × sin φ = kVA × sin φ

In a power system, the energy meters normally record the useful power kW, which is directly used in the system and the consumer is charged based on total kW consumed over a period of time (kWh) and the maximum demand required over a period of time. However, the kVAr determines the kVA to be supplied by the source to meet the consumer load after overcoming the reactive components, which will vary depending on the power factor of the system. Hence, it is common practice to penalise a consumer whenever the consumer’s system has a low power factor.

Obviously, if one can reduce the amount of ‘useless’ power, power that is more ‘useful’ will be available to the consumer; so it pays to improve the Power Factor wherever possible.

As most loads are inductive in nature, adding shunt capacitance can reduce the inductive reactance as the capacitive reactance opposes the inductive reactance of the load.

3.3 Calculation of short circuit MVA

We have studied various types and effects of faults that can occur on the system in an earlier chapter. It is important that we know how to calculate the level of fault current that will flow under these conditions, so that we can choose equipment to withstand these faults and isolate the faulty locations without major damages to the system.

In any distribution system, the power source is a generator and it is a common practice to use transformers to distribute the power at the required voltages. A fault can occur immediately after the generator or after a transformer and depending upon the location of fault, the fault current could vary. In the first case, only the source impedance limits the fault current whereas in the second case the transformer impedance is an important factor that decides the fault current.

Generally, the worst type of fault that can occur is the three-phase fault, where the fault currents are the highest. If we can calculate this current then we can ensure that all equipment can withstand (carry) and in the case of switchgear, interrupt this current. There are simple methods to determine short circuit MVA taking into account some assumptions.

Consider the following system. Here the source generates a voltage with a phase voltage of Ep and the fault point is fed through a transformer, which has a reactance Xp (see Figure 3.5).

Figure 3.5
Short circuit MVA calculation

Let Is = r.m.s. short circuit current
I = Normal full load current
P = Transformer rated power (rated MVA)
Xp = Reactance per phase
Ep = System voltage per phase

At the time of fault, the fault current is limited by the reactance of the transformer after neglecting the impedances due to cables up to the fault point. Then from Ohm’s law:


Multiplying top and bottom by




It can be noted above, that the value of X will decide the short circuit MVA when the fault is after the transformer. Though it may look that increasing the impedance can lower the fault MVA, it is not economical to choose higher impedance for a transformer. Typical percent reactance values for transformers are shown in the table below.

Primary voltage
Reactance % at MVA rating
MVA rating Up to 11 kV 22 kV 33 kV 66 kV 132 kV
0.25 3.5 4.0 4.5 5.0 6.5
0.5 4.0 4.5 5.0 5.5 6.5
1.0 5.0 5.5 5.5 6.0 7.0
2.0 5.5 6.0 6.0 6.5 7.5
3.0 6.5 6.5 6.5 7.0 8.0
5.0 7.5 7.5 7.5 8.0 8.5
10.0 & above 10.0 10.0 10.0 10.0 10.0

It may be noted that these are only typical values and it is always possible to design transformer with different impedances. However, for design purposes it is customary to consider these standard values to design upstream and downstream protective equipment.

In an electrical circuit, the impedance limits the flow of current and ohm’s law gives the actual current. Alternatively, the voltage divided by current gives the impedance of the system. In a three-phase system which generates a phase voltage of Ep and where the phase current is Ip,

Impedance in ohms =

The above forms the basis to decide the fault current that may flow in a system where the fault current is due to a phase-to-phase or phase-to-ground short. In such cases, the internal impedances of the equipment rather than the external load impedances decide the fault currents.


For the circuit shown below calculate the short-circuit MVA on the LV side of the transformer to determine the breaking capacity of the switchgear to be installed (see Figure 3.6).

Figure 3.6
Short circuit MVA example


Short-circuit MVA =

Therefore, fault current =

and source impedance =

Calculate the fault current downstream after a particular distance from the transformer with the impedance of the line/cable being 1 ohm (see Figure 3.7).

Figure 3.7
Calculation of fault current at end of cable

Fault current =

It should be noted that, in the above examples, a few assumptions are made to simplify the calculations.

These assumptions are the following:

  • Assume the fault occurs very close to the switchgear. This means that the cable impedance between the switchgear and the fault may be ignored.
  • Ignore any arc resistance.
  • Ignore the cable impedance between the transformer secondary and the switchgear, if the transformer is located in the vicinity of the substation. If not, the cable impedance may reduce the possible fault current quite substantially, and should be included for economic considerations (a lower rated switchgear panel, at lower cost, may be installed).
  • When adding cable impedance, assume the phase angle between the cable impedance and transformer reactance are zero, hence the values may be added without complex algebra, and values readily available from cable manufacturers’ tables may be used.
  • Ignore complex algebra when calculating and using transformer internal impedance.
  • Ignore the effect of source impedance (from generators or utility).

These assumptions are quite allowable when calculating fault currents for protection settings or switchgear ratings. When these assumptions are not made, the calculations become very complex and computer simulation software should be used for exact answers. However, the answers obtained with making the above assumptions are found to be usually within 5% correct.

3.4 Useful formulae

Following are the methods adopted to calculate fault currents in a power system.

  • Ohmic method – All the impedances are expressed in ohms.
  • Percentage impedance method – The impedances are expressed in percentage with respect to a base MVA.
  • Per unit method – Is similar to the percentage impedance method except that the percentages are converted to equivalent decimals and again expressed to a common base MVA. For example, 10% impedance on 1 MVA is expressed as 0.1 p.u on the same base.

3.4.1 Ohmic reactance method

In this method, all the reactance’s components are expressed in actual ohms and then it is the application of the basic formula to decide fault current at any location. It is known that when fault current flows it is limited by the impedance to the point of fault. The source can be a generator in a generating station whereas transformers in a switching station receive power from a remote station. In any case, to calculate source impedance at HV in ohms:

Source Z ohms =

Transformer impedance is expressed in terms of percent impedance voltage and is defined as the percentage of rated voltage to be applied on the primary of a transformer for driving a full load secondary current with its secondary terminals shorted. Hence, this impedance voltage forms the main factor to decide the phase-to-phase or any other fault currents on the secondary side of a transformer (see Figure 3.8).

To convert transformer impedance in ohms:
Transformer Z ohms =

kV is the rated voltage and
kA is the rated current.

Multiplying by kV on both numerator and denominator, we get:
Transformer Z in ohms =

Z is expressed in percentage impedance value.

In a case consisting of a generator source and a transformer, total impedance at HV including transformer:
Total Z ohms HV = Source Z ohms + Trfr Z ohms

To convert Z ohms from HV to LV:
Z ohms LV=

To calculate LV fault current:
LV fault current =

Note: All voltages to be expressed in kilovolts.

In the following circuit calculate:
a) Total impedance in ohms at 1000 volts
b) Fault current at 1000 volts

Figure 3.8
Calculation of total impedance and fault currents

Z ohms source =

Z ohms transformer =

Z ohms total = 2.54 + 5.324 = 7.864 ohms

Z ohms total at 1000 V =

Fault current at 1000 V =

3.4.2 Other formulae in ohmic reactance method

In predominantly inductive circuits, it is usual to neglect the effect of resistive components, and consider only the inductive reactance X and replace the value of Z by X to calculate the fault currents. The following are the other formulae, which are used in the ohmic reactance method. (These are obtained by multiplying numerators and denominators of the basic formula with the same factors)

(1) Fault value MVA =



3.4.3 Percentage reactance method

In this method, the reactance values are expressed in terms of a common base MVA. Values at other MVA values and voltages are also converted to the same base, so that all values can be expressed in a common unit. Then it is a simple circuit analysis to calculate the fault current in a system. It should be noted that these are also extensions of basic formulae.

Formulae for percentage reactance method

(4) Fault value in MVA =


(6) X% at ‘N’ MVA =

For ease of mathematics, the base MVA of N may be taken as 100 MVA, so the formula would now read:

However, the base MVA can be chosen as any convenient value depending upon the MVA of equipment used in a system.


To calculate the fault current in the earlier example using the percentage reactance method:

Fault MVA at the source = 1.732 × 11 × 2.5 = 47.63 MVA

Take the transformer MVA (1.25) as the base MVA.
Then source impedance at baseMVA
= = 2.624 % (using (5))

Transformer impedance = 5.5 % at 1.25 MVA.
Total percentage impedance to the fault = 2.624 + 5.5 = 8.124%
Hence fault MVA after the transformer = = 15.386 MVA
Accordingly fault current at 1 kV = = 8.883 kA
It can be noted that the end answers are the same in both the methods.

Formulae correlating percentage and ohmic reactance values



3.4.4 Per unit method

This method is almost same as the percentage reactance method except that the impedance values are expressed as a fraction of the reference value.

Per unit impedance =

Initially the base kV (kVb) and rated kVA or MVA (kVAb or MVAb) are chosen in a system. Then,
Base current Ib = Base kVA/(1.732 x Base kV)

Base impedance Zb = Base V/(1.732 x BaseA)=(kVb/1000)/(1.732 x Ib)

Multiplying by kV
= (kVb2 x 1000)/kVAb

Per unit impedance of a source having short circuit capacity of kVAs.c. is:
Z p.u.= kVAb/kVAS.C.

Calculate the fault current for the same example using p.u. method.

Here base kVA is chosen again as 1.25 MVA.

Source short circuit MVA = 1.732 × 11 × 2.5 = 47.63 MVA

Source impedance = = 0.02624 p.u.

Transformer impedance = 0.055 p.u.

Impedance to transformer secondary = 0.02624 + 0.055 = 0.08124 p.u.

Hence short circuit current at 1 kV = = 8.883 kA

Depending upon the complexity of the system, any method can be used to calculate the fault currents.

General formulae

It is quite common that the interconnections in any distribution system can be converted or shown in a combination of series and parallel circuits. Then it would be necessary to calculate the effective impedance at the point of fault by combining the series and parallel circuits using the following well-known formulae. The only care to be taken is that all the values should be in the same units and should be referred to the same base.

Series circuits:

(9) Xt = X1 + X2 + X3 +...Xn where all values of X are either:

(a) X% at the same MVA base; or
(b) X at the same voltage.

Parallel circuits:


3.5 Cable information

Though cable impedances have been neglected in the above cases, to arrive at more accurate results, it may be necessary to consider cable impedances in some cases, especially where long distance of transmission lines and cables are involved. Further the cables selected in a distribution system should be capable of withstanding the short circuit currents expected until the fault is isolated / fault current is arrested.

Cables are selected for their sustained current rating so that they can thermally withstand the heat generated by the current under healthy operating conditions and at the same time, it is necessary that the cables also withstand the thermal heat generated during short circuit conditions. Appendix B contains a table showing the standard conductor sizes adopted in the USA and their mm2 equivalence. A table giving the electrical and physical properties of copper conductors is also included.

Table 3.1 below will assist in cable selection, which also states the approximate impedance in ohms / kilometer, current rating and voltage drop of 3 and 4 core PVC insulated cables with stranded copper conductors.

Sustained current rating
Rated area mm² Z approx ohm/km Ground Duct Air Voltage drop per amp metre mV
1.5 13.41 23 19 22 23.2
2.5 8.010 30 25 30 13.86
4 5.011 40 34 40 8.67
6 3.344 50 42 51 5.79
10 2.022 67 55 68 3.46
16 1.253 87 72 91 2.17
25 0.808 119 95 115 1.40
35 0.578 140 114 145 1.00
50 0.410 167 135 180 0.71
70 0.297 200 166 225 0.51
95 0.226 243 205 270 0.39
120 0.185 278 231 315 0.32
150 0.154 310 257 360 0.27
185 0.134 354 294 410 0.23
240 0.113 390 347 480 0.20
300 0.097 443 392 550 0.17
400 0.087 508 448 670 0.15

Table 3.1
Data of standard PVC insulated copper cables with stranded copper conductors

Fault current ratings for cables are given in the manufacturers’ specifications and tables, and must be modified by taking into account the fault duration.


The reference to Table B.2 in Appendix B shows that a 70 mm2 copper cable can withstand a short circuit current of 8.05 kA for 1 second. However, the duration of the fault or the time taken by the protective device to operate has to be considered. This device would usually operate well within 1 second, the actual time being read from the curves showing short circuit current / tripping time relationships supplied by the protective equipment manufacturer. Suppose the fault is cleared after 0.2 seconds. We need to determine what short circuit current the cable can withstand in this time.

This can be found from the expression:
ISC= A × K

K = 115 for PVC / copper cables of 1000 V rating
K = 143 for XLPE / copper cables of 1000 V rating
K = 76 for PVC / aluminium (solid or stranded) cables of 1000 V rating
K = 92 for XLPE / aluminium (solid or stranded) cables of 1000 V rating
And where;
A = the conductor cross sectional area in mm2
t = the duration of the fault in seconds

So in our example:
ISC = 70 × 115 = 18 kA (for 0.2 sec)

Cable bursting is not normally a real threat in the majority of cases where armored cable is used since the armoring gives a measure of reinforcement. However, with larger sizes, in excess of 300 mm2, particularly when these cables are unarmored, cognizance should be taken of possible bursting effects.

When the short circuit current rating for a certain time is known, the formula E = I2t can also be used to obtain the current rating for a different time. In the above example:
I12t1 = I22t2
⇒ I2 = √ I12t1/ t2
I2 = √(8.052 x 1)/0.2
= 18 kA

Naturally, if the fault is cleared in more than one second, the above formulae can also be used to determine what fault current the cable can withstand in this extended period.

Note: In electrical protection, engineers usually cater for failure of the primary protective device by providing back-up protection. It makes for good engineering practice to use the tripping time of the back-up device, which should only be slightly longer than that of the primary device in short circuit conditions, to determine the short circuit rating of the cable. This then has a built-in safety margin.


System grounding

4.1. Introduction

In chapter 2, we briefly the situation where the phase to ground faults in a system can limit the ground fault current depending on adding external impedance between neutral and the ground. This chapter briefly covers the various methods of grounding that are adopted in the electrical systems. In the following sections, the star connected transformer is shown. This is widely used in power distribution. The grounding methods are also applicable to the case of generators, whose windings are also invariably star connected.

The following table highlights the possible problems that can occur in a system due to the common faults and the solutions that can be achieved by adopting system grounding.

Phase faults:
  High fault currents.
  Only limited by inherent impedance of power supply.
Ground faults:
  Solid grounding means high ground fault currents.
  Only limited by inherent zero sequence impedance of power system.
1)Heavy currents damage equipment extensively–danger of fire hazard.
2)This leads to long outage times–lost production, lost revenue.
3)Heavy currents in ground bonding gives rise to high touch potentials–dangerous to human life.
4)Large fault currents are more hazardous in igniting gases–explosion hazard.
Phase segregation:
  Eliminates phase-to-phase faults.
Resistance grounding:
  Means low ground fault currents–can be engineered to limit to any chosen value.
1) Fault damage now minimal–reduces fire hazard.
2) Lower outage times–less lost production, less lost revenue.
3) Touch potentials kept within safe limits–protects human life.
4) Low fault currents reduce possibility of igniting gases–minimizes explosion hazard.
5)No magnetic or thermal stresses imposed on plant during fault.
6)Transient overvoltages limited–prevents stressing of insulation, breaker re-strikes.

4.2 Grounding devices

4.2.1 Solid grounding

In this case, the neutral of a power transformer is grounded solidly with a copper conductor as shown in Figure 4.1.

Figure 4.1
Solid grounding of power transformer


  • Neutral held effectively at ground potential
  • Phase-to-ground faults of same magnitude as phase-to-phase faults so no need for special sensitive relays
  • Cost of current limiting device is eliminated
  • Grading insulation towards neutral point N reduces size and cost of transformers


  • As most system faults are phase-to-ground, severe shocks are more considerable than with resistance grounding
  • Third harmonics tend to circulate between neutrals

4.2.2 Resistance grounding

A resistor is connected between the transformer neutral and ground (see Figure 4.2):

  • Mainly used below 33 kV
  • Value is such as to limit a ground fault current to between 1 and 2 times full load rating of the transformer. Alternatively, to twice the normal rating of the largest feeder, whichever is greater.
Figure 4.2
Resistance grounding


  • Limits electrical and mechanical stress on system when a ground fault occurs, but at the same time, current is sufficient to operate normal protection equipment


  • Full line-to-line insulation required between phase and ground

4.2.3 Reactance grounding

A reactor is connected between the transformer neutral and ground (see Figure 4.3):

  • Values of reactance are approximately the same as used for resistance grounding
  • To achieve the same value as the resistor, the design of the reactor is smaller and thus cheaper
Figure 4.3
Reactance grounding

4.2.4 Arc suppression coil (petersen coil)

A tunable reactor is connected in the transformer neutral to ground (see Figure 4.4):

  • Value of reactance is chosen such that reactance current neutralizes capacitance current. The current at the fault point is therefore theoretically nil and unable to maintain the arc, hence its name.
  • Virtually fully insulated system, hence current available to operate protective equipment is so small as to be negligible. To offset this, the faulty section can be left in service indefinitely without damage to the system as most faults are ground faults of a transient nature, the initial arc at the fault point is extinguished and does not re-strike.
Figure 4.4
Arc suppression coil (petersen coil)

Sensitive watt-metrical relays are used to detect permanent ground faults.

4.2.5 Grounding via neutral grounding compensator

Figure 4.5
Grounding via neutral grounding compensator

This provides a ground point for a delta system and combines the virtues of resistance and reactance grounding in limiting ground fault current to safe reliable values (see Figure 4.5).

4.3 Evaluation of grounding methods

The grounding method is called effectively grounded when it is directly connected to ground (solidly grounded) without any passive component in between. Non-effective grounding refers to, the method of grounding through a resistance, reactance, transformer, etc. The following table compares the grounding methods.

Evaluation of relative merits of effective and resistive grounding
Effective grounding
Resistive grounding
Rated voltage of system components, particularly power cables and metal oxide surge arresters. Need not exceed 0.8 Um Must be at least 1.0 Um for 100 s
Ground fault current magnitude. Approximately equal to three-phase fault current (typically 2-10 kA) Reduced ground fault current magnitude (typically 300-900 A)
Degree of damage, because of a ground fault. High degree of damage at fault point and possible damage to feeder equipment. Lesser degree of damage at fault point and usually no damage to feeder equipment.
Step and touch potentials during ground fault. High step and touch potentials. Reduced step and touch potentials.
Inductive interference on and possible damage, to control and other lower voltage circuits. High probability. Lower probability.
Relaying of fault conditions. Satisfactory. Satisfactory.
Cost Lower initial cost but higher long-term equipment repair cost. Higher initial cost but lower long-term equipment repair cost, usually making resistive grounding more cost-effective.

Figure 4.6 gives the touch potential with solid grounding.

Figure 4.6
Touch potentials–solid grounding

Figure 4.7 shows the touch potentials with resistance R introduced in the neutral. Here the ground fault current is limited by the resistance R, so only reduced current flows to the ground.

Figure 4.7
Touch potentials–resistive grounding

However, it is a normal practice to adopt solid grounding method at low voltages (up to say 600 volts) and resistance grounding is adopted for higher voltages (up to 33 kV). The other methods of grounding (reactor, transformer, etc.) are generally adopted in the cases of voltages beyond 33 kV. Cost invariably determines the grounding method.

The main reason for adopting solid grounding is because, the resistance grounding cannot be used for single-phase loads, whereas most of the LV distribution mainly households, etc. consist of single-phase loads. Nevertheless, resistance grounding is considered at low voltages in industrial environments, where three-phase loads are connected and the process conditions do not accept frequent shutdowns due to ground faults. Though it is true that the power interruptions can be kept low with the use of the resistive grounding method, human protection demands that the power be isolated in case of ground faults. This is one more reason for using solid grounding in utility distribution transformers.

4.4 Effect of electric shock on human beings

4.4.1 Electric shock and sensitive ground leakage protection

There are four major factors, which determine the seriousness of an electric shock:

  • Path taken by the electric current though the body
  • Amount of current
  • Time the current is flowing
  • The body’s electrical resistance
Figure 4.8
Dangerous current flows

The most dangerous and most common path is through the heart (see Figure 4.8).

Persons are not normally electrocuted between phases or phase to neutral, almost all accidents are phase to ground.

Figure 4.9 shows the four stages of the effect of a current flow through the body:

  • Perception–tingling–about 1mA
  • Let-go threshold level–about 10 mA
  • Non-let-go threshold level–16 mA
  • Constriction of the thoracic muscles–death by asphyxiation and ventricular fibrillation–about 70-100 mA
Figure 4.9
Effects of current flow through the body

Figure 4.10 shows the normal electrocardiogram–one pulse beat–at 80 bpm = 750 msecs.

  • QRS phase–normal pumping action
  • T phase–refractory or rest phase–about 150 msecs
  • Death could occur if within this very short period of 150 msecs a current flow was at the fibrillation level.
Figure 4.10

Figure 4.11 shows the resistance of the human body–hand-to-hand or hand to foot.

Consider an example of a man working and perspiring, he touches a conductor at 300 volts (525 volts phase to ground). 300 volts divided by 1000 ohms = 300 mA!

It is important to remember that, it is the current that kills and not voltage.

Figure 4.11
Resistance of human body

4.4.2 Sensitive ground leakage protection

Grounding does not ensure that humans will be protected when coming in contact with a live conductor. Though there may be relays, which are set to sense the ground leakages, invariably their settings are high. Hence ground leakage circuit breakers (ELCB) or residual current circuit breakers (RCCB) are adopted where possibility of human interaction to a live conductor is high. These breakers work on the core balance current principle.

Figure 4.12 illustrates the operation of the core balance leakage device. When the system conditions are normal, the phase current and neutral current will be equal and in phase. Hence the CT will not detect any current under normal conditions since IL + IN = 0 (vector sum).

Figure 4.12
Principles of core balance protection

The ELCB comprising of core balance CT is mounted at the source end. When a human comes in contact on any part of the line, a part of the current will start flowing through the body. It will result in unbalance of the currents entering and returning to the CBCT of the ELCB. If the fault current IF, flows through the human body, IN is reduced by this amount. Relay is operated by this unbalance quantity, and immediately trips the ELCB.

It is normal that the ELCBs are moulded breakers similar to the miniature circuit breakers including, CBCT mounted inside. It is also common that the CBCT can be mounted outside and the unbalanced current can be taken to trip a separate relay namely Ground leakage relay.

The above example considered a single-phase system. However, the principle is the same for three-phase systems with neutral, where also the vector sum of the three-phase currents (IR + IY + IB) and the returning neutral current IN will be zero. All the phase and neutral conductors are taken in through the CBCT so that the CBCT does not sense any current under normal conditions. In the event of any leakage in any phase, the CBCT immediately detects unbalance and causes the breaker to trip.

The ELCBs are available with a sensitivity of 30 mA, 100 mA and 300 mA. For human protection, 30 mA ELCBs is recommended, since currents flowing above 30 mA in a human can cause serious injury including death.



5.1 Historical

The fuse is the most common and widely used protective device in electrical circuits. Though the ‘fuse-less’ concept has been growing in importance for quite some time, a lot of low voltage distribution circuits are still protected with fuses. Fuses also form a major backup for protection in medium voltage and high voltage distribution to 11 kV, where switches and contactors with limited short circuit capacities are used.

In 1881, Edison patented his ‘Lead safety wire’, which was officially recognized as the first fuse.

However, it was also said that Swan actually used this device in late 1880 in the lighting circuits of Lord Armstrong’s house. He used strips of tin-foil jammed between brass blocks by plugs of woods. The application of the fuse in those days was not to protect the wires and system against short-circuit, but to protect the lights which cost 25 shillings a time (a fortune in those days).

Later, as electrical distribution systems grew, it was found that after short circuits, certain conductors failed. This was due to the copper conductors, not being accurately drawn out (extruded) to a constant diameter throughout the cable length; faults always occurring at the smallest cross-sectional area.

Fuses were often considered casual devices until quite recently. The open tin-foil (re-wireable) fuse sometimes came in for a lot of abuse. If it blew constantly, then the new fuse was just increased in size until it stayed in permanently. Sometimes hairpins were used. Greater precision only became possible with the introduction of the Cartridge fuse.

5.2 Re-wireable type

As the name indicates the fuse can be replaced or ‘rewired’ once it fails. Fusible wire used to be contained in an asbestos tube to prevent splashing of volatile metal.


1) Open to abuse due to incorrect rating of replacement elements hence affording incorrect protection

2) Deterioration of element as it is open to the atmosphere

5.3 Cartridge type

This comprises a silver element, specially shaped, enclosed in a barrel of insulating material, filled with quartz. Silver and quartz combine to give a very good insulator and prevent the arc from re-striking (see Figure 5.1).

Figure 5.1
Sectional view of a typical class–GP type 5
Cartridge fuse–link


  1. Correct rating and characteristic fuse always fitted to a circuit-not open to abuse as re-wireable type.
  2. Arc and fault energy contained within insulating tube-prevents damage.
  3. Normally sealed therefore not affected by atmosphere hence gives more stable characteristic-reliable grading.
  4. Can operate considerably faster, suitable for higher short circuit duty:
    • - Cartridge type can handle 100,000 amps
    • - Semi-open type can handle 4,000 amps

Normal currents carried continuously are much closer to fusing current due to special design of element.

These fuses are most widely used in electrical systems and are referred to as HRC (High rupturing capacity) fuses, with the name synonymous with their short circuit current breaking capacity. In North American terminology, these fuses go by the name of cartridge fuses.

5.4 Operating characteristics

All fuses irrespective of the type have inverse characteristic as shown in the graph that follows. Inverse means that they can withstand their nominal current rating almost indefinitely but as the currents increases their withstanding time starts decreasing making them ‘blow’. The blowing time decreases as the flowing currents increase. The thermal characteristic or withstand capacity of a fuse is indicated in terms of ‘I2 t’ where I is the current and t is the withstand time (see Figure 5.2).

Figure 5.2
Inverse characteristic of fuse

The prospective current is the Irms that would flow on the making of a circuit when the circuit is equipped for insertion of a fuse but that the fuse is replaced with a solid link.

The curves are very important when determining the application of fuses as they allow the correct ratings to be chosen to give grading.

5.5 Governing standards

Low Voltage cartridge type fuses are governed by various national and international standards; examples being IEC 60269, BS 88, BS EN 60269, NEMA standard FU 1:2002 etc. The standards aim at bringing uniformity in respect of various ratings and operating parameters and other aspects such as overall dimensions, interchangeability etc. For example, British standard BS 88 lays down definite limits of:

  1. Temperature rise
  2. Fusing factor =
  3. Breaking capacity

These are all dependent on one another and by careful balancing of factors a really good fuse can be produced. For example, a cool working fuse may be obtained at the expense of breaking capacity. Alternatively, too low a fusing factor may result in too high a temperature, therefore too close protection and possibilities of blowing are more.

Another popular standard adopted in North America is NEMA standard document FU 1:2002. This standard categorizes the fuses based on their performance requirements and specifies the voltage/current ratings for different categories. It also specifies the dimensions (derived from FPS system) for each category of fuse and indicates the ferrule/blade details for the fuse where it connects with the fuse holder or other external means of connection so as to ensure interchangeability between fuses manufactured by different vendors.

NEMA LV fuses have voltage ratings of 60V, 125V, 160V, 250V, 300V, 400V, 500V and 600V (AC RMS). Fuses are categorized under classes G, H, J, K, L, R, T and CC based on their current/voltage/interrupting ratings. The standard also stipulates the maximum temperature rise permissible over the ambient temperature and indicates exact details of measuring the temperature. Details of overload and short circuit tests are also specified.

5.6 Energy ‘let through’

Fuses operate very quickly and can cut-off fault current long before it reaches its first peak (see Figure 5.3):

Figure 5.3
Energy ‘let through’

If a fuse cuts off in the first quarter cycle, then the power let-through is I²t.

By comparison, circuit breakers can clear faults in any time up to 10 cycles and in this case the power let-through is the summation of I2 for 10 cycles. The energy released at the fault is therefore colossal compared with that let through by a fuse. Damage is therefore extensive.

In addition, all apparatus carrying this fault current (transformers etc) is subjected to high magnetic forces proportional to the fault current squared (If 2)!!

5.7 Application of selection of fuses

The fuses blow in cases where the currents flowing through them last for more than its withstand time. This property limits the use of fuses in circuits where the inrush currents are quite high and flow for considerable time such as motors, etc, which draw more than 6 times their full load current for a short time ranging from milli seconds to few seconds depending on the capacity. Hence, it is not possible to use fuses as over load protection in such circuits, since it may be necessary to select a higher rated fuse to withstand inrush currents. Accordingly, the fuses are mostly used as short circuit protection rather than as over load protection in such circuits.

The fuses can be used as either for overload and short circuit protection or for short circuit protection as noted below:

  • Circuits where the load does not vary much above normal value during switching on and operating conditions. Resistive circuits such as lamps show such characteristics. Hence, it is possible to use fuses as overload protection in such circuits. They also protect against short circuits.
  • Circuits where loads vary considerably compared to the normal rating e.g.
    • - Direct-on-line motors
    • - Cranes
    • - Rolling mills
    • - Welding sets, etc. In these cases, fuses are used to provide short-circuit protection only as it is not possible to select a size meeting both overload and inrush conditions.

Fuse selection depends on a number of factors:

  • Maximum fault kVA of circuit to be protected
  • Voltage of circuit

The above factors help to calculate the prospective current of circuit to be protected. The full prospective current is usually never reached due to rapid operation of the fuse and hence the following factors need to be considered.

(1) Full load current of circuit

Short circuit tests show that the cut-off current increases as the rating increases. Hence if a higher rated fuse is used it may take longer to blow under short circuits which may affect the system depending upon the value and duration. Hence, a greater benefit is derived from the use of correct or the nearest rating of cartridge fuses compared to the circuit rating.

(2) Degree of overcurrent protection required

It is necessary to consider slightly higher ratings for the fuses compared to the maximum normal current expected in a system. This factor is called the fusing factor (Refer to section 5.5) and can be anywhere between 1.25 to 1.6 times the normal rating.

(3) The level of overcurrent required to be carried for a short time without blowing or deteriorating e.g. motor starting currents

This point is important for motor circuits. Fuses must be able to carry starting surge without blowing or deteriorating.

(4) Whether fuses are required to operate or grade in conjunction with other protective apparatus. This factor is necessary to ensure that only faulty circuits are isolated during fault conditions without disturbing the healthy circuits.

Depending on the configuration used, discrimination must be achieved between:

  • - Fuses and fuses
  • - Fuses and relays, etc.

There is no general rule laid down for the application of fuses and each problem must be considered on its own merits.

5.8 General ‘rules of thumb’

5.8.1 Short circuit protection

Transformers, fluorescent lighting circuits
Transient switching surges - take next highest rating above full load current.

Capacitor circuits
Select fuse rating of 25% or greater than the full load rating of the circuit to allow for the extra heating by capacitance effect.

Motor circuits
Starting current surge normally lasts for 20 seconds. Squirrel cage induction motors:

  • - Direct-on-line takes about 7 times full load current
  • - 75% tap autotransformer takes about 4 times full load current
  • - 60% tap autotransformer takes about 2.5 times full load current
  • - Star/delta starting takes about 2.5 times full load current

5.8.2 Overload protection

Recommend 2:1 ratio to give satisfactory discrimination.

5.9 Special types

5.9.1 Striker pin

This type is most commonly used on medium and low voltage circuits. When the fuse blows, a striker pin protrudes out of one end of the cartridge. This is used to hit a tripping mechanism on a three-phase switch-fuse unit, so tripping all three-phases. This prevents single phasing on three-phase motors.

Note: On switch fuse L.V. distribution gear, it is a good policy to have an isolator on the incoming side of the fuse to facilitate changing.

5.9.2 Drop-out type

Used mainly on rural distribution systems. Drops out when fuse blows, isolating the circuit and giving line patrolman easy indication of fault location.

5.10 General

The fuse acts as both a fault detector and interrupter. It is satisfactory and adequate for both of these functions in many applications. Its main virtue is speed.

However, as a protective device it does have a number of limitations, the more important of which are as follows:

  • It can only detect faults that are associated with excess current.
  • Its operating characteristic (i.e. current/time relationship) cannot be adjusted or set.
  • It requires replacement after each operation.
  • It can be used only at low and medium voltages.

Because of these limitations, fuses are normally used only on relatively unimportant, small power, low and/or medium voltage circuits (see Figure 5.4).

Figure 5.4
Characteristic of transformer HV/LV

5.9.3 Series overcurrent A.C. trip coils

These are based on the principle of working of fuses where the coils are connected to carry the normal current and operated as noted below:

  • A coil (instead of a fuse) is connected into the primary circuit and magnetism is used to lift a plunger to trip a circuit breaker.
  • Refinement on this arrangement is the dashpot, which gives a time/current characteristic like a fuse.
  • Amps-turns are a measurement of magnetism, therefore for the same flux (i.e. lines of magnetism necessary to lift the tripping plunger) say 50 Amp-turns, a 50 amp coil would have 1 turn, whereas a 10 amp coil would have 5 turns (see Figure 5.5)
Figure 5.5
Series over-current A.C. trip coil characteristic

Limitation of this type of arrangement is:

Thermal rating
This coil must carry the full fault current and if this is high then the heating effect (I²) may be so great as to burn out the insulation. The design must therefore be very conservative.

Magnetic stresses
High fault currents induce tremendous magnetic forces inside the trip coil tending to force the windings apart. Here again the design must display a large margin of support and clamping to contain such stresses.

5.11 IS-limiter

A very ‘special’ type of fuse is the IS-limiter, originally developed by the company ABB. The device consists of two main current conducting parts, namely the Main conductor and the Fuse, as illustrated in Figure 5.6.

Figure 5.6
Construction of IS-limiter

The device functions as an ‘intelligent fuse’, as illustrated in Figure 5.7. The functional parts are the following:

  1. Current transformer (detects the short-circuit current)
  2. Measuring and tripping device (measures the current and provides the triggering energy)
  3. Pulse transformer (converts the tripping pulse to busbar potential)
  4. Insert holder with insert (conducts the operating current and limits the short-circuit current)
Figure 5.7
Functional diagram of IS-limiter

The IS-limiter is intended to interrupt very high short-circuit currents very quickly, in order to protect the system against these high currents. Currents of values up to 210 kA (11 kV) can be interrupted in 1 ms. This means that the fault current is interrupted very early in the first cycle, as illustrated in Figure 5.8.

Figure 5.8
Fault current cycle

When a fault current is detected, the main conductor is opened very swiftly. The current then flows through the fuse, which interrupts the fault current. The over voltage occurring due to the interruption of current is relatively low due to the fact that the magnitude of current on the instant of interruption is still relatively low. The main conductor and parallel fuse have to be replaced after each operation.

The IS-limiter is only intended to interrupt high fault currents, leaving the lower fault currents to be interrupted by the circuit breakers in the system. This is achieved by the measuring device detecting the instantaneous current level and the rate of current rise. The rate of current rise (di/dt), is high with high fault currents, and lower with lower fault currents, as illustrated in Figure 5.9 The IS-limiter only trips when both set response values are reached.

A practical use of the IS-limiter is illustrated in Figure 5.10, where the combined fault current supplied by two transformers in parallel would be too high for the switchgear panel to withstand.

Figure 5.9
Rate of current rise
Figure 5.10
Practical use of IS-limiter

Here I2 is interrupted first thereby decreasing the fault current to the value of I1 and I1 is interrupted subsequently. The net resultant fault current follows the path of I1 once the limiter functions thereby limiting the overall fault current.


Instrument transformers

6.1 Purpose

The voltage transformers and current transformers continuously measure the voltage and current of an electrical system and are responsible to give feedback signals to the relays to enable them to detect abnormal conditions. The value of actual currents in modern distribution systems vary from a few amperes in households, small industrial/commercial houses, etc., to thousands of amperes in power intensive plants, national grids, etc., which also depend on the operating voltages. Similarly, the voltages in electrical systems vary from few hundred volts to many kV. However, it is impossible to have monitoring relays designed and manufactured for each and every distribution system and to match the innumerable voltages and currents present. Hence the voltage transformers and current transformers are used which enable same types of relays to be used in all types of distribution systems ensuring the selection and cost of relays to be within manageable ranges.

The main tasks of instrument transformers are:

  • To transform currents or voltages from usually a high value to a value easy to handle for relays and instruments.
  • To insulate the relays, metering and instruments from the primary high voltage system.
  • To provide possibilities of standardizing the relays and instruments, etc. to a few rated currents and voltages.

Instrument transformers are special versions of transformers in respect of measurement of current and voltages. The theories for instrument transformers are the same as those for transformers in general.

6.2 Basic theory of operation

The transformer is one of the high efficient devices in electrical distribution systems, which are used to convert the generated voltages to convenient voltages for the purpose of transmission and consumption. A transformer comprises of two windings viz., primary and secondary coupled through a common magnetic core.

When the primary winding is connected to a source and the secondary circuit is left open, the transformer acts as an inductor with minimum current being drawn from the source. At the same time, a voltage will be produced in the secondary open circuit winding due to the magnetic coupling. When a load is connected across the secondary terminals, the current will start flowing in the secondary, which will be decided by the load impedance and the open circuit secondary voltage. A proportionate current is drawn in the primary winding depending upon the turns ratio between primary and secondary. This principle of transformer operation is used in transfer of voltage and current in a circuit to the required values for the purpose of standardization.

A voltage transformer is an open circuited transformer whose primary winding is connected across the main electrical system voltage being monitored. A convenient proportionate voltage is generated in the secondary for monitoring. The most common voltage produced by voltage transformers is 100 volts to 120 volts (as per local country standards) for primary voltages from 380 volts to 800 kilo volts or more.

However, the current transformer has its primary winding directly connected in series with the main circuit carrying the full operating current of the system. An equivalent current is produced in its secondary, which is made to flow through the relay coil to get the equivalent measure of the main system current. The standard currents are generally 1 ampere and 5 amperes universally.

6.3 Voltage transformers

There are basically, two types of voltage transformers used for protection equipment.

  1. Electro-magnetic type (commonly referred to as a VT)
  2. Capacitor type (referred to as a CVT).

The electro magnetic type is a step down transformer whose primary (HV) and secondary (LV) windings are connected as below (see Figure 6.1).

Figure 6.1
Electro-magnetic type

The number of turns in a winding is directly proportional to the open circuit voltage being measured or produced across it. The above diagram is a single phase VT. In the three-phase system it is necessary to use three VTs with one per phase and they are connected in star or delta depending on the method of connection of the main power source being monitored. These types of electro magnetic transformers are used in voltage circuits up to 110/ 132 kV.

For still higher voltages, it is common to adopt the second type namely the capacitor voltage transformer (CVT). Figure 6.2 below gives the basic connection adopted in this type. Here the primary portion consists of capacitors connected in series to split the primary voltage to convenient values.

Figure 6.2
Capacitor type VT

The magnetic voltage transformer is similar to a power transformer and differs only so far as a different emphasis is placed on cooling, insulating and mechanical aspects.

The primary winding has a larger number of turns and is connected across the line voltage; either phase-to-phase or phase-to-neutral.

The secondary has lesser turns however, the volts per turn on both primary and secondary remains same.

The capacitor VT is more commonly used on extra high voltage (EHV) networks. The capacitors also allow the injection of a high frequency signal onto the power line conductors to provide end-to-end communications between substations for distance relays, telemetry/supervisory and voice communications. Hence, in EHV national grid networks of utilities, the CVTs are commonly used for both protection and communication purposes.

It should be remembered that these voltage transformers are also used for measuring purposes. It is possible to have one common primary winding and two or more secondary windings in one unit. The voltage transformers having this kind of arrangement are referred to as a two core or three core VT depending on the number of secondary windings.

6.3.1 Vector diagram

The vector diagram for a single-phase voltage transformer is as follows. The primary parameters are suffixed with p while the secondary parameters have suffix s. It is to be noted that the vector diagram for a three-phase connection will be identical, except for the phase shift introduced in each phase in relation to the other phases (Figure 6.3).

Figure 6.3
Vector diagram of a voltage transformer

The capacity of a voltage transformer is normally represented by a VA rating, which indicates the maximum load that can be connected across its secondary. The other common name for this VA rating is ‘Burden’. Output burdens of 500 VA per phase are common.

6.3.2 Accuracy of voltage transformers

The voltage transformers shall be capable of producing secondary voltages, which are proportional to the primary voltages over the full range of input voltage expected in a system. Voltage transformers for protection are required to maintain reasonably good accuracy over a large range of voltages from 0-173% of normal.

Table 6.1
Accuracy class, voltage transformers

However, the close accuracy is more relevant for metering purposes, while for protection purposes the margin of accuracy can be comparatively less. Permissible errors vary depending on the burden and purpose of use and typical values as per IEC are as follows (see Table 6.1).

The accuracy is not a major cost-deciding factor for a voltage transformer due to the high efficiency of the transformers, which normally ensures that there is no major voltage drop in the secondary leads. Thus, it is common to select voltage transformers based on the loads (choosing appropriate rated burden). The question of accuracy of VT’s used in protection circuits can be ignored and is generally neglected in practice.

6.3.3 Connection of voltage transformers

Electro-magnetic voltage transformers may be connected inter-phase or between phase and ground. However, capacitor voltage transformers can only be connected phase-to-ground.

Voltage transformers are commonly used in three-phase groups, generally in star-star configuration. Typical connection is as per Figure 6.4.

With this arrangement, the secondary voltages provide a complete replica of the primary voltages as shown below and any voltage (phase-to-phase or phase-to-ground) may be selected for monitoring at the secondary (see Figure 6.5).

Figure 6.4
Voltage transformers connected in star-star configuration
Figure 6.5
Vector diagram for VT’s in star-star configuration

6.3.4 Connection to obtain the residual voltage

It is common to detect ground faults in a three-phase system using the displacement that occurs in the neutral voltage when ground faults take place. The residual voltage (neutral displacement voltage, polarizing voltage) for ground-fault relays can be obtained from a VT between neutral and ground, for instance at a power transformer neutral. It can also be obtained from a three-phase set of VTs, which have their primary winding connected phase to ground and one of the secondary windings connected in a broken delta. Figure 6.6 below illustrates the measuring principle for the broken delta connecting during a ground-fault in a high-impedance grounded (or ungrounded) and an effectively grounded power system respectively.

Figure 6.6
Connection to source residual voltage

From the figure below it can be seen that a solid close-up ground-fault produces an output voltage of Ursd = 3 × Usn in a high impedance grounded system, and Ursd = U2n in an effectively grounded system (see Figure 6.7).

Figure 6.7
Residual voltage (neutral displacement voltage) from an open delta circuit

Therefore a VT secondary normal voltage of:

which is often used in high-impedance grounded systems and U2n = 110 V in effectively grounded systems. A residual voltage of 110 V is obtained in both the cases. VTs with two secondary windings, one for connection in Y and the other in broken delta can then have the ratio:

for high impedance and effective grounded systems respectively. Other nominal voltages than 110 V e.g. 100 V or 120 V are also used depending on national standards and practice.

Ferro-resonance in magnetic voltage transformer
While the ferro-resonance in a CVT is an internal oscillation between the capacitor and the magnetic IVT, the ferro-resonance in a magnetic voltage transformer is an oscillation between the magnetic voltage transformer and the network. The oscillation can only occur in a network having an insulated neutral. An oscillation can occur between the network’s capacitance to ground and the non-linear inductance in the magnetic voltage transformer. The oscillation can be triggered by a sudden change in the network voltage.

It is difficult to give a general figure of a possible risk of ferro-resonance. It depends on the design of the transformer. We can roughly calculate that there will be a risk of resonance when the zero-sequence capacitance is expressed in a S km transmission line.

Un - System voltage in kV.

The corresponding value for cable is:

Damping of ferro-resonance
The magnetic voltage transformer will be protected from ferro-resonance oscillation by connecting a resistor across the open delta point in the three-phase secondary winding.

A typical value is 50-60 ohm, 200 W (see Figure 6.8).

Figure 6.8
Damping of ferro-resonance

6.3.5 Protection of voltage transformers

It is possible to protect a voltage transformer from a secondary short circuit by incorporating fuses in the secondary circuits. A short circuit on the secondary winding gives only a few amperes in the primary winding and is not sufficient to rupture a high voltage fuse. Hence high voltage fuses on the primary side do not protect the transformers; they protect only the network in case of any short circuits on the primary side.

6.3.6 Voltage drop in voltage transformers

The voltage drop in the secondary circuit is of importance. The voltage drop in the secondary fuses and the long connection wires can change the accuracy of the measurement. It is especially important for revenue metering windings of high accuracy (class 0.2, 0.3). The total voltage drop in this circuit must not be more than 0.1 percent.

Typical values of resistance in fuses:
6A 0.048
10A 0.024
16A 0.0076
25A 0.0042

6-10A is a typical value for safe rupture of the fuses.

The voltage drop in the leads from the VT to the associated equipment must be considered as this, in practice, can be significant especially in the case of measuring circuits. This is the one issue that separates the metering circuits (with low burden) from protective circuits (with higher burdens). Refer to Figure 6.9.

Figure 6.9
The accuracy of a voltage transformer is guaranteed at the secondary terminals

6.3.7 Secondary grounding of voltage transformers

To prevent secondary circuits from reaching a dangerous potential, the circuits should be grounded. Grounding should be made at only one point of a VT secondary circuit or galvanically interconnected circuits.

A VT with the primary connected phase-to-ground shall have the secondary grounded at terminal n.

A VT with the primary winding connected across two-phases, shall have that secondary terminal grounded which has a voltage lagging the other terminal by 120°.

Windings not under use shall also be grounded (see Figure 6.10).

Figure 6.10
VT’s connected between phases

Figure 6.11 (a) shows the methods of connection in a three-phase system with primary connected in star and secondary connected in two different ways viz., star and broken delta.

Figure 6.11 (a)
A set of VT’s with one Y-connected and one broken delta secondary circuit

Alternatively, it is often a common practice to ground the white phase as shown. This practice stems from metering where the 2 watt meter method requires 2 CTs and 2 line voltages. With this arrangement the red and blue phases now at line potential to the white and it saves the expense and bother of running a neutral conductor throughout the panels (see Figure 6.11 (b)).

Figure 6.11 (b)
VT secondary grounded on white phase

6.4 Current transformers

All current transformers used in protection are basically similar in construction to standard transformers in that they consist of magnetically coupled primary and secondary windings, wound on a common iron core, the primary winding being connected in series with the network unlike voltage transformers. They must therefore withstand the networks short-circuit current.

There are two types of current transformers.

  1. Wound primary type
  2. Bar primary type

Wound type CT is shown in Figure 6.12.

Figure 6.12
Wound primary

The wound primary is used for the smaller currents, but it can only be applied on low fault level installations due to thermal limitations as well as structural requirements due to high magnetic forces

For currents greater than 100 Amps, the bar primary type is used as shown in Figure 6.13.

Figure 6.13
Bar primary

If the secondary winding is evenly distributed around the complete iron core, its leakage reactance is eliminated (see Figure 6.14).

Figure 6.14
Secondary winding is evenly distributed around iron core

Protection CTs are most frequently of the bar primary, toroidal core with evenly distributed secondary winding type construction.

The standard symbol used to depict current transformers is shown in Figure 6.15.

Figure 6.15
Standard symbol for current transformers

The basis of all transformers is that:

AMP TURNS on the Primary = AMP TURNS on the secondary

e.g. 100 amps × 1 turn = 1 amp × 100 turns

The primary current contains two components:

  • An exciting current, which magnetizes the core and supplies the eddy current and hysteresis losses etc.
  • A remaining primary current component, which is available for transformation to secondary current in the inverse ratio of turns.

The exciting current is not being transformed and is therefore the cause of transformer errors.

The amount of exciting current drawn by a CT depends upon the core material and the amount of flux that must be developed in the core to satisfy the output requirements of the CT That is, to develop sufficient driving voltage required, pushing the secondary current through its connected load or burden.

This can be explained vectorally in Figure 6.16.

Figure 6.16
Vector diagram for a current transformer

6.4.1 Magnetization curve

This curve is the best method of determining a CTs performance. It is a graph of the amount of magnetizing current required to generate an open-circuit voltage at the terminals of the unit.

Due to the non-linearity of the core iron, it follows the B-H loop characteristic and comprises three regions, namely the initial region, unsaturated region and saturated region (see Figure 6.17).

Figure 6.17
Typical C.T. magnetization curve

6.4.2 Knee-point voltage

The transition from the unsaturated to the saturated region of the open circuit excitation characteristic is a rather gradual process in most core materials. This transition characteristic makes a CT not to produce equivalent primary current beyond certain point. This transition is defined by ‘knee-point’ voltage in a CT, which decides its accurate working range.

It is generally defined as the voltage at which a further 10% increase in volts at the secondary side of the CT requires more than 50% increase in excitation current. For most applications, it means that current transformers can be considered as approximately linear up to this point.

6.4.3 Metering CTs

Instruments and meters are required to work accurately up to full load current, but above this, it is advantageous to saturate and protect the instruments under fault conditions. Hence, it is common to have metering CTs with a very sharp knee-point voltage. A special nickel-alloy metal having a very low magnetizing current is used in order to achieve the accuracy.

Following curve shows the magnetization curve of metering CT (see Figure 6.18).

Figure 6.18
Metering CT magnetization curve

6.4.4 Protection CTs

Protective relays are not normally expected to give tripping instructions under normal conditions. On the other hand these are concerned with a wide range of currents from acceptable fault settings to maximum fault currents many times normal rating. Larger errors may be permitted and it is important that saturation is avoided wherever possible to ensure positive operation of the relays mainly when the currents are many times the normal current (see Figure 6.19).

Figure 6.19
Protection CT magnetization curve

Test setup for the CT magnetic curve

It is necessary to test the characteristics of a CT before it is put into operation, since the results produced by the relays and meters depend on how well the CT behaves under normal and fault conditions.

Figure 6.20 shows a simple test connection diagram that is adopted to find the magnetic curve of a CT.

Figure 6.20
Circuit to test magnetization curve

6.4.5 Polarity

Polarity in a CT is similar to the identification of +ve and –ve terminals of a battery. Polarity is very important when connecting relays, as this will determine correct operation or not depending on the types of relays. The terminals of CT are marked by P1 and P2 on the primary, and S1 and S2 on the secondary as per Figure 6.21 (a).

Figure 6.21 (a)
Polarity markings of a CT

B.S.3938 states that at the instant when current is flowing from P1 to P2 in primary, then current, in secondary must flow from S1 to S2 through the external circuit.

Figure 6.21 (b)
Testing of a CT polarity

Figure 6.21 (b) shows the simple testing arrangement for cross checking the CT polarity markings at the time of commissioning electrical systems.

Connect battery –ve terminal to the current transformer P2 primary terminal. This arrangement will cause current to flow from P1 to P2 when +ve terminal is connected to P1 until the primary is saturated. If the polarities are correct, a momentary current will flow from S1 to S2.

Connect centre zero galvanometer across secondary of the current transformer. Touch or flick the +ve battery connection to the current transformer P1 primary terminal. If the polarity of the current transformer is correct, the galvanometer should flick in the +ve direction.

6.4.6 Open circuits of CTs

Current transformers generally work at a low flux density. The core is made of a high quality material to give a small magnetizing current. On open circuit, the secondary impedance becomes infinite and the core saturates. This induces a very high voltage in the primary winding, up to approximately system volts and the corresponding volts in the secondary will depend on the number of turns, multiplied by the ratio (i.e. volts/turn × no. of turns). Since a CT normally has much many turns in the secondary compared to the primary, the voltage generated on the open circuited CT will be much more than the system volts, leading to flashovers.


6.4.7 Secondary resistance

The secondary resistance of a CT is an important factor, as the CT has to develop sufficient voltage to push the secondary current through its own internal resistance as well as the connected external burden. This should always be kept as low as possible.

6.4.8 CT specification

A current transformer is normally specified in terms of:

  • A rated burden at rated current
  • An accuracy class
  • An upper limit beyond which accuracy is not guaranteed. (known as the Accuracy limit factor, ALF), which is more vital in case of protection CTs.

These requirements are variously specified in different national and international standards. The governing ANSI/IEEE standards for current transformers are:

  • IEEE Std C37.110-1996 IEEE Guide for the Application of Current Transformers Used for Protective Relaying Purposes
  • IEEE/ANSI C57.13-1978 Requirements for Instrument Transformers (ANSI)

The relevant UK standard is BSS 3938 and the various accuracy classes of current transformers are reproduced in tables (see Table 6.2 and Table 6.3) as an example.

Table 6.2
Limits of error for accuracy classes 0.1 to 1 (metering CT).
Table 6.3
Limits of error for accuracy class 5P and class 10P (protection CT)

In terms of the specification a current transformer would, for example, be briefly referred to as 15 VA 5P20 if it were a protection CT or 15 VA Class 0.5 if it is a metering CT. The meanings of these figures are as below:

  Protection Metering
Rated Burden 15 VA 15 VA
Accuracy Class 5P 0.5
Accuracy Limit Factor 20 Class 1,0
(ALF is 20 times normal or rated current)

6.4.9 Class X current transformers

These are normally specified for special purpose applications such as busbar protection, where it is important that CTs have matching characteristics.

For this type of CT an exact point on the Magnetization curve is specified, e.g.

  1. Rated primary current
  2. Turns ratio
  3. Rated knee point e.m.f. at maximum secondary turns
  4. Maximum exciting current at rated knee point e.m.f.
  5. Maximum resistance of secondary winding

In addition, the error in the turns ratio shall not exceed +/– 0.25%.

6.4.10 Connection of current transformers

Current transformers for protection are normally provided in groups of three, one for each phase.

They are most frequently connected in ‘star as illustrated in Figure 6.22.

Figure 6.22
Star connection of current transformers

The secondary currents obtainable with this connection are the three individual phase currents and the residual or neutral current. The residual current is the vector sum of the three-phase currents, which under healthy conditions would be zero. Under ground fault conditions, this would be the secondary equivalent of the ground fault current in the primary circuit.

Sometimes, current transformers are connected in ‘delta’. The reasons for adopting this connection are one or more of the following:

  • To obtain the currents Ir − Iw, Iw − Ib, Ib − Ir
  • To eliminate the residual current from the relays
  • To introduce a phase-shift of 30° under balanced conditions, between primary and relay currents (see Figure 6.23 and Figure 6.24).
Figure 6.23
Delta connection of current transformers
Figure 6.24
Current distribution under ground fault conditions (I0 circulating inside the delta)

6.4.11 Terminal designations for current transformers

According to IEC publication 185, the terminals are to be designated as shown in Figure 6.25. All terminals that are marked P1, S1 and C1 should have the same polarity.

Figure 6.25
Marking of current transformers
(a) one secondary winding, (b) two secondary windings, (c) one secondary winding which has an extra tapping, (d) two primary windings and one secondary winding.

6.4.12 Secondary grounding of current transformers

To prevent the secondary circuits from attaining dangerously high potential to ground, these circuits are to be grounded. Connect either the S1 terminal or the S2 terminal to ground.

For protective relays, ground the terminal that is nearest to the protected objects. For meters and instruments, ground the terminal that is nearest to the consumer.

When metering instruments and protective relays are on the same winding, the protective relay determines the point to be grounded.

If there are taps on the secondary winding, which are not used, then they must be left open.

If two or more current transformers are galvanic connected together they shall be grounded at one point only (e.g. differential protection).

If the cores are not used in a current transformer, they must be short-circuited between the highest ratio taps and should be grounded.

It is dangerous to open the secondary circuit when the CT is in operation. High voltage will be induced.

Current transformer connections
Figure 6.26 (a)—(c) shows the various ways of connecting current transformers at various parts of an electrical system.

Figure 6.26 (a)
Current transformers for a power transformer
Figure 6.26 (b)
Current transformers monitoring cable currents
Figure 6.26 (c)
CT connections in busbars

6.4.13 Test windings

It is often necessary to carry out on-site testing of current transformers and the associated equipment but it is not always possible to do primary injection because of access of test sets not being large enough to deliver the high value of current required.

Additional test windings can be provided to make such tests easier. These windings are normally rated at 10 amps and when injected with this value of current produce the same output as the rated primary current passed through the primary winding.

It should be noted that when energizing the test winding, the normal primary winding should be open circuited, otherwise the CT will summate the effects of the primary and test currents.

Conversely, in normal operation the test winding should be left open-circuited.

Test windings do, however, occupy an appreciable amount of additional space and therefore increase the cost. Alternatively, for given dimensions they will restrict the size and hence the performance of the main current transformer.

6.5 Application of current transformers

In earlier chapters, we have come across AC trip coils, which are to be designed to carry the normal and fault currents. However, it is difficult to use the same items for higher current circuits. In order to overcome the limitations experienced by series trip coils, current transformers are used so that the high primary currents are transformed down to manageable levels that can be handled comfortably by protection equipment

A typical example would be fused AC trip coils. These use current transformers, which must be employed above certain limits i.e., when current rating and breaking capacity becomes excessively high. Some basic schemes are:

6.5.1 Overcurrent

In this application, the fuses bypass the AC trip coils as shown in Figure 6.27. Under normal conditions, the fuses carry the maximum secondary current of the CT due to the low impedance path.

Figure 6.27
CTs for overcurrent use in series trip coils

Under fault conditions, Isec having reached the value at which the fuse blows and operates, trip coil TC to trip the circuit breaker. Characteristic of the fuse is inverse to the current, so a limited degree of grading is achieved.

6.5.2 Overcurrent and ground fault

There are two methods of connection and the second one shown in Figures 6.28 and Figure 6.29 are the most economical arrangement for this protection.

Figure 6.28
CTs for overcurrent and ground fault protection using series trip coils

Figure 6.29

Economical use of overcurrent and ground fault configuration

6.6 Introducing relays

The electro-mechanical relays basically comprise of armature coils with mechanical contacts to energise a tripping coil of a breaker. The CTs are connected in the same way as seen in the earlier pictures. Figure 6.30--6.32 gives an overview of the various connections commonly adopted.

6.6.1 Relays in conjunction with fuses

Figure 6.30
Inverse overcurrent tripping characteristic
Figure 6.31
Inverse overcurrent & instantaneous ground fault
Figure 6.32
More economic method

6.7 Inverse definite minimum time lag (IDMTL) relay

Here the relays are designed to have inverse characteristics similar to that of fuses and hence the fuses are eliminated in the CT connections as shown in Figure 6.33--6.36.

Figure 6.33
Figure 6.34
Overcurrent + ground fault
Figure 6.35
IDMTL overcurrent + time lag ground fault
Figure 6.36
IDMTL OC + EF relay with AC trip coils


Circuit breakers

7.1 Introduction

Where fuses are unsuitable or inadequate, protective relays and circuit breakers are used in combination to detect and isolate faults. Circuit breakers are the main making and breaking devices in an electrical circuit to allow or disallow flow of power from source to the load. These carry the load currents continuously, and are expected to be switched ON with loads (making capacity). These should also be capable of breaking a live circuit under normal switching OFF conditions as well as under fault conditions carrying the expected fault current until completely isolating the fault side (rupturing / breaking capacity).

Under fault conditions, the breakers should be able to open upon signals from monitoring devices like relays. The relay contacts are used in the making and breaking of control circuits of a circuit breaker, to prevent breakers getting closed or to trip breaker under fault conditions as well as for some other interlocks.

7.2 Protective relay-circuit breaker combination

The protective relay detects and evaluates the fault and determines when the circuit should be opened. The circuit breaker functions under control of the relay, to open the circuit when required.

A closed circuit breaker has sufficient energy to open its contacts stored in one form or another (generally a charged spring). When a protective relay gives the signal to open the circuit, the stored energy is released causing the circuit breaker to open. Except in special cases where the protective relays are mounted on the breaker, the connection between the relay and circuit breaker is by hard wiring.

Figure 7.1 indicates schematically this association between relay and circuit breaker. From the protection point of view, the important parts of the circuit breaker are the trip coil, latching mechanism, main contacts and auxiliary contacts.

The roles played by these components in the tripping process is clear from Figure 7.1 and the following step by step procedure takes place while isolating a fault (the time intervals between each event will be in the order of a few electrical cycles i.e. milliseconds):

  • The relay receives information, which it analyses and determines that the circuit should be opened.
  • Relay closes its contacts energizing the trip coil of the circuit breaker.
  • The circuit breaker is unlatched and opens its main contacts under the control of the tripping spring.
  • The trip coil is de-energized by opening of the circuit breaker auxiliary contacts.

Circuit breakers are normally fitted with a number of auxiliary contacts, which are used in a variety of ways in control and protection circuits (e.g. to energize lamps on a remote panel to indicate whether the breaker is open or closed).

Figure 7.1
Relay-circuit breaker combination

7.3 Purpose of circuit breakers (switchgear)

The main purpose of a circuit breaker is to:

  • Switch load currents
  • Make onto a fault
  • Break normal and fault currents
  • Carry fault current without blowing itself open (or up!) i.e. no distortion due to magnetic forces under fault conditions.

The important characteristics from a protection point of view are:

  • The speed with which the main current is opened after a tripping impulse is received
  • The capacity of the circuit that the main contacts are capable of interrupting

The first characteristic is referred to as the ‘tripping time’ and is expressed in cycles. Modern high-speed circuit breakers have tripping times between 3 and 8 cycles. The tripping or total clearing or break time is made up as follows:

  • Opening time
    The time between instant of application of tripping power to the instant of separation of the main contacts.
  • Arcing time
    The time between the instant of separation of the main circuit breaker contacts to the instant of arc extinction of short circuit current.
  • Total break or clearing time
    The sum of the above (see Figure 7.2).
Figure 7.2
Total fault clearing time

The second characteristic is referred to as ‘rupturing capacity’ and is expressed in MVA.

MVA rating (breaking capacity) =

Typical rupturing capacities of modern circuit breakers are as follows:

3.3 50 8.8
  75 13.1
  150 26.3
6.6 150 13.1
  250 21.9
  350 31.5
11 150 7.9
  250 13.1
  500 26.3
  750 40.0
33 500 8.8
  750 13.1
  1500 26.3
66 1500 13.1
  2500 21.9

The selection of the breaking capacity depends on the actual fault conditions expected in the system and the possible future increase in the fault level of the main source of supply. In the earlier chapters we have studied simple examples of calculating the fault currents expected in a system. These simple calculations are applied with standard ratings of transformers, etc., to select the approximate rupturing capacity duty for the circuit breakers.

7.4 Behaviour under fault conditions

Before the instant of short circuit, load current will be flowing through the switch and this can be regarded as zero when compared to the level of fault current that would flow (see Figure 7.3).

Figure 7.3
Behaviour under fault conditions

7.5 Arc

The arc has three parts:

  1. Cathode end (-ve): There is approximately 30-50 volts drop due to emission of electrons.
  2. Arc column: Ionized gas, which has a diameter proportional to current. Temperature can be in the range of 6000-25000°C
  3. Anode end (+ve): Volt drop 10-20 volts.

When a short circuit occurs, fault current flows, corresponding to the network parameters. The breaker trips and the current are interrupted at the next natural current zero. The network reacts by transient oscillations, which give rise to the transient recovery voltage (TRV) across the circuit breaker main contacts.

All breaking principles involve the separation of contacts, which initially are bridged by a hot, highly conductive arcing column. After interruption at current zero, the arcing zone has to be cooled to such an extent that the TRV is overcome and it cannot cause a voltage breakdown across the open gap.

Three critical phases are distinguished during arc interruption, each characterized by its own physical processes and interaction between system and breaker:

7.5.1 High current phase

This consists of highly conductive plasma at a very high temperature corresponding to a low mass density and an extremely high flow velocity. Proper contact design prevents the existence of metal vapor in the critical arc region.

7.5.2 Thermal phase

Before current zero, the diameter of the plasma column decreases very rapidly with the decaying current but remains existent as an extremely thin filament during the passage through current zero.

This thermal phase is characterized by a race between the cooling of the rest of the plasma and the re-heating caused by the rapidly rising voltage. Due to the temperature and velocity difference between the cool, relatively slow axial flow of the surrounding gas and the rapid flow in the hot plasma core, vigorous turbulence occurs downstream of the throat, resulting in effective cooling of the arc.

This turbulence is the dominant mechanism, which determines thermal re-ignition or interruption.

7.5.3 Dielectric phase

After successful thermal interruption, the hot plasma is replaced by a residual column of hot, but no longer electrically conducting medium. However, due to marginal ion-conductivity, local distortion of the electrical field distribution is caused by the TRV appearing across the open break.

This effect strongly influences the dielectric strength of the break and has to be taken into account when designing the geometry of the contact arrangement.

7.6 Types of circuit breakers

The types of breakers basically refer to the medium in which the breaker opens and closes. The medium could be oil, air, vacuum or SF6. The further classification is single break and double break. In a single break type only the busbar end is isolated but in a double break type, both busbar (source) and cable (load) ends are broken. However, the double break is the most common and accepted type in modern installations.

7.6.1 Arc control device

A breaker consists of moving and fixed contacts, and during the breaker operation, the contacts are broken and the arc created during such separation needs to be controlled. The arc control devices, otherwise known as a Turbulator or Explosion pot achieves this as follows:

  1. Turbulence caused by arc bubble.
  2. Magnetic forces tend to force main contacts apart and movement causes oil to be sucked in through ports and squirted past gap.
  3. When the arc is extinguished (at current zero), ionized gases get swept away and this prevents re-striking of the arc (see Figure 7.4).
Figure 7.4
Arc control device

7.6.2 Oil circuit breakers

In modern installations, oil circuit breakers, which are becoming obsolete, are being replaced by vacuum and SF6 breakers. However there are many installations, which still employ these breakers where replacements are found to be costly proposition. In this design, the main contacts are immersed in oil and the oil acts as the ionizing medium between the contacts. The oil is mineral type, with high dielectric strength to withstand the voltage across the contacts under normal conditions.

  1. Double break (used since 1890), see Figure 7.5.
Figure 7.5
Double break oil circuit breaker
  • (b) Single break (more popular in earlier days as more economical to produce - less copper, arc control devices etc, see Figure 7.6).
Figure 7.6
Single break oil circuit breaker

Arc energy de-composes oil into, 70% hydrogen, 22% acetylene, 5% methane, 3% ethylene. Arc is in a bubble of gas surrounded by oil.

Oil has the following advantages:

  • Ability of cool oil to flow into the space after current zero and arc goes out.
  • Cooling surface presented by oil.
  • Absorption of energy by de-composition of oil.
  • Action of oil as an insulator lending to more compact design of switchgear.


  • Inflammability (especially if there is any air near hydrogen).
  • Maintenance (changing and purifying)

In the initial stages, the use of high volume (bulk) oil circuit breakers was more common. In this type, the whole breaker unit is immersed in the oil. This type had the disadvantage of production of higher hydrogen quantities during arcing and higher maintenance requirements. Subsequently these were replaced with low oil (minimum oil) types, where the arc and the bubble are confined into a smaller chamber, minimizing the size of the unit.

7.6.3 Air break switchgear

Interrupting contacts situated in air instead of any other artificial medium (see Figure 7.7).

Figure 7.7
Air break switchgear

The arc is chopped into a number of small arcs by the Arc-shute as it rises due to heat and magnetic forces. The air circuit breakers are normally employed for 380 V~480 V distribution systems.

7.6.4 SF6 circuit breakers

Sulphur-hexaflouride (SF6) is an inert insulating gas, which is becoming increasingly popular in modern switchgear designs both as an insulating as well as an arc-quenching medium.

Gas insulated switchgear (GIS) is a combination of breaker, isolator, CT, PT, etc., and are used to replace outdoor substations operating at the higher voltage levels, namely 66 kV and above.

For medium and low voltage installations, the SF6 circuit breaker remains constructionally the same as that for oil and air circuit breakers mentioned above, except for the arc interrupting chamber which is of a special design, filled with SF6.

To interrupt an arc drawn when contacts of the circuit breaker separate, a gas flow is required to cool the arcing zone at current interruption (i.e. current zero). This can be achieved by a gas flow generated with a piston (known as the ‘puffer’ principle), or by heating the gas of constant volume with the arc’s energy. The resulting gas expansion is directed through nozzles to provide the required gas flow.

The pressure of the SF6 gas is generally maintained above atmospheric so good sealing of the gas chambers is vitally important. Leaks will cause loss of insulating medium and clearances are not designed for use in air.

7.6.5 Vacuum circuit breakers and contactors

Vacuum circuit breakers and contactors were introduced in the late 1960’s. A circuit breaker is designed for high through-fault and interrupting capacity and as a result has a low mechanical life.

On the other hand, a contactor is designed to provide large number of operations at typical rated loads of 200/400/600 amps at voltages of 1500/3300/6600/11000 V.

The following table illustrates the main differences between a contactor and a circuit breaker:

Hence, it is necessary to use back up fuses when contactors are employed to take care of the high fault conditions. Vacuum breakers are also similar in construction like the other types of breakers, except that the breaking medium is vacuum and the medium sealed to ensure vacuum. Figure 7.8 and Figure 7.9 give the components of a vacuum circuit breaker.

Figure 7.8
General construction of a vacuum circuit breaker
Figure 7.9
Diagrammatic representation

The modern vacuum bottle, which is used in both breakers and contactors, is normally made from ceramic material. It has pure oxygen-free copper main connections, stainless steel bellows and has composite weld-resistant main contact materials. A typical contact material comprises a tungsten matrix impregnated with a copper and antimony alloy to provide a low melting point material to ensure continuation of the arc until nearly current zero.

Because it is virtually impossible for electricity to flow in a vacuum, the early designs displayed the ability of current chopping i.e. switching off the current at a point on the cycle other than current zero. This sudden instantaneous collapse of the current generated extremely high voltage spikes and surges into the system, causing failure of equipment.

Another phenomenon was pre-strike at switch on. Due to their superior rate of dielectric recovery, a characteristic of all vacuum switches was the production of a train of pulses during the closing operation. Although of modest magnitude, the high rate of rise of voltage in pre-strike transients can, under certain conditions produce high insulation stresses in motor line end coils.

Subsequent developments attempted to alleviate these shortcomings by the use of ‘softer’ contact materials, in order to maintain metal vapor in the arc plasma so that it did not go out during switching. Unfortunately, this led to many instances of contacts welding on closing.

Re-strike transients produced under conditions of stalled motor switch off was also a problem. When switching off a stalled induction motor, or one rotating at only a fraction of synchronous speed, there is little or no machine back e.m.f., and a high voltage appears across the gap of the contactor immediately after extinction. If at this point of time the gap is very small, there is the change that the gap will break down and initiate a re-strike transient, puncturing the motor’s insulation (see Figure 7.10 and Figure 7.11).

Figure 7.10
Typical prestrike transient at switch on of 6.6 kV 200 kW motor
Figure 7.11
Switch off of stalled 6.6 kV 200 kW motor-escalating re-strike on R phase

Modern designs have all but overcome these problems. In vacuum contactors, higher operating speeds coupled with switch contact material are chosen to ensure high gap breakdown strength, produce significantly shorter trains of pulses.

In vacuum circuit breakers, operating speeds are also much higher which, together with contact materials that ensure high dielectric strength at a small gap, have ensured that pre-strike transients have ceased to become a significant phenomenon. These have led to the use of vacuum breakers more common in modern installations.

7.6.6 Types of mechanisms

The mechanisms are required to close and break the contacts with high speed. Following are the types of mechanisms employed.

  1. Hand operated: Cheap but losing popularity. Speed depends entirely on operator. Very limited use in modern installations that too for low voltage applications only.
  2. Hand operated spring assisted: Hand movement compresses spring over top deadcentre. Spring takes over and closes the breaker.
  3. Quick make: Spring charged-up by hand, then released to operate mechanism.
  4. Motor wound spring: Motor charges spring, instead of manual. Mainly useful when remote operations are employed, which are common in modern installations because of computer applications.
  5. Solenoid: As name implies.
  6. Pneumatic: Used at 66 kV and above. Convenient when drying air required.

7.6.7 Dashpots

In oil circuit breakers, when the breaker is closed, if the operation is not damped then contact bounce may occur and the breaker may kick open. Dashpots prevent this. They also prevent unnecessary physical damage to the contacts on impact. Their use of course depends on the design.

7.6.8 Contacts

Fixed contacts normally have an extended finger for arc control purposes. Moving contacts normally have a special tip (Elkonite) to prevent burning from arcing.

7.7 Comparison of breaker types

Following curve gives the requirement of electrode gaps for circuit breakers with different insulating mediums (see Figure 7.12).

Figure 7.12
Influence of electrode gap for different mediums

Following table highlights the features for different types of circuit breakers.

7.8 Breaker Failure Protection

Malfunctioning of the mechanical system may prevent the circuit breaker main contacts from following trip or close initiation, or a malfunction may move the main contacts into a partially open position, allowing the fault, load, or line charging current to flow through the preinsertion resistor.

The function of the circuit breaker failure protection helps to check if a tripping order given to the circuit breaker has executed correctly. For transmission/sub-transmission systems, slow fault clearance can also threaten system stability. It is therefore common practice to install circuit breaker failure protection, which monitors that the circuit breaker has opened within a reasonable time. If the fault current has not been interrupted following a set time delay from circuit breaker trip initiation, breaker failure protection will operate.

The state diagram given in Figure 7.13 depicts the state diagram of the circuit breaker. During its operation, the breaker could be in any state defined by the circles. The lines are the state transitions by which the breaker changes the state.

The breaker normally operates by moving around the state diagram in a counter clockwise direction. If the breaker is in the OPEN state, and its close coil is energized, the mechanism of the breaker begins to move. To accommodate the time taken by the physical processes of closing resistor operation and main contact operation, the CLOSING state is defined. A successful close leaves the breaker in the CLOSED state. If the trip coil is energized, then the mechanism begins to move again, opening the main contacts, and possibly opening one or more trip resistor contacts. This interruption process takes place in the OPENING state. A successful trip leaves the breaker in the OPEN state.

Figure 7.13
State diagram of a Circuit Breaker

As can be seen from the diagram, breaker failure could occur in any state, leading to the FAILED state. This diagram helps identify the ways a circuit breaker can fail. Once these are identified, we can find electrical means of detecting these failures. Since the means of protection are state dependent, it makes sense to design a breaker failure relay that determines the state of the circuit breaker from external features, and applies the protection appropriate to that state. Before discussing the means of detecting failures, we need to identify as many possible failures as we can.

Breakers can fail to clear a fault for several reasons:

  1. the trip circuit can be open ( broken wire, blown fuse, open trip coil)
  2. the interrupting mechanism can stick, leaving a single phase of a three-phase circuit connected;
  3. the interrupter can flash-over due to the loss of dielectric strength through contamination or damage;
  4. the operating mechanism can fail to operate.

The purpose of the breaker failure relay is to detect these conditions and initiate contingency, or backup, procedures. Figure 7.14 demonstrates a typical timing chart of a circuit breaker failure protection.

Figure 7.14
Circuit breaker failure protection timing chart

Some of the failures of breaker protection are discussed in detail here and in the later section, details of a particular model of microprocessor based breaker protection is discussed.

Failure to Trip – Current Leads Trip (Mode A1)
Figure 7.15 shows a circuit breaker with four heads per pole, where two poles remain closed after tripping under fault conditions. The two open heads flashed over, thereby maintaining fault current through the circuit breaker of the failed pole.

Figure 7.15
Failure to trip during fault conditions

Figure 7.16 shows the logic diagram for a scheme which is initiated when the fast pickup/dropout element A1:50 picks up, followed by the assertion of the TRIP input. After initiation, if the current does not allow the A1:50 to drop out, the timer A1:62 expires, and tripping results. Current is required to lead trip in this mode, to distinguish it from the A2 mode, which involves sequential clearing.

Figure 7.16
A1 mode breaker failure logic (failure to trip)

Failure to Trip – Trip Leads Current (Mode A2)
In a ring bus, for example, the current into the line passes through two breakers in parallel. The current division between the two breakers is not generally predictable. Therefore, enough fault current to pick up the A1:50 element may only begin to flow through one breaker when the other breaker opens, if the breakers share the current unevenly.

Suppose the breaker with the initially weak current fails to trip. The BFR first receives the trip signal. Next, the overcurrent element A1:50 picks up. The logic shown in Figure 7.17 detects this condition. It is identical to the A1 logic scheme, except for the B before A sense of the comparator.

Figure 7.17
A2 mode breaker failure logic (sequential failure trip)

Timer A2:62:2 is common to both schemes, to ensure that A1 or A2 initiates for any fault causing the A1:50 to pick up. Timer A2:62:1 can be set shorter than the corresponding A1©scheme timer A1:62, since the sequence B before A indicates the relay is late in obtaining current. System stability benefits from the shorter time setting, as it reduces the fault duration for this type of breaker failure.

Failure to Trip – Resistors Stuck Closed (Mode A3)
When one or more resistors remains inserted following a trip, the fully open heads are not likely to withstand the added voltage stress, and will flash over. Current due to charging, load or a fault continues to flow, and the temperature of the resistors rises at a rate proportional to the power input to the resistors. Eventually, the resistors may be destroyed. Figure 7.18 shows one pole of a circuit breaker with two stuck resistors and two heads flashed over.

Figure 7.18
Trip resistors remain inserted (Mode A3)

Figure 7.19 shows the logic of a scheme that detects this failure. The trip resistor thermal model accepts inputs of the current through the breaker and the voltage across the breaker and computes power into the trip resistor. The single node thermal model estimates the thermal energy stored in the resistor, and includes cooling to ambient with a settable time constant.

Figure 7.19
A3 breaker failure logic (trip resistor failure)

Tripping occurs when the energy stored in the resistor exceeds the A3:26 setting. The scheme does not depend on any breaker failure initiate inputs. Security is enhanced by requiring the A3:59 overvoltage, A4:50, and A3:37 elements to all pick up before heating is allowed. The A3:37 pickup value is the product of the overvoltage and overcurrent elements.

Failure to trip with charging Current Flowing (A4)
The trip failure shown in Figure 7.15 could occur when tripping for load or charging current, i.e. current insufficient to initiate the A1 or A2 schemes. Although such a trip failure probably does not pose much risk to the system, it indicates a potentially dangerous situation.

Figure 7.20 gives the logic for this sensitive scheme. It is initiated by trip in the presence of minimum current. A long time delay would normally be applied for security.

Figure 7.20
A4 mode breaker failure logic ( sensitive failure to trip)

Charging current is about 3.5 A per mile at 500 kV. The A4:50 element may be set down as low as 0.1 A secondary. With 2000/5 CTs, this implies a line at least 12 miles long draws sufficient charging current to pick up this element.

Failure to Close, Heads Stuck Open (B1)
Figure 7.21 shows one pole of a circuit breaker that has partially closed. Assuming that the open heads do not flash over, the condition can be detected by current unbalance, as shown in the block diagram of Figure 7.22 for pole A.

Figure 7.21
Failure to close – Heads stuck open (Mode B1)
Figure 7.22
B1 Mode breaker Failure logic – Heads stuck open

Current unbalance is checked for during a time window defined by timer B1:62:1, initiated by any close signal. When the currents are balanced, the magnitude of each equals 1/3 of the magnitude sum of the three phases. If the current in any pole is less than 1/8 the magnitude-sum current (i.e. less than 3/8 of the expected value), then the currents are declared unbalanced. In the time window just after closing, one cause of this is an open pole. Another cause of current unbalance after closing is a fault. Thus the time window must be chosen, by the timer settings, to exclude switch-into-fault possibilities immediately after closing the breaker.

Failure to close – Heads Practically Stuck Open (B2)
A failure similar to Figure 7.21, where a closing resistor is switched in, but the main contact fails to short it out, leaves current flowing through the resistor. Figure 7.23 shows the logic for a thermal scheme which is identical to the A3 trip-resistor thermal scheme, except for its settings and when power into the breaker drives it.

Figure 7.23
B2 Mode breaker failure logic ( close resistor failure)

The trip-resistor model is driven whenever the breaker is closed or opening, whereas the close-resistor model is driven whenever the breaker is open or closing. Thus the relay has six resistor thermal models: one for tripping and one for closing in each of the three poles.

Current Flowing while Breaker is Open

When the circuit breaker is open, the flow of current in any pole indicates a failure. The E1 scheme detects this failure. For security, the scheme is only enabled when the voltage across the pole in question is above 67 volts per phase secondary, i.e. greater than one per-unit. RMS voltages greater than 1 pu occur during synchronizing and out-of-step events.

The N:50 element sets the sensitivity of the scheme. It is designed for sensitivity and security at the expense of speed, as pickup and dropout times are not critical. The remaining logic in Figure 6.4 ensures that the scheme is applied only when the breaker is truly open; not when it is opening or closing.

Figure 7.24
Failure mode E1 (current while open) logic

Case studies of Circuit Breaker related failures

We cover two case studies in this appendix. One of the cases relates to the failure of a circuit breaker to trip leading to a chain of other failures. The other case discusses how a TG unit suffered an outage because of a simple mistake in the choice of an auxiliary relay in a circuit breaker scheme.


This case discusses how a circuit breaker can fail to trip not just because of a relay or coil failure but a mechanical failure of the operating mechanism and what is the fall out of such a failure.

The study concerns a 6.6 kV motor control center (MCC) feeding a number of synchronous motors. The MCC had two incomer breakers and a sectionaliser breaker (normally kept OFF) with a feature of automatic bus transfer. All outgoing feeders for motors were breaker controlled.

During the commissioning operations in a process plant, a large capacity fan driven by a 6.6 kV synchronous motor was being tested. The excitation unit of the motor developed a problem due to which the motor lost field supply. This resulted in its operation as an induction machine taking more than the rated current. Because the field wiring was incomplete, the failure of excitation did not result in any alarm.

The MCC was located in an unattended building. The overload protection of the motor detected the problem and sent a tripping impulse to the breaker. The circuit breaker did not trip. The motor continued to run while an operator from the feeding substation was sent to investigate the overload alarm, which was triggered from the MCC and was displayed to the feeding end station as an abnormal condition in MCC. When the operator reached the MCC, he found that the overload flag in the motor feeder cubicle was down. He phoned to the process plant operator to trip the fan. It was found that the motor was not tripping either from the plant control room or from the local emergency trip facility. The operator tried to trip the feeder through the mechanical leaver and found that it did not function also.

Meanwhile, the motor cable terminations at both end got severely overheated and this resulted in cable termination failure at the motor end and the terminal box cover got blown away. Fortunately, it did not hit anyone but in the confusion that followed the explosion, a few operating personnel who were on the fan deck jumped down resulting in fracture injuries to one of them.

The short circuit finally caused the incomer circuit breaker to trip. However, the supply was restored by the bus section breaker, which closed on the same fault and tripped. This resulted in the MCC totally losing power.

The supply was restored after the defective breaker was racked out.

Investigations revealed the following.

  • The quick-acting auxiliary contact of the breaker through which the trip coil gets supply had suffered mechanical jamming and the tripping shaft could not move as a result.
  • The incomplete field wiring resulted in the excitation fault alarm not being conveyed to the MCC and thereby to the feeding substation.
  • Though the overload relay did energise the trip coil, the tripping could not be effected. Continued impulse to the trip coil had caused the coil to burn out.
  • The failure of tripping had caused a cable termination fault which ultimately was cleared by the tripping of the incomer.
  • The restoration action could however have been avoided, if the scheme was designed to prevent bus transfer action when the incomer tripped on a fault.

Remedial actions

  • The circuit breaker manufacturers were informed about the serious design flaw and a re-design and phased modification exercise was carried out as a long-term measure on all the breakers of this type.
  • In the medium term, a simple breaker failure scheme was designed and put in place so that the activation of the trip output relay of any panel persisting beyond a few seconds will trip the respective incomer. The bus transfer scheme was modified to block operation so that the supply is not restored to a faulty circuit.
  • In the near term, all connections between field and the MCC were completed before further trails were taken up.
  • As a procedural measure, it was arranged that running trials of equipment be done only during specified periods and an operator was arranged to be in the vicinity of the MCC with instructions to trip the incomer in any such eventuality.


This case discusses the tripping of a 60MW turbo generator, which was meant to provide assured power to critical loads in a process plant due to a wrong selection of an output relay in the control scheme of a circuit breaker.

A newly commissioned turbo generator set tripped due to loss of feed water to the steam generator following a tripping of the feed pump. The feed water pump driven by a 2000kW 6.6 kV motor had its bearings supplied with lubricating oil from an electrically driven oil pump. The recommendation of the vendor to have a shaft mounted oil pump had been turned down on cost considerations. The lubrication motor was fed from an LV MCC through an ac contactor operated feeder. This pump suddenly tripped for no apparent reason. Since there was no standby to this pump and no scheme to auto start the pump, the restarting had to depend on the unit operator. The abrupt loss of lubrication caused the 6.6 kV motor feeder to trip out. The operator restarted the lube oil pump but found that the main motor was locked out and could not be started. Meanwhile the loss of feed water caused the loss of steam pressure and the unit tipped.

The reason for abrupt trip of the unit was found to be due to a voltage sag condition in the power system due to which the ac contactor dropped and the lubrication pump tripped. This was dome by correlating the power system event records with the loss of the generator unit. This in turn was traced to an external system fault where the tripping was delayed due to the mal-operation of the main protection of a feeder which had to trip on the back up protection, thus causing a longer than usual sag.

The loss of oil pressure caused the main feed pump motor to trip. Normally only electrical trips such as motor earth fault or short circuits are done through a high speed lock out trip relay, while trips due to mechanical systems are routed through a self-reset output relay. In this case, all trips were through a single lock-out trip relay. Because of this, the operator was unable to restart the feed pump. Restarting required the lock-out relay in the circuit breaker panel to be reset by the electrical operator.

Remedial actions
The following actions were taken to prevent such problems.

  • As a long-term measure, the plant technical specifications made it mandatory to have shaft-mounted lubrication for all critical auxiliaries. Where this feature was not offered by a manufacturer, the critical auxiliary equipment will have to be provided with redundancy. Also, the use of dc control supply with a battery back up was recommended for all LV boards of future generation units.
  • As a medium term measure, the trip output relays in motor feeders for mechanical abnormalities were replaced with self reset relays, by ordering suitable type of relays and diverting all such impulses to the new relay was carried out by suitable wiring modifications.
  • As an immediate measure, the LV board control supply was diverted to an UPS source so that sags in the system will not be felt by the control supply.


Tripping batteries

8.1 Tripping batteries

8.1.1 Importance

The operation of monitoring devices such as relays and the tripping mechanisms of breakers require an independent power source, which does not vary with the main source being monitored. Batteries provide this power and hence they form an important role in protection circuits.

The relay / circuit breaker combination depends entirely on the tripping battery for successful operation. Without this, relays and breakers will not operate, becoming ‘solid’, making their capital investment very useless and the performance of the whole network unacceptable.

It is therefore necessary to ensure that batteries and chargers are regularly inspected and maintained at the highest possible level of efficiency at all times to enable correct operation of relays at the correct time.

8.1.2 How does a battery work?

A battery is an assembly of cells. Whether it is used to make a call using a mobile phone or to trip a circuit breaker, every cell has three things in common-positive and negative electrodes and an electrolyte. Whereas some of the dry cell batteries drain out their energy and are to be discarded, a stationary or storage battery used in the switchgear protection is capable of being recharged.

There are two types of batteries used in an electrical control system

  1. Lead acid type
  2. Nickel cadmium type

Both the above types can be classified further into flooded type and sealed maintenance free type. The flooded cell construction basically refer to the electrodes of the cell in the electrolyte medium, which can be topped up with distilled water as the electrolyte gets diluted due to charging and discharging cycles.

The batteries also discharge hydrogen during these cycles and it is necessary to restrict this discharge to less than 4% by volume to air, to avoid the surroundings becoming hazardous.

The higher discharge of H2 in lead acid cells have resulted in the manufacture of sealed maintenance free or valve regulated lead acid (VRLA) batteries. Here the H2 discharge is restricted to be below the hazardous limit.

Nickel cadmium batteries are comparatively costlier though they are considered more reliable with lower maintenance and environmental issues than the lead acid types. In addition, the hydrogen discharge in a nickel cadmium cell is comparatively less. Hence, for conventional switchgear protection applications, sealed nickel cadmium batteries are not required. As such, the sealed nickel cadmium cells are only used for small battery cells used in modern electronic gadgets.

The rechargeable lead acid cells as used in switchgear/relay applications are generally of the Plante type and has an electrical voltage of 2 volts. The cell contains a pure lead (Pb) positive plate, a lead oxide (Pb02) negative plate, and an electrolyte of dilute sulphuric acid. The nickel cadmium cell has an electrical voltage of 1.2 volts containing nickel compound (+) and cadmium compound (-) plates with potassium hydroxide solution as the electrolyte.

The following table briefly gives the advantages and disadvantages of nickel cadmium batteries over lead acid type, the most common types being used for protection application (see Table 8.1).

Table 8.1
Nickel cadmium versus lead acid cells

Discharging and recharging
When a load is connected across the plate terminals of a charged cell, an electrical current flows and the lead and lead oxide start to change into lead sulphate. A similar phenomenon occurs with the nickel cadmium cell. The result is the dilution and weakening of the electrolyte. It is thus possible to measure the state of the battery’s charge by measuring the electrolyte’s specific gravity with a hydrometer.

The cell is recharged by injecting a direct current in the opposite direction using another source to restore its plates and electrolyte to their original state.

Application guide (see Table 8.2)

Table 8.2
Application for different electrode types

8.1.3 Life expectancy

Plante25 - 30 years
Flat Plate5 - 6 years
Tubular10 - 12 years

8.1.4 Construction

For long life with very high reliability needed in places like power stations and substations, batteries are made up of cells of the kind named after Plante. Figure 8.1 gives typical construction of a lead acid battery.

Figure 8.1
Typical construction of a lead acid cell

The positive plate is cast from pure lead in a form which gives it a surface twelve times its apparent area. The negative plate is of the pasted grid type made by forcing lead oxide paste into a cast lead alloy grid.

The positive and negative plates are interleaved and insulated from each other to prevent short circuits, and are mounted in transparent plastic containers to allow visual checking of the acid level and general condition.

Because of the high initial cost of Plante cells, specially designed flat plate cells have been developed to provide a cheaper but shorter-lived alternative source of standby power. Although this is the basis of the modern car battery, it is totally unsuitable for switch-tripping duty because it has been designed to give a high current for a short time as when starting a car engine.

Cells with tubular positive plates are also available but these are normally used to power electric trucks etc., where daily recharging is needed i.e. frequent charge/discharge cycles.

8.1.6 Voltage and capacity

The nominal voltage is 2 volts per lead acid cell, i.e. a 110 volts battery will have 55 cells. On discharge, the recommended final voltage at which the discharge should be terminated depends on the discharge rate. This is shown in discharge curves, as shown in Figure 8.2, (e.g. the final voltage for the 3 hour rate of discharge is 1.8 volts)

Figure 8.2
Typical battery discharge curves

8.1.7 Capacity

The capacity that can be provided by a cell varies with the discharge rate as indicated in the capacity curves shown above. The capacity of a battery is defined in terms of ampere-hour (AH) related to 5 hour or 10 hour duty. It refers to the capacity of the battery to supply a load current over a period, until it reaches its predefined final cell voltage. After this time, the cell has to be recharged to again feed a load. For example, in case of lead acid batteries, the acceptable final cell voltage could be as low as 1.70 volts. But it is common to define the capacity of the lead acid batteries for different cell voltages like 1.75 V, 1.80 V and 1.85 V. Accordingly, the discharge curves of a battery vary showing comparatively higher time to reach the lowest acceptable cell voltage.

Table 8.3 gives the current that can be drawn from a battery depending upon the 10 hour rating.

Table 8.3
Capacity variation of a lead acid cell with load current

The above table typically refers to a cell, which can supply 100% of its rated amperes for 10 hours at the end of which it reaches an end voltage of 1.85 V. The cell will reach 1.85 V if 100% rated current is continuously drawn for 10 hours. Alternatively, if the current drawn is 600% of it’s rating, the cell will reach 1.75 V at the end of 1 hour itself. Hence, while designing the capacity of the cell, proper margins should be taken into account based on the nature of loads and the likely currents to be drawn over a cycle.

Capacity is also affected by ambient temperature. The lower the ambient temperature, the capacity will be comparatively higher. A detailed methodology for calculating the capacity of a lead acid battery for station applications is explained in the IEEE standard 485:1997.

8.1.8 Battery charger

In a protection system, it is necessary that the control DC voltage shall remain constant for as much time as possible, so that the system works without interruption. Hence, the batteries are normally kept on charge continuously by a battery charger. The charger is a rectifier, which produces a slightly higher voltage compared to the nominal cell voltage of a battery. The main power source is derived from the normally available AC source, which is rectified by the charger. Typical connection is as seen in Figure 8.3.

Figure 8.3
Charger/battery/load connection

Here the battery is a combination of multiple cells connected in series to get the nominal DC tripping/control voltage required for the operation of relays and breakers and could be from 24 V to 220 V, depending on the loads and the capacity requirement.

8.1.9 Trickle charge

Trickle charging is a method of keeping the cells in a fully charged condition by passing a small current through them. The correct trickle charge current is that which does not allow the cell to discharge gas and does not allow the specific gravity to fall over a period. The cell voltage will be approximately 2.25 volts for lead acid cell and 1.35 volts for nickel cadmium cell.

8.1.10 Float charge

Float charging is keeping the voltage applied to the battery at 2.25 volts per lead acid cell or 1.35 volts for nickel cadmium cell, i.e. maintaining a constant voltage across each cell. This method is usually adopted in conjunction with supplying continuous and variable DC loads from the charging equipment, as would typically happen for a substation battery.

The loads in a substation normally comprise a small continuous load consisting of pilot lamps, relays etc, and momentary short time loads of comparatively high values such as those for circuit breaker tripping and closing operations, motor wound springs and so on.

Since the charger, battery and load are all connected in parallel as per Figure 8.3, the continuous load is carried by the charger at normal floating voltage and the battery draws its own maintenance current at the same time. Any load that exceeds the charger capacity will lower its voltage slightly, to the point where the battery discharges to supply the remainder. If there should be a complete power failure the battery will supply the entire load for a period depending on the Ah capacity and the load, until AC power is restored and then automatically starts being recharged.

Typical float currents will be in the range of 30-50 milliamps per 100 Ah of rated capacity, increasing to about 10 times towards the end of the battery’s life.

8.1.11 Specific gravity

A simple hydrometer reading indicates the state of charge in a cell. A fully charged cell will have a specific gravity reading of between 1.205 and 1.215.

As a rule of thumb, in a lead acid battery,

Open circuit volts = specific gravity + 0.84

Thus, the open circuit voltage of a cell with a S.G. of 1.21 will be 2.05 volts; one with an S.G. of 1.28 will be 2.12 volts.

8.1.12 Recharge

The ampere-hour efficiency of the cells is 90%; therefore, on recharge, the amount of recharge required is equal to the discharge in ampere-hours plus 11%.

On recharge, the voltage increases and reaches a saturation value as the charge proceeds. The highest voltage reached with the finishing rate of charge flowing is 2.7 volts per lead acid cell.

It is possible to recharge a cell by limiting the voltage of the charging equipment to a much lower value than 2.7 volts per cell; 2.4 volts per cell being the minimum desirable value.

This will result in an extended recharge period, as the battery will automatically limit the charge current irrespective of the charger output.

8.2 Construction of battery chargers

Battery charging is accomplished with sophisticated electronically controlled rectifiers that permit a battery to be continuously maintained on a floating charge and to recharge a discharged battery as fast as possible. It also has to handle the electrical load.

Chargers presently used in stationary applications are normally of the constant voltage type. Voltage adjustments can be made with precision to 0.01 of a volt per cell. This is necessary because floating voltage and equalizing voltage levels critically affect battery performance and life expectancy. Voltage level specifications are normally expressed to two decimal places, i.e. 2.16 to 2.33 volts for a lead acid cell.

Proper specifications and correct adjustments of the battery charger are the most important factors affecting the satisfactory performance and life of the battery cells. Voltage levels from the charger also usually serve the electrical load, so changes in charger voltage output affect the load.

Chargers are normally equipped to accommodate normal float voltages and the higher voltages for equalizing charges when required.

As the charger DC output is rectified from AC there will be a ripple on the output unless smoothing techniques are employed.

Care must be taken to ensure that the maximum rms current value of the AC component does not exceed 7% of the battery capacity expressed in amps. Failure to do this will result in a phenomenon called AC corrosion, where the negative peak of the AC component reverses the direction of the charging current, leading to corrosion and ultimate destruction of the plates in the cells.

8.3 Maintenance guide

Following are brief guidelines for maintaining the lead acid battery system, which are also applicable for nickel cadmium batteries.

  • Check batteries and chargers regularly, at least once per month.
  • Take specific gravity reading–should be 1.215 minimum.
  • Check electrolyte level–top up if necessary to keep level between its normal and upper limits. Use distilled water wherever possible. Impurities in normal tap water such as chlorine and iron tend to increase internal losses. Frequent topping up of electrolyte means excessive gassing brought about by overcharging.
  • Check for gassing. This normally starts when lead acid cell voltage reaches 2.30–2.35 volts per cell (1.30-1.35 for Ni-Cad cell) and increases as charge progresses. At full charge, most energy goes into gas, oxygen being liberated at the positive plate and hydrogen at the negative. 4% hydrogen in the air may be hazardous. The room employing lead acid batteries must be well ventilated. However, the nickel cadmium batteries discharge very low hydrogen.
  • Look between the plates for any signs of mossing or treeing. This is a build up of a sponge like layer of lead on the negative plates, which can accumulate to such an extent as to bridge over or around the separators and cause a short circuit to the adjacent positive plate. This condition is usually an indication of overcharging.
  • Also look for sediment build up on the floor of the container. If this increases to the point where it reaches the bottom of the plates, it will short them out to cause failure. Overcharging can also accelerate the accumulation of sediment and shorten the useful life of the battery.
  • Battery cells must be kept clean and dry to the extent that no corrosion, dust or moisture offers a conducting path to partially short-circuit the cell or contact ground.
  • Finally, proper charging is the most important factor in battery service and life. A short boost charge is beneficial on a regular basis to prevent stratification, to freshen the electrolyte and to equalize the cells. Ensure that the charger is working properly and that it is operating in accordance with the manufacturers recommended settings.
  • The VRLA batteries cannot be inspected visually as with the flooded cells but their healthiness is ascertained by measuring the cell voltage with/without the charger input. Cells reaching end voltage after disconnection of charger comparatively faster than the other cells need to be replaced completely, as there is no question of changing the electrolyte.
  • The VRLA batteries last longer if their ambient temperature is controlled to around 25°C by use of air conditioning, as otherwise they may lose their charge more quickly.
  • The flooded type lead acid batteries are normally prone for spill over of electrolyte and it is highly recommended to keep these batteries in separate room with acid proof tiles to take care of the spill over conditions. The nickel cadmium batteries on the other hand do not pose such major hazards though they are quite costlier compared to lead acid type.

8.3.1 Arrangement of DC supplies

For strategic switch boards it is sometimes worthwhile fitting two trip coils to each circuit breaker to ensure positive tripping.

Two batteries and chargers should then be installed to ensure the integrity of each tripping system, DC fail relays being installed on each panel to monitor the continuity of each supply (see Figure 8.4).

Figure 8.4
Arrangement of DC supplies with two trip coils for each circuit breaker

For breakers fitted with only one trip coil, a single battery and charger should be installed and trip coil supervision relays fitted to monitor each circuit (see Figure 8.5).

Figure 8.5
Arrangement of DC supplies with one trip coil

8.3.2 Grounding of DC supplies

It is a normal practice to ground the tripping battery at one point to prevent it floating all over the place with respect to ground. One popular method is to ground the negative rail (see Figure 8.6).

Figure 8.6
Grounding of DC supplies negative rail

It will be noted that in this case a solid link is used instead of a fuse on the negative side. This ensures that the negative is never lost. If it was, ‘sneak circuits’ become a distinct possibility causing many vexing problems etc.

The drawback with this system is that the first ground fault on the wiring could possibly create a short on the battery.

A more secure system is the center-point high impedance ground method, which utilizes a battery ground fault alarm relay (BEFAR) see Figure 8.7.

Figure 8.7
Center point high impedance grounding method of DC supplies

A ground fault on either the positive or negative rail will cause a very small current to flow up the neutral (0 volt) connection. This will cause the BEFAR to operate to alarm and indicate which leg has faulted. The supply will however remain on but this condition should be attended to before a second ground fault occurs. A test button is also provided to check the relay is functional at any time, by offsetting this away from the center zero point.

8.4 Trip circuit supervision

It is necessary to monitor the trip supply availability in a trip circuit to ensure that the system is continuously being monitored. This is sometimes achieved by means of ‘fail-safe circuits’, which ensure that there is no question of operating a system without monitoring.

Trip circuit supervision is a method, where the trip supply is continuously monitored, so that any break in the circuit is brought to the operators’ attention. There are two possible types a) supervision only when the breaker is in closed (in service) condition; b) supervision irrespective of the breaker status. These are achieved by using breaker auxiliary contacts in the DC trip circuits as shown in Figure 8.8 (a)—(c).

Figure 8.8 (a)
Supervision while circuit breaker is closed.
Figure 8.8 (b)
Supervision while circuit breaker is open or closed
Figure 8.8 (c)
Supervision with circuit breaker open or closed with remote alarm

8.5 Reasons why breakers and contactors fail to trip

8.5.1 Breakers

  1. Open circuited DC shunt trip coil
  2. Loss of circuit DC trip supply
    • - Trip fuse blown or removed or
    • - Trip MCB open
  3. Loss of station DC trip supply
    • - Battery and/or charger failure
    • - Battery and/or charger disconnection
  4. Burnt out DC shunt trip coil
  5. Failure by open circuit of control wiring or defective relay contact
  6. Breaker mechanically jammed:
    • - Trip bar solid
    • - Trip coil mechanically jammed
    • - Trip coil loose or displaced
    • - Broken mechanism
    • - Lack of regular/correct maintenance
    • - Main contacts welding
    • - Contacts arcing – loss of vacuum or SF6 gas pressure.

Trip circuit supervision (TCS) provides continuous monitoring and gives an immediate warning of conditions 1 to 5 before the breaker is called upon to trip. Corrective action can then be taken before the event, to prevent breaker failure occurring.

Breaker fail (BF) protection covers all conditions but only highlights a problem after a system primary fault occurs and the breaker has failed to clear.

TCS can be regarded as the fence at the top of the cliff whereas BF is the ambulance at the bottom, only operating after the event!

8.5.2 Contactors

  1. Latched type
    • - Suffer same failures as breakers
  2. Electrically held-in type
    • - Can be energized from battery source but not favored because of battery drain
    • - Usually energized from AC supply via built-in rectifiers
    • - Dip-proofing provided by capacitor across hold-in coil to delay drop out by 200-300 ms for transient dips.

Failures to open could arise from:

  • Welding closed of normally open control contacts
  • Accidental short-circuiting of normally closed contacts preventing de-energizing hold-in coil
  • Welding closed of main contacts (old vacuum or air break types)
  • Mechanism mechanically jammed

8.6 Capacitor storage trip units

These units are intended for use in substations where no tripping batteries have been provided.

They can also be used as an alternative tripping supply for installations, which employ two-shunt trip coils per circuit breaker, one connected to the tripping battery and the other to the capacitor storage unit.

The unit comprises two capacitors to provide short-time storage of auxiliary energy, one to operate a protective relay whilst the other operates the circuit breaker trip coil.

The device has three inputs, which may be fed from DC or AC sources. A test button is provided for checking the degree of capacitor charge, whilst an in-built signaling relay with a normally closed contact offers remote indication of discharged capacitors.

Figure 8.9 shows the unit below.

Figure 8.9
Capacitor storage trip unit

8.6.1 Points to watch for

  • Always endeavor to feed the unit from a busbar connected VT if possible as the first priority as this is the most secure supply.
  • Only feed one relay and circuit breaker from each unit and check that the stored energy is sufficient to do the job required of it.
  • When the storage device is fed from current transformers, it is recommended that at least two phases are used.
  • A set of special interposing auxiliary CT’s should be installed between the main CT’s and the storage device, to protect it from over voltages caused by nearby short-circuits. They should be designed to saturate at about 200 volts rms.
  • However, they must also ensure that they are able to charge the capacitors from zero to maximum in two cycles to cover the case of ‘closing onto fault’.
  • Ratios and performance of the line CT’s on light loads must also ensure that the capacitors can be charged rapidly.
  • Care should be taken when installing these devices into CT circuits that they do not overburden other relays and protection that may be connected to the same CT’s. The recommended interposing CT’s may well pose a problem in this regard.
  • As the protection and tripping will depend entirely on the correct performance of the capacitor storage unit, it would be as well to consider allocating an exclusive dedicated set of CT’s for this function.



9.1 Introduction

It had been repeatedly indicated in the earlier chapters that relays are the devices, which monitor the conditions of a circuit and give instructions to open a circuit under unhealthy conditions. The basic parameters of the three-phase electrical system are voltage, current, frequency and power. All these have predetermined values and/or sequence under healthy conditions. Any shift from this normal behavior could be the result of a fault condition either at the source end or at the load end. The relays are devices, which monitor various parameters in various ways and this chapter gives a brief outline of their principles of operation.

The types of relays can be broadly classified as:

  • Electromechanical relays
  • Static relays (analogue and digital)
  • Microprocessor based relays

The electromechanical relays had been dominating the electrical protection field until the use of silicon semiconductor devices became more common. The use of static relays in the early stages was more due to the advantages such as lower weight, non-moving mechanical parts, reduced wear and tear, etc. However, the initial static relays had not been overwhelmingly accepted in the electrical field also due to their ‘static’ nature. Further, the reliability of electronic components in the initial stages had been unsatisfactory due to the quality issues and their ability (or inability) to withstand source fluctuations and ambient temperature conditions. However, the reliability of electronic components improved subsequently, the advent of digital electronics technology and microprocessor developments gave a completely different picture to the use of static relays. The earlier analogue relays have been slowly replaced with digital relays and today’s protection technology is more inclined towards use of digital relays, though the electromechanical relays are still preferred in certain applications, with cost being one of the main reasons. The use of static analogue relays is not so common.

9.2 Principle of the construction and operation of the electromechanical IDMTL relay

As the name implies, it is a relay monitoring the current, and has inverse characteristics with respect to the currents being monitored. This (electro-mechanical) relay is without doubt one of the most popular relays used on medium and low voltage systems for many years, and modern digital relays’ characteristics are still mainly based on the torque characteristic of this type of relay. Hence, it is worthwhile studying the operation of this relay in detail to understand the characteristics adopted in the digital relays (see Figure 9.1).

Figure 9.1
Typical mechanical relay

The above relay can be schematically represented as shown in Figure 9.2.

Figure 9.2
The IDMTL relay

The current I1 from the line CTs, sets up a magnetic flux A and also induces a current I2 in the secondary winding which in turn sets up a flux in B.

Fluxes A and B are out of phase thus producing a torque in the disc causing it to rotate.

Now, speed is proportional to braking torque, and is proportional to driving torque. Therefore, speed is proportional to I².



This therefore gives an inverse characteristic (see Figure 9.3).

Figure 9.3
Characteristic curve of relay

It can be seen that the operating time of an IDMTL relay is inversely proportional to a function of current, i.e. it has a long operating time at low multiples of setting current and a relatively short operating time at high multiples of setting current.

The characteristic curve is defined by BS 142 and is shown in Figure 9.4.

Two adjustments are possible on the relay, namely:

  1. The current pick-up or plug setting: This adjusts the setting current by means of a plug bridge, which varies the effective turns on the upper electromagnet.
  2. The time multiplier setting: This adjusts the operating time at a given multiple of setting current, by altering by means of the torsion head, the distance that the disc has to travel before contact is made.
Figure 9.4
Time and pick-up errors at unity time multiplier

9.2.1 Current (plug) pickup setting

This setting determines the level of current at which the relays will pick-up or its disc will start to rotate.

BS142 states that, the relay must definitely operate at 130% setting and reset at 70% setting. In this context, the plug setting is that current at which the operating and restraining torques are in a state of balance. In practice, BS142 requires that the relay should definitely not operate at the setting and to ensure this, a relay may display a slight tendency to reset at the normal setting.

The relay therefore normally picks up in the range of 105% to 130% its current plug setting.

Usually the following ranges of nominal current are used, giving a 1:4 ratio in seven steps:

Percentage plug settings (Reyrolle)

Overcurrent: 50% 75% 100% 125% 150% 175% 200%
Ground fault: 20% 30% 40% 50% 60% 70% 80%
Or 10% 15% 20% 25% 30% 35% 40%

Current plug settings (GEC)–For 5 amp relay

Overcurrent: 1.5A 3.5A 5.0A 6.25A 7.5A 8.75A 10A
Ground fault: 1.0A 1.5A 2.0A 2.5A 3.0A 3.5A 4.0A
Or 0.5A 0.75A 1.0A 1.25A 1.5A 1.75A 2.A

Normally, the highest current tap is automatically selected when the plug is removed, so that adjustments can be made on load without open-circuiting the current transformer.

9.2.2 Time multiplier setting

This dial rotates the disc and its accompanying moving contact closer to the fixed contact, thereby reducing the amount of distance to be traveled by the moving contact, hence speeding up the tripping time of the relay.

This has the effect of moving the inverse curve down the axis as shown in Figure 9.5.

Figure 9.5
Time/current characteristic

The above curve is the most common type used, namely the Normal inverse curve. Its characteristic shows an operating time of 3 seconds at 10 times the current plug setting i.e. with the plug bridge set at 1 amp, when 10 amps flows through, the relay will close its contacts after 3 seconds (i.e. with the time multiplier set at 1.0). The time of operation of the relay is chosen by collectively selecting the current and time plug settings. There is another popular version, which has an operating time of 1.3 seconds at 10 times the current setting.

It is possible to manufacture relays with different characteristics, but the principle of operation remains the same. Other characteristic curves popular are very and extremely inverse. The different time characteristic curves of an IDMTL relays is shown in Figure. 9.6 These are represented in logarithmic graphs due to the exponential nature.

Figure 9.6
Fault current (multiple of current setting)

9.2.3 Burden

The burden is the normal continuous load imposed on the current transformers by the relay, normally expressed in VA or some times in ohms.

For electro-mechanical relays, this is normally stated as 3 VA nominal. The modern electronic relays offer a much lower figure, which is one of their virtues.

However, for the electro-mechanical type, the selection of the plug setting does have an effect on the burden. As stated earlier, the operating coil is wound to give time/current curves of the same shape on each of the seven taps, which are selected on the plug bridge. As there is a required minimum amp-turns of magnetic flux to get the relay to pickup, the lower the current the more turns are necessary. The lower the setting therefore results in higher the burden on the CTs. Example:

For 5 amp relay on 200% tap,

On 10% tap,

The lower tap therefore, places a higher burden on the CTs and they must have adequate performance to meet such demands. This is often not the case in low ratio CTs. A mistaken impression is created that the relay is at its most sensitive setting when it is set on its lowest tap. However, the fact is that the CTs may saturate under these conditions due to the higher burden, causing the electro mechanical relay to respond more slowly, if at all it picks up. However, the modern digital relays do not exhibit such behavior and have constant burden through out its operating range.

Table 9.1 gives the burden values exhibited by one of the most common type of electromechanical relays used in the electrical systems and the curves that follow show the advantage of static / digital relays over electromechanical relays in this aspect (see Figure 9.7).

Table 9.1
Electro-mechanical relays—Coil impedance versus plug setting
Figure 9.7
Impedance versus plug setting (electromechanical and digital)

9.2.4 General

Since an electrical system employs many relays, mechanical or electrical flag indication is provided in each relay to indicate whether that relay has operated to indicate the type of fault involved.

Many modern relays are of the draw out type so that, the relay can be removed from its case even when the CT circuits are alive. This is possible as the associated CT terminals in the case are short-circuited just before the relay contacts break whilst the relay is being withdrawn.

Certain models also have catches, which hold the relay in its case. When these catches are unlatched, the tripping circuit is opened so that accidental closing of the trip contacts will not trip the associated circuit breaker. This feature must not always be relied upon to prevent tripping as it does not necessarily isolate all tripping circuits and the feature is not present in all relays.

9.2.5 Testing of IDMTL relays

Modern relays are very reliable and in their dust proof cases, they remain clean. However, dirt and magnetic particles are the biggest cause of problems in electro mechanical relays. Hence, when this type of relay is removed for testing, it should be covered, while not being actually tested. It should preferably be kept in a spare case or a plastic bag if stored or transported.

For operational tests, a load transformer and variac can be used to supply current, while a timer will indicate when the tripping contacts close. Typical connections are shown in Figure 9.8.

Figure 9.8
Testing of IDMTL relays

This method can be used to check that the relay operates, that the flag drops correctly just as the contacts are made with slow disc operation and that the contacts are made positively with good pressure.

Caution: This method is not reliable for timing or pick-up tests. A proper relay current test set is necessary for accurate tests as with this simple set up, distorted non-sinusoidal currents result because of the non-linear magnetic circuit of the relay.

In service the relay is driven from a pure current source, namely the line CTs. The voltage that is developed to drive this current through the non-linear magnetic circuit of the relay becomes distorted, but the current remains ‘pure’ and faithful to the primary current. When testing from the normal 220-volt supply, we have a pure voltage source. Hence, the current now becomes distorted and non-sinusoidal, giving the relay false parameters on which to operate.

Special test sets are on the market, which are designed to inject sinusoidal currents into the relays so that accurate timing and pick-up currents can be recorded.

If the relay timing is found to be outside the tolerance limits, do not attempt to rectify this by adjusting the spiral hairspring at the top of the disc shaft, as this could upset the whole characteristic. This spring should only be adjusted by trained relay service technicians when checking for ‘disc creep’ and this together with adjustments of the magnets, determine the accuracy of the timing characteristics (see Figure 9.9—Figure 9.11).

Figure 9.9
Typical waveforms when relay driven from CTs in service
Figure 9.10
Typical waveforms when relay driven from plain 240 v aux. supply and table of errors
Figure 9.11
5 amp ground fault relay supplied from 200/5 amp current transformers

Irelay = I amp, plug setting = 0.5 amp. The following table gives the margin of errors in the test results based on the testing source.

Setting of an IDMT relay
Example: Calculate the plug setting and time multiplier setting for an IDMTL relay on the following network so that it will trip in 2.4 seconds (see Figure 9.12).

Figure 9.12
Example of calculation of plug and time multiplier setting
Fault current   =     1000 amps
CT ratio   =     100/5 amps

Hence expected current into relay under fault conditions,

Choose plug setting of 5 amps (100%). Therefore, current into relay as a multiple of plug setting during fault:

We require the relay to operate after 2.4 seconds as soon as this much current starts flowing in the circuit.

Referring to characteristc curves below, read time multiplier setting where 10 times plug setting current and 2.4 seconds cross, which is about 0.8. Accordingly, relay settings = current plug tap 5 amps (100%) and time multiplier 0.8.

Alternatively, if the current plug setting is chosen as 125% (6.25 amps), the fault current through the relay will be 50/6.25 = 8 amps. The graph shows that 8 times plug setting to operate in 2.4 seconds, the time multiplier should be about 0.7.

This technique is fine if the required setting falls exactly on the TM curve. However, if the desired setting falls between the curves, it is not easy to estimate the intermediate setting accurately as the scales of the graph are log/log. The following procedure is therefore recommended (see Figure 9.13).

Figure 9.13
Multiples of plug setting current

Go to the multiple of plug setting current and read the seconds value corresponding to the 1.0 time multiplier curve. Then divide the desired time setting by this figure. This will give the exact time multiplier setting:

Seconds value at 10 times = 3 (at 8 times it is about 3.4)

Desired setting = 2.4

Therefore time multiplier = 2.4/3 = 0.8 or 2.4/3.4 = 0.7 in the second case.

9.3 Factors influencing choice of plug setting

  1. Load conditions: Must not trip for healthy conditions, i.e. full load and permissible overloads, re-energization and starting surges
  2. Load current re-distribution after tripping
  3. Fault currents: High fault currents can cause saturation of CT.’s. Choice of CT ratio is important
  4. CT performance: Magnetization curve. It’s internal resistance
  5. Relay burden: Increases at lower taps on electro-mechanical relays
  6. Relay accuracy: Better at top end of curve. Attempt to use in tight grading applications

9.4 The new era in protection–microprocessor vs electronic vs traditional

9.4.1 Background

Electromechanical relays of various types have been available from the earliest days of electrical power supply. Some of these early designs have been improved over the years. One of the most successful types of electromechanical protection relays has been the previously discussed inverse definite minimum time (IDMT) overcurrent relay based on the induction disc. With the introduction of electronic devices such as the transistor in the 1950’s, electronic protection relays were introduced in the 1960’s and 1970’s. Since then, the development of relays has been related to the general development of electronics.

By the late 1960’s, extensive experience in the use of electronics in simple protection systems enabled the development of many quite advanced protection schemes and the first high-voltage substations were equipped with static protective relays. Over a period, these have been extended to cover other equipments such as transmission lines, motors, capacitors and generators. New measuring techniques have been introduced, measurements that are more accurate can be performed and high overall quality, reliability, and performance of the protection system for high voltage power systems have been reached.

Developments in the 1970’s concentrated on improving reliability through improved design of printed circuit boards leading to integrated circuits and general improvements in substation designs, particularly grounding. In general, most static protective relays of that time were designed to match or improve on the basic electromechanical performance features. Improvements introduced included low current transformer burden, improved setting accuracy and repeatability as well as improved speed. Also, during this period, experiments were conducted in Europe, Japan and the USA to test computer-based protection systems based on the availability of digital electronics.

This is particularly true with IDMT overcurrent relays, where it was both difficult and expensive to provide the inverse time characteristics by means of analogue electronic circuits. However with the advent of microprocessors, it is much easier to provide the most commonly used characteristics such as definite time, normal inverse, very inverse, extremely inverse and thermal characteristics using different algorithms stored in the microprocessor’s memory.

The overcurrent relay is undoubtedly the most common type of protection relay used by electricity supply authorities for protection on distribution systems. This chapter concentrates on the various features of modern static overcurrent protection relays in relation to the older electromechanical relays, which are still commonly used on distribution systems today. The purpose is to clarify some of the arguments for and against static protection relays, particularly for medium voltage applications.

What is a static protection relay?
Static relays are those in which the designed response is developed by electronic or magnetic means without mechanical motion.

This means, that the designation ‘static relay’ covers the electronic relays, of both the analogue and digital designs. The analogue relays refer to electronic circuits with discrete devices like transistors, diodes, etc., which were adopted in the initial stages. However, the digital designs incorporate integrated chips, microprocessors, etc., which had been developed subsequently. In recent years, very few relays of the analogue type are being developed or introduced for the first time.

Most modern overcurrent relays are of the digital type. There are many reasons for this, the main ones being associated with cost, accuracy, flexibility, reliability, size, auxiliary power drain, etc. Many of these reasons will become evident during the course of this chapter, which will concentrate on relays of the digital type. Microprocessor relays are of the digital type.

The main objective of using static relays is to improve the sensitivity, speed and reliability of a protection system by removing the delicate mechanical parts that can be subject to wear due to vibration, dust and corrosion. During the early development of static relays, the use of static components were particularly attractive for the more complicated relays such as impedance relays, directional relays, voltage regulating relays, etc. On the other hand, the early static IDMT overcurrent relays were expensive because it was difficult to match the inverse time characteristic using analogue protection circuits. The battery drain associated with these static IDMT relays was too high and this discouraged the use of this type of relay for medium voltage applications. The general developments in the field of electronics and the introduction of digital circuits, has overcome many of the above problems. Using modern microprocessor relays, almost any characteristic is possible and economical, even for the simplest applications such as, over current relays and motor protection relays.

What is a microprocessor relay?
A microprocessor relay is a digital electronic relay, which derives its characteristics by means of a pre-programmed series of instructions and calculations (algorithms), based on the selected settings and the measured current and/or voltage signals. For example the formula used to derive the inverse time characteristics in an overcurrent relay that comply with IEC 255 and BS 142 is mathematically defined as follows:

t = operating time in seconds
k = time multiplier
I = current value
I> = set current value.

The unit includes four BS 142 specified characteristics with different degrees of inverse. The degree of inverse is determined by the values of the constants α and β.

A description of a typical microprocessor (or numerical) relay follows–which includes:

  • Introduction
  • The simplified block diagram
  • Handling of the energizing signal
  • The microprocessor circuits
  • The output stages
  • The self-supervision

Introduction to the numerical relay
The measurement principle is based on sampling of the energized currents or voltages, analogue to digital conversion and numerical handling, where all settings are made in direct numerical form in a non-volatile memory. Setting can be performed either manually on the relay front or by serial communications using either a personal computer or a control/monitoring system. In addition, the operation of the self-supervision is described. (see figures 19.14 and 19.15)

Figure 9.14
A typical microprocessor relay
Figure 9.15
Rear view of a microprocessor relay

The operation of a protective relay can well be described by using a simplified block diagram as shown above. Here we can recognize the input signal path with the signal processing parts, the output circuits for trip and signal, and the self-supervision circuits.

Numerical relays are preferred by users due to the following reasons :

  1. Integration of many functions into one relay
  2. The design is compact and easier for implementation
  3. Ability to store data – measured values, statistics of circuit breaker operations etc. Also the memorisation of the variables existing on the network just before the fault.
  4. Because the processing is fully numerical, there is no aging of measuring characteristics
  5. The measuring accuracy is very high due to the digital filters and the measuring algorithms used
  6. Local operation keypad and display – either 4 line or fully graphical
  7. Enhanced communications capabilities – serial lines and ethernet connectivity for data transfer
  8. Support standard (IEC 61850) and popular (Modbus) communication protocols
  9. Capability to synchronize the clock for better sequence of events log
  10. Self monitoring

9.4.2 Handling of the energizing signal

The basic function of the relay is to measure the input and assess its condition. A digital relay comprises of sensitive devices and hence it is necessary that they do not fail because of the input changes. This is taken care by the isolating transformer and the limiter used in the relay. Figure 19.6 (a) shows a high level block diagram of a microprocessor relay. A detailed functional block diagram is shown in Figure 9.16(b).

Figure 9.16(a)
A high level block diagram of a microprocessor relay

The energizing currents or voltages are brought into the relay using the internal matching transformer (1). After the transformer there is, a voltage limiter (2), which cuts the voltages entering the relay at a safe level, should there be an extremely high current or voltage input. The reasons for this limiting are only to protect the internal circuits of the relay from being destroyed by too high an input voltage. Together with the limiting circuit, a filter can also often be implemented. In this case, the reason is that the harmonics contents of the energizing signal is not wanted and is filtered out. A typical filtering level here is that the third harmonics are attenuated by a factor of 10 and the fifth harmonics or higher are attenuated by factors of 100 and more.

Figure 9.16(b)
A typical simplified block diagram for a relay

The next stage is to measure the signals, which are to be monitored. In an AC circuit, the voltage, current and power undergo changes in relation to the supply frequency.

The multiplexer (3) selects the signals that are to be measured. A sample of each signal is measured once per ms. If the measuring module is of type C, with setting knobs, the setting values are also read through the multiplexer. Finally, the multiplexer also selects a reference channel once per second to have a condition check for the input circuits.

The analogue-to-digital-converter (A/D) (5) measures the level of the measured samples and transforms the analogue values into a numerical form. The resolution of the A/D converter is 8 bits, representing numerical values 0….255 (20 –1 to 28 – 1).

Because the dynamic range of the signal levels to be measured is quite high, the 8-bit conversion is as such not enough to give a good accuracy over the whole current or voltage span. Therefore, a programmable attentuator (4) is needed between the multiplexer and the A/D converter to enable an accurate handling for both low and high current or voltage levels.

For low signals, the amplification is 1, passing the signal directly to the converter. For phase current measurements, e.g. at a current level of 1.00 × In, the numerical value from the A/D is 100. When the signal is too high to be handled directly, i.e. for values above 200-255, an attenuation of × 5 is put on the signal. Furthermore, if the signal is still too high, the attenuation is switched up to × 25. This means that the overall range of measuring capability is 0…6375, corresponding to more than a 12 bit conversion. When the numerical value 100 represents a current of 1.00 × In, the highest measurable current is thus 63 × In.

The sampling rate is typically 1ms, which means that every half-period of the 50 Hz sine wave is measured by ten samples (see Figure 9.17). This gives a very accurate measure of the peak value during the half-period. For the worst case of the two top samples hitting evenly on both sides of the exact peak, a maximum error could theoretically be about–1%. As all signal handling is based on the mean value of two consecutive half-waves, and the sampling is non-synchronized, the probable theoretical fault is less than 0.5% and is partially compensated in the unit calibration.

Figure 9.17
Sampling of the sine-wave at 1ms intervals

As the measured current now is available in a numerical form, several things can be made. For example, the problem with handling of a signal with a DC-component is now very straightforward. When the mean-value of two consecutive half-waves is calculated, the DC-component is eliminated to almost 100% without any need for non-linear air gap transformers or similar components (see Figure 9.18).

Figure 9.18
Elimination of the DC-component by mean-value calculation of two consecutive half-waves

On the other hand, the calculation of the mean value consumes 10 ms, which is not wanted for very high short-circuit current levels where an instantaneous trip is called for. For this case another trip criteria is simply added. If the current in the first half-wave exceeds twice the setting, it is obvious that the mean value of the two half-waves will exceed the set level and therefore a trip can be carried out instantaneously without the need to wait for the next half-wave.

All measured numerical values can of course easily be transferred over the serial communication, be stored in memory banks etc for later retrieval e.g. when fault reasons are being investigated.

The sampling is also used in another good way, i.e. to minimize the transient overreach. When the operating time for a stage has elapsed and the trip order is to be carried out, the stage will wait for still one single sample exceeding the set level before the trip is linked to the output relay. In this triggered state, the relay will wait for a short time and if no further samples are detected, the relay will reset. This means that the retardation time or the transient overreach is very short, less than 30 ms.

The F650 Bay controller unit from GE-Multilin briefly describes its architecture as follows :

F650 units incorporate a series of interconnected modules to perform protection and control functions. Firstly, it includes a group of AC transformers for retrieving current and voltage. These magnitudes, once digitized, are sent to a digital signal processor (DSP), which performs metering functions and communicates with the main processor via a wide band bus. This architecture liberates the main processor from performing real time metering, allowing a high sampling rate, of up to 64 samples per cycle, without interfering with global performance.

Contact Inputs/Outputs are signals associated to physical input/output contacts in the relay

Analog Inputs are signals coming from the inputs of current and voltage transformers, used for monitoring the power system signals.

Remote CAN Bus Inputs/Outputs: are signals associated to physical input/output contacts from independent modules connected to the 650 unit via a fiber optic CAN Bus.

PLC: Programmable Logic Controller. Control module that enables the unit configuration (assignment of inputs/outputs) and the implementation of logic circuits.

Protection Elements: Relay protection elements, for example: Overcurrent, overvoltage, etc.

9.4.3 The microprocessor circuits

In the entire signal handling stages, the microprocessor or more accurately the microcontroller (6) of course takes part as every operation is controlled by this component. Furthermore, all protective decisions are made here, the operating time is counted for every stage and after that, the outputs are linked to the output relays.

The display used for the MMI is also served by the controller. The control functions and the measurement quantities are processed in the microcomputer system. They especially consist of:

  • Control of command outputs,
  • Decision for close commands,
  • Processing of indication inputs,
  • Storage of annunciations, fault data and fault values for fault analysis,
  • Control of signals for logical functions,
  • Filtering and conditioning of the measured signals,
  • Continuous monitoring of the measured quantities
  • Monitoring the communication with other devices,
  • Querying of limit values and time sequences,
  • Management of the operating system and the associated functions such as data recording, real-time clock, communication, interfaces, etc.

External components to the controller which are not shown in the figure are also the three different memory components that are used:

  • The random access memory (RAM), which is used as a scratchpad for measuring and calculating results, storing of memorized values etc.
  • The read-only memory (ROM), which contains the program firmware for the module
  • The electrically erasable programmable read-only memory (EEPROM), which is being used as parameter storage memory, e.g. for all the setting values.

The processing power of these units has been enormously increased by the introduction of the 32-bit technology. This permits, on the one hand, a more compact design and provides, on the other hand, sufficient processing reserve for the future introduction of additional functions.

A decisive step in the direction of user friendliness has been made with the implementation of large nonvolatile Flash EPROM memories. The system parameters can be loaded via a serial port at the front panel of the central unit. Bay level parameters are automatically downloaded.

9.4.4 The output stages

The outputs from the module is linked from the micro controller, via a power buffer amplifier (8) to the electromechanical output relays (9) on the output card.

To prevent a disturbance condition from causing a false output, a double signal arrangement is used. This means that an enable signal (ENA) must be sent together with the output command before any output relay can be activated. Furthermore, the outputs can also be inhibited by self-supervision. The mechanical operating times of the output relays, typically about 10...15 ms are subtracted from the operate times for the definite time protective stages. Thus, very accurate timings can be achieved for these operations. For IDMT-operations, this is however not possible as you cannot decide when you have reached the trip instant – 10 ms for all possible variations of current.

9.4.5 Self-supervision

In order to avoid false operations due to relay internal faults and to maximize the overall availability of the protection, a set of auto diagnostic circuit arrangements have been implemented in the relay modules. Generally, all tests are performed during a period of six minutes.

The different memory circuits, i.e. the RAM, the ROM and the EEPROM are all continuously tested by different methods at a speed of about one byte per 10 ms. Thus all memory is cyclically checked out.

The microprocessor and the program execution are supervised by a watchdog (12) once every 5 ms.

The multiplexer, the switchable attenuator and the A/D converter are tested by measuring of a very accurate reference voltage once a minute and always before tripping. This is to ensure that a measured signal is real, and not caused by a fault or disturbance in some input circuit, all to avoid false outputs.

The settings are tested once a minute by the use of a checksum arrangement. It is obvious that the settings must be ensured under all conditions of power breakdown etc. Any kind of battery backup must also be avoided as all batteries have too short a lifetime for this purpose. A relay is designed to have a lifetime of 20 years but the best life batteries cannot survive much more than about 5 years.

The solution is to have all settings stored in a non-volatile memory (EEPROM) and in two identical subsets (see Figure 9.19). For both the setting memory areas, the microcontroller automatically keeps track of the exclusive or checksum for the whole block. This checksum is stored in the last memory place of the block and is used as a reference of the correctness of the contents in the memory block. If a fault is detected in one block, the controller will directly check the other one and replace the contents of the faulty block with the contents of the correct one. This means that the settings are self-correcting, for e.g. ageing/refreshment faults due to the properties of the EEPROM. Normally a refresh cycle should be carried out every 10 years, in this way the relay module makes the refreshment when needed.

The internal supply voltages from the power supply module (11) are all tested once a minute by measurement of the different supply voltages, +8 V, ±12 V and +24 V. This test is performed by the voltage limit detector (13).

Figure 9.19
The two memory areas allocated for keeping the relay settings secured

The trip output path, the output amplifier and the output relay are checked once a minute by injecting a 40 ms voltage pulse into the circuit and checking (10) that a current flows through the trip circuit.

If the self-supervision detects a fault, the output buffer amplifier (8) is immediately blocked to ensure that no false signals are carried out due to the fault condition. After this, the watch-dog tries to get the microcontroller to work properly again, by resetting the process three times. If this attempt is not successful, a signal about the internal relay fault (IRF) is sent after a time delay (14) linked to the output relay (15). Furthermore information about the fault is sent as an event over the serial communication RxTx and a red LED on the front of the module is activated. If the module is still in an operative condition, also an indication about the character of the fault is shown as a code number in the front display.

Even a full breakdown of the relay, e.g. by loss of power supply will be detected as the IRF relay (15) operates in a fail-safe mode, causing a signal when the relay drops off. In addition, the serial communication will indicate loss of contact to the module and later on the module goes into a reset condition.

9.5 Universal microprocessor overcurrent relay

Electromechanical relays are designed specifically for particular protection applications and they usually have a limited setting range. For example, a different relay is necessary when a ‘very inverse’ characteristic is required or if a setting is required that is outside the range of the standard relay. This means that at the time when an electric power system is being designed and specified, considerable thought must be given to both the type of protection characteristic that will be required and the likely setting of the relay to ensure that the correct relay is specified.

The concept of many modern microprocessor relays is to provide a protection relay that covers all likely protection requirements in one relay.

This includes wide setting ranges and, in addition, several selectable characteristics and options to cover many protection applications. Microprocessor overcurrent relays are typically selectable for definite time, normal inverse, very inverse, extremely inverse, longtime inverse and sometimes a thermal characteristic as well to cover all likely application requirements. In addition, several output options are often provided to enable the user to select, for example, whether he requires an overcurrent ‘starting’ output contact or not. From a user’s point of view, this delay in decision characteristic and setting range is required to the time of commissioning.

The concept of a universal relay tends to improve the availability of protection relays from the manufacturers by making them ‘stock’ item. From a manufacturing point of view, this minimizes the number of relay types that have to be manufactured and held in stock and allows him to provide a faster and better service to the users of protection relays. This also tends to reduce the cost of protection relays by reducing the number of variations.

Table 9.2 summarizes the available characteristics and setting ranges of a modern microprocessor overcurrent relay in comparison to a typical induction disc IDMT overcurrent relay.

Table 9.2
Comparison of microprocessor versus electro-mechanical relays
    Static (Digital)   Electromechanical
Characteristics   Selectable   Separate relay
    Definite Time or Definite Time
  and Normal Inverse or Normal Inverse
  and Very Inverse or Very Inverse
  and Extr. Inverse or Extr. Inverse
  and Long Time Inverse or Long Time Inverse
Current Inputs   1 Amp and 5 amp   1 amp or 5 amp
Thermal Current Withstand        
Continuous : 3 amp/15 amp   2 × setting current
For 10 sec : 25 amp/100 amp   -
For 3 sec : -   20 amp/100 amp
For 1 sec : 100 amp/300 amp   -
Overcurrent Setting   Continuous   Plug Setting
    50% - 500%   50% - 200% in 7 steps
Ground Fault Setting   Continuous   Plug Setting
    10% - 80%   10% - 40% in 7 steps
      Or 20% - 80% in 7 steps
Time Multiplier   Continuous   Continuous
    0.05 – 1.0   0.1 – 1.0
High-set Overcurrent   Included   Extra Add-on
    0.5 – 40 times    
High-set Time Delay   Included   Extra Add-on
    0.05 – 300 sec    

Bay Controllers

Bay controllers provide high speed protection, control and monitoring for bay applications, including overcurrent protection, directional elements, voltage, frequency, breaker failure, autoreclosure, synchrocheck, and more.

Microprocessor based Bay controllers are capable of performing multiple functions of protection, control, monitoring and metering. Most bay controllers in the market support the following features:

  • Directional overcurrent protection for phases, neutral, ground and sensitive ground
  • Under and overvoltage protection
  • Under and overfrequency protection
  • Autorecloser
  • Synchronism
  • Metering
  • Oscillography registers, fault reports, data logger
  • Bay control (open/close commands, etc.)
  • Bay mimic
  • Communications (RS232/RS485/fibre optic/Ethernet)

A sample functional block diagram of a Bay controller is provided below with ANSI device numbers and functions.

Figure 9.20
Functional block diagram of a bay controller

Some of the functions of a microprocessor based relay are discussed here

High-speed busbar transfer
This function allows the fast synchronized transfer of motor busbars between the main and standby supply. Automatic transfer at phase coincidence of the voltages as well as slow transfer (low voltage, max. time) and manual transfer are included.

Thermal overload
The thermal overload function can be used for either cables or transformers. It is equipped with alarm and tripping stages and has a wide setting range for adjusting the time constant to match that of the protected unit.

Instantaneous overvoltage function(instantaneous tripping)
The frequency-dependent voltage function can be applied either as maximum or minimum function for instantaneous tripping or with settable delay. Single or three-phase measurement with maximum value detection for multi-phase functions. The voltage function is supplementary to the voltage indicator used for interlocking of the feeder earthing switch. Adjustable lower limiting frequency.

Definite time voltage function
The voltage function can be set to operate on overvoltage or undervoltage with a definite time delay. Either single or three-phase measurements can be performed.

Instantaneous overcurrent function(instantaneous tripping)
The frequency-dependent current function can be applied either as maximum or minimum function for instantaneous tripping or with settable delay. Single or three-phase measurement with maximum value detection for multi-phase functions. Adjustable lower limiting frequency. Definite time current function The current function can be set to operate on overcurrent or undercurrent with a definitetime delay. Either single or three-phase measurementscan be performed.

Inverse time-overcurrent function
The operating time of the inverse time-overcurrent function reduces as the fault current increases and it can therefore achieve shorter operating times for fault locations closer to the source. Four different characteristics according to British Standard 142 designated normal inverse, very inverse, extremely inverse and long time inverse with an extended setting range are provided. The function can be configured for single-phase measure mentor a combined three-phase measurement with detection of the highest phase current.

Inverse time ground fault overcurrent function
The inverse time ground fault overcurrent function monitors the neutral current of the system which is either measured via a neutral current input transformer or derived internally in the terminal from the three phase currents. Four different characteristics according to British Standard 142 designated normal inverse, very inverse, extremely inverse and long time inverse but with an extended setting range are provided.

Directional overcurrent protection
The directional overcurrent protection function is available either with inverse time or definite time overcurrent characteristic. This function comprises a voltage memory for faults close to the relay location. The function response after the memory time has elapsed can be selected (trip or block).

Frequency function
The frequency function is based on the measurement of one voltage. This function is able to be configured as maximum or minimum function and is applied as protection function and for load shedding. By multiple configuration of this function almost any number of stages can be realized.

Rate-of-change of frequency
This function offers alternatively an enabling by absolute frequency. It contains an undervoltage blocking facility. Repeated configuration of this function ensures a multi-step setup.

Both measuring functions measure the single or three-phase rms values of voltage, current, frequency, real power and apparent power for display on the local HMI or transfer to the station control system. A choice can be made between phase-to-neutral and phase-to-phase voltages.

Ancillary functions
Ancillary functions such as a logic and a delay/integrator enable the user to create logical combinations of signals and pick-up and reset delays. A run-time supervision feature enables checking the opening and closing of all kinds of breakers (circuit-breakers, isolators, ground switches...). Failure of a breaker to open or close within an adjustable time results in the creation of a corresponding signal for further processing.

Plausibility check
The current and voltage plausibility functions facilitate the detection of system asymmetries, e.g. in the secondary circuits of c.t’s and v.t’s. The internal sum of phasors can be compared with an external summation when quantities are applied to an input.

Sequence of events recorder
The event recorder function provides capacity for up to 256 binary signals including time marker with a resolution in the order of milliseconds. It is also possible to activate flutter recognition in order to avoid filling up the memory by continuously recurring signal response(flutter).

Disturbance recorder
The disturbance recorder monitors up to 9analogue inputs, 16 binary inputs and internal results of protection functions. The capacity for recording disturbances depends on the duration of a disturbance as determined by its pre-disturbance history and the duration of the disturbance itself. The total recording time is approximately 5 s.

The autoreclosure function included inREC316*4 permits up to four three-phase reclosure cycles to be carried out, each with an independently adjustable dead time for fast and slow autoreclosure. Where single-phase reclosure is being applied, the first reclosure is the single-phase one and the others are three-phase. The function may be actuated by internal protection functions or external protection relays via optocoupler inputs.

The synchrocheck function determines the difference between the amplitudes, phase angles and frequencies of two voltage vectors. Checks are also included to detect a deadline or busbar.

9.6 Technical features of a modern microprocessor relay

9.6.1 Fault Analysis

The evaluation of faults is simplified by numerical protection technology. In the event of a fault in the network, all events as well as the analog traces of the measured voltages and currents are recorded.

The fault data is stored in the memory of the relay for reading and analysis. The data may be grouped as mentioned below:

Operational event memory: Alarms that are not directly assigned to a fault in the network (e.g. monitoring alarms, alternation of a set value, blocking of the automatic reclose function).

Fault-event histories: Alarms that occurred during previous faults on the network (e.g. type of fault detection, trip commands, fault location, auto reclose commands) are stored in this section. The number of previous faults for which this data is available will vary from relay to relay. A reclose cycle with one or more reclosures is treated as one fault history. Each new fault in the network overrides the oldest fault history.

The fault recordings of voltage and current are stored in a separate section. The fault recording memory may be organized as a ring buffer, i.e. a new fault entry overrides the oldest fault record.

Earth-fault event memory: Event record of the sensitive earth fault detector (e.g. faulted phase, real component of residual current) are stored in this section.

The time tag attached to the fault-record events is a relative time from fault detection with a resolution of 1 ms. In the case of devices with integrated battery back-up clock, the operational events as well as the fault detection are assigned the internal clock time and date stamp. The memory for operational events and fault record events is protected against failure of auxiliary supply with battery back-up supply. An integrated operator interface or any suitable data acquisition program can fetch this data.

9.6.1 Current transformer burden

One of the disadvantages of the IDMT relays of the induction disk type is that they have relatively high CT burdens when compared to static IDMT relays. The ohmic value of these burdens varies with the setting as shown in Table 9.3. As the setting is reduced, the burden on the CT is increased. Induction disc relays have a burden typically specified as 3 VA. Modern static relays, on the other hand, have a very low burden of less than 0.02 ohm for 5 amp input and 0.10 ohm for 1 amp input, which is independent of the setting. The table below shows the calculated ohmic burden of a 1 amp induction relay at the various settings compared to a microprocessor overcurrent relay. (Also refer Table 9.1 in the beginning of this chapter)

Table 9.3
Comparison between the CT burdens in ohms of equivalent 1 amp relays of the induction disc and microprocessor types
Setting % Induction disc relay burden (Ohm) Microprocessor relay burden (Ohm)

The main consequence of the high burden is the poor performance of the CT/relay combination under high fault current conditions, particularly when low CT ratios are used. The high burdens can affect the actual primary setting achieved by the CT/relay combination. The example below shows that, with an electromechanical relay, the actual primary setting increases even though the plug setting is reduced on the relay.

With the static relay, almost any primary setting is possible. This means that on a distribution network using static relays, relay co-ordination is still possible at high fault levels even for a very low relay current setting and low CT ratios (see Figure 9.20 (a)).

Figure 9.20 (a)
Primary to relay tap setting

9.6.2 Accuracy of settings

The current and time-multiplier settings on a microprocessor relay are done with the aid of a digital display, which is part of the measuring unit. The accuracy and repeatability of the settings on this type of relay is far greater than that for electromechanical relays. Setting accuracy’s of ± 1% and operating accuracy’s of ± 3% of set value for the static relay compare very favorable with the ± 7.5% accuracy of the electromechanical device. The accuracy of the electromechanical relay is also dependent on the frequency and the presence of harmonics further affects accuracy.

This greater accuracy and repeatability of the static relay, generally independent of harmonics, combined with negligible ‘overshoot’ means that reduced grading intervals are now possible, especially when these relays are used in combination with the faster operating SF6 and vacuum switchgear. This is clear when one recalls that the grading times are dependent on the following:

  • Errors in CTs
  • Errors in the relay operating time
  • Relay ‘overshoot’ time
  • Circuit breaker operating time
  • Safety margin

It is practical to consider grading intervals of as low as 0.2 sec when using microprocessor relays in combination with SF6 or vacuum breakers as compared to 0.4 ˜ 0.5 seconds needed with electromechanical ones.

9.6.3 Reset times

Electromechanical IDMT relays have reset times of up to 10 secs at time multiplier settings = 1, which means that during auto re-close sequences an integration effect can take place and co-ordination can be lost. This situation can occur when the disc has turned some distance in response to a fault in the network cleared possibly by some other breaker with an auto re-close feature.

If the fault is still present when the breaker re-closes and if the disk has not fully returned to its reset position, the relay would take less time than calculated to trip. Uncoordinated tripping is then possible. The reset times of static relays are negligible.

9.6.4 Starting characteristics

An IDMT relay of the induction disc type is an electromechanical device, which includes mechanical parts such as a disc, bearings, springs, contacts, etc., which are subject to some mechanical inertia. When the current exceeds the setting, the disc only starts to move somewhere between 103% and 110% of the setting and closes for currents between 115% and 120% of the setting.

Static relays have a definite pickup point within 5% of the current setting and this initiates the timing characteristics. The pickup usually accompanied by an LED indication, makes it easy to check the accuracy of the current setting during testing of the relay.

On some static relays, this ‘start’ signal is available on a separate pair of output contacts, which can be used for indication or to initiate a simple busbar protection scheme.

This type of busbar protection when used on metal clad MC switchgear is superior to frame leakage protection because it covers both phase-faults in the switchgear and avoids the necessity of insulating the switchgear and cable glands from ground. The principle of this type of protection is illustrated in Figures 9.20 (b) and 9.20 (c).

Figure 9.20 (b)
Busbar protection scheme using starting contact of the static overcurrent relays
Figure 9.20 (c)
Busbar protection scheme using starting contact of the static overcurrent relays

9.6.5 Dual setting banks

Some digital relays are now designed to provide a dual settings bank, which provides a complete duplication of all the settings and operating switch positions. Setting 1 or setting 2 can be selected at the relay, via the serial communications system or a remote switch, which can be an output contact of another relay or a circuit breaker auxiliary switch.

In many instances, when setting relays, such as the example shown in Figure 9.21 (a) and (b), we are faced with having to set a relay for the lowest or an average value of two possible settings. Now we can have both settings, calculated exactly, and switch from setting 1 to setting 2 at will.

This dual setting bank can also be useful in a ring main circuit, which can be opened at different places, necessitating differing settings when a relay can be in two different places in two radial feeders.

Figure 9.21 (a)
Open ring protection
Figure 9.21 (b)
Parallel feeder protection

9.6.6 High-set instantaneous overcurrent element

In microprocessor overcurrent and ground fault relays, a high-set overcurrent element is provided as a standard feature and often has a timer associated with it to provide a time delay. If not required, it can be set to be ‘out-of-service’. Because of the measurement method, the transient overreach is very low and the instantaneous overcurrent setting can be set much closer to the maximum fault current for a fault at the remote end of the feeder. The transient overreach is the tendency of the relay to respond to the DC-offset, which is commonly present in most fault current waveforms. To avoid this problem on electromechanical relays, the setting of the high-set element has to be at least twice the calculated maximum fault current, making the protection less effective.

High-set overcurrent protection is particularly useful on the higher voltage side of a transformer, where it provides fast protection for most faults on the HV side while the time-delayed overcurrent relay provides protection for the faults on the lower voltage side of the transformer.

9.6.7 Breaker fail protection

Modern microprocessor relays are now provided with breaker fail protection. When the main trip contact of the relay signals a trip to the circuit breaker and if after a pre-set delay (say 150 m secs), current is still flowing through the relay this indicates that the circuit breaker has not opened. The relay with a second trip contact sends another signal to a second trip coil in the same breaker or a second breaker.

9.6.8 Digital display

Light emitting diodes (LEDs) and a display screen (LCD) on the front panel provide information such as messages related to events and functional status of the relay. Some of the new generation relays also have a graphic display to depict line diagrams. The LCD is the primary source for obtaining information from the relay or when locally setting the relay. Information such as targets, metering values, demand values, communication parameters, the active logic scheme name and diagnostic information is provided by the LCD. Information and settings are displayed in a menu with six branches. The Menu Tree sub-section provides more information about the menu branches.

Integrated control and numeric keys in conjunction with the LCD facilitate local interaction with the device. The display is used for the following:

  • Accurate relay settings–The settings are adjusted by means of potentiometers or the software, but the actual value of the setting is accurately displayed on the display window.
  • Measured values–Information such as the measured values of the various parameters can be displayed in a cyclic order by selecting the sequence of display or by default.
  • Memorized fault information–When the replay operates for a fault, the values of the measured parameters and times are stored in memory. This information can later be recalled to assist in the analysis of the cause of the fault.
  • Indications and status information–Other functions and information such as the number of starts, blocking information etc. can be displayed for motor control applications.
Figure 9.21 (c)
Two different displays of GE-Multilin and SIEMENS SIPROTEC relays

9.6.9 Memorized fault information

Microprocessor relays, which provide memorized fault information, have been available for some years but this information had been initially limited to the maximum value of the measured current or the most recent fault. The advancement in digital technology nowadays enable much more comprehensive fault analysis with up to quite a number of memorized values of the three-phase currents, zero sequence current, maximum demand current (15 mins) duration of the start of the low-set and high-set overcurrent. There are possibilities to have these data stored in hard disks connected on a continuous manner for later retrieval (see Figure 9.22).

Figure 9.22
Example of memorized fault information

9.6.10 Auxiliary power requirements

Electromechanical IDMT overcurrent relays do not require an external source of auxiliary power to operate the relay. They take their power requirements from the CT and this is the main reason for their high burden mentioned earlier. However, this ‘zero battery drain’ during quiescent conditions has allowed municipal engineers to fit tripping batteries and chargers of limited capacity at small stations for tripping purposes only. With the introduction of static relays, which require an auxiliary power supply to drive the electronic circuits and the output relays, users were reluctant to change these small battery and charger arrangements to accommodate additional power requirements. This is not normally a problem in larger stations because the station battery usually has sufficient capacity for the relay auxiliary supply, typically at voltages of 30V DC, 110V DC or 220V DC. Some manufacturers overcame this problem by building a CT power supply card as an extra option. However, this tends to defeat one of the main advantages of static relays, which is their low CT burden.

Consequently, in microprocessor relays a lot of effort has been made to reduce the auxiliary supply requirements as much as possible by using circuit techniques, such as CMOS, which requires very little power. Auxiliary power requirements of 3 watts and lower can be achieved depending on the type of relay.

To simplify matters further, universal power supplies for relays have been developed to operate over a wide voltage range and cover several ‘standard’ voltages. For example an 80V–265V universal power supply is suitable for 110V DC or 220V DC station batteries and will operate right down to 80 volts. This type of power supply is independent of polarity and can be supplied from AC or DC. It uses a Pulse width modulation (PWM) technique, which is self-regulating, short circuit and overload protected. It is also protected against ripple and transients in the auxiliary supply voltage. In practice, battery voltages in a substation can vary over a wide range. During the ‘boost’ charging cycle the voltage can be up to 30% higher than normal and has often been the cause of power supply overheating in early day static relays. Conversely, during low charge situations the voltage can fall as low as 80% of nominal. The universal power supply can easily accommodate these wide fluctuations without any additional heating or loss of performance. A block diagram is shown in Figure 9.23.

Some of the benefits of PWM self-regulated universal power supply units are as follows:

  • The same relay can be used in several applications for a wide range of battery voltages resulting in one power supply for all standard battery voltages from 30 v–220 v.
  • Battery fluctuations due to the charger do not affect the replay performance.
  • Low battery voltage, within reasonable limits, does not affect the relay performance.

In small stations where no station battery is available or economic, auxiliary supply can be arranged from a capacitor storage unit fed from both the CT and the PT’s. This unit will provide auxiliary power to the relay even when no current is flowing in the primary circuit.

Figure 9.23
Block diagram of pulse width modulated (PWM) self-regulating power supply

Because of the relays, universal power supply, fluctuations of voltage due to the variations in the supply do not affect relay performance. A typical connection of a capacitor storage unit supplying a relay using a PWM self-regulating power supply is shown in Figure 9.24. The capacitor storage unit also provides the energy to trip the circuit breaker where there is no tripping battery.

Figure 9.24
Capacitor storage unit is supplied from both the CTs and a CT to provide auxiliary power for the relay and for tripping the circuit breaker

9.6.12 Flexible selection of output relay configuration

With the help of six output relays (two heavy duty and three medium duty) and a completely flexible software-switching programme, we can choose to have any function to operate any combination of output relays–including the various ‘start’ operations, see Figure 9.25.

Figure 9.25
Flexible selection of output relay configurations

9.7 Type testing

9.7.1 Type tests

To ensure that static protection relays of all types comply with reasonable requirements and are suitable for applications to power system networks, many national standard organizations such as BEAMA, ANSI, SEN, etc introduced stringent testing requirements for static relays. These requirements are now included in the international recommendations by IEC. The following electrical type tests are normally applied by manufacturers to ensure that relays comply with the requirements of IEC 255:

  • Insulation test voltage : 2 kV, 50 Hz, 1 min
    IEC 255-5
  • Impulse test voltage : 5 kV, 1.2/50 micro sec, 0.5 Joule
    IEC 255-5
  • High frequency interface test : 2.5 kV, 1 MHz
  • Spark interference test : 4 to 8 kV
    SS 436 15 03

9.7.2 Self supervision

Numerical relays monitor their own hardware and software. Exhaustive self-monitoring and failure diagnostic routines are not restricted to the protective relay itself, but are methodically carried through from current transformer circuits to tripping relay coils. Equipment failures and faults in the c.t. circuits are immediately reported and the protective relay blocked. Thus, the service personnel are now able to correct the failure upon occurrence, resulting in a significantly upgraded availability of the protection system.

Perhaps the most important feature introduced by microprocessor relays is that of continuous self-supervision. One of the classical problems of the older protection relays lies in the absence of any ready means to identify a fault in the relay. As protective relays are, for most of their lives, in a quiescent state, regular secondary injection tests are necessary to prove that the relays are operational.

The microprocessor relays, on the other hand, utilize their capacity during quiescent periods to continuously monitor their circuits and will provide an alarm if a failure occurs. The digital readout can be used to diagnose the problem. This enhances protection system reliability on a continuous basis and intervals between manual inspections can be prolonged.

Digital devices tend to work either 100% or not at all. Consequently, it is very easy to check a microprocessor relay on a regular basis and achieve a very high certainty that the relay is operational. By pressing the button requesting the display of the phase current, a reading that matches the ammeter on the panel confirms the following:

  • The CTs are healthy
  • The wiring from the CT to the relay is okay
  • The relay is working

If necessary, a trip-test can be done from the relay to ensure that the relay output trip contacts are working and that the breaker trip coil and mechanism are okay.

9.8 Summary of advantages of Microprocessor-based relays

9.8.1 Reduction in outage time

Usage of microprocessor-based protective relays with fault locating and automated/remote control capabilities assist crews in finding trouble areas much more quickly than by random line patrol - an extremely valuable asset. In addition, programmable automatic reclosing (fuse-saving or trip-saving methods) provides the ability to restore the line automatically. In addition, the remote capability allows SCADA or other master device commands to restore the line.

9.8.2 Maximize flexibility

Microprocessor-based relays are feature-rich, programmable devices with configurable I/O that provides for flexible designs. Relay settings can be downloaded locally by means of a laptop computer, or remotely through a modem connected to one of the relay serial ports. Multiple settings groups give the user the flexibility to select the appropriate settings for system conditions via a selector switch, serial port command, or from the relay Human Machine Interface (HMI).

9.8.3 System Analysis Tools

Microprocessor-based relays can be used to provide system analysis by means of full-length event reports and programmable Sequence of Events Recorder (SER) reports.

Microprocessor relays can also provide some power system measurements for both power providers and users. Breaker wear and DC battery monitoring are other features that allow analysis of the integrity of the breaker or battery bank in question

9.8.4 System Reliability

High quality components and a proven, robust relay design lead to a highly reliable product which in turn leads to increased system reliability. The combination of a high mean time between failure (MTBF), relay self test diagnostics, and alarm capability helps to ensure that the relay will provide proper, reliable protection.

Also, since microprocessor-based relays are less expensive than the many devices they replace, it is more economically feasible to provide redundant backup protection and further improve system reliability.

9.8.5 Higher System protection availability

Protection availability is improved through high product reliability, reduced maintenance intervals, self test diagnostics and relay trouble alarming that microprocessor relays offer. Should the relay become disabled, it is easily identified and can be quickly repaired or replaced. This provides minimal downtime and maximum system protection availability that is unmatched by electromechanical or solid state devices.

Self-tests offer a major advantage over electromechanical relays, which are equipped with no self-checking facility, and are only tested at scheduled maintenance intervals.

9.8.6 Reduction in Commissioning time

Commissioning is the process of verifying the entire scheme before it is put into operation. With microprocessor based relays, this time is significantly reduced.

9.8.7 Reduction in Space & wiring Requirements

Save panel space by using feature-rich microprocessor-based relays where one device may replace multiple relays, meters, control switches, indicators, and quite often, communications gear and RTUs. Create more room in the control house by replacing complete panels of equipment with just a few microprocessor-based devices.

Complicated dual panel layouts per terminal for protection and control are easily reduced to a clean, single panel or rack that includes all of the protection, monitoring, and control - with space to spare.

In addition to requiring less panel space, the use of multifunction microprocessor-based relays reduces the amount of panel wiring required in a design. Control wiring is minimized, and specific functions such as reclosing, torque control, and trip coil monitoring are performed by the single relay unit instead of several devices.

9.8.8 Self-Diagnostics

Save money by changing maintenance procedures to take advantage of microprocessor relay capabilities. Microprocessor-based relays do not require the same periodic maintenance associated with electromechanical devices and are equipped with self-test diagnostics that continuously monitor the health of the device.

A relay that is malfunctioning or has failed closes a dedicated "alarm" output contact to signal that assistance is required. This signal can also be used to activate special back up protection, or modify protection schemes when the primary protective relay has detected a problem and taken itself out of service. The periodic tests required to detect failures that the self-tests do not detect are reduced to a minimum.

In addition, users can analyze data from relay event reports to detect unusual conditions earlier than the next periodic test.

9.8.9 Design Simplicity

Replacing multiple relays, meters, switches, indicators, and communications gear with a single microprocessor-based protective relay leads to simplified designs. Substation/system schematics and wiring diagrams are much easier to generate and reproduce due to the reduced number of devices and related wiring.

9.8 The future of protection for distribution systems

With the second generation of microprocessor relays now available, the emphasis is on the broader use of the protection relays as data acquisition units and for the remote control of the primary switchgear. Protection relays continuously monitor the primary system parameters such as current, voltage, frequency, etc. as part of the protection function of detecting faults. Since faults seldom occur, protection relays are expected to fulfill the protection requirements for a very small portion of their lifetime.

By utilizing the protection relays for other duties during the periods when the power system is normal, it permits integration of the various systems such as Protection, supervisory control and data acquisition and results in savings on other interface components such as measuring transducers for current and voltage, meters, circuit breaker control interface etc.

Improvements in digital communications by means of optical fibers allow the information available at the relay to be transferred without interference to the substation control level for information or event recording.

The following information is typically available from the relay:

  • Measurement data of current and voltage
  • Information stored by the relay after a fault situation
  • Relay setting values
  • Status information on the circuit breakers and isolators
  • Event information

The communication link to the relay can also be used for control purposes:

  • Circuit breaker open/close commands
  • Remote reset of the relay or auto re-close module
  • Changes to the protective relay settings.

Figure 9.26 shows the components of an integrated protection and control system that could be implemented in distribution substations.

Figure 9.26
Components of an integrated protection and control system

9.9 The era of the IED

As already discussed earlier, protection relays became more advanced, versatile and flexible with the introduction of microprocessor based relays. The initial communication capabilities of relays were intended mainly to facilitate commissioning. Protection engineers realized the advantages of remotely programming relays, the need developed for data retrieval, and so the communication aspects of relays became steadily more advanced.

PLC functionality became incorporated into relays, and with the development of small RTUs, it was soon realized that relays could be much more than only protection devices. Why shouldn’t equip protection relays with advanced control functions? Why shouldn’t protection functions be added to a bay controller? Both of these approaches have been followed, with different manufacturers (and sometimes different divisions within the same manufacturing group) adopting different approaches to the question of protection, control and communications. This resulted in an extensive range of devices on the market, some stronger on protection, some stronger on control, and the term protection relay became too restrictive to describe these devices. This resulted in the term ‘Intelligent electronic device’ (IED).

9.9.1 Definition

The term ‘Intelligent electronic device’ (IED) is not a clear-cut definition, as for example the term ‘Protection relay’ is. Broadly speaking, any electronic device that possesses some kind of local intelligence can be called an IED. However, concerning specifically the protection and electrical industry, the term really came into existence to describe a device that has versatile electrical protection functions, advanced local control intelligence, monitoring abilities and the capability of extensive communications directly to a SCADA system.

9.9.2 Functions of an IED

The functions of a typical IED can be classified into five main areas, namely protection, control, monitoring, metering and communications. Some IEDs may be more advanced than the others, and some may emphasize certain functional aspects over others, but these main functionalities should be incorporated to a greater or lesser degree.

9.9.3 Protection

The protection functions of the IED evolved from the basic overcurrent and ground fault protection functions of the feeder protection relay (hence certain manufacturers named their IEDs ‘feeder terminals’). This is because a feeder protection relay is used on almost all cubicles of a typical distribution switchboard, and that more demanding protection functions are not required to enable the relay’s microprocessor to be used for control functions. The IED is also meant to be as versatile as possible, and is not intended to be a specialized protection relay, for example generator protection. This also makes the IED affordable.

The following is a guideline of protection related functions that may be expected from the most advanced IEDs (the list is not all-inclusive, and some IEDs may not have all the functions). The protection functions are typically provided in discrete function blocks, which are activated and programmed independently.

  • Non-directional three-phase overcurrent [low set, high set and instantaneous function blocks, with low set selectable as long time-, normal-, very-, or extremely inverse, or definite time]
  • Non-directional ground fault protection [low set, high set and instantaneous function blocks]
  • Directional three-phase overcurrent [low set, high set and instantaneous function blocks, with low set selectable as long time-, normal-, very-, or extremely inverse, or definite time]
  • Directional ground fault protection [low set, high set and instantaneous function blocks]
  • Phase discontinuity protection
  • Three-phase overvoltage protection
  • Residual overvoltage protection
  • Three-phase undervoltage protection
  • Three-phase transformer inrush / motor start-up current detector
  • Auto-re-closure function
  • Under frequency protection
  • Over frequency protection
  • Synchro-check function
  • Three-phase thermal overload protection

9.9.4 Control

Control function includes local and remote control, and are fully programmable.

  • Local and remote control of up to twelve switching objects (open/close commands for circuit-breakers, isolators, etc.)
  • Control sequencing
  • Bay level interlocking of the controlled devices
    • - Status information
    • - Information of alarm channels
  • HMI panel on device

9.9.5 Monitoring

Monitoring includes the following functions:

  • Circuit-breaker condition monitoring, including operation time counter, electric wear, breaker travel time, scheduled maintenance
  • Trip circuit supervision
  • Internal self-supervision
  • Gas density monitoring (for SF6 switchgear)
  • Event recording
  • Other monitoring functions, like auxiliary power, relay temperature, etc.

9.9.6 Metering

Metering functions include:

  • Three-phase currents
  • Neutral current
  • Three-phase voltages
  • Residual voltage
  • Frequency
  • Active power
  • Reactive power
  • Power factor
  • Energy
  • Harmonics
  • Transient disturbance recorder (up to 16 analogue channels)
  • Up to twelve analogue channels

9.9.7 Communications

Communication capability of an IED is one of the most important aspects of modern electrical and protection systems, and is the one aspect that clearly separates the different manufacturers’ devices from one another regarding their level of functionality (see Figure 9.27).

Figure 9.27
Typical IED internal configuration (source: GE universal relay)

9.10 Substation automation

Substation automation is not easy to achieve in existing substations. Automation in a substation is considered the provision of new generation intelligent electronic devices (IEDs), programmable logic controllers (PLCs) and computers to monitor and communicate. It is always simple to incorporate these components in new substations at the design stage itself. But in an existing substation, which is already using older types of relays, automation is a question of what can be done to reduce the operating expenses and improve customer service, from a practical and economical viewpoint. One way to improve customer service is giving the control over the feeder breakers to the operator of distribution substations. This effectively reduces the number of trips that have to be made to substations and allows service to be restored more rapidly after an outage.

9.10.1 Existing substations

A typical scheme is shown in Figure 9.28, for providing just those functions needed to reduce the expense and improve customer service. It helps planners to reduce capital expenditures and helps operators to minimize trips to substations and reduce outage time. Existing relays are retained and feeder automation units are added on each feeder panel as shown in the diagram below. This is referred to as a distributed architecture whereby the feeder automation units are installed close to the input/output wiring sources.

Figure 9.28
Typical incorporation of feeder automation units in a substation

The feeder automation units are available as add-on units to the existing feeders. Feeder current and bus voltage are given as inputs for each feeder automation unit. In addition, the status inputs such as re-close status, breaker status, and the outputs from the trip current relays. Some outputs are needed from the automation unit for trip, close, and enable/disable re-close. The feeder automation units generate relay target information from the trip current relay inputs. Trip current relays are available that can be mounted directly on the studs of relay cases. This allows them to be installed without changing the trip circuit wiring.

The provision of simple feeder automation units provides the following capabilities in automation of existing substations.

Control functions

  • Trip/close for each feeder breaker
  • Disable/enable re-closing relay on each feeder

Status information

  • Breaker position for each feeder (open/closed)
  • Re-close status of re-closing relay on each feeder (enabled/disabled)

Target data

  • Sequential listing of all time-overcurrent trips on each feeder
  • Sequential listing of all instantaneous-overcurrent trips on each feeder

Revenue accuracy real-time metering

  • Bus voltage (average three-phase measurement)
  • Current on each feeder
  • Kilowatts and kilovars on each feeder

Planning data on 30 day log at 15/30 minute intervals

  • Bus voltage (average three-phase measurement)
  • Current on each feeder
  • Kilowatts and kilovars on each feeder
  • Accumulated kWh and kVar on each feeder

Power quality data once a minute

  • Bus voltage harmonics to the 31st order on each phase
  • Total harmonic distortion in percent

Adding new multifunction feeder relays
New feeder relays can be added along with the feeder automation units described above to get more detailed fault data and to implement improvements in feeder protection. Outputs from the overcurrent relay are for breaker trip, breaker close, and breaker fail. The relay requires an input for breaker status. The additional capabilities provided over and above the previous scheme are as follows:

Fault data

  • Fault summary reports
  • Oscillographic records of fault clearings
  • Sequence of events data

Additional protective functions

  • Negative sequence overcurrent for more sensitive phase to phase protection
  • Four relay setting groups for adapting protection to system conditions
  • Coordination with bus relay to achieve feeder relay backup
  • Automatic re-closing
  • Breaker failure detection

Maintenance data

  • Breaker contact wear data
  • Breaker operations counter
  • Breaker trip speed monitoring

Operating information

  • Yesterday’s peak demand current
  • Today’s peak demand current
  • Peak demand current since last reset

Use of computer in the substation
Ultimately a computer is the most useful addition to record all the information about the various systems and feeders. A substation computer is a key system element in that it allows intelligence to be moved downward to the substation. That intelligence reduces the amount of data that must be communicated between substations and the master station. For example, information can be retrieved as and when needed from databases maintained at the substation. It also provides a way to overcome the need for a standard protocol.

If the optional monitor is employed along with a keyboard, the computer can also serve as the human-machine interface for information and control in the substation.

The additional capabilities added by including a computer in the substation are as follows:

Maintains databases at substation

  • One or more years of demand data
  • One or more years of chart data

Mathematical operations on the data

  • Watts and VArs can be derived from the three-phase current and voltage data


  • Easy to add new functions and for expansions

Human-machine interface in the substation

  • Elimination of manual control switches
  • Displays reports
  • Alarm panel
  • Event log
  • Load control schedules
  • Daily summary
  • Volts & amps
  • Monthly peaks report

General system requirements

There are some basic requirements that should be considered when selecting an automation system for a substation. These are:

  • An open system
  • Distributed architecture to minimize wiring
  • Flexible and easily setup by the user
  • Inclusion of a computer to store data and pre-process information
  • Setting up the computer software without requiring a programmer
  • Ability to communicate with the existing SCADA master
  • Ability to handle various communications protocols simultaneously

9.11 Communication capability

IEDs are able to communicate directly to a SCADA system. Figure 9.29 shows the modern concept of a SCADA system using IED’s connected through LAN and other network configurations.

Figure 9.29
Typical structure of IED Communication


Protection Co-ordination

10.1 Introduction

The goal of a protective device coordination study is to assure the system is capable of clearing a fault in the minimum amount of time possible, while minimizing the impact to the power system.

To put it simply, coordination means that downstream devices (breakers/fuses) should activate before upstream devices. This minimizes the portion of the system effected by a fault or other disturbance. At the substation level, feeder breakers should trip before the main. Likewise, downstream panel breakers should trip before the substation feeder supplying the panel.

A protection system consists of many components to accommodate the fault in a system (i.e., distance relay, overcurrent relay and directional overcurrent relay). The coordination of these protective relays is set up during the process of system design based on the fault current calculation. To clear faults properly with in a specific time, each protective relay has to coordinate with the other protective relays which are located at all adjacent buses.

The Protection / Coordination Study:

  • Helps reduce unnecessary downtime!
  • Provides recommended settings for adjustable trip circuit breakers and relays.
  • Helps increase coordination (selectivity) between devices.
  • Identifies deficiencies in system protection.
  • Provides recommended solutions to help correct problem areas.
  • Reviews and discusses the use of system devices with respect to National Electric Code requirements, and appropriate ANSI/IEEE standards.

10.2 What is Coordination?

Where there are two or more series protective devices between the fault point and the power supply, these devices must be coordinated to insure that the device nearest the fault point will operate first. The other upstream devices must be designed to operate in sequence to provide back-up protection, if any device fails to respond. This is called selective coordination. To meet this requirement, protective devices must be rated or set to operate on minimum overcurrent, in minimum time, and still be selective with other devices on the system. When the above objectives are fulfilled, maximum protection to equipment, production, and personnel will be accomplished. As will be seen later in this chapter, protection and coordination are often in direct opposition with each other. Protection may have to be sacrificed for coordination, and vice versa. It is the responsibility of the electrical engineer to design for optimum coordination and protection. This is sometimes more art than science.

Figure 10.1
Protection co-ordination

Figure 10.1 helps us quickly understand the primary function of protection co-ordination. When the protection co-ordination is perfect, for fault 1, breaker F only will operate. Similarly, for fault 2, breaker E alone shall operate. In case of improper co-ordination, for fault 1, breakers D or A might operate. Similarly, for fault 2, breakers B or A might operate.

The present analysis discusses the coordination between the different devices dedicated to the protection of zones and specific components with a view to:

  • guaranteeing safety for people and installation at all times;
  • identifying and rapidly excluding only the zone affected by a problem, instead of taking indiscriminate actions and thus reducing the energy available to the rest of the network;
  • containing the effects of a malfunction on other intact parts of the network (voltage dips, loss of stability in the rotating machines);
  • reducing the stress on components and damage in the affected zone;
  • ensuring the continuity of the service with a good quality feeding voltage;
  • guaranteeing an adequate back-up in the event of any malfunction of the protective device responsible for opening the circuit;
  • providing staff and management systems with the information they need to restore the service as rapidly as possible and with a minimal disturbance to the rest of the network;
  • achieving a valid compromise between reliability, simplicity and cost effectiveness.

A valid protection system must draw a balance between
a) understanding what happened and where it happened
b) take rapid action to limit damage and safeguard the continuity of the power supply

10.3 Over-current coordination

The strategy adopted to coordinate the protective devices depends mainly on the rated current (In) and short-circuit current (Ik) values in the considered point of network.

Coordination can be classified into the following

  • current discrimination
  • zone discrimination
  • time discrimination
  • energy discrimination

IEC 60947 defines over-current discrimination as “coordination of the operating characteristics of two or more over-current protective devices such that, on the incidence of over-currents within stated limits, the device intended to operate within these limits does so, while the others do not operate

Total discrimination means “over-current discrimination such that, in the case of two over-current protective devices in series, the protective device on the load side provides protection without tripping the other protective device

Partial discrimination means “over-current discrimination such that, in the case of two over-current protective devices in series, the protective device on the load side provides protection up to a given over-current limit without tripping the other

10.3.1 Current discrimination

This type of discrimination is based on the observation that the closer the fault comes to the network’s feeder, the greater the short-circuit current will be. We can therefore pinpoint the zone where the fault has occurred simply by calibrating the instantaneous protection of the device upstream to a limit value higher than the fault current which causes the tripping of the device downstream. We can normally achieve total discrimination only in specific cases where the fault current is not very high (and comparable with the device’s rated current) or where a component with high impedance is between the two protective devices (e.g. a transformer, a very long or small cable...) giving rise to a large difference between the short-circuit current values.

The devices’ time-current tripping curves are generally used for the study.

This solution is:

  • rapid;
  • easy to implement;
  • and inexpensive.

10.3.2 Time discrimination

This type of discrimination is an evolution from the previous one. The setting strategy is therefore based on progressively increasing the current thresholds and the time delays for tripping the protective devices as we come closer to the power supply source. As in the case of current discrimination, the study is based on a comparison of the time-current tripping curves of the protective devices.

This type of coordination:

  • is easy to study and implement;
  • is relatively inexpensive;
  • enables to achieve even high discrimination levels, depending on the Icw ofthe upstream device;
  • allows a redundancy of the protective functions and can send valid information
  • to the control system,

However, the tripping times and the energy levels that the protective devices (especially those closer to the sources) let through are high, with obvious problems concerning safety and damage to the components even in zones unaffected by the fault;

10.3.3 Zone discrimination

This type of coordination is implemented by means of a dialogue between current measuring devices that, when they ascertain that a setting threshold has been exceeded, give the correct identification and disconnection only of the zone affected by the fault.

It is available with the circuit-breakers of Emax series only. In practice, it can be implemented in two ways:

  • the releases send information on the preset current threshold that has been exceeded to the supervisor system and the latter decides which protective device has to trip;
  • in the event of current values exceeding its setting threshold, each protective device sends a blocking signal via a direct connection or bus to the protective device higher in the hierarchy (i.e. upstream with respect to the direction of the power flow) and, before it trips, it makes sure that a similar blocking signal has not arrived from the protective device downstream; in this way, only the protective device immediately upstream of the fault trips.

The first mode foresees tripping times of about one second and is used mainly in the case of not particularly high short-circuit currents where a power flow is not uniquely defined.

The second mode enables distinctly shorter tripping times: with respect to a time discrimination coordination, there is no longer any need to increase the intentional time delay progressively as we move closer to the source of the power supply. The maximum delay is in relation to the time necessary to detect any presence of a blocking signal sent from the protective device downstream.


  • reduction of the tripping times and increase of the safety level; the tripping times will be around 100 milliseconds;
  • reduction of both the damages caused by the fault as well of the disturbances in the power supply network;
  • reduction of the thermal and dynamic stresses on the circuit-breakers and on the components of the system;
  • large number of discrimination levels;
  • redundancy of protections: in case of malfunction of zone discrimination, the tripping is ensured by the settings of the other protection functions of the circuit-breakers. In particular, it is possible to adjust the time-delay protection functions against short-circuit at increasing time values, the closer they are to the network’s feeder.


  • higher costs;
  • greater complexity of the system (special components, additional wiring, auxiliary power sources, ...).

This solution is therefore used mainly in systems with high rated current and high short-circuit current values, with precise needs in terms of both safety and continuity of service: in particular, examples of logical discrimination can be often found in primary distribution switchboards, immediately downstream of transformers and generators and in meshed networks.

10.3.4 Energy discrimination

Energy coordination is a particular type of discrimination that exploits the current limiting characteristics of moulded-case circuit-breakers. It is important to remember that a current-limiting circuit-breaker is “a circuit-breaker with a break time short enough to prevent the short-circuit current reaching its otherwise attainable peak value” (IEC 60947-2, def. 2.3).

In general, it is necessary to verify that the let-through energy of the circuit breaker downstream is lower than the energy value needed to complete the opening of the circuit-breaker upstream. This type of discrimination is certainly more difficult to consider than the previous ones because it depends largely on the interaction between the two devices placed in series and demands access to data often unavailable to the end user. Manufacturers provide tables, rules and calculation programs in which the minimum discrimination limits are given between different combinations of circuit breakers.


  • fast breaking, with tripping times which reduce as the short-circuit current increases;
  • reduction of the damages caused by the fault (thermal and dynamic stresses), of the disturbances to the power supply system, of the costs...;
  • the discrimination level is no longer limited by the value of the short-time withstand current Icw which the devices can withstand;
  • large number of discrimination levels;
  • possibility of coordination of different current-limiting devices (fuses, circuitbreakers,..) even if they are positioned in intermediate positions along the chain.


  • difficulty of coordination between circuit-breakers of similar sizes.

10.3.5 Protection co-ordination example

A sample feeder configuration is given in Figure 10.2 and its assigned load and short-circuit currents are given in Table 10.1

Figure 10.2
Sample feeder configuration

For this example, SIEMENS O/C relays 7SJ60 with normal inverse-time characteristic are applied. The relay operating times can be taken from the equation given below:

The IP /IN settings shown in Fig. 10.2 have been chosen to get pickup values safely above maximum load current. This current setting shall be lowest for the relay farthest downstream. The relays further upstream shall each have equal or higher current setting. The time multiplier settings can now be calculated as follows:

Station C:

  • For coordination with the fuses, we consider the fault in location F1. The short-circuit current related to 13.8 kV is 523 A. This results in 7.47 for I/IP at the o/c relay in location C.
  • With this value and TP = 0.05 we derive from the above given equation, an operating time of tA = 0.17 s

This setting was selected for the o/c relay to get a safe grading time over the fuse on the transformer low-voltage side.

The setting values for the relay at station C are therefore:

  • Current tap: IP /IN = 0.7
  • Time multipler: TP = 0.05

Station B:

The relay in B has a back-up function for the relay in C.

The maximum through-fault current of 1.395 A becomes effective for a fault in location F2.

For the relay in C, we obtain an operating time of 0.11 s (I/IP = 19.9).

We assume that no special requirements for short operating times exist and can therefore choose an average time grading interval of 0.3 s. The operating time of the relay in B can then be calculated:

  • tB = 0.11 + 0.3 = 0.41 s
  • Value of Ip /In = 1395 A / 220 A = 6.34
  • With the operating time 0.41 s
  • and Ip /In = 6.34,
  • we can now derive TP = 0.11 from the equation given above.

The setting values for the relay at station B are herewith

  • Current tap: IP /IN = 1.1
  • Time multiplier TP = 0.11

Given these settings, we can also check the operating time of the relay in B for a close-in fault in F3:

The short-circuit current increases in this case to 2690 A (see Fig. 117). The corresponding I/IP value is 12.23.

  • With this value and the set value of TP = 0.11 we obtain again from the above equation an operating time of 0.3 s.

Station A:

We add the time grading interval of 0.3 s and find the desired operating time

tA = 0.3 + 0.3 = 0.6 s.

Following the same procedure as for the relay in station B we obtain the following values for the relay in station A:

  • Current tap: IP /IN = 1.0
  • Time multiplier: TP = 0.17
  • For the close-in fault at location F4 we obtain an operating time of 0.48 s.

10.4 Protection design on medium and low voltage networks

Although not appreciated by many engineers, the widespread use of inverse definite minimum time over current and ground fault (IDMT OCEF) relays as the virtual sole protection on medium and low voltage networks requires as much detailed study and applications knowledge as does the more sophisticated protection systems used on higher voltage networks.

10.4.1 Introduction

Traditionally, design engineers have regarded medium and low voltage networks to be of lower importance from a protection view, requiring only the so-called simpler type of IDMT overcurrent and ground fault relays on every circuit. In many instances, current transformer ratios were chosen mainly based on load requirements, whilst relay settings were invariably left to the commissioning engineer to determine. Most of the time; the relay settings had been chosen considering the downstream load being protected without an effort to coordinate with the upstream relays. However, experience has shown that there has been a total lack of appreciation of the fundamentals applicable to these devices. Numerous incidents have been reported where breakers have tripped in an uncoordinated manner leading to extensive network disruption causing longer down times or failed to trip causing excessive damage, extended restoration time and in some cases loss of life.

This chapter reviews some of the fundamental points for the design engineer to watch for in planning the application of IDMTL OCEF protection to medium voltage switchboards and networks.

10.4.2 Why IDMT?

Though it may be possible to grade the relay settings based on the fault currents, it is noted that the fault currents in a series network differs marginally when the sections are connected by cables without any major equipment like transformers in between the two ends. In such types, if networks grading the settings based on current values do not serve the purpose. It is required to go for time grading between successive relays in most of the networks.

To achieve selectivity and co-ordination by time grading two philosophies are available, namely:

  • Definite time lag (DTL), or
  • Inverse definite minimum time (IDMT)

For the first option, the relays are graded using a definite time interval of approximately 0.5 seconds. The relay R3 at the extremity of the network is set to operate in the fastest possible time, whilst its upstream relay R2 is set 0.5 seconds higher. Relay operating times increase sequentially at 0.5-second intervals on each section moving back towards the source as shown in Figure 10.3.

Figure 10.3
Definite time philosophy

The problem with this philosophy is, the closer the fault to the source the higher the fault current, the slower the clearing time–exactly the opposite to what we should be trying to achieve. On the other hand, inverse curves as shown in Figure 10.4 operate faster at higher fault currents and slower at the lower fault currents, thereby offering us the features that we desire.

Figure 10.4
Inverse definite minimum time

This explains why the IDMT philosophy has become standard practice throughout many countries over the years.

10.4.3 Types of relays

Until the eighties in the last century, electro-mechanical disc-type relays were the standard choice, the most popular being GEC’s type CDG and the TJM manufactured by Reyrolle. They both follow the BS 142 specification for the normal inverse curve as highlighted in Figure 10.5, with an acceptable error margins as identified in the graph.

Figure 10.5
BS 142 tolerance limits

Being of the moving-disc principle, the disc has a tendency to ‘overshoot’ before resetting after the fault current is removed by a down-stream breaker. This phenomenon has to be considered, together with the tolerance on the tripping characteristic coupled with the breaker clearing time when determining the optimum time grading interval of 0.4-seconds as developed in Figure 10.6 and Figure 10.7.

Figure 10.6
Typical disc-type relays
Figure 10.7
Minimum grading intervals

However, on the modern electronic digital versions there is no overshoot to worry. In addition, they offer better tolerance over the whole curve–better than 5% is claimed–so the combination of these two factors means the time-grading interval can be reduced to 0.3 seconds (see Figure 10.8).

Figure 10.8
Typical micro-processor relays

Another point often overlooked in the use of electro-mechanical relays is that the burden of the relay varies inversely with the plug setting. The lower the plug taps setting, the higher the burden.

This had been illustrated in the previous chapter where it had been noticed that for a 1 amp relay the range varies from 0.75 ohms on the 200% tap to 300 ohms on the 10% tap. Similarly for the 5 amp relay the range varies from 0.03 ohms on the 200% tap to 12 ohms on the 10% tap. The choice of plug tap could therefore have a significant effect on the performance of the current transformers to which the relay is connected.

This shortcoming has been addressed on modern electronic relays, the burden remaining constant over the whole setting range and at a very low value, typically 0.02 ohms as seen in the previous chapter, without any major implication on the settings adopted.


Depending on the type of time-current characteristics available in an IDMTL relay, it can be classified as Standard Inverse (SI), Very Inverse (VI) or Extremely Inverse (EI). Modern relays can generally offer different characteristics in the same unit, unlike the earlier electro-mechanical designs which can offer only a single type of characteristic curves. These curves are often expressed using mathematical functions. Both IEC 60255 and IEEE C37.112-1996 specify the mathematical functions for each of the above-mentioned operating characteristic curves.

10.4.4 Network application

When deciding to apply IDMT relays to a network, a number of important points have to be considered.

Firstly, it must be appreciated that IDMT relays cannot be considered in isolation. They have to be set to co-ordinate with both upstream and downstream relays. Their very purpose and being is to form part of an integrated whole system. Therefore, whoever specifies this type of relay should also provide the settings and co-ordination curves as part of the design package to show that he knew what he was doing when selecting their use. This very important task should not be left to others and once set, the settings must not be tampered (even by the operating staff) as otherwise co-ordination is lost.

Overcurrent grading

When assessing the feasibility of applying such protection, one must be aware of certain constraints that will be applied by the supply authority at the one end and the co-ordination requirements of the low voltage network at the other. These factors can often place severe limitations on the number of grading steps that can be achieved. It will be seen from Figure 10.9 that one could soon run out of time on overcurrent relays at the downstream side and it may be impossible to provide the settings for the downstream end relays.

Figure 10.9
Overcurrent–time grading intervals

Using modern electronic relays does help in that with a 0.3-sec time interval a couple of extra grading steps can be gained.

The message here is therefore very clear. When designing medium voltage network, one must aim for the minimum number of grading levels. In other words, medium voltage networks should be designed ‘short and fat’ rather than ‘long and thin’ as shown in Figure 10.10 (a) and 10.10 (b).

Figure 10.10 (a)
Influence on network design (short and fat)
Figure 10.10 (b)
Influence on network design (long and thin)

If this recommendation is not followed, then one may be faced with running a network radially by opening a ring at a specific point in order to achieve some moderately acceptable form of grading as seen in Figure 10.11. The relay settings would thus be dictating at which point the ring must be open. This is bad design practice as protection relays should never place any limitations on which way the network should be operated, as maximum flexibility is essential at all times. Furthermore, running radially means continuity of supply is lost under fault conditions and co-ordination would be lost when the network is re-arranged to restore supply from an alternative source.

Figure 10.11
Impact on system configuration

Ground fault grading

Generally, MV systems are impedance grounded at its neutral end usually using a neutral grounding resistor (NGR), which limits the ground fault current to around 300 amps. Figure 10.12 shows the current distribution for an MV ground fault from which it will be seen that only a small overcurrent flows on the HV side of the supply transformer under a fault. This is of no embarrassment to the supply authority so they often allow greater clearance times for ground faults on the consumer’s network. Times of 3.0 to 3.6-seconds are typical for the supply authority’s back-up protection. This allows for a number of grading steps to be achieved for the ground fault protection into the consumer’s network.

Figure 10.12
Ground fault

However, a point that is not often appreciated is that the NGR is the dominant impedance in the ground fault loop. This means that a ground fault anywhere on the MV network is controlled to a virtual constant level of current by the NGR. If the ground fault current is constant, then the IDMT EF relays behave as definite time relays, operating longer for a fault closer to the source (see Figure 10.3). A ground fault near to the source can therefore easily develop into high–current phase fault before the ground fault relay has timed-out leading to enormous damage.

Transformer protection

IDMT relays have often been used as the main HV protection on distribution transformers, without due regard for certain limitations.

It is often very difficult, in fact impossible, to set an HV IDMT relay to detect a ground fault on the LV winding of a transformer. As will be seen from Figure 10.11 the equivalent HV current for a ground fault on the LV winding (especially towards the neutral end) can be below the primary full load current. If the LV winding is grounded via a resistor the ground fault current will not exceed 57% of the full load rating of the transformer. The transformer should therefore be fitted with an additional protection such as Buchholz or Restricted ground fault (REF) on the LV side to cover this condition.

It has been common practice not to fit Buchholz relays to small transformers because it is too expensive relative to the cost of the transformer. However, the size of the transformer is not that important but its strategic location in the network that counts. Its loss may have a major impact on production downtime etc, irrespective of its size, so it is worth protecting it properly and the Buchholz alarm does give early warning of impending trouble (see Figure 10.13 (a) and (b)).

Figure 10.13 (a)
HV overcurrent on transformers
Figure 10.13 (b)
Fault current due to grounding resistor

Another poor design practice is for the HV IDMT relay only to trip the HV breaker. For an HV winding fault the breaker is tripped but the fault can continue to be fed via the low voltage side, the back-feed coming from the adjacent transformer(s) where the LV protection is set high to co-ordinate with downstream requirements. Transformer protection should always trip both HV and LV circuit breakers wherever possible as shown in Figure 10.14.

This is very much important when a low voltage bus is connected from more than one source. In some cases, it is a common practice to ensure that the secondary breaker is tripped whenever the primary breaker is tripped/open (intertrip) and to introduce interlock to avoid secondary breaker being closed without primary breaker in closed position.

Figure 10.14
Protection should trip HV and LV

There is also a general misconception that, the HV IDMT overcurrent relay is there and to be set to cover overloading of the transformer. It is not true since the overcurrent relay acts more as a protection against faults and not as overload protection. If the thermal characteristic of a transformer is plotted against the normal inverse IDMT curve (which is on log-log graph scale) it will be seen as a straight line crossing the IDMT characteristic at some point (see Figure 10.15).

Figure 10.15
IDMT normal inverse not for overload

It may be possible to select the settings such that, for small overloads the relay will trip before the transformer heats up to its limit. However, for sudden heavy overloads the transformer will cook before the relay trips. The normal inverse IDMT relay is therefore NOT suitable for overload duty–it is a fault protection. If overload protection is desired then a relay with a suitable thermal characteristic should be applied or alternatively select the inverse characteristic in the IDMT range, the time being approximately inversely proportional to the square of the current. This characteristic is much closer to the thermal characteristic of a transformer and any fuses downstream in the LV network.

However, why trip the transformer out for overload–why not just remove the load by tripping the LV breaker? The same current that flows through the transformer flows through the LV breaker and nearly all have thermal characteristics as an integral part of their protection. This approach would certainly save operators having to test and check out a transformer before returning it to service, thereby reducing downtime.

10.4.5 Current transformers

There are numerous installations where the performance of the current transformers has been overlooked or misunderstood.

The most widely mistaken error has undoubtedly been the choice of CT ratio which was invariably selected on the basis of full load current without due regard to performance under fault conditions. Despite its name, the performance parameter that we are most interested in is the current transformer’s secondary voltage. In other words, the voltage developed across the CT secondary shall be sufficient to drive the transformed current through its own internal impedance plus the impedance of the relay and any other equipment to which it is connected (see Figure 10.16).

Figure 10.16
CT performance important

It is necessary to fix the typical form of a magnetization curve for the CT. The knee-point voltage and the CTs internal resistance should be specified / checked to ensure that they are adequate for the application.

A classical example of how-not-to-do-it was seen recently on a feeder to a mini-sub from a main 11 kV switchboard whose fault level was approximately 9000 amps. Refer to Figure 10.17.

Figure 10.17
Typical selection of CT

CT ratio: 25/5

Burden: 5 VA

Accuracy: 10P10

Over current relay: CDG set at 50%

In the above example, for a 9000 amp fault on the feeder cable, the CT secondary current would be 1800 amps. The burden of the relay at the chosen setting is 0.48 ohms, therefore the secondary voltage required to drive 1800 amps through an impedance of 0.48 ohms = 1800 × 0.48 = 864 volts. With 5 turns on the CT the best that can be expected is 1 volt per turn which equals 5 volts. It will now be evident why the magnetization curve and internal resistance of the CT are so important, especially when electromechanical relays are used for protection.

With such a low ratio, this CT would undoubtedly be of the wound primary type in order to get the required number of amp-turns to magnetize the core. Unless the CT manufacturer was told, the high fault current would cause this CT to burst due to the high thermal and magnetic stresses set up in the primary winding under fault conditions which are a function of the fault current squared.

CT ratios should therefore be chosen based on fault current NOT load current.

In such applications, the use of 1 amp secondary is recommended as there would be one fifth of the current and five times the voltage available to drive this smaller current around its connected load.

The accuracy stated in the above example of 10P10 means that the CT will remain 10% accurate up to 10 times its rating (i.e. up to 250 amps)–not much use for a fault current of 9000 amps. Ideally, the chosen ratio should have been 900/1 10P10 or 450/1 10P20.

The correct technique in choosing a CT ratio is to calculate the fault current and divide this by 10 for a 10P10 accuracy rating or by 20 for a 10P20 specification. Accuracy is important, especially in tight grading applications as highlighted above.

It is also a common practice by some designers to add an ammeter into the protection circuit. This is invariably done for reasons of economy to save fitting another set of CTs. However, this is not a good practice because:

  1. It adds more burden into the CT circuit–typically 1 VA for a normal ammeter and 5 VA for a thermal maximum demand ammeter – thereby giving the CT more work to do, thereby pushing into saturation; and
  2. Ammeters are designed to operate under healthy conditions over the range 0–1.2 times full load. Ideally, they should be connected to metering cores, which saturate at this upper level to protect the instrument under fault conditions.
  3. Protection cores on the other hand are designed to operate under fault conditions at 10 to 20 times full load current. Connecting ammeters to protection cores therefore subjects the instruments to enormous shocks under fault conditions, which initially affects the accuracy but ultimately destroys the bearings, and mechanisms etc.

It is evident that this common wrongful practice of adding meters onto protection cores is the main influencing factor in deciding the CT ratio. A classic case of the tail wagging the dog!

Figure 10.18 indicates the CT ratios and the settings adopted in a typical network comprising of various transformers. It can be noted that the CT knee point voltages as per the actual fault current figures are quite different from the actual knee point voltage of the available CTs. (refer lines marked ‘?’) It is a very clear case, wherein the wrongful selection of current transformers could lead to relays not operating at fault conditions. This shall be avoided, which can be done by doing proper calculations before deciding the component details.

Take the settings for a transformer in line 3. The fault current is around 6200 amps and with a CT ratio of 100/5 A, the relay, current under fault will be about 310 amps. This requires a knee point voltage of not less than 164.5 for the provided CT but the actual knee point is only around 46 volts. The relay is not going to serve any purpose under fault conditions. Just consider the CT ratio of 100/1 amps. The relay current under fault will reduce by one fifth, and the knee point voltage required will be only around 33 volts and the available CT will do its job without any problem.

This kind of analysis is necessary while choosing CT ratio and knee point voltages while designing a network, which requires coordination for relay grading.

Figure 10.18
Typical case of CT selection in a large network

10.4.6 Importance of settings and co-ordination curves

One can have the finest protection in the world, correctly designed, installed, commissioned and maintained but if it is not set correctly then it is not much use. Careful attention should therefore be paid to the settings of IDMT relays in particular, as they have to co-ordinate with upstream and downstream relays. To repeat what has been stated previously, the person who selects and specifies this type of relay should therefore also provide the settings and co-ordination curves to prove that the relay can fit correctly into the new or existing network. Many instances have arisen where it has not been possible to achieve any sort of adequate settings (as has been highlighted in the examples above) thereby proving the designer did not know what he was doing or misunderstood the fundamentals.

In setting the IDMT relay it must be appreciated that moving the plug bridge moves the curve left or right in the horizontal direction and selects the current pick-up value. Adjusting the time multiplier dial moves the curve up or down in the vertical direction to select the time of operation (see Figure 10.19).

Figure 10.19
Effect of settings

It is therefore possible to achieve the same setting using two different combinations of plug setting and time multiplier as illustrated in Figure 10.20. Notice how the curves cross. Even with a time interval between them, it is still possible to choose plug/time dial settings such that the curves cross. This means that for low fault currents relay A operates before relay B but for high fault currents relay B operates before relay A. Co-ordination is therefore lost. It is vitally important that after selecting settings for the relays, the co-ordination curves are drawn to ensure that they do not cross and that they stack up nicely on top of one another as shown in Figure 10.21.

Figure 10.20
Curves must not cross
Figure 10.21
Ideal co-rdination of setting curves

Two basic rules are that they must pick-up for the lowest fault level (minimum plant) and must co-ordinate for the highest fault level (maximum plant).

One final word on a point not often appreciated. The electrical network is in fact a living thing. It grows and changes over time. Generation is added, load centers develop, old plant’s de-commissioned, new plant’s extended and so on. Fault levels therefore change and invariably increase. IDMT relay settings should therefore be reviewed on a regular basis, especially if there are extensions or changes planned. The opportunity should be taken to up-grade the protection at the same time. The old electro-mechanical disk relays have done a wonderful job over the last century and can still continue to do so in certain applications provided one is aware of their limitations. However, we are now starting to ask more than they are capable of delivering. Nothing wrong with the relay–it’s just the application. So one should take advantage of the additional facilities offered by the new range of numerical relay equivalents.

10.4.7 Conclusion

To engineers planning the protection for a medium to low voltage network and wishing to adopt the widespread use of the IDMT OCEF relay, the above can be summarized as follows:

  • Design networks with the minimum number of grading levels possible
  • Choose CT ratios based on fault current – not load current
  • Consider using 1 amp secondary
  • Check CT magnetization curves for knee-point voltage and internal resistance
  • Connect ammeters etc onto own metering cores
  • Provide relay settings and co-ordination curves as part of the design package
  • Be careful when choosing relay plug tap setting on electro-mechanical relays. The lower the tap, the higher the burden
  • Relays should not pick-up for healthy conditions such as permissible transient overloads, starting surges and reconnection of loads, which have remained connected after a prolonged outage
  • Care should also be taken that the re-distribution of load current after tripping does not cause relays on healthy circuits to pick-up and trip
  • HV IDMT relays on transformers should trip both HV and LV breakers
  • Normal inverse curves should not be selected for overload protection. Rather use the inverse characteristic for this duty
  • Take advantage of the additional features offered by the modern electronic relays, e.g. fixed very low burden, integral high-set, breaker fail and busbar blocking protections, event memory etc. However, remember, one has to do the same calculation exercises for settings and draw co-ordination curves whether the relays are of the electronic or electro-mechanical design.
  • Finally, if the switchgear suppliers also manufacture relays, do not expect them to do the protection application settings free of charge as part of the service. If this is required, specify this as a separate cost item in the specification

Many problems down the line can be avoided and the performance, efficiency and safety of the plant improved if a protection engineer is included in the design team, if not full time, but at least to do an audit on the proposals.

Finally, remember–whilst IDMT relays are the most well known and the cheapest, they are in fact the most difficult relays to set.

10.5 Sensitive ground fault protection

A number of instances arise where the load current demands high ratio line current transformers, and the neutral current has been limited to a low value by the use of a remote high-impedance neutral grounding device for safety reasons.

In this situation, the use of a conventional IDMTL ground fault relay with a minimum setting of 10% would be unable to detect a ground fault condition.

For such an application, sensitive ground fault protection should be considered (see Figure 10.22).

Figure 10.22
Ground fault–current limited by NGR.

In addition, on overhead rural distribution systems it is possible for high resistance ground faults to occur, especially if a conductor breaks and falls on very dry ground having say high silica content. Instances have been recorded where the initial rush of fault current has caused the silica to form a glass envelope around the end of the broken conductor, so a live conductor then remained undetected following the auto-reclose shot.

Besides this type of unusual incident, it is not uncommon for broken conductors to fall on dry ground, and this presents a hazard to human life and livestock if left undetected for any length of time, particularly if the line does not have ground wires installed.

It is therefore necessary to apply sensitive ground fault relays to cover these and other demanding situations.

Another factor is the possible predominance of a third harmonic component in the residual current even under quiescent conditions. Third harmonics appear as zero sequence currents and could cause mal-operation of the relay. It is therefore wise to select a design of relay, which has been tuned to reject currents of this frequency. Also, ensure that the response decreases at higher frequencies to render the relay immune to harmonic resonant conditions, which may vary according to the power system configuration. There are a number of sensitive ground fault relays on the market, essentially of the definite-time variety, having pick-up setting ranges typically of the order of 0.4% to 40% of 5 amps.

One model offers a useful digital read-out of the standing neutral current when interrogated via a push-button. If this is recorded on a regular basis, trends can be established which would assist in determining the deterioration of the line insulators and help to plan preventative maintenance programs.

Time setting ranges vary from 0.1 to 99-seconds. Adjustable time delays ensure stability during switching and other transient disturbances and allow for adequate grading with other protection systems.

On rural networks, it is as well necessary to ensure that the relay contacts are self-reset (i.e. they do not latch) so that auto-reclosing can take place.


Low voltage networks

11.1 Introduction

The low voltage network is a very important component of a power system as it is at this level that much of the power is distributed and utilized by the end consumer. Essential loads such as lighting, heating, ventilation, refrigeration, air-conditioning and so on are generally fed at voltages such as 380 V, 400 V, 415 V, 480 V, 500 V, 525 V (as defined in the relevant national standards) from three-phase three-wire or three-phase 4 wire supply network. In mining industry, heavy motor loads often require voltages as high as 1000 volts.

Because of the diverse nature of the loads coupled with the large number of items requiring power, it is usual to find a bulk in-feed to an LV switchboard, followed by numerous outgoing circuits of varying current ratings, in contrast to the limited number of circuits at the medium voltage level.

Large frame (high current rated) air circuit breakers are therefore specified as incomers from the supply transformer and moulded case circuit breakers (MCCBs) for all outgoing feeders. The down stream network generally consists of MCCBs of varying current ratings and as the current levels drop miniature circuit breakers (MCBs) are used for compactness and cost saving.

11.2 Air circuit breakers

These breakers are available in frame sizes ranging from 630 A to 6000 A in 3 and 4 pole versions and are generally insulated for 1000 volts. Rated breaking capacities of up to 100 kA rms symmetric to IEC947-2 are claimed at rated voltage of 660 volt.

Fixed and draw-out models are available and each unit invariably comes complete with a protection device, which, in keeping with modern trends, is generally of the electronic type and will be discussed in more detail later.

Typical total breaking times are of the order of 40 to 50 milliseconds for short circuit faults.

Their operating speed is important as air circuit breakers (ACBs) are applied as the main incoming devices to the low voltage network where they are subject to the highest fault levels determined by the supply transformer.

A typical construction of an ACB is shown on the next page. The spring charging can be manual and electrical. The operating and tripping mechanisms are similar to the ones used in high voltage oil / vacuum / Sf6 circuit breakers.

It is common to note that most of the present day ACBs are fitted with solid-state built-in overcurrent and ground fault relay. The same can be set for various current and time characteristics without the need for using external relays. These relays are provided with ample current and time setting ranges to achieve discrimination for various types of LV distribution systems (see Figure 11.1).

Figure 11.1
Typical internal construction of an air circuit breaker

11.3 Moulded case circuit breakers

MCCBs are power switches with built-in protective functions used on circuits requiring lower current ratings. They include the following features:

  • Normal load current open and close switching functions.
  • Protection functions to automatically disconnect excessive overloads and to interrupt short circuit currents as quickly as possible.
  • Indication status of the MCCB: either open, closed or tripped.

Although many different types are manufactured, they all consist of five main parts:

  • Moulded case (frame)
  • Operating mechanism
  • Contacts and extinguishers
  • Tripping elements and
  • Terminal connections.

11.3.1 Moulded case

This is the external cover of the MCCB, which houses all the sensing and operating components. This is moulded from resin/glass-fiber materials, which combine ruggedness with high dielectric strength.

The enclosure provides a frame on which to mount the components, but more importantly, it provides insulation between the live components and the operator.

Different sized cases are required according to the maximum rated voltage / current and interrupting capacity. They are assigned a ‘frame size’. It is to be noted that the case is moulded and as such, it is not possible to access the internal components in case of any failures and it would be necessary to replace the complete MCCB under those circumstances.

Operating switch / mechanism
The operating switch is accessible from outside for ON/OFF/RESET purposes. This is a handle, which connects to the internal mechanism for the ON/OFF/RESET operations. In passing from ON to OFF (or vice versa), the handle tension spring passes through alignment with the toggle link and a positive rapid contact-operating action is produced to give a ‘quick break’ or a ‘quick make’ action. This makes it independent of the human element i.e. the force and speed of operating the handle.

The mechanism also has a ‘trip free’ feature, which means that it cannot be prevented from tripping by holding the operating handle in the ON position during faults. In other words, the protective contact-opening function cannot be defeated.

In addition to indicating when the breaker is ON (in the up position) or OFF (in the down position), the TRIP condition is indicated by the handle occupying the position midway between the extremes as shown in Figure 11.2 below.

To restore service after the breaker has tripped, the handle must first be moved to the OFF position to reset the mechanism before being moved to the ON position.

Figure 11.2
Handle positions

Contacts and extinguishers
A pair of contacts comprises a moving contact and a fixed contact. The instants of opening and closing impose the most severe operating conditions. Contact materials must therefore be selected with consideration of three criteria:

  • Minimum contact resistance
  • Maximum resistance to wear
  • Maximum resistance to welding.

Silver or silver-alloy contacts are low in resistance but wear rather easily. Tungsten or tungsten-alloys are strong against wear due to arcing but rather high in contact resistance.

Contacts are thus designed to have a rolling action, containing mostly silver at the closing current-carrying points, and mostly tungsten at the opening (arcing) point (see Figure 11.3).

Figure 11.3
Dual function contacts

In order to interrupt high short-circuit currents, large amounts of energy must be dissipated within the moulded case.

This is achieved by using an arc-chute, which comprises a set of specially shaped steel grids, isolated from each other and supported by an insulated housing. When the contacts are opened and an arc is drawn, a magnetic field is induced in the grids, which draws the arc into the grids.

The arc is thus lengthened and chopped up into a series of smaller arcs, which are cooled by the grids’ heat conduction. Being longer, it requires far more voltage to sustain the arc and being cooler, it tends to lose ionization and extinguish at the first current zero (see Figure 11.4).

Figure 11.4
The arc shute

Tripping elements
The function of the trip elements is to detect the overload or short-circuit condition and trip the operating mechanism.

Thermal overload
The thermal trip characteristic is required to be as close as possible to the thermal characteristics of cables, transformers, etc. To cover this overload condition, two types of tripping methods are available, namely bi-metallic and hydraulic.

Bi-metallic Method
The thermal trip action is achieved by using a bi-metallic element heated by the load current.

The bi-metal consists of two strips of dissimilar metals bonded together. Heat due to excessive current will cause the bi-metal to bend because of the difference in the rate of expansion of the two metals. The bi-metal must deflect far enough to physically operate the trip bar. These thermal elements are factory-adjusted and are not adjustable in the field. A specific thermal element must be provided for each current rating.

A number of different variations on this theme are available as shown in Figure 11.5 below.

The bi-metal is temperature sensitive and automatically re-rates itself with variations in ambient temperature.

Figure 11.5
Thermal tripping methods

Hydraulic method
For its operation, this device depends on the electro-magnetic force produced by the current flowing in a solenoid wound around a sealed non-magnetic tube. The tube, filled with a retarding fluid, contains an iron core, which is free to move against a carefully tensioned spring. For normal load current, the magnetic force is in equilibrium with the pressure of the spring.

When an overload occurs, the magnetic force exceeds that of the spring and the iron core begins to move, reducing the air-gap in the tripping armature. Once the magnetic field is large enough, the armature closes to trip the mechanism. The time delay characteristic is controlled by the retarding action of the fluid. The concept is illustrated in Figure 11.6 below.

Figure 11.6
Hydraulic tripping method

Short circuits
For short circuit conditions, the response time of the thermal element is too slow and a faster type of protection is required to reduce damage. For this reason, a magnetic trip action is used in addition to the thermal element. When a fault occurs, the short circuit current causes the electro-magnet to attract an armature, which unlatches the trip mechanism. This is a fast action and the only delay is the time it takes for the contacts to physically open and extinguish the arc. This is normally in the order of 20 milliseconds--typically 1 cycle.

In the hydraulic method, the current through the solenoid will be large enough to attract the armature instantaneously, irrespective of the position of the iron core. The interruption speeds for this type of breaker for short circuit currents are also less than 1 cycle (20 ms) similar to the bi-metallic type.

In both of the above methods, the thermal-magnetic and the hydraulic-magnetic, the tripping characteristics generally follow the same format as shown in Figure 11.7.

Figure 11.7
Typical tripping characteristics

Electronic protection MCCBs
Moulded case circuit breakers of the conventional types mentioned above are increasingly being replaced by electronic trip units and current transformers, which are an integral part of the breaker frame.

This modern trend in technology results in increased accuracy, reliability and repeatability.

However, the main advantage is the adoptability of the tripping characteristics, as compared with the above-mentioned electro-mechanical devices, which are generally factory pre-set and fixed for each current rating. Discrimination can be improved. Furthermore, semi-conductor controlled power equipment can be a source of harmonics which may cause malfunctions.

Electronic protective devices detect the true r.m.s. value of the current, thereby remaining unaffected by harmonics.

A comparison of the thermal-magnetic and hydraulic-magnetic types is given in Figure 11.8.

Terminal connections
These connect the MCCB to a power source and a load. There are several methods of connection such as busbars, straps, studs, plug-in adaptors, etc.

Up to 250-300 A, whenever cables are used, compression type terminals are used to connect the conductor to the breaker. Above 300 A, stubs, busbars or straps are recommended to ensure reliable connections, particularly when using aluminum cables.

Please refer to the subsequent pages regarding the caution to be taken while connecting the MCCB in a power circuit.

Miniature circuit breakers
Miniature circuit breakers are similar to moulded case circuit breakers but as their name implies, these are smaller in size and are mostly used for current ratings below 100 amperes. These are normally available in single pole (SP), single pole neutral (SPN), double pole (DP), triple pole (TP), triple pole neutral (TPN) and four pole (FP) versions.

DC circuits
The MCCBs and MCBs are available for both AC and DC ratings for the various standard voltages. However, it must be remembered that a 220 V AC MCB may not be suitable for a 110 V DC application, unless it is tested and approved by the manufacturer. Hence, proper care must be taken while using MCBs and MCCBs in DC circuits.

Figure 11.8
Comparison of thermal-magnetic and hydraulic-magnetic types

11.3.2 Current limiting MCCBs

Current limiting MCCBs are essentially extremely fast-acting breakers that interrupt the short circuit fault current before it reaches the first peak, thus reducing the current or energy let-through in the same manner as a fuse. They are therefore required to operate in the first quarter of a cycle, i.e.5 milli-seconds or less, and limit the peak short circuit current to a much lower value, after which can be switched on again, if necessary, without replacement of any parts or elements (see Figure 11.9).

Figure 11.9
Limited short circuit let-through current

This high contact speed of separation is achieved by using a reverse loop stationary contact.

When a fault develops, the current flowing in the specially designed contacts causes an electro-dynamic repulsion between them. The forces between the contact arms increase exponentially rather than linearly. As the contact gap widens, the arc is quickly extinguished by a high performance arc chute.

By limiting the let-through current, the thermal and magnetic stresses on protected equipment such as cables and busbars is reduced in case of a short circuit.

Provided combination series tests have been done and certified, this also permits the use of MCCBs with lower short circuit capacities to be used at downstream locations from the current limiting MCCB. This is known as cascading, and results in a more economical system, but additional care must be taken to preserve discrimination between breakers. This will be discussed in more detail in section 11.4.

The following accessories are available with all different makes of MCCB:

  • Shunt trip coils
  • Under-voltage release coils
  • Auxiliary switches
  • Mechanical interlocks
  • Residual current devices (ground fault protection)

A typical moulded case circuit breaker (MCCB) is shown in Figure 11.10. When selecting an MCCB for an application, it is important to ensure that the following ratings are correct:

  • Voltage rating (AC/ DC)
  • Current rating
  • Breaking capacity rating
Figure 11.10
Typical moulded case circuit breaker

Figure 11.11 indicates the standard precautions to be followed while installing the MCCB.

Figure 11.11
Cautions for installation

Figure 11.12 indicates the standard precautions to be followed while connecting the MCCB.

Figure 11.12
Cautions for connections

11.4 Application and selective co-ordination

The basic theory of selective co-ordination is applicable for all values of electrical fault current.

  • Milli-amperes - Ground leakage protection
  • Hundreds of amps - Overload protection
  • Thousands of amps - Short circuit protection.

Ground leakage protection will be discussed later under section 11.5.

It is generally accepted that most short circuit currents that occur in practice fall below the calculated theoretical value for a three-phase bolted fault. This is because not all faults occur close to the MCCB (except when the supply cable is connected to the bottom of the MCCB). The resistance of the cable between the MCCB and the fault reduces the fault current; also, most faults are not bolted faults - the arc resistance helps to reduce the fault current even further.

For economic and practical reasons, it is not feasible to apply the same sophisticated relay technology as used on the medium voltage to low voltage networks, as this would result in a very complicated and expensive system. Therefore, the present system of using air and moulded case circuit breakers is a successful compromise developed over many years.

These devices, however, are current operated as described previously, so it is possible to achieve varying degrees of co-ordination by the use of:

  • Current grading
  • Time grading
  • Current and time grading

11.4.1 Air circuit breaker

Let us now consider the protection provided by the air circuit breaker on the LV side of the main in-feed transformer.

Transformer overload condition
The thermal element on the air circuit breaker can be set to protect the transformer against excessive overloading, as the same current that flows through the transformer flows through the air circuit breaker. Tripping this breaker removes the overload and allows the transformer to cool down. The transformer has not faulted - it is only being driven above its continuous design rating, which if allowed to persist for some time, will cook the insulation, eventually leading to failure. By checking the temperature indicators on the transformer, the operator then obtains a clear indication of the problem. The transformer is still alive from the HV side so it has not faulted. It is purely an overload condition (see Figure 11.13).

Figure 11.13
LV air circuit breaker on transformer

It has been common practice to trip the transformer from the HV IDMT overcurrent relay for an overload condition. With this approach, the operator does not know if the transformer has faulted or if it was just an overheating condition. He is now faced with a decision to make and if he is conscientious, he may decide to test the unit before switching in again. This could lead to excessive downtime.

In addition, the HV IDMT overcurrent relay (normal inverse) does not have the correct characteristic for overload protection as pointed out in Chapter 10.

Short circuit protection
Short circuits at points A, B and C must now be considered. The fault currents will be the same as there is virtually no impedance between them. The short circuit protection on the air circuit breaker (ACB) should therefore be set with a short time delay to allow the downstream MCCB to clear fault C. However, if the fault is on the busbar the time delay should be short enough to effect relatively fast clearance to minimise damage and downtime.

Fault A will have to be cleared by the HV overcurrent relay in order to protect the cable from the transformer to the LV switchboard. This in turn should have a longer time delay to co-ordinate with the LV ACB and provide discrimination for faults B and C.

These requirements show the value of specifying adjustable current pick-ups and time delays for the protection devices on air circuit breakers, most of which are available in electronic form.

In addition, they also come equipped with a very high set instantaneous overcurrent feature having a fast fixed time setting of 20 milliseconds to cover ‘closing-onto-fault’ conditions (see Figure 11.14).

Figure 11.14
ACB adjustable protection tripping characteristics

Moulded case circuit breakers
A reasonable degree of current grading can be achieved between two series-connected MCCBs by simply applying a higher rated breaker up-stream of a given unit. The extent of the co-ordination is shown on the following time-current characteristic curves (see Figure 11.15).

Figure 11.15
Current co-ordination in MCCB

It will be noted that selectivity is obtained in the thermal overload and partial high current region co-ordination being lost above the short circuit pick-up current level of the up-stream breaker.

For large consumers, the integrity of the supply is important. The ability of the up-stream breaker to hold in under such fault conditions is enhanced when it is equipped with an additional short time delay facility, provided by the modern electronic trip elements (see Figure 11.16).

Figure 11.16
Current-time co-ordination

MCCB un-latching times
Once triggered, MCCBs have an un-latching time, which is dictated by the physical size and inertia of the mechanism. It stands to reason that the physically smaller, lower rated breakers will have a shorter un-latching time than the higher rated, larger up-stream breakers, thereby enhancing their clearing time.

Experience in practical installation of fully rated breakers has shown that unexpected degrees of discrimination have been achieved because of this.

For current limiting circuit breakers, where contact parting occurs independently of the mechanism, the un-latching times do not have such an impact on the clearance times.

Fully rated systems
When time delayed MCCBs are used to achieve extended co-ordination, all downstream circuit breakers must be rated to withstand and clear the full prospective short circuit current at the load side terminals.

Cascading systems
This approach can be used if saving on the initial capital cost is the overriding factor.

This necessitates using a current-limiting breaker to contain the let-through energy, thus allowing lower rated (hence less costly) breakers to be used downstream.

To achieve successful co-ordination, careful engineering is required, especially with regard to clearance and un-latching times, in addition to the size and length of interconnecting cables, together with accurate calculation of fault levels.

If the let-through energy is sufficient to cause the downstream breaker to un-latch, then the faulty circuit will be identified, although the upstream current-limiting MCCB will also have tripped to drop the whole portion of the network being served by this main breaker.

However, if the downstream breaker does not un-latch then extended outage time is inevitable to trace the fault location.

It is vital that the complete system be tested and approved to ensure the delicate balance of the system is not disturbed.

There are a number of factors that need careful consideration.

Sluggish mechanisms
It is well known that any electro-mechanical assembly of links, levers, springs, pivots etc. which remain under tension or compression for a long period, tend to ‘bed in’. Also, dust and corrosion contribute further to retarding the operation after long periods of inactivity. The combined effect could add a delay of 1-3 ms when eventually called into operation.

This additional delay has little effect on fully rated breakers which generally operate after one cycle (20 ms), but on current-limiting MCCBs, which are required to operate in 5 ms, the additional 1-3 ms will have a significant impact on their performance. The increased energy let-through could have disastrous results for both themselves and, in particular, the downstream breaker.

Point-on-wave switching
Most specifications and literature show current / energy-limitation based on fault initiation occurring at a point-on -wave corresponding to current zero. Should the fault occur at some other point on the wave, the di/dt of the fault current would be much greater than that shown, resulting in higher energy let-through (see Figure 11.17).

Figure 11.17
Effect of point-on-wave fault occurrence

Service deterioration
Qualification type tests in most international specifications require the MCCB to successfully perform one breaking operation and one or two make-break operations. In practice, it is rare that the number of operations by a breaker under short-circuit conditions is monitored. This shortcoming is not critical on fully rated systems as the protection of the downstream breakers is of no consequence.

However, in a series-connected cascading system, where the downstream breakers rely for their survival on the energy limiting capabilities of the upstream current limiting breaker, there is always the danger that replacement of the upstream device could be overlooked. There is therefore a strong case for monitoring the number of operations.

For the reasons stated above, any upstream or downstream breakers in a cascade system must be replaced with identical breakers from the same manufacturer in accordance with the original test approvals. This also applies to any system extensions. Any deviation could prove disastrous.

Incorrect replacement of the upstream breaker could result in higher energy let-through and longer operating times, whilst incorrect replacement of downstream breakers may lead to lower energy- handling capability coupled with shorter operating times.

These conflicting requirements are such that even experienced or well-trained technicians may be confused unless they are fully conversant with the principle of the cascade system.

There could be an even greater problem for the maintenance electrician and his artisan, in selecting a replacement device, which may often be dictated by availability.

In view of the problems of staff turnover and the possibility of decreasing skills, it is a stringent requirement that all switchboards carry a prominent identifying label with all relevant technical information to ensure the satisfactory operation and maintainability of cascaded or series connected systems.

Although cascaded systems may offer an attractive saving in initial capital expenditure, it requires a higher level of engineering for the initial design and extensions.

Maintenance can be difficult, as total knowledge and understanding of the system and all its components is required by all operating personnel.

The consultant, contractor or user is thus faced with the decision of choosing between two quite different systems:

  • A fully rated properly co-ordinated system
  • A system based on cascaded ratings.

The first choice may have a slightly higher initial cost. The alternative, offers some initial cost savings whilst sacrificing some system integrity, selectivity and flexibility.

11.5 Ground leakage protection

In the industrial and mining environment the possibility of persons, making direct contact with live conductors is very remote. This is because the conductors are housed in specially designed enclosures, which are lockable and where only trained qualified electricians are allowed access.

The danger lies, however, when a ground fault occurs on a machine and because of poor ground bonding, the frame of the machine becomes elevated to an unsafe touch potential as illustrated in Figure 11.18 below. This is an ‘indirect’ contact situation, which must be guarded against.

Figure 11.18
Protection against indirect contact

Safety codes specify that in mining and industrial installations any voltage above the range of 25 to 40 volts is considered to be unsafe. These figures are derived from the current level that causes ventricular fibrillation - 80 mA times the minimum resistance of the human body which can be in the range of 300 ohms (3 × safety factor) to 500 ohms (2 × safety factor). Please refer to Chapter 4.

It would not be possible to utilize the sensitive domestic ground leakage devices (30 milliamps, 30 milliseconds) in these applications because of the transient spill currents that occur during motor starting. Instantaneous tripping would occur and the machine would never get started.

Tests have been carried out in coalmines to determine the maximum resistance that could occur on an open ground bond. This was measured as 100 ohms. With 25 volts specified as the safe voltage, then a current of 250 milliamps can be regarded as the minimum sensitivity level (derived from dividing 25 volts by 100 ohms). This level was found to be stable for motor starting. It is however above the 80 milliamp fibrillation level of the heart, so speed is now of the essence if we are to save human life.

The ground leakage relays used in industrial applications should therefore operate in 30 milliseconds.

Modern ground leakage relays can achieve this and one such method is to use a unique sensitive polarized release as illustrated in Figure 11.19.

Figure 11.19
I.E.S. 4 polarized release

11.5.1 Construction

The device consists of a U shaped stator on top of which sits an armature. The magnet mounted adjacent to one limb sets up a flux strong enough to hold the armature closed against the action of the spring. There is a multi-turn coil on the other limb, which is connected to the core balance current transformer. When a ground fault occurs, an output is generated by the core balance CT into the coil which reduces the standing flux to the extent that the spring takes over to flip the armature onto the tripping bar to open the breaker. The calibration grub screw is a magnetic shunt.

Screwing it in bleeds off magnetism from the main loop, making the release more sensitive. Screwing it out allows more magnetism around the main loop, making the armature attraction stronger, and hence less sensitive.

The burden of the release is only 400 micro VA (10 millivolts, 40 milliamps), which allows extremely high sensitivities to be achieved.

The release can be complimented by the addition of some electronics in order to produce a series of inverse time/current tripping curves (see Figure 11.20).

Figure 11.20
Internal circuitry

11.5.2 Description of operation

When a ground fault or ground leakage condition occurs on the system, the core balance CT mc generates an output. On the positive half cycle, the secondary current flows through diode d1, resistor r, and charges up capacitor c. On the negative half cycle, the current flows through diode d2, resistor r and charges up capacitor c even further.

The voltage across the capacitor c is monitored by the resistor divider and once it reaches a pre-set voltage level the gate of the scr is triggered. All of the energy stored in the capacitor now flows through the release i to cause operation of the relay.

The capacitor is now fully discharged, enabling the relay to be reset immediately.

By varying the values of r and c, the charge-up time can be varied.

11.5.3 Application and co-ordination of ground leakage relays

A family of relays has been designed to provide co-ordinated ground fault protection for low voltage distribution systems.

Using the above mentioned technology, the following time/current inverse curves have been developed (see Figure 11.21).

Figure 11.21
Time/current response curves

This allows co-ordinated sensitive ground fault protection to be applied to a typical distribution system. They afford ‘back-up’ protection to the end relay, which provides instantaneous protection to the apparatus where operators are most likely to be working (see Figure 11.22).

Figure 11.22
Typical LV distribution system

11.5.4 Optimum philosophy

It is important to note that the choice of relay settings cannot be considered in isolation. They are influenced by the manner of neutral grounding, current pick-up levels and time grading intervals, which in turn will be dictated by the system configuration.

All are inter-dependent and in the following example, it will be seen that optimum philosophy for the system would be a definite time lag philosophy (DTL) as opposed to an inverse definite time lag philosophy (IDMTL) as faster clearance times can be achieved (see Figure 11.23).

Figure 11.23
Optimum philosophy


Mine underground distribution protection

12.1 General

A typical colliery underground network is shown in Figure 12.1. The protection required for the medium voltage (11 kV) network from the surface substation to the mobile transformer will require consideration of the trailing cable. However, this could be the standard protection that is followed in a normal industrial substation, taking care of short circuit and over current conditions.

However, it is important to pay particular attention to the protection of the low voltage ‘front-end electrics’–especially at the coalface where most activity takes place, increasing the possibility of electrical faults occurring.

In coal mining, the normal protection found in the flameproof gate-end boxes comprises:

  • Ground leakage protection
  • Pilot wire monitors (ground continuity monitors)
  • Ground fault lockout
  • NGRM (neutral grounding resistor monitors)

These features will now be discussed in detail on a point-by-point basis.

Figure 12.1
Typical colliery UG network

12.2 Ground leakage protection

Ground leakage protection is primarily employed to protect life. It must therefore detect and isolate faulty equipment as soon as possible to protect the rest of the system and to minimize fault damage.

Consequently, it needs to be as sensitive and as fast as possible. However, ultra-sensitivity and high speeds can lead to nuisance tripping, so a compromise is necessary. Generally, one only needs to consider protecting against indirect contact. This is considered justified, as only qualified persons should have access to live terminals, and equipment and interlocks should be designed accordingly (see Table 12.1).

Table 12.1
Ground-leakage protection

12.2.1 Sensitivities

The factors that influence relay sensitivities are:

  • Stray capacitance
  • Unsymmetrical mounting of core balance CTs
  • Motor starting in-rush currents
  • Transients:
    • - Switching surges/point-on-wave switching
    • - Lightning
    • - Voltage dips
    • - Harmonics (especially 3rd and 9th etc).

Unbalances can be caused by one or more combinations of the above. Relay sensitivities of 250 mA were found to be immune from the above whereas levels of 100 mA were susceptible so they had to be time delayed by 100 milliseconds to ride through the transient disturbances.

Using 250 mA instantaneous sensitivity, typical relay coordination for ground leakage protection is shown in Figure 12.2 and Table 12.2.

Figure 12.2
Typical ground leakage current sensitivities
Table 12.2
Ground-leakage sensitivities

12.2.2 Clearance times

Typical clearance times for South African equipment compared to UK equipment are shown in Table 12.3.

Table 12.3
Clearance times

The faster speeds are desirable, as they are much less than the ‘T’ phase resting period of the heart.

12.3 Pilot wire monitor

This is a very important and sophisticated relay as it carries out the following functions (see Figure 12.3):

  • Prevents on-load un-coupling of cable couplers
  • Ensures continuity and measures ground bond resistance
  • Detects pilot-to-ground short circuit
  • Permits remote start/stop of contactor using pilot
  • Unit has to be fail safe.
Figure 12.3
Pilot wire monitor (ground continuity monitor)

It is designed to meet very fine tolerances as shown in Figure 12.4.

Note: The contactor must be capable of following the relay under all of the above conditions.

Figure 12.4
Pilot wire monitor operating characteristics

As it is continuously monitoring the resistance of the ground bond to keep equipment within safe touch–potential limits, it can be considered as important, if not more so, than the ground leakage relay.

12.4 Ground fault lockout

As an additional safety measure, a ground fault lockout feature is installed, typically as shown in Figure 12.5. After the contactor has been tripped, a DC signal is injected onto the power conductor via the resistor bank to monitor the insulation. Closing is prevented if this drops below the pre-set value. As an example, this would ensure safety on start-up should a rock fall have occurred during the off-shift period.

Figure 12.5
Ground fault lockout

12.5 Neutral grounding resistor monitor (NGRM)

The final element in the protection system is this relay, which ensures the integrity of the neutral grounding resistor. If this latter device should open or short circuit, the NGRM will operate to either alarm on trip (see Figure 12.6).

Figure 12.6
NGR monitor

The problems experienced with solid grounding are as shown in Figure 12.7, namely:

  • High fault currents, only limited by inherent impedance of power system
  • Solid grounding means high ground-fault currents
  • This damages equipment extensively
  • This leads to long outage times – lost production, lost revenue
  • Heavy currents in ground bonding give rise to high touch potentials –dangerous to human life
  • Large fault currents are more hazardous in igniting gases (explosion hazard)
Figure 12.7

These can be overcome by introducing a ground barrier between the phases so that all faults become ground faults and then controlling the ground fault current levels by the neutral grounding resistor (see Figures 12.8—12.10 and Table 12.4).

Figure 12.8
  • Phase segregation eliminates phase-to-phase faults
  • Resistance grounding means low ground-fault currents
  • Fault damage minimal–reduces fire hazard
  • Lower outage times–less lost production, lost revenue
  • Touch potentials kept within safe limits–protects human life
  • Low ground-fault currents reduce possibility of igniting gases (explosion hazard)
  • No magnetic or thermal stresses imposed on major plan during fault
  • Transient overvoltages limited–prevents stressing of insulation, MCB re-strikes
Figure 12.9
Screened trailing cable
Figure 12.10
Table 12.4
Concerns over failures

Air ionizes to cause phase-to-phase flashover. Hence, phase segregation is achieved by insulation barriers, which are made of silicon rubber (see Figure 12.11).

Figure 12.11
Solution – rubber phase barrier

Proving tests

Fault energy formula = I2 × R × t
I = fault current
R = resistance of fault arc
t = time in seconds fault is on

Khutala fault throwing tests
Fault current = 4000 amps
Clearance time = 350 milliseconds
Assume arc resistance of 1 ohm
Fault energy = 4000 × 4000 × 1 × 0.35
   = 5.6 Mega Joules

If clearance time reduced to 100 m/s
Fault energy = 4000 × 4000 × 1 × 0.35
   = 1.6 Mega Joules

70% reduction
If steps could also be taken to reduce the level of fault current, then major strides would be made.

Fault location

In the mining industry, identification of a fault location is critical. The following sketches/ pictures show how couplers are useful in identifying a fault location (see Figures 12.12—12.14 and Tables 12.15—12.18).

Major problem

Figure 12.12
Great difficulty in locating ground faults
Figure 12.13
Fast fault location
Figure 12.14
Early warning alarm system
Table 12.5
Table 12.6
Table 12.7
Other factors
Table 12.8
Summary of recommendations


Principles of unit protection

13.1 Protective relay systems

The basic function of protection is to detect faults and to clear them as soon as possible. It is also important that in the process, the minimum possible amount of equipment is disconnected. The ability of the protection (i.e. relays and circuit breakers) to accomplish the latter requirement is referred to as ‘selectivity’.

Speed and selectivity may be considered technically as figures of merit for a protection scheme. In general, however greater the speed and/or selectivity, the greater is the cost. Hence, the degree of speed or selectivity in any scheme is not purely a technical matter; it is also an economic one.

13.2 Main or unit protection

The graded overcurrent systems described earlier do not meet the protection requirements of a power system. As seen in chapter 10, it is not possible to achieve grading in long and thin networks and grading of settings may lead to longer tripping times closer to the sources, which is not always desired. These problems have given way to the concept of ‘unit protection’ where the circuits are divided into discrete sections without reference to the other sections.

Ideally, to realize complete selectivity of protection, the power system is divided into discrete zones. Each zone is provided with relays and circuit breakers to allow for the detection and isolation of its own internal faults.

This ideal selective zoning is illustrated in Figure 13.1. The protection used in this manner – essentially for internal faults in a particular zone – is referred to as main or unit protection.

Figure 13.1
Overall schematic indicating busbar, feeder, transformer and motor protection

13.3 Back-up protection

It is necessary to provide additional protection to ensure isolation of the fault when the main protection fails to function correctly. This additional protection is referred to as ‘back-up’ protection. For example, referring to the above figure, assume that a fault has occurred on the feeder and that the breaker at A fails to open. To clear this fault, the circuits, which are able to feed current to the fault through the stuck breaker A must be opened. The fault is outside the zones of the main protection and can only be cleared by the separate back-up protection.

Back-up protection must be time delayed to allow for the selective isolation of the fault by the main or unit protection.

13.4 Methods of obtaining selectivity

The most positive and effective method of obtaining selectivity is the use of differential protection. For less important installations, selectivity may be obtained, at the expense of speed of operation, with time-graded protection.

The principle of unit protection was initially established by Merz and Price who were the creators of the fundamental differential protection scheme. These systems basically employ the direction of current rather than their actual values, protecting a particular zone by means of detecting the circulating currents through pilot wires and relays. The basic principles of these well known forms of protection will now be considered.

13.5 Differential protection

Differential protection, as its name implies, compares the currents entering and leaving the protected zone and operates when the differential between these currents exceeds a pre-determined magnitude.

This type of protection can be divided into two types, namely balanced current and balanced voltage.

13.5.1 Balanced circulating current system

The principle is shown in Figure 13.2.

Figure 13.2
Balanced circulating current system, external fault (stable)

The CTs are connected in series and the secondary current circulates between them.

The relay is connected across the mid-point, thus the voltage across the relay is theoretically nil. Therefore, no current flows through the relay; hence there is no operation for any faults outside the protected zone. Similarly, under normal conditions, the currents leaving zone A and B are equal, causing the relay to be inactive by the current balance.

Under internal fault conditions (i.e. between the CTs at end A and B) relay operates. This is basically due to the direction of current reversing at end B making the fault current to flow from B to A instead of the normal A to B condition in the earlier figure (see Figure 13.3).

Figure 13.3
Balanced circulating current system internal fault (operate)

The current transformers are assumed identical and are assumed to share the burden equally between the two ends. However, it is not always possible to have identical CTs and to have the relay at a location equidistant from the two end CTs. It is common practice to add a resistor in series with the relay to balance the unbalance created by the unequal nature of burden between the two end circuits. This resistor is named the ‘stabilizing resistance’.

13.5.2 Balanced voltage system

As the name implies, it is necessary to create a balanced voltage across the relays in end A and end B under healthy and out-of-zone fault conditions. In this arrangement, the CTs are connected to oppose each other (see Figure 13.4).

Figure 13.4
Balanced voltage system –external fault (stable)

Voltages produced by the secondary currents are equal and opposite, thus no currents flow in the pilots or relays, hence they are stable under through fault conditions.

Under internal fault conditions, relays will operate (see Figure 13.5).

Figure 13.5
Balanced voltage system, internal fault (operate)

The balanced or circulating current systems are invariably used for generator, transformer and switchgear main protection where it is convenient to readily access the midpoint of the pilots. This is because both sets of CTs are mounted in the same substation and a single relay is used to detect the fault condition within the protected zone.

On the other hand, balanced voltage systems are used mainly on feeder protection where the CTs are mounted in different substations, which are some distance apart. As there are two relays involved, one at each end, they can each be mounted in their respective substations.

Although similar, the various forms of differential protection differ considerably in detail. The differences are concerned with the precautions taken to ensure stability, i.e. to ensure that the protection does not operate incorrectly for a through fault.

13.5.3 Bias

The spill current in the differential relay due to the various sources of errors is dependent on the magnitude of the through current. Hence, it is necessary to consider the setting of the differential relay to be more than or proportional to the worst spill current likely to occur under through fault conditions. Because of the wide range of fault current magnitudes, it is not always satisfactory to make the relay insensitive to lower spill current values. This problem had been overcome by adjusting the operating level of the relay according to the total amount of fault current. This was done originally by providing a restraining winding or electromagnet which carried the total fault current while an operating electromagnet was allowed to carry only the differential current. This principle of bias is applied to circulating current protection to ensure proper operation under all fault conditions.

If the two zone boundary currents are I1 and I2, then;

Operating quantity: K1 (I1 – I2)

Biasing quantity: K2 (I1 + I2)

A suitable choice of constants K1 and K2 ensures stability for external fault currents despite measurement errors, while still ensuring stability under internal fault conditions.

13.5.4 Machine differential protection

The balanced circulating current principle is normally used. The bias feature is introduced to ensure stability despite possible small differences in the performance of the two nominally balanced sets of current transformers.

The sensitivity of this protection is normally in the order of 10%, which means that the protection will operate when the differential current is greater than 10% of the normal full load.

Without bias, for a through fault current of 10 times full load the protection would operate if the ‘spill’ or differential current exceeded 10% of full load or 1% of the through-fault current.

To avoid the necessity of matching current transformers to this degree of accuracy, the protection is biased with through current.

13.6 Transformer differential protection

A typical transformer differential protection system also adopts the circulating current principle. The first point to notice is that the CTs on one side are connected in delta whilst they are connected in star on the other. This has been done for two reasons:

  • To correct for the phase-shift through the transformer in order to obtain co-phasal currents at the relay
  • To prevent the relay from operating incorrectly for an external ground fault on the side of the power transformer where the windings are connected in star with the neutral grounded.

Through current bias is necessary on these relays not only for the inherent unbalances of the CTs but also to take care of any voltage tappings on the transformer provided by the tap-changer. For example:

A transformer with a nominal ratio of 132/40 kV and a tap change range of + 15% -5% on the 40 kV side would have CT ratios selected to be balanced at the mid-tap, namely 132/42 kV.

The above is discussed in more detail in Chapter 15.

13.7 Switchgear differential protection

In switchgear differential protection, all the currents entering and leaving the protected zone are added and if the result is zero, then the busbars are healthy. However, if the current exceeds the chosen setting, the protection will operate and trip all associated circuit breakers.

The stability of this type of protection is obviously of vital importance since an incorrect operation could result for example in the shutdown of a power station.

On account of the large number of circuits involved, all carrying different currents, stability is also a more difficult problem than with machine or transformer differential protection.

A number of different schemes are used for this protection, normally referred to as ‘Bus zone protection’. The schemes differ mainly in the principle adopted to obtain stability and these are discussed in detail in Chapter 16.

13.8 Feeder pilot-wire protection

Pilot-wire protection is similar to differential protection in that it normally compares the current entering the circuit at the one end with the current leaving at the other end.

Its field of application is the protection of power cables and short transmission lines. For these circuits the distance between the current transformers at the two ends of the protected zone is too great for the circulating current differential protection of the type described previously for machines and transformers etc.

The pilot-wire provides the communicating channel for conveying the information relative to conditions at the one end of the feeder to protective relays at the other end of the feeder and vice versa. These relays or groups of relays, at the two ends are able to make a comparison between local and remote conditions and thus determine if there is an internal fault. Each relay normally trips only its associated circuit breaker.

There are many different types of pilot wire protection schemes, but the most commonly used are of the opposing voltage type, an example of which is illustrated in Chapter 14.

13.9 Time taken to clear faults

With the inherently selective forms of protection, apart from ensuring that the relays do not operate incorrectly due to initial transients, no time delay is necessary. Operating times for the protection, excluding the breaker tripping / clearing time, are generally of the following order:

Machine differential - Few cycles

Transformer differential - 10 cycles

Switchgear (busbar) differential - 4 cycles

Feeder differential - Few cycles

These operating times are practically independent of the magnitude of fault current.

13.10 Recommended unit protection systems

  • Cable feeders - Pilot wire differential
  • Transformer - HV balanced (restricted) ground fault
    • - HV high set instantaneous overcurrent
      (low transient overreach)
    • - LV restricted ground fault
    • - Buchholz
  • Busbars - Medium/low impedance schemes for strategic busbars (including busbars operating on closed rings)
    • - Busbar blocking schemes for radial networks
  • Unit protection - Should be used where possible throughout the network to remove the inverse time. Relays (IDMT) from the front line
  • IDMT - Must be retained as back-up only to cover for a failure of the main protection

13.11 Advantages of unit protection

13.11.1 Fast and selective

Unit protection is fast and selective. It will only trip the faulty item of the plant, thereby ensuring the elimination of any network disruptions.

13.11.2 Easy to set

Unit protection is easy to set and, once installed, very rarely requires changing, as it is independent of whatever happens elsewhere on the system.

13.11.3 No time constraints

Time constraints imposed by the supply authorities do not become a major problem anymore. They only need consideration when setting up the back-up inverse time (IDMT).

13.11.4 Maximum operating flexibility

The system can be operated in any switching configuration without fear of a loss of discrimination.

13.11.5 Better continuity of supply

In many applications rings can be run closed, so that switching would not be necessary to restore loads, resulting in better continuity of supply.

13.11.6 Future expansion relatively easy

Any future expansion that may require another in-feed point can be handled with relative ease without any change to the existing protection.


Feeder protection for cable feeders and overhead lines

14.1 Introduction

Two commercially available systems have been chosen as typical examples to illustrate the concepts. However, there are other similar products on the market using essentially the same technology.

14.2 Translay (see Figure 14.1)

Figure 14.1
Simplified connections illustrating principles of operation

14.2.1 Translay is a voltage balance system

Whilst the feeder is healthy, the line CTs at each end carry equal currents. Equal and opposite voltages are induced in the secondary windings 12 and 12a and no current flows in the pilots. No magnetic flux is set up in the bottom magnets 16 and 16a so the relays do not operate. Under heavy through-fault conditions there may be a small circulating current due to line CT mismatch. A restraint torque is produced by bias loop 18, which also stabilizes the relay against pilot capacitance currents. A fault fed from one end causes current to circulate in the pilots and the relay at that end will operate to trip. A fault fed from both ends will cause a current reversal in the remote CTs, making the circulating current additive so that both ends operate to trip.

14.3 Solkor protection

Solkor unit protection is used where solid metallic pilot wires are available. The system is a differential protection system and is available as Solkor R/Rf. Optional equipment includes pilot wire supervision and injection intertripping systems.

Solkor protection can be configured in two modes. The R mode caters for systems where pilot/ground insulation levels are 5 kV or less. The Rf mode is used in newer systems with either 5 kV or 15 kV insulation. Solkor Rf gives faster clearance times for internal faults whilst its stability for through faults is the same high value as Solkor R.

The standard relay has a pilot circuit to ground withstand of 5 kV and interposing transformers are available to cater for circumstances when a 15 kV pilot insulation level is required. Solkor equipment will trip both ends of a faulty feeder even if current is fed from one end only. Solkor R/Rf relays are designed to use telephone type pilot cables with a loop resistance of up to 2000 ohms and a maximum capacitance between cores of 2.5 uF.

The relays incorporate diodes, which act as switches and permit the use of a single pilot loop for two-way signaling using a system of time sharing switched at the power frequency (see Figures 14.2—14.6).

Figure 14.2
Basic circuit of Solkor-R protection system
Figure 14.3
Schematic diagram of complete 5 kV Solkor –R protective system
Figure 14.4
Behaviour of basic circuit under external-fault conditions when Ra = Rp
(a) and (b) show the effective circuit during successive half-cycles; (c) indicates the voltages across relaying points X and Y during one cycle
Figure 14.5
Behavior of basic circuit under external-fault conditions when Ra = Rp and; (b) show the effective circuit during successive half-cycles; (c) indicates the voltages across relaying points X and Y during one cycle
Figure 14.6
Behavior of basic circuit under internal-fault conditions (fault fed from both ends (a) and (b) show effective circuits during successive half cycle)

Normally, only two pilot wires are used for interconnecting the relays at the two ends of the feeder. For this reason, summation transformers are incorporated in the protection (see Figure 14.7).

Figure 14.7
Schematic diagram, table of characteristics and vectoral demonstration of summation transformer

Because of the summation transformer the sensitivity of the protection is dependent upon phases that are involved in short-circuit. Typical figures for sensitivity are as follows:

Type of fault Sensitivity (%)
Red to ground 25%
White to ground 32%
Blue to ground 42%
Red to white 125%
White to blue 125%
Blue to red 62%
Three-phase 72%

14.4 Distance protection

14.4.1 Basic principle

A distance relay, as its name implies, has the ability to detect a fault within a pre-set distance along a transmission line or power cable from its location.

Every power line has a resistance and reactive per kilometre related to its design and construction so its total impedance will be a function of its length or distance.

A distance relay therefore looks at current and voltage and compares these two quantities on the basis of Ohm’s law (see Figure 14.8).

Figure 14.8
Basic principle of operation

The concept can best be appreciated by looking at the pioneer-type balanced beam relay (see Figure 14.9).

Figure 14.9
Balanced beam principle

The voltage is fed onto one coil to provide restraining torque, whilst the current is fed to the other coil to provide the operating torque.

Under healthy conditions, the voltage will be high (i.e. at full rated level), whilst the current will be low (at normal load value), thereby balancing the beam and restraining it so that the contacts remain open. Under fault conditions, the voltage collapses and the current increase dramatically, causing the beam to unbalance and close the contacts.

By changing the ampere-turns relationship of the current coil to the voltage coil, the ohmic reach of the relay can be adjusted. A more modern technique for achieving the same result is to use a bridge comparator (see Figure 14.10).

Figure 14.10
Bridge comparator

14.4.2 Tripping characteristics

If the relay’s operating boundary is plotted on an R/X diagram, its impedance characteristic is a circle with its centre at the origin of the co-ordinates and its radius will be the setting (reach) in ohms.

The relay will operate for all values less than its setting, i.e. for all points within the circle.

Figure 14.11
Plain impedance characteristic

This is known as a plain impedance relay and it will be noted that it is non-directional, in that it can operate for faults behind the relaying point. It disregards the phase angle between voltage and current.

This limitation can be overcome by a technique known as self-polarization. Additional voltages are fed into the comparator in order to compare the relative phase angles of voltage and current, so providing a directional feature. This has the effect of moving the circle such that the circumference of the circle now passes through the origin. Angle θ is known as the relay’s characteristic angle (see Figure 14.12).

Figure 14.12
MHO characteristic

This is known as the MHO relay, so called because it appears as a straight line on an admittance diagram.

By the use of a further technique of feeding voltages from the healthy phases into the comparator (known as cross polarization) a reverse movement or offset of the characteristic can be obtained (see Figure 14.13).

Figure 14.13
Offset MHO characteristic

This is called the Offset MHO characteristic.

14.4.3 Application onto a power line

Correct co-ordination of the distance relays is achieved by having an instantaneous directional zone 1 protection and one or two more time delayed zones. A transmission line has a resistance and reactance proportional to its length, which also defines its own characteristic angle. It can therefore be represented on an R/X diagram as shown below.

Zone 1
The relay characteristic has also been added, from which it will be noted that the reach of the measuring element has been set at approximately 80% of the line length (see Figure 14.14)

Figure 14.14
Zone 1 MHO characteristic

This ‘under-reach’ setting has been purposely chosen to avoid over-reaching into the next line section to ensure sound selectivity, for the following reasons:

  • It is not practical to accurately measure the impedance of a transmission line, which could be very long (say 100 km). Survey lengths are normally used and these could have errors up to 10%.
  • Errors are also present in the current and voltage transformers, not to mention the possible transient performance of these items.
  • Manufacturing tolerances on the relay’s ability to measure accurately etc.

This measuring element is known as zone 1 of the distance relay and is instantaneous in operation.

Zone 2
To cover the remaining 20% of the line length, a second measuring element can be fitted, set to over-reach the line, but it must be time delayed by 0.5 seconds to provide the necessary co-ordination with the downstream relay. This measuring element is known as zone 2. It not only covers the remaining 20% of the line, but also provides backup for the next line section should this fail to trip for whatever reason.

Zone 3
A third zone is invariably added as a starter element and this takes the form of an offset MHO characteristic. This offset provides a closing-onto-fault feature, as the MHO elements may not operate for this condition due to the complete collapse of voltage for the nearby fault. The short backward reach also provides local backup for a busbar fault.

This element can also be used for starting a carrier signal to the other end of the line–see later section.

The zone 3 element also has another very useful function. As a starter it can be used to switch the zone 1 element to zone 2 reach after say 0.5 seconds, thereby saving the installation of a second independent zone 2 measuring element and reducing costs (see Figure 14.15).

Figure 14.15
3 zone MHO characteristics

14.4.4 Effect of load current

Load current can also be expressed as impedance, again by the simple application of Ohm’s law. This can be shown on the R/X diagram as depicted by the shaded area, the angular limits being governed by the power factor of the load.

It is important when setting a distance relay, especially zone 3, which has the longest reach, that its characteristic does not encroach on the load area, as unnecessary tripping will undoubtedly occur (see Figure 14.16).

Figure 14.16
Load encroachment

14.4.5 Effect of arc resistance

Resistance of the fault arc can also have an impact on the performance of a distance relay, as can be seen on the following R/X diagram (see Figure 14.17).

Figure 14.17
Effect of arc resistance

It will be noted that the resistance of the fault arc takes the fault impedance outside the relay’s tripping characteristic, so that it does not detect this condition. Alternatively, it is only picked up by either zone 2 or zone 3, in which case tripping will be unacceptably delayed.

The effect of arc resistance is most significant on short lines where the reach of the relay setting is small. It can be a problem if the fault occurs near the end of the reach. High fault-arc resistances tend to occur during mid-span flashovers to ground during a veldt fire or on transmission lines carried on wood poles without ground wires.

These problems can usually be overcome by using relays with different shaped characteristics as described below.

14.4.6 Different shaped characteristics

To overcome the problems of load encroachment and arc resistance, distance relays have been developed with different shaped tripping characteristics, some examples of which are as follows:

  • Circular (as illustrated above)
  • Lenticular
  • Figure of eight
  • Trapezoidal

With the advent of modern digital technology, many shapes are now possible to suit a variety of applications (see Figure 14.18 (a)—(c)).

Figure 14.18 (a)
Lenticular characteristic
Figure 14.18 (b)
Figure-of-eight characteristic
Figure 14.18 (c)
Trapezoidal characteristic

14.4.8 Distance protection schemes

Because of its various zones, distance protection is strictly speaking not a pure form of unit protection. However, with the addition of an information link between the two ends of the line, it can be made into a very effective unit protection system.

The normal method of achieving this is to install a power line carrier signaling channel between the two ends. The signal is injected into the power line conductors at one end via a capacitor voltage transformer and picked off the other end by a similar device. Line traps are installed at either end to prevent the signal dispersing through all other lines, etc., in the network. Other types of communication media can be used, such as copper or fiber-optic pilots; microwave radio could be considered if line-of-sight is available.

Conventional distance scheme
When carrier or signaling equipment is not available, the conventional distance scheme illustrated in Figure 14.19 (a)--(c) is used; however, faults in the end 20% of the line will only be cleared in zone 2 time, namely 0.5 seconds.

Figure 14.19 (a)
Stepping time/distance characteristics
Figure 14.19 (b)
Trip circuit (contact logic)
Figure 14.19 (c)
Trip circuit (solid state logic)

Zone 1 extension or overlap
Fast tripping for these portions can be achieved by extending the reach of zone 1 to 120% of the line and cutting it back to 80% reach after tripping before auto-closing the breaker. The logic is shown in Figures 14.20 (a)--(c).

Figure 14.20 (a)
Distance/time characteristics
Figure 14.20 (b)
Trip circuit (contact logic)
Figure 14.20 (c)
Simplified solid state logic

Direct transfer trip (under-reaching scheme)
When carrier / signaling is available, the simplest way to speed up fault clearance at the terminal which clears an end-zone fault in zone 2 time is to adopt a direct transfer trip or intertrip technique as shown in Figures 14.21 (a)--(c). A zone 1 contact is used to send a carrier signal to the remote end to directly trip that breaker via a receive relay.

The disadvantage of this scheme is the possibility of undesired tripping by accidental or malfunction of the signaling equipment.

Figure 14.21 (a)
Trip circuit contact logic
Figure 14.21 (b)
Signaling channel send arrangement (contact logic)
Figure 14.21 (c)
Simplified solid state logic

Permissive under-reach scheme
The direct transfer trip scheme is made more secure by monitoring the received signal with an instantaneous zone 2 operation before allowing tripping, as shown in Figure 14.22 (a)--(c).

Time delayed resetting of the ‘signal received’ element is required to ensure that the relays at both ends have time to trip when the fault is close to one end. When the breaker at one end is open, instantaneous clearance cannot be achieved for end-zone faults near the breaker open terminal.

Figure 14.22 (a)
Trip circuit (contact logic)
Figure 14.22 (b)
Signaling send arrangement (contact logic)
Figure 14.22 (c)
Simplified solid-state logic

Acceleration scheme
This scheme is similar to the permissive under-reach scheme in its principle of operation, but is applicable only to zone switched distance relays, which share the same measuring elements for zones 1 and 2.

In this scheme, the incoming carrier signal switches the zone 1 reach to zone 2 immediately without waiting for the zone 2 timer (0.5 secs) to switch the reach. This accelerates the fault clearance at the remote end. The scheme is shown in Figure 14.23 (a)--(d).

The longer reach of the measuring elements gives better arc resistance coverage so it is better suited to short lines. This scheme is sometimes referred to as a ‘directional comparison’ scheme.

Figure 14.23 (a)
Distance/time characteristics
Figure 14.23 (b)
Trip circuit (contact logic)
Figure 14.23 (c)
Signaling channel send arrangement (contact logic)
Figure 14.23 (d)
Simplified solid-state logic

Permissive over-reach scheme
In this scheme, a measuring element at end A is set to over-reach beyond the far end of the protected line, typically 120% or more.

The same scheme is installed at end B of the line, looking towards end A.

This element sends an intertrip signal to the remote end. It is set to trip its own breaker immediately a signal is received. If no signal is received, it will trip its own breaker after zone 2 time (0.5 sec).

The longer reach of the measuring elements gives better arc resistance coverage so it is better suited to short lines. This scheme is sometimes referred to as a ‘directional comparison’ scheme (see Figure 14.24 (a)—(c)).

Figure 14.24 (a)
Trip circuit (contact logic)
Figure 14.24 (b)
Signaling send arrangement (contact logic)
Figure 14.24 (c)
Simplified solid-state logic

Blocking scheme
The schemes described above use a signaling channel to transmit a tripping instruction, normally through the fault.

A blocking scheme uses inverse logic, the signal preventing tripping. Signaling is initiated only for external faults and takes place over healthy line sections. Fast fault clearance occurs when no signal is received and the over-reaching zone 2 measuring elements looking into the line operate.

The signaling channel is keyed by a reverse-looking distance element (zone 3). An ideal blocking scheme is shown in Figure 14.25 (a)--(d).

Figure 14.25 (a)
Distance/time characteristics
Figure 14.25 (b)
Trip circuit (contact logic)
Figure 14.25 (c)
Signaling channel send arrangement (contact logic)
Figure 14.25 (d)
Simplified solid-state logic

14.5 Line Differential Protection

The basic principle of the differential protection assumes that all currents flowing into a healthy protected section add up to zero. If the current transformer sets at the line ends have different transformation errors in the overcurrent range, the total of the secondary currents can reach considerable peaks when a short-circuit current flows through the line. These peaks may feign an internal fault.

Recognition of short-circuits in the protection zone only with the measured currents is the basic function of the differential protection. Also high resistive faults with small currents can be recognized. Even complex multiphase faults are precisely detected, as the measured values are evaluated phase segregated. The protection system is restraint against inrush currents of power transformers in the protection zone. When switching onto a fault at any point of a line, an undelayed trip signal can be emitted.

The differential protection represents the first main protection function of the device. It is based on current comparison. For this, one device must be installed at each end of the zone to be protected. The devices exchange their measured quantities via communications links and compare the received currents with their own. In case of an internal fault the allocated circuit breaker is tripped.

A major advantage of the differential protection principle is the instantaneous tripping in the event of a short-circuit at any point within the entire protected zone. The current transformers limit the protected zone at the ends towards the remaining system. This rigid limit is the reason why the differential protection scheme shows such an ideal selectivity.

For this discussion of differential protection, a SIPROTEC relay is taken as the example. However, the basic functionality will remain the same for all relays providing this function.

14.5.1 Basic principle with two ends

Differential protection is based on current comparison. It makes use of the fact that e.g. a line section L (Figure 14.26) carries always the same current i(dotted line) at its two ends in healthy operation. This current flows into one side of the considered zone and leaves it again on the other side. A difference in current is a clear indication of a fault within this line section. If the actual current transformation ratios are the same, the secondary windings of the current transformers CT1and CT2at the line ends can be connected to form a closed electric circuit with a secondary current I; a measuring element Mwhich is connected to the electrical balance point remains at zero current in healthy operation. When a fault occurs in the zone limited by the transformers, a current i1 + i2 which is proportional to the fault currents I1 + I2 flowing in from both sides is fed to the measuring element. As a result, the simple circuit shown in Figure 14.26 ensures a reliable tripping of the protection if the fault current flowing into the protected zone during a fault is high enough for the measuring element Mto respond.

Figure 14.26
Basic principle of the differential protection for a line with two ends

14.5.2 Basic principle with multiple ends

For lines with three or more ends or for busbars, the principle of differential protection is extended in that the total sum of all currents flowing into the protected object is zero in healthy operation, whereas in case of a fault the total sum is equal to the fault current (see Figure 14-27 as an example for four ends).

Figure 14.27
Basic principle of differential protection for four ends (single-phase)

14.5.3 Transmission of measured values

If the entire protected object is located in one place — as is the case with generators, transformers, busbars, the measured quantities can be processed immediately. This is different for lines where the protected zone spans a certain distance from one substation to the other. To be able to process the measured quantities of all line ends at each line end, these have to be transmitted in a suitable form. In this way, the tripping condition at each line end can be checked and the respective local circuit breaker can be operated if necessary. The relay can transmit the measured quantities as digital telegrams via communication channels. For this, each device is equipped with at least one protection data interface. Figure 14.28 shows this for a line with two ends. Each device measures the local current and sends the information on its intensity and phase relation to the opposite end. The interface for this communication between protection devices is called protection data interface. As a result, the currents can be added up and processed in each device.

Figure 14.28
Differential protection for a line with two ends

In case of more than two ends, a communication chain is built up by which each device is informed about the total sum of the currents flowing into the protected object. Figure 14.29 shows an example for three ends. Ends 1 and 2 are derived from the arrangements of the current transformers shown on the left. Although this is actually only one line end, it should be treated in terms of differential protection as two ends because the current is measured in two places. Line end 3 is situated on the opposite side. Each device receives its local currents from the current transformers. Device 1 measures the current i1 and transmits its data as a complex phasor I1 to device 2. This device adds the share I2 from its own measured current i2 and sends this partial sum to device 3. The partial sum I1 + I2 finally reaches device 3 which then adds its share I3. Vice versa, a corresponding chain leads from device 3 via device 2 to device 1. In this way, the total sum of the three currents measured at the measuring points is available to all three devices. The sequence of the devices in the communication chain need not correspond to the indexation, as shown in Figure 14.29.

Figure 14.29
Differential protection for a line with three ends

The communication chain can also be connected to a ring, as shown in dashed lines in Figure 14.29. This provides for redundancy of transmission: even if one communication link fails, the entire differential protection system will be fully operational. The devices detect communication failures and switch automatically to another communication channel. It is also possible to switch off one line end, e.g. for a check or a revision, and put the local protection out of operation. With a communication ring, the rest of the operation can proceed without disturbances.

14.5.4 Measured value synchronisation

The devices measure the local currents in an asynchronous way. This means that each device measures, digitizes and pre-processes the associated currents of the current transformers with its own, random processor pulse. If the currents of two or more line ends are to be compared, it is necessary, however, to process all currents with the same time base.

All devices which belong together exchange their time with each telegram. The device with index 1 functions as a “timing master” thus determining the time base. The other devices then calculate the time delay from the transmission and processing times related on the “timing master”. With this “rough synchronization” the equality of the time bases with a precision of ± 0.5 ms is provided.

To reach a sufficiently precise synchronization all current values are marked with a “time stamp” before they are transmitted from one device to the other as digital telegrams. This time stamp indicates at which point in time the transmitted current data were valid. Therefore, the receiving devices can carry out an optimized synchronization of the current comparisons based on the received time stamp and their own time management, i.e. they can compare the currents which were actually measured at exactly the same time (<5 μ s tolerance).

The transmission periods are permanently monitored by the devices using the time data stamps and considered at the respective receiving end. The frequency of the measured quantities, which is decisive for the comparison of complex phasors, is also continuously measured and with the calculation, if necessary, corrected to achieve a synchronous comparison of the phasors. If the device is connected to voltage transformers and at least one voltage of a sufficient level is available, the frequency is derived from this voltage. If not, the measured currents are used for the determination of the frequency. The measured frequencies are interchanged between the devices via the communication link. Under these conditions all devices work with the currently valid frequency.

14.5.5 Restraint

The precondition for the basic principle of the differential protection is that the total sum of all currents flowing into the protected object is zero in healthy operation. This precondition is only valid for the primary system and even there only if shunt currents of a kind produced by line capacitances or magnetizing currents of transformers and reactors can be neglected. The secondary currents which are applied to the devices via the current transformers, are subject to measuring errors caused by the response characteristic of the current transformers and the input circuits of the devices. Transmission errors such as signal jitters can also cause deviations of the measured quantities. As a result of all these influences, the total sum of all currents processed in the devices in healthy operation is not exactly zero. Therefore, the differential protection is restrained against these influences.

14.5.6 Charging current compensation

Charging current compensation is an ancillary function for the differential protection. It allows achieving a higher sensitivity by partially compensating the charging currents caused by the capacitances of the overhead line or cable. Charging currents flow through the capacitance of the line. Due to the phase-to-earth and phase-to-phase capacitances, charging currents are flowing even in healthy operation and cause a difference of currents at the ends of the protected zone. Especially when cables and long lines have to be protected, the capacitive charging currents can reach considerable magnitude. If the feeder-side transformer voltages are connected to the devices, the influence of the capacitive charging currents can be compensated to a large extent arithmetically. It is possible to activate a charging current compensation which determines the actual charging current. With two line ends, each device takes over half of the charging current compensation, with M devices each device takes the Mth part. For more simplicity, Figure 14.30 shows a single-phase system.

Figure 14. 30
Charging current compensation for a line with two ends (single-phase)

In healthy operation charging currents can be considered as being almost constant under steady-state conditions, since they are only determined by the voltage and the capacitances of the lines. Without charging current compensation, they must therefore be taken into account when setting the sensitivity of the differential protection. With charging current compensation, no charging currents need to be taken into account here. With charging current compensation, the steady-state magnetizing currents across shunt reactance are taken into account as well. The devices have a separate inrush restraint feature for transient inrush currents (see below under the margin heading “Inrush Restraint”).

14.5.7 Current transformer errors

To consider the influences of current transformer errors, each device calculates a self restraining quantity Ierror. This is calculated by estimating the possible local transformer errors from the data of the local current transformers and the intensity of the locally measured currents (see Figure 14.31). The current transformer data have been parameterized in the power system data and apply to each individual device. Since each device transmits its estimated errors to the other devices, each device is capable to form the total sum of possible errors; this sum is used for restraint.

Figure 14.31
Approximation of the current transformer errors

14.5.8 Further influences

Further measuring errors which may arise in the actual device by hardware tolerances, calculation tolerances, deviations in time or due to the “quality” of the measured quantities such as harmonics and deviations in frequency are also estimated by the device and automatically increase the local self-restraining quantity. Here, the permissible variations in the data transmission and processing periods are also considered. Deviations in time are caused by residual errors during the synchronization of measured quantities, data transmission and operating time variations, and similar events. When GPS synchronization is used, these influences are eliminated and do not increase the self-restraining quantity.

If an influencing parameter cannot be determined — e.g. the frequency if no sufficient measured quantities are available — the device will assume nominal values by definition. In this example, it means that if the frequency cannot be determined because no sufficient measured quantities are available, the device will assume nominal frequency. But since the actual frequency can deviate from the nominal frequency within the permissible range (± 20% of the nominal frequency), the restraint will be increased automatically. As soon as the frequency has been determined (max. 100 ms after reappearance of a suitable measured quantity), the restraint will be decreased correspondingly. This is important during operation if no measured quantities exist in the protected area before a fault occurs, e.g. if a line with the voltage transformers on the line side is switched onto a fault. Since the frequency is not yet known at this time, an increased restraint will be active until the actual frequency is determined. This may delay the tripping, but only close to the pickup threshold, i.e. in case of very low-current faults.

The self-restraining quantities are calculated in each device from the total sum of the possible deviations and transmitted to the other devices. In the same way as the local currents (differential currents) are calculated, each device calculates the total sum of the restraining quantities. It is due to the self-restraint that the differential protection always operates with the maximum possible sensitivity since the restraining quantities automatically adapt to the maximum possible errors. In this way, also high-resistance faults, with high load currents at the same time, can be detected effectively. Using GPS synchronisation, the self-restraint when using communication networks is once more minimised since differences in the transmission times are compensated automatically. A maximum sensitivity of the differential protection consists of an optical-fiber connection.

14.5.9 Inrush restraint

If the protected area includes a power transformer, a high inrush current can be expected when connecting the transformer. This inrush current flows into the protected zone but does not leave it again. The inrush current can amount to a multiple of the rated current and is characterised by a considerable 2nd harmonic content (double rated frequency) which is practically absent during a short-circuit. If the second harmonic content in the differential current exceeds a selectable threshold, tripping is blocked. The inrush restraint has an upper limit: if a certain (adjustable) current value is exceeded, it will not be effective any more, since there must be an internal current-intensive short-circuit. Figure 14.32 shows a simplified logic diagram. The condition for the inrush restraint is examined in each device in which this function has been activated. The blocking condition is transmitted to all devices so that it is effective at all ends of the protected object.

Figure 14.32
Logic diagram of the inrush restraint for one phase

Since the inrush restraint operates individually for each phase, the protection is fully operative when the transformer is switched onto a single-phase fault, whereby an inrush current may possibly flow through one of the undisturbed phases. It is, however, also possible to set the protection in such a way that when the permissible harmonic content in the current of only one single phase is exceeded, not only the phase with the inrush current but also the remaining phases of the differential stage are blocked. This cross-block function can be limited to a selectable duration. Figure 14.33 shows the logic diagram.

The cross-block function also affects all devices since it not only extends the inrush restraint to all three phases but also sends it to the other devices via the communication link.

Figure 14.33
Logic diagram of the cross block function for one end

14.5.9 Evaluation of the measured quantities

The evaluation of measured values is performed separately for each phase. Additionally, the residual current is evaluated. Each device calculates a differential current from the total of the current phasors that were formed at each end of the protected zone and transmitted to the other ends. The differential current value is equal to the value of the fault current that is registered (“seen”) by the differential protection system. In the ideal case it is equal to the fault current value. In a healthy system the differential current value is low and, in a first approximation, equal to the charging current. With charging current compensation it is very low.

The restraining current counteracts the differential current. It is the total of the maximum measured errors at the ends of the protected object and is calculated from the current measured quantities and power system parameters that were set. Therefore the highest possible error value of the current transformers within the nominal range and/or the short-circuit current range is multiplied with the current flowing through each end of the protected object. The total value, including the measured internal errors, is then transmitted to the other ends. This is the reason why the restraining current is always an image of the greatest possible measurement error of the differential protection system.

The pickup characteristic of the differential protection (Figure 14.34) derives from the restraining characteristic Idiff = Irest (45°-curve), that is cut below the setting value IDIFF>. It complies with the formula

Irest = I-DIFF>+ Σ (errors by CT´s and other measuring errors)

If the calculated differential current exceeds the pickup limit and the greatest possible measurement error, the fault must be internal (shaded area in Figure 14.34).

Figure 14.34
Differential protection pickup characteristics, Idiff > stage

If not only an internal fault is to cause a TRIP command, but if a local current of a specific quantity is to exist additionally, the value of this current can be set at address 1219 I> RELEASE DIFF. Zero is preset for this parameter so that this additional criterion does not become effective.

14.5.10 High-speed charge comparison

The charge comparison protection function is a differential protection stage which is superimposed on the current comparison (the actual differential protection). If a highcurrent fault occurs, high-speed tripping decision is then possible. The charge comparison protection function does not sum up the complex current phasors at the ends of the protected object, but the integral of currents calculated according to the following formula:

It includes the integration interval of t1 to t2, which is selected in the 7SD5 device to period 1/4. The calculated charge Q is a scalar value which is faster to determine and to transmit than a complex phasor. The charges of all ends of the protected object are added in the same way as done with the current phasors of the differential protection. Thus the total of the charges is available at all ends of the protected zone.

Right after a fault occurrence within the protected zone a charge difference emerges. For high fault currents which can lead to saturation of current transformers, a decision is taken before the saturation begins.

The charge difference of external faults is theoretically equal to zero at the beginning. The charge comparison protection function immediately detects the external fault and blocks its own function. If saturation begins in one or more current transformers which limit the protected zone, the before-mentioned function remains blocked. Thus possible differences resulting from the saturation are excluded. Generally it is assumed that least one integration interval (1/4 cycle) that commenced with the occurrence of a fault.

When the power line is switched on, the pickup value of the charge comparison is automatically redoubled for a period of approximately 1.5 s. This is to prevent from malfunction caused by transient current in the CT secondary circuit due to remanence of the CTs (e.g. during auto-reclosure). This current would simulate a charge value which is not found in the primary quantities.

Each phase is subject to the charge comparison. Therefore an internal fault (sequential fault) in a different phase after the external fault occurred is detected immediately. The functional limitation of the charge comparison is reached in the less probable case that an internal fault (sequential fault) appears after the occurrence of an external fault with considerable current transformer saturation in the same phase. This must be detected by the current comparison stage in the differential protection.

Furthermore the charge comparison is influenced by charge currents from lines and shunt currents from transformers (steady-state and transient) that also cause a charge difference. Therefore the charge comparison is, as aforesaid, a function suited to complete the differential protection ensuring a fast tripping for high-current short-circuits. Normally, the charge comparison is set higher than the nominal current. For charge comparison, it is irrelevant whether the charging current compensation is activated or not.

14.5.11 Blocking / interblocking

The distance protection, provided that it is available and configured, automatically takes over as protection function if the differential protection is blocked by a binary input signal. The blocking at one end of a protected object affects all ends via the communications link (interblocking). If the distance protection is not available or ineffective, and if overcurrent protection has been configured as emergency function, all devices automatically switch to emergency mode.

Please keep in mind that the differential protection is phase-selectively blocked at all ends when a wire break is detected at one end of the protected object. The message “Wire break” appears only on the device in which the wire break has been detected. All other devices show the phase-selective blocking of the differential protection by displaying dashes instead of the differential and restraint current for the failed phase. In the case of a phase-selective blocking of the differential protection due to wire break, the distance protection, even if it is available and configured, does not take over the protection function for the failed phase.

14.5.12 Tripping logic of the differential protection

The tripping logic of the differential protection combines all decisions of the differential stages and forms output signals which are also influenced by the central tripping logic of the entire device (Figure 14.35). The pickup signals that identify the concerned stages of the differential protection stages can be delayed via the time stage T-DELAY I-DIFF>. Independently of this condition, a single-phase pickup can be blocked for a short time in order to bridge the transient oscillations on occurrence of a single earth fault in a resonant-earthed system.

The output signals generated by the stages are combined to the output signals “Diff. Gen. TRIP”, “Diff TRIP 1p L1”, “Diff TRIP 1p L2”, “Diff TRIP 1p L3”, “Diff TRIP L123” in the tripping logic. The single-pole information implies that tripping will take place single-pole only. The actual generation of the commands for the tripping (output) relay is executed within the tripping logic of the entire device.

Figure 14.35
Tripping logic of the differential protection


Transformer protection

15.1 Winding polarity

A transformer consists of two windings, namely primary and secondary, coupled to a common magnetic core. International standards define the polarity of the primary and secondary windings sharing the same magnetic circuit as follows:

If the core flux induces an instantaneous e.m.f., from a low number terminal to a high number terminal in one winding, then the direction of induced e.m.f. in all other windings linked by that flux will also be from a low number terminal to a high number terminal. In the following sketch the induced e.m.f on primary winding Ep is from A1 to A2 in the A phase when a primary voltage V is applied across A as shown.

The secondary e.m.f Es is also from a1 to a2 in the secondary a phase (see Figure 15.1).

Figure 15.1
Principle of operation of a transformer

From the laws of induction, it can be seen that the current flow in the windings is in the opposite direction.

15.2 Transformer connections

Transformer windings can be connected either in a star (Y) or delta (D) configuration; bearing in mind that each phase will be displaced 120° from the other.

Figure 15.2 and Figure 15.3 show the three windings of a three-phase core type transformer. This shows the primary connected in delta while the secondary windings are connected in star. The vectorial representation of primary and secondary voltages are also indicated.

Figure 15.2
Physical connection of delta (D) or star (Y) configuration
Figure 15.3
Vectorial representation of delta and star configuration

Depending on the method chosen for the primary and the secondary, a phase-shift can take place between the corresponding phases in the primary and secondary voltages of a transformer (see Figure 15.4).

Figure 15.4
Phase shift of transformer

Clock face numbers are used to represent phase shifts, the highest voltage winding being used as the reference. 360° shift corresponds to a full 12 hours of a clock with each 30° shift being represented by 1 hour. For example, 30° corresponds to 1 o’clock position, 150° shift corresponds to 5 o’clock position and 330 (or –30)° shift corresponds to 11 o’clock position.

The vector grouping and phase shift can then be expressed using a simple code. The primary winding connection is represented by capital letter while small letter represents the secondary connection. The ‘N’ means the primary neutral has been brought out.

For example:

YNd1= Primary winding connected in star with neutral brought out.
  Secondary winding connected in delta.
  Phase shift of secondary 30° from 12 to 1 o’clock compared to primary phase angle.

A knowledge of the primary connections and polarities of the windings enables connections of the CT secondary leads to be correctly determined, which is very important for sensing the fault currents, the basic need for correct protection.

15.3 Transformer magnetising characteristics

When a transformer is energized, it follows the classic magnetization curve given in Figure 15.5.

Figure 15.5
Transformer magnetizing characteristics

For efficiency reasons, transformers are generally operated near to the ‘knee-point’ of the magnetic characteristic. Any increase above the rated terminal voltage tends to cause core saturation and therefore demands an excessive increase in magnetization current.

15.4 In-rush current

Under normal steady state conditions, the magnetizing current required to produce the necessary flux is relatively small, usually less than one percent of full load current (see Figure 15.6).

Figure 15.6
Steady state conditions

However, if the transformer is energized at a voltage zero then the flux demand during the first half voltage cycle can be as high as twice the normal maximum flux. This causes an excessive unidirectional current to flow, referred to as the magnetizing in-rush current as shown in Figure 15.7.

Figure 15.7
Illustration of magnetizing in-rush current

An analysis of this waveform will show that it contains a high proportion of second harmonic and will last for several cycles. Residual flux can increase the current still further, the peak value attained being in the order of 2.8 times the normal value if there is 80% reminisce present at switch-on.

As the magnetizing characteristic is non-linear, the envelope of this transient in-rush current is not strictly exponential. In some cases, it has been observed to be still changing up to 30 minutes after switching on (see Figure 15.8).

Figure 15.8
Typical transient current-rush when switching in a transformer at instant when E=O

It is therefore important to be aware of this transient phenomenon when considering differential protection of transformers, which will be discussed later.

15.5 Neutral grounding

It is important that the neutral of a power system be grounded otherwise this could ‘float’ all over with respect to true ground, thereby stressing the insulation above its design capability.

This is normally done at the power transformer as it provides a convenient access to the neutral point.

On HV systems (i.e. 6 KV and above), it is common practice to effectively ground the primary neutral by means of a solid copper, in which case the system is referred to as an effectively grounded system (see Figure 15.9).

Figure 15.9
Grounding of the neutral

This has the advantage that when a ground fault occurs on one phase, the two healthy phases remain at phase-to-neutral voltage above ground. This allows insulation of the transformer windings to be graded towards the neutral point, resulting in a significant saving in cost. All other primary plants need only phase-to-neutral insulation; surge arrestors in particular need only be rated for 80% line-to-line voltage. This provides an enormous saving in capital expenditure and explains why utility HV systems are invariably solidly grounded.

The disadvantage is that when a ground fault occurs, an extremely high current flows (approximately equal to three-phase fault current), stressing the HV windings both electro-magnetically and thermally. The forces and heat are proportional to the current squared. Grounding of the LV system neutral can be achieved as shown in Figure 15.10.

Figure 15.10
Grounding of the LV system

It will be noted that the LV system is impedance and/or resistance grounded. This allows the ground fault current to be controlled to manageable levels, normally in the order of the transformer full load current, typically 300 amps.

Here, the transformer does not get a shock on the occurrence of each ground fault; however, the phase conductors now rise to line potential above ground during the period of the ground fault (see Figure 15.11).

Figure 15.11
Phase diagram illustrating phase conductors rising to phase voltage on fault

Phase-to-ground insulation of all items of primary plant must therefore withstand line-to-line voltage.

15.6 On-load tap changers

On load tap changers are very necessary to maintain a constant voltage on the LV terminals of the transformer for varying load conditions.

This is achieved by providing taps, generally on the HV winding because of the lower current levels. The tap changer changes the turns ratio between primary and secondary, thereby maintaining a nominal LV voltage within a specific tolerance (see Figure 15.12).

Figure 15.12
On-load tap changer

A typical range of taps would be +15% to –5% giving an overall range of 20% (see Figure 15.13).

Figure 15.13
Top changer range of operations

The tap changer is usually mounted in a separate compartment to the main tank with a barrier board in between. This sometimes has a vent between the two to equalize the pressures.

15.7 Mismatch of current transformers

Current transformers are provided on the HV and LV sides of a power transformer for protection purposes. Consider a nominal 132/11 kV 10 MVA transformer: the HV and LV full load currents are as shown in Figure 15.14.

Figure 15.14
Nominal 132/11kV 10 MVA transformer

A ratio of 50/1 amps would most likely be chosen for the HV current transformers, as it’s not possible to obtain fractions of a turn. 525/1 could be achieved comfortably for the LV current transformers. We therefore have a mismatch of current transformer ratios. Furthermore, it is more than likely that the HV CTs will be supplied by a different manufacturer than the LV CTs. There is therefore no guarantee that the magnetization curves will be the same, so adding to the mismatch.

15.8 Types of faults

The following is a brief summary of the types of faults that can occur in a power transformer:

  • HV and LV bushing flashovers (external to the tank)
  • HV winding ground fault
  • LV winding ground fault
  • Inter-turn fault
  • Core fault
  • Tank fault

Phase-to-phase faults within the tank of a transformer are relatively rare by virtue of its construction. They are more likely to occur external to the tank on the HV and LV bushings. If a transformer develops a winding fault, the level of fault current will be dictated by:

  • Source impedance
  • Method of neutral grounding
  • Leakage reactance
  • Position of fault in winding (i.e. fault voltage).

15.8.1 Ground faults

Effectively grounded neutral
The fault current in this case is controlled mainly by the leakage reactance, which varies in a complex manner depending on the position of the fault in the winding.

The reactance decreases towards the neutral so that the current actually rises for faults towards the neutral end (see Figure 15.15).

Figure 15.15
Relationship of fault current to position from neutral (grounded)

The input primary current is modified by the transformation ratio and is limited to 2 to 3 times the full load current of the transformer for fault positions over a major part of the star winding.

An overcurrent relay on the HV side will therefore not provide adequate protection for ground faults on the LV side.

Resistance grounded neutral
For this application, the fault current varies linearly with the fault position, as the resistor is the dominant impedance, limiting the maximum fault current to approximately full load current (see Figure 15.16).

Figure 15.16
Relationship of fault current to positions from neutral (resistance grounded)

The input primary current is approximately 57% of the rated current making it impossible for the HV overcurrent relay to provide any protection for LV ground faults.

Restricted ground fault protection is therefore strongly recommended to cover winding ground faults and this will be covered in more detail in a later section.

15.8.2 Inter-turn faults

Insulation between turns can break down due to electro-magnetic / mechanical forces on the winding causing chafing or cracking. Ingress of moisture into the oil can also be a contributing factor.

Also an HV power transformer connected to an overhead line transmission system will be subjected to lightning surges, sometimes several times the rated system voltage. These steep-fronted surges will hit the end windings and may possibly puncture the insulation leading to a short-circuited turn. Very high currents flow in the shorted turn for a relatively small current flowing in the line (see Figure 15.17).

Figure 15.17
Inter-turn faults

15.8.3 Core faults

Heavy fault currents can cause the core laminations to move, chafe and possibly bridge causing eddy currents to flow, which can then generate serious overheating.

The additional core loss will not be able to produce any noticeable change in the line currents, and thus cannot be detected by any electrical protection system. Power frequency overvoltage not only increases stress on the insulation but also gives an excessive increase in magnetization current. This flux is diverted from the highly saturated laminated core into the core bolts, which normally carry very little flux. These bolts may be rapidly heated to a temperature, which destroys their own insulation, consequently shorting out core laminations.

Fortunately, the intense localized heat, which will damage the winding insulation, will also cause the oil to break down into gas. This gas will rise to the conservator and be detected by the Buchholz relay (see later).

15.8.4 Tank faults

Loss of oil through a leak in the tank can cause a reduction of insulation and possibly overheating on normal load due to the loss of effective cooling.

Oil sludge can also block cooling ducts and pipes, contributing to overheating, as can the loss of forced cooling pumps and fans generally fitted to the larger transformer.

15.9 Differential protection

Differential protection, as its name implies, compares currents entering and leaving the protected zone and operates when the differential current between these currents exceed a per-determined level.

The type of differential scheme normally applied to a transformer is called the current balance or circulating current scheme as shown in Figure 15.18.

Figure 15.18
Differential protection using current balance scheme.(external fault conditions)

The CTs are connected in series and the secondary current circulates between them. The relay is connected across the mid-point where the voltage is theoretically nil, therefore no current passes through the relay, hence no operation for faults outside the protected zone.

Under internal fault conditions (i.e. faults between the CTs) the relay operates, since both the CT secondary currents add up and pass through the relay as seen in Figure 15.19.

Figure 15.19
Differential protection and internal fault conditions

This protection is also called unit protection, as it only operates for faults on the unit it is protecting, which is situated between the CTs. The relay therefore can be instantaneous in operation, as it does not have to co-ordinate with any other relay on the network.

This type of protection system can be readily applied to auto-transformers as shown in Figure 15.20.

Figure 15.20
Differential protection applied to auto-transformers

All current transformer ratios remain the same and the relays are of the high impedance (voltage operated) type, instantaneous in operation (see Figure 15.21).

Figure 15.21
Auto-transformer–phase and ground fault scheme

Unfortunately, the same parameters cannot be applied to a two winding transformer. As stated earlier, there are number of factors that need consideration:

  • Transformer vector group (i.e. phase shift between HV and LV)
  • Mismatch of HV and LV CTs
  • Varying currents due to on-load tap changer (OLTC)
  • Magnetizing in-rush currents (from one side only)
  • The possibility of zero sequence current de-stabilizing the differential for an external ground fault.

Factor (a) can be overcome by connecting the HV and LV CTs in star/delta respectively (or vice versa) opposite to the vector group connections of the primary windings, so counteracting the effect of the phase shift through the transformer.

The delta connection of CTs provides a path for circulating zero sequence current, thereby stabilizing the protection for an external ground fault as required by factor (e).

It is then necessary to bias the differential relay to overcome the current unbalances caused by (b) mismatch of CTs and (c) OLTC. Finally, as the magnetizing current in-rush is predominantly 2nd, harmonic filters are then utilized to stabilize the protection for this condition (d).

Most transformer differential relays have a bias slope setting of 20%, 30% and 40% as shown. The desired setting is dictated by the operating range of the OLTC, which is responsible for the biggest current unbalance under healthy conditions.

E.g. if the OLTC range is +15% to –5% =20% then the 20% bias setting is selected.

Typical connections for a delta-star transformer are as shown in Figure 15.22.

Figure 15.22
Typical connections for a delta-star transformer

Under load or through-fault conditions, the CT secondary currents circulate, passing through the bias windings to stabilize the relay, whilst only small out-of-balance spill currents will flow through the operate coil, not enough to cause operation. In fact, the higher the circulating current, the higher the spill current required to trip the relay, as can be seen from Figure 15.23 and Figure 15.24.

Figure 15.23
Operating current versus bias current

Figure 15.24
Biased differential configurations

15.10 Restricted ground fault

As demonstrated earlier in this chapter, a simple overcurrent and ground fault relay will not provide adequate protection for winding ground faults.

Even with a biased differential relay installed, the biasing de-sensitizes the relay such that it is not effective for certain ground faults within the winding. This is especially so if the transformer is resistance or impedance grounded, where the current available on an internal fault is disproportionately low.

In these circumstances, it is often necessary to add some form of separate ground fault protection. The degree of ground fault protection is very much improved by the application of unit differential or restricted ground fault systems as shown in Figure 15.25.

Figure 15.25
A restricted ground fault system

On the HV side, the residual current of the three line CTs is balanced against the output current of the CT in the neutral conductor, making it stable for all faults outside the zone.

For the LV side, ground faults occurring on the delta winding may also result in a level of fault current of less than full load, especially for a mid-winding fault which will only have half the line voltage applied. HV overcurrent relays will therefore not provide adequate protection. A relay connected to monitor residual current will inherently provide restricted ground fault protection since the delta winding cannot supply zero-sequence current to the system.

Both windings of a transformer can thus be protected separately with restricted ground fault, thereby providing high-speed protection against ground faults over virtually the whole of the transformer windings, with relatively simple equipment.

The relay used is an instantaneous high impedance type, the theory of which is shown in Figure 15.26.

Figure 15.26
Basic circuit of high impedance current balance scheme

15.10.1 Determination of stability

The stability of a current balance scheme using a high impedance relay depends upon the relay voltage setting being greater than the maximum voltage which can appear across the relay for a given through fault condition.

This maximum voltage can be determined by means of a simple calculation, which makes the following assumptions:

  • One current transformer is fully saturated, making its excitation impedance negligible
  • The resistance of the secondary winding of the saturated CT together with lead resistance constitute the only burden in parallel with the relay
  • The remaining CTs maintain their ratio.

Hence, the maximum voltage is given by Equation (15.1):

V = I(Rct + R1)         15.1


I = CT secondary current corresponding to the maximum steady-state through-fault current

Rct = Secondary winding resistance of CT

R1 = Largest value of lead resistance between relay and current transformer.

For stability, the voltage setting of the relay must be made equal to or exceed the highest value of V calculated above.

Experience has shown that if this method of setting is adopted the stability of the protection will be very much better than calculated. This is because a CT is normally not continuously saturated and consequently any voltage generated will reduce the voltage appearing across the relay circuit.

15.10.2 Method of establishing the value of stabilizing resistor

To give the required voltage setting, the high impedance relay operating level is adjusted by means of an external series resistor as follows:

Let v = operating voltage of relay element

Let i = operating current of relay equipment and

V = maximum voltage as defined under ‘determination of stability’ above.

Then the required series resistor setting;

It is sometimes the practice to limit the value of series resistor to say 1000 ohms, and to increase the operating current of the relay by means of a shunt connected resistor, in order to obtain larger values of relay operating voltage.

15.10.3 Method of estimating maximum pilot loop resistance for a given relay setting

From Equation 15.1 above V = I(Rct + R1). Therefore

15.10.4 Primary fault setting

The primary fault setting can now be calculated.

In order for this protection scheme to work, it is necessary to magnetize all current transformers in the scheme plus provide enough current to operate the relay.

Therefore, if;

Ir = relay operating current

I1, I2, I3, I4 = excitation currents of the CTs at the relay setting voltage

N = CT ratio.

Then the primary fault setting = N * (Ir + I1 + I2 + I3 + I4).

In some cases, it may be necessary to increase the basic primary fault setting as calculated above.

If the required increase is small, the relay setting voltage may be increased (if variable settings are available on the relay), which will have the effect of demanding higher magnetization currents from the CTs I1, I2 etc.

Alternatively, or when the required increase is large, connecting a resistor in parallel with the relay will increase the value of Ir.

15.10.5 Current transformer requirements

Class X CTs are preferably required for this type of protection, however experience has shown that most protection type CTs are suitable for use with high impedance relays, providing the following basic requirements are met:

  • The CTs should have identical turns ratio. Where turns error is unavoidable, it may be necessary to increase the fault setting to cater for this.
  • To ensure positive operation, the relay should receive a voltage of twice its setting. The knee-point voltage of the CTs should be at least twice the relay setting voltage. (Knee-point = 50% increase in mag. Current gives 10% increase in output voltage).
  • CTs should be of the low reactance type.

15.10.6 Protection against excessively high voltages

As the relay presents very high impedance to the CTs, the latter are required to develop an extremely high voltage. In order to contain this within acceptable limits, a voltage dependant resistor (VDR), or metrosil, is normally mounted across the relay to prevent external flashovers, especially in polluted environments (see Figure 15.27).

Figure 15.27
Protection against excessively high voltages

15.10.7 Example

Calculate the setting of the stabilizing resistor for the following REF protection. The relay is a type CAG14, 1 Amp, 10%-40%, burden 1.0 VA (see Figure 15.28).

Figure 15.28
Example for calculation of setting of stabilizing resistor

Current transformer must therefore have a minimum knee-point voltage of 2 × 120 = 240 volts to ensure positive operation of protection for an internal fault.

15.11 HV overcurrent

It is common practice to install an IDMTL overcurrent and ground fault relay on the HV side of a transformer. The inherent time delay of the IDMTL element provides back-up for the LV side.

High-set instantaneous overcurrent is also recommended on the primary side mainly to give high-speed clearance to HV bushing flashovers. Care must be taken, however, to ensure that these elements do not pick up and trip for faults on the LV side.

For this reason, it is essential that the HSI element should be of the low-transient overreach type, set approximately to 125% of the maximum through-fault current of the transformer to prevent operation for asymmetrical faults on the secondary side (see Figure 15.29).

Figure 15.29
Fault current as seen from the HV side

This relay therefore looks into, but not through the transformer, protecting parts of the winding, thus behaving like unit protection by virtue of its setting.

15.11.1 Current distribution

When grading IDMTL overcurrent relays across a delta-star transformer, it is necessary to establish the grading margin between the operating time of the star side relay at the phase-to-phase fault level and the operating time of the delta side relay at the three-phase fault level.

This is because under a star side phase-to-phase fault condition, which represents a fault level of 86% of the three-phase fault level, one phase of the delta side transformer will carry a current equivalent to the three-phase fault level (see Figure 15.30 and Figure 15.31).

Figure 15.30
Delta star transformer configuration
Figure 15.31
Graphical representation of the fault

15.12 Protection by gas sensing and pressure detection (Buchholz relay)

Failure of the winding insulation will result in some form of arcing, which can decompose the oil into hydrogen, acetylene, methane, etc. Localized heating can also precipitate a breakdown of oil into gas. An incipient fault releases small amounts of gas for a long time before the unit fails. Thus, adequately early warning can be obtained when collection of gas can be sensed and an alarm initiated.

On the other hand, a complete and sudden failure of winding insulation will result in severe arcing which in turn will cause a rapid release of a large volume of gas as well as oil vapor. The action can be so violent that the build-up of pressure can cause an oil surge from the tank to the conservator.

The Buchholz relay can detect both gas and oil surges as it is mounted in the pipe to the conservator (see Figure 15.32 and Figure 15.33).

Figure 15.32
Mounting of the Buchholz relay
Figure 15.33
Details of the Bucholtz relay construction

The unit contains two mercury switches. The production of gas in the tank will eventually bubble up the pipe to be trapped in the top of the relay casing, so displacing and lowering the level of the oil. This causes the upper float to tilt and operate the mercury switch to initiate the alarm circuit.

A similar operation occurs if a tank leak causes a drop in oil level.

The relay will therefore give an alarm for the following conditions, which are of a low order of urgency:

  • Hot spots on the core due to shorted laminations
  • Core bolt insulation failure
  • Faulty joints
  • Inter-turn faults and other incipient faults involving low power
  • Loss of oil due to leakage

The lower switch is calibrated by the manufacturers to operate at a certain oil flow rate (i.e. surge) and is used to trip the transformer HV and LV circuit breakers.

This calibration is important, particularly with large transformers with forced circulation, where starting of the pumps can sometimes cause a rush of oil into the conservator pipe. Obviously, operation should not occur for this condition.

When oil is being cleaned and filtered on load as part of routine maintenance, aeration will take place and air will accumulate in the Buchholz relay. It is therefore recommended that tripping be disconnected, leaving the alarm function only during this oil treatment process and for about 48 hours afterwards. Discretion must then be used when dealing with the alarm signals during this period.

Because of the universal response to faults within the transformer, some of which are difficult to protected against by other means, the Buchholz relay is invaluable. Experience has shown that it can be very fast in operation. Speeds as fast as 50 milliseconds have been recorded, beating all other protection systems on the transformer in process.

Gas sampling facilities are also provided to enable gas to be easily collected for analysis.

Other designs provide for sensing of pressure both to vent the gases/coolant and to trip the transformer in the event of an internal fault. Variants are available with capability for sensing of the liquid pressure build up, or the pressure increase of the inert gas space above the liquid level within the tank. Generally, these switches are useful for smaller capacity transformers without a conservator.

15.13 Overloading

A transformer is normally rated to operate continuously at a maximum temperature based on an assumed ambient. No sustained overload is usually permissible for this condition.

At lower ambient temperatures, it is often possible to allow short periods of overload but no hard and fast rules apply, regarding the magnitude and duration of the overload.

The only certain factor is that the winding must not overheat to the extent that the insulation is cooked, thereby accelerating ageing. A winding temperature of 98°C is considered to be the normal maximum working value, beyond which a further rise of 8°C --10°C, if sustained, is considered to halve the life of the transformer. Oil also deteriorates from the effect of heat.

It is for these reasons that winding and oil temperature alarm and trip devices are fitted to transformers.

Winding temperature is normally measured by using a thermal image technique. A sensing element is placed in a small pocket near the top of the main tank. A small heater, fed from a current transformer on the LV side is also mounted in this pocket and this produces a temperature rise similar to that of the main winding, above the general oil temperature.

Dial type thermometers connected by a capillary tube to a bulb in the oil pocket have been extensively used. These have two contacts fitted, which are adjustable to give alarm and trip signals.

Typical settings normally adopted (unless otherwise recommended by the manufacturers) are as follows:

Winding temperature alarm = 1000C

Winding temperature trip = 1200C

Oil temperature alarm = 950C

Oil temperature trip = 1050C

On the larger transformers, cooling fans and pumps are employed to control the temperature.

In many cases, normal practice seems to be to use IDMTL overcurrent relays for overload protection, CT ratios being chosen on the basis of the transformer full load current.

To use IDMTL overcurrent relays for overload is not good practice for three reasons:

  • The IDMTL relay-operating (time-current) characteristic is not compatible with the thermal characteristic of a power transformer. Incorrect and often unnecessary tripping can occur for light overloads, whilst failure to trip for heavy overloads could shorten the life of the transformer dramatically.
  • If set too fine, there is also the danger of tripping on the magnetizing in-rush current of its own or an adjacent transformer.
  • It may not co-ordinate with LV circuit breaker protection for an LV fault, beating it in the process.

Overload protection should be done by oil and winding temperature devices, or relays that have similar tripping characteristics to the thermal time constant of the transformer.

15.13.1 Oil testing and maintenance

There are three important purposes of the oil in a transformer:

  • Good dielectric strength
  • Efficient heat transfer and cooling
  • To preserve the core and assembly.
    • - By filling voids (to eliminate partial discharge)
    • - By preventing chemical attacks on the core, copper and insulation by having a low gas content and natural resistance to ageing

It is therefore vital that the oil is kept in tip-top condition and that regular testing and maintenance be carried out.

Samples should be drawn annually and tested to see if they comply with the following limits:

Dielectric strength - 50 kV/min

Moisture content - 30 ppm max

Acidity - 0.2 mg KOH/g max

Interfacial tension - 20 mN/m min

M.I.N. - 160 min

A typical test report is shown in Table 15.1 from which it is immediately apparent if major problems are imminent and urgent action needs to be taken.

However, it is very important to also conduct a gas analysis on the samples. This analysis of the various constituents can provide some valuable information as to the rate of deterioration (or otherwise) of the transformer insulation.

Table 15.2 illustrates typical readings on an anonymous sample and it is important to interpret trends rather than absolute levels. There are no hard and fast rules that can be applied and even the oil filtration / purification companies fight shy of interpreting results. The production rates in Table 15.3 do, however, assist in drawing conclusions in order to pre-empt major problems occurring in the future (see also Table 15.4 and Table 15.5).

A typical interpretation would be as follows:

‘Interpretation of historical results/trends
The high level of Ethane (C2H6) detected in sample no. 5 is a cause for concern. This is consistent with localized overheating having taken place in the transformer. The level of Ethylene (41 ppm) is also consistent with this conclusion.

The transformer appears to have had a localized hot spot between samples 4 and 5 but now appears to be fine. If the oil was purified between samples 5 and 6, then the results of sample 6 may not be significant and further samples should be drawn in 6 months time.’

Tight control of these procedures and testing can prevent transformer faults occurring, whereas protection relays only operate after the event when the damage has been done.

Gas analysis of samples taken from the Buchholz relay can also prove very illuminating and reveal potential major problems.

Table 15.1
Typical transformer oil test report
Table 15.2
Typical gas analysis summary
Table 15.3
Typical gas analysis on transformer oil
Table 15.4
Case 1: Transformer rating: 250 MVA; voltage: 400/30 kV
Table 15.5
Case 1: Transformer rating: 11 MVA; voltage: 20/6/6 kV


Switchgear (busbar) protection

16.1 Importance of busbars

Busbars are the most important component in a distribution network. They can be open busbars in an outdoor switch yard, up to several hundred volts, or inside a metal clad cubicle restricted within a limited enclosure with minimum phase to phase and phase to ground clearances. We come across busbars which are insulated, as well as those which are open and are normally in small length sections interconnected by hardware.

They form an electrical ‘node’ where many circuits come together, feeding in and sending out power (see Figure 16.1).

Figure 16.1
Schematic illustrating area of busbar zone

From the above diagram, it is very clear that if for any reason the busbars fail, it could lead to a shutdown of all distribution loads connected through them, even if the power generation is normal and the feeders are normal.

The important issues of switchgear protection can be summarized as:

  • Very serious and sometimes catastrophic loss
  • Switchgear damaged beyond repair
  • Multi-panel boards not available ‘off-the-shelf’
  • Numerous joints
  • Air enclosure
  • Dust build up
  • Insect nesting
  • Ageing of insulation
  • Frequency of stress impulses
  • Long ground fault protection tripping times

16.2 Busbar protection

Busbars are frequently left without protection because:

  • Low susceptibility to faults–especially metal clad switchgear
  • Rely on system back up protection
  • CTs too expensive
  • Problems with accidental operation–greater than infrequent busbar faults
  • Majority of faults are ground faults – limited ground fault current –fast protection not required

However, busbar faults do occur.

16.3 The requirements for good protection

Successful protection can be achieved subject to compliance with the following:

  • Speed
    • - Limit damage at fault point
    • - Limit effect on fault stability
  • Selectivity
    • - Trip only the faulted equipment
    • - Important for busbars divided into zones
  • Stability
    • - Not to operate for faults outside the zone
    • - Most important for busbars
    • - Stability must be guaranteed
  • Reasons for loss of stability
    • - Interruption of CT circuits–imbalance
    • - Accidental operation during testing
  • Tripping can be arranged ‘two-out-of-two’
    • - Zone and check relays

16.4 Busbar protection types

  • Frame leakage
  • High impedance differential
  • Medium impedance biased differential
  • Low impedance biased differential
  • Busbar blocking

16.4.1 Frame leakage protection

This involves the measurement of fault current from the switchgear frame to the ground. It consists of a current transformer connected between frames and ground points and energizes an instantaneous ground fault relay to trip the switchgear. It generally trips all the breakers connected to the busbars.

Care must be taken to insulate all the metal parts of the switchgear from the ground to avoid spurious currents being circulated. A nominal insulation of 10 ohms to ground is sufficient. The recommended minimum setting for this protection is about 30% of the minimum ground fault current of the system (see Figure 16.2 and Figure 16.3).

Figure 16.2
Requirements of frame leakage BB protection
Figure 16.3
Schematic connections for frame leakage protection

16.4.2 Differential protection

This requires sectionalizing the busbars into different zones (see Figure 16.4—Figure 16.9).

High impedance bus zone

  • Relays relatively cheap – offset by expensive CTs
  • Simple and well proven
  • Fast–15…45 m secs
  • Stability and sensitivity calculations easy, provided data is available
  • Stability can be guaranteed.


  • Very dependent on CT performance
  • CT saturation could give false tripping on through faults
  • Sensitivity must be decreased
  • DC offset of CTs unequal–use filters
  • Expensive class X CTs–same ratio–Vknp = 2 times relay setting
  • Primary effective setting (30...50%)
  • Limited by number of circuits
  • Z grounded system difficult for ground fault
  • Duplicate systems–decreased reliability
  • Require exact CT data
  • Vknp, Rsec, imag, Vsetting
  • High voltages in CT circuits (+/– 2.8 kV) limited by volt dependent resistors
Figure 16.4
Zoned busbar (switchgear) protection
Figure 16.5
Single line diagram high impedance busbar protection


  • Additional CTs six per circuit
  • Space problems on metal clad switchgear
  • Long shutdowns
  • CT performance important
  • Class X
  • Vknp = 2 times setting
  • Rsec must be low
  • Limit on number of circuits
  • CT polarity checks required
  • Primary injection tests required
  • Compete switchboard
  • Separate relay cubicle
  • Differential relays
  • Auxiliary relays
  • CT cabling
  • Busbar tripping cabling

Biased medium impedance differential

  • High speed 8…13 m secs
  • Fault sensitivity +/– 20%
  • Excellent stability for external faults
  • Normal CTs can be used with minimal requirements
  • Other protection can be connected to same CTs
  • No limit to number of circuits
  • Secondary voltages low (medium impedance)
  • Well proven 10000 systems worldwide
  • Any busbar configuration
  • No need for duplicate systems
  • Retrofitting easy
  • No work on primary CTs
  • Biasing may prevent possibility of achieving a sensitive enough ground fault setting of Z grounded systems.


  • Relays relatively expensive
  • Offset by minimal CT requirements
  • Relays with auxiliary CTs require a separate panel.
Figure 16.6
BMID single-phase circuit
Figure 16.7
BMID single-phase circuit–external fault
Figure 16.8
BMID single phase circuit–internal
Figure 16.9
Stability characteristic busbar protection

Low impedance busbar protection
Principle: Merz-price circulating current biased differential CT saturation detector circuits (inhibit pulses), (see Figure 16.10).

Figure 16.10
Low impedance busbar protection

On a through fault, one CT may saturate – this does not provide a balancing current for the other CT. A spill current (i1 – i2) then flows through the operating coil. Electronics will detect CT saturation and short out a differential path. The inhibit circuit only allows narrow spikes in the differential coil. The relay will be stable.

For an internal fault with a differential current in phase with a saturated CT current:

  • Inhibit pulses remove an insignificant portion of the differential current. Relay operates.
  • Setting range: 20% – 200%
  • Operating time: less than 20 milliseconds
  • CT supervision: Alarms and blocks or trips after 3 seconds for CT open circuit (see Figure 16.11).
Figure 16.11
Low impedance busbar protection

Saturation detectors
The CTs feed the differential circuit via auxiliary transformers, which in turn feed a typical saturation detector circuit shown in Figure 16.12):

  • A voltage C (Vc) is developed across the resistor R
  • The capacitor C is charged to the peak value of that voltage
  • A comparator compares voltage with 0.5 V stored in capacitor
  • On saturation, V drops below 0.5 V capacitor voltage
  • The comparator then turns on electronic switch across buswires
  • The pulse width increases with optimum philosophy.
Figure 16.12
Saturation detectors

Busbar blocking system

  • Very low or no cost system
  • Simple
  • Faster than faults cleared by back-up relays
  • Covers phase and ground faults
  • Adequate sensitivity–independent of no. of circuits
  • No additional CTs
  • Commissioning is simple–no primary current stability tests (see Figure 16.13)


  • Only suitable for simple busbars
  • Additional relays and control wiring for complex busbars
  • Beware of motor in-feeds to busbar faults
  • Sensitivity limited by load current


  • Easy if starting contacts available; if not, they need to be added
  • Modern microprocessor relays have starters
  • No need to work on CTs
  • Most work is done with the system operational
  • Final commissioning requires a very short shutdown time; injection to prove stability between up and downstream relays.
Figure 16.13
Busbar blocking scheme


Protection of Motors

17.1 Introduction

Of all motors, squirrel cage induction motors, particularly the TEFC type (Totally Enclosed, Fan Cooled), have become extremely popular mainly because of their simple, rugged construction and good starting and running torque characteristics. The TEFC design improves the mechanical life of the motor because dust and moisture are excluded from the bearings and windings. This type of motor has proved to be extremely reliable with an expected lifetime of up to 40 years when used in the correct application.

However, the industry is witnessing failures in this kind of motors also, for various reasons, in spite of these much-improved designs and the continually improving maintenance practices. According to the statistics gathered by the ABB Group, as shown in Figure 17.1, 81% of such motor failures could have been avoided by using an accurate and effective relay for protecting the motor concerned. It is shown in Figure 17.2 that 81% of these failures could have been avoided by using an accurate and effective relay.

Figure 17.1
Protective functions needed to detect the motor drive faults

The life of an electric motor is determined by the shorter of the following two factors:

1) Mechanical life

This is the life of the mechanical parts such as bearings, shaft, fan and the frame and depends on the environment (dust, moisture, chemicals, etc.), vibration and lubrication. The mechanical life can be extended by means of regular inspection and maintenance.

2) Electrical life

This is the life of the electrical parts such as the stator winding and insulation, rotor winding and the cable terminations in the motor connection box. Assuming that the cable terminations are properly done and regularly checked, the electrical life may be extended by ensuring that the windings and insulation are not subjected to excessive temperatures which are usually the consequence of overloading or single phasing (loss of one-phase).

Figure 17.2
Protective functions needed to detect the motor drive faults

The purpose of good motor protection is to continuously monitor the current flowing into the motor to detect overloading or fault conditions and to automatically disconnect the motor when an abnormal situation arises. This protection, when correctly applied, extends the useful life of the motor by preventing insulation damage through overheating.

Most people in the industry can easily understand the relatively simple mechanical aspects of an electric motor but few fully appreciate the electrical limitations and relationship between overloading and the useful life of the motor. Essentially, mechanical overloading causes excessively high currents to flow in the winding (since current in the motor is proportional to the load torque) and this results in overheating of the stator and motor windings.

These high temperatures result in the deterioration of the insulation materials through hardening and cracking, eventually leading to electrical breakdown or faults. In many cases, the motor can be repaired by rewinding the stator but this is expensive with a longer downtime. The larger the motor, the higher the cost.

There are several types of insulation materials commonly used on motors. In the IEC specifications for motors, the insulation materials are classified by the temperature rise above maximum ambient temperature that the materials can continuously withstand without permanent damage. The insulation classes specified by NEMA standards are also identical. For example, safe maximum operating temperatures for commonly used insulation classes are:

Class A 105 °C
Class B 130 °C
Class F 155 °C
Class H 180 °C

It is worth noting that these temperatures correspond to an expected insulation life of 20000 hours of operation and every 10-degree increase in the operating temperature will reduce the insulation life by half. The operating temperature is the sum of the ambient temperature and the temperature rise. Since the rated temperature represents the maximum permissible stable temperatures during operation, it is the temperature rise which assumes importance.

This means that the temperature rise of a given motor will have to be reduced if the ambient temperature in which it operates becomes higher. This is only possible by restricting the output rating of the machine. Thus, any motor has a specified ambient temperature. Use of the motor at an ambient temperature higher than the specified value will necessitate a derating factor to be applied to the rated kW/HP output. Usually, derating tables are supplied by manufacturers on request.

Another aspect to be noted is that the winding temperature that is measured (usually by measuring the winding resistance and deriving the temperature rise by the known temperature coefficient of resistance of the winding material) is actually an average value. There may be specific locations within the winding where the temperatures can be much higher. These are called hot spots and these can become points of failure. Even in designs where temperature sensors are installed within the winding, the locations of installation may not be the ones with the highest temperature. It is therefore necessary to provide a safety cushion in the design so that no point of the winding reaches an unsafe temperature.

In a squirrel cage induction motor, the current flowing into the stator winding is directly proportional to the mechanical load torque. The motor manufacturer designs the motor to operate within specified limits. The motor is rated in terms of kilowatts (kW) at a rated supply voltage (V) and current (I). This means that a machine can drive a mechanical load continuously up to rated torque at rated speed. Under these conditions, supply current is within the specified current and the internal heating will be within the capabilities of the specified insulation class. At full load with class B insulation, the winding temperature will stabilize below 130°C.

The main cause of heating in the motor windings is a function of the square of the current flowing in the stator and rotor windings. This is shown on the motor equivalent circuit of Figure 17.3 where the losses are I² (Rs + Rr). These are often referred to as the copper losses. The stator windings have only a small mass and heat-up rapidly because of the current flowing. The heat insulation and the cooling time constants are consequently quite long. Other losses also generate heat. These are referred to as the iron losses but are relatively small and are quickly dissipated into the body of the motor.

Figure 17.3
Equivalent circuit of a squirrel cage motor

17.1.1 Thermal Overload Protection

Normally a motor’s operational heating curve and cooling circuit efficiency curve, as shown in Figure 17.4, can be represented as two exponential curves showing the temperature rise and drop against a particular time frame respectively. During normal running of a motor passage of load current through the winding results in I2R copper losses and other magnetic losses that will ultimately rise the temperature of the motor. This is represented by the heating curve. As the motor gets heated up, the rate of rise of temperature reduces and hence it is an exponential curve. In the same way, a running motor when stopped it looses the heat in it, to the environment. Also this temperature drop is also an exponential curve. In the normal running of a motor, the rate of heating and the rate of cooling strike a balance, specifically for a particular load.

Figure 17.4
Temperature rise versus time for a motor

At this point, the temperature of the motor remains constant for a particular load, at a particular ambient temperature. As the load on the motor changes, this stabilized temperature varies depending on the balance between the heating and cooling phenomena. At higher, persistent loads the motor temperature may reach dangerous values. If the motor is left to continue in these conditions, for long, the stator insulation may start breaking down resulting in the failure of the motor. Even if the motor doesn’t break down immediately, the high temperatures to which the insulation system is subjected to, will accelerate the degradation process of the insulation system (the details are already covered in the topic on insulation failure in Chapter 4). In this context it is worth remembering that higher the operating temperature of a motor the lesser the service life of the motor. Also, it has been proven empirically that for every 10 0C rise in temperature, the life of a motor reduces to half.

Hence, the basic intention of the thermal overload protection is to safeguard the motor against such overheating of the stator insulation system so as to extend the life of the motor. However, there is a trade-off between the loading of a motor and its protection. This demarcation line drawn between the load current and time is called as thermal capability curve or motor thermal withstand characteristic of the motor. Also it will have two different curves – the cold one involving no thermal trip and the hot one connected with a thermal trip. Operation of the motor above the thermal capability curve can be detrimental to the motor’s life in the long run, if not immediately, and the motor is said to be thermally overloaded. Therefore, this protection is called as thermal overload protection.

Also known as running protection, this is intended to protect the motor against only persistent overloads, while in operation. The National Electric Code (NEC) defines Motor Overload Protection as that which is intended to protect motors, motor-control apparatus, and motor branch-circuit conductors against excessive heating due to motor. This is not expected to protect the components against a ground fault or a short circuit fault. Hence a protection against thermal overloads is aimed at enhancing the longevity of a motor.

Motors can be protected against thermal overload by two broad methods – indirect method is by simulating the motor internal conditions by sensing the current flowing through it and direct method by sensing the temperature within the motor. Indirect methods employ thermal overload relays or magnetic overload relays or through differential current sensing systems. Direct methods can be are of inherent type or thermostat type. Inherent type engages bi-metallic strip to sense the ambient temperature, motor internal temperature, internal motor heating and the current flowing in the circuit. These are used for small (FHP) motors. Using thermostat type the motor winding temperature is directly sensed and the contact is used for tripping the motor. Usually it is used in conjunction with thermal overload relays.

17.1.2 Thermal time constants

The time constant T (tau) is defined (IEC 255-8) as the time in minutes required for the temperature of a body to change from an initial temperature θ0 to 63% of the difference between θ0 and the new steady state temperature θ∞.

Unfortunately the thermal time constant T of the motor is frequently not known. Table 17.1 gives typical values in relation to motor ratings and mechanical design.

The cooling time constants during operation are approximately equal to those for temperature rises, while at standstill they are four to six times the values given in the table.

Table 17.1
Mean thermal time constants of asynchronous motors from Brown Boveri in relation to motor rating and type

17.1.3 Steady state temperature rise

In the interest of maximum efficiency, electrical machines should be loaded as close as possible to their permitted operating temperature limit; however, excessive thermal stressing of any appreciable duration must be avoided if the life of the insulation is not to be shortened.

Under steady-state conditions, the temperature of a motor will rise exponentially, due to the dissipation of heat to the environment or cooling medium. Since a motor is not a homogeneous mass, heat is dissipated in several stages. Temperature rise and fall takes place according to a series of partial time constants. Refer to Figure 17.5.

Figure 17.5
Temperature rise versus time (illustrating time constant)

In spite of this, it is sufficient for a thermal overload relay intended for protection under steady-state conditions to be set to the mean time constant of the motor. This means that proper account is taken only of the copper losses. Measurement of the voltage would be necessary in order to include the iron losses, but is not generally possible since the voltage transformers are usually located on the busbar and not adjacent to each motor. Most modern thermal overload relays only measure current, filtering out the highest of the three-phase current. The critical cases of starting, stalling and failure of a phase are taken care of by other protective functions.

17.1.4 Early relays

Some of the early designs of motor protection relays had a single function whose purpose was to protect the motor against overloading. This was done by continuously monitoring the electrical current drawn by the motor and arranging for the motor to be disconnected when the current exceeded the rated current for a certain period of time. The higher the overload current, the shorter the permissible time before disconnection. This time delay was achieved in various ways. An example is the “solderpot” relay, which relied on the time taken for solder in the measuring circuit to melt when the load current was passed through it. The bimetal type relays disconnect the motor when the load current passing through a resistor heated in a bimetallic strip sufficiently to bend it beyond a preset limit. This released the trip mechanism. In recent years, electronic relays utilise an analogue replica circuit, comprising a combination of resistors and capacitors, to simulate the electrical characteristics of the stator and rotor. The main principle linking all these methods is the design of a replica system to simulate as closely as possible the electrical characteristics of the motor.

It has in the past been common practice to detect high temperatures for temperature dependent elements built into the winding of the motor. However, this form of temperature measurement is in most cases is unsatisfactory as it is not taken directly from the current conductor. Instead it is taken through the insulation which gives rise to considerable sluggishness. Due to insulation considerations, insertion of thermocouples in high-voltage motors can cause problems. Furthermore, after a fault (e.g. a break in the measuring lead inside the machine) high repair costs are encountered. Another problem is that no one can accurately predict, during the design, how many and where the “hot spots” will be.

Consequently, protection is preferably based on monitoring the phase currents instead. Because the temperature is determined by the copper and iron losses, it must be possible to derive it indirectly by evaluating the currents in the motor supply leads.

The performance of a Motor Protection Relay depends on how closely and accurately the protection simulates the motor characteristics. The ideal simulation occurs when the heating and cooling time constants of the motor windings are matched by the relay under all operating conditions. In some of the early devices, the protection could underestimate the heating time of the windings from cold and could trip before a motor/load combination with a long run-up time had reached running speed.

On the other hand, during several sequential starts and stops, the device could underestimate the cooling time of the windings, allowing the motor windings to overheat. This situation can very easily arise with the bimetallic thermal overload relays commonly used on motor starters even today. Under certain conditions, bimetallic thermal overload relays do not provide full protection because the device does not have exactly the same thermal heating and cooling characteristics as the motor which it is protecting. The heating and cooling time constants of a bimetallic relay are much the same but in actual installations it should be borne in mind that a stopped motor has a longer cooling time constant than that for a running motor. When a motor has stopped, the fan no longer provides a forced draft and cooling takes longer than when the motor is running on no load. A simple bimetallic device is a compromise and is calibrated for normal running conditions. As soon as an abnormal situation arises, difficulties can be expected to arise.

To illustrate the point, take the case of a motor that has been running at full load for a period of time when the rotor is suddenly stalled. Figure 17.4 shows typical temperature curves of the winding temperature (solid line) compared to the heating and cooling curve of the protective device (dotted line). Starting at a normal continuous running temperature of 120°C, the current increases for the locked rotor condition and temperature rises to 140°C when the thermal device trips the motor after some seconds. After about 10 minutes, the bimetal will have cooled to ambient, but the windings will only have reading 100°C. With the bimetal reset, it is then possible to attempt a restart of the motor. With the rotor still locked, high starting currents cause the temperature to quickly rise to 165°C before the bimetal again trips the motor.

Considering that a similar sequence of events as described above can again be repeated, where the different cooling times of the motor and bimetal strip allow the bimetal to reset before the windings have cooled sufficiently, and if the motor is again restarted after another 10 minutes, the winding temperature is likely to exceed 180°C, the critical temperature for Class B insulation materials. This illustrates the importance of an accurate simulation by the protection device in both conditions where the motor is running and when the motor is stopped.

17.1.5 New digital relays

Nowadays, solid-state electronic relays are able to deliver various functionalities integrated under one casing. They extend all the protections offered earlier by electromechanical relays. Apart from this, they can be programmed as universal relays suitable for even the smallest motor to even a multi MW rated motor. With the earlier relays, one was required to specify the rating of a motor for which it is intended to be used. These digital relays have lot of special features to their credit as mentioned blow:

  • Compact as compared to their conventional equivalents.
  • Very stable against temperature variations
  • Longer calibration accuracy – some of the relays hardly require any testing
  • Versatility – there is no need of specifying the motor rating before hand
  • Reliability is very high
  • Very low power consumption

The most recent versions of motor protection relays are digital, microprocessor based ones and have the capability to incorporate various, programmable protections. Even their prices are also making them very attractive as compared to their earlier counterparts, especially after considering the various functionalities.

Typically a new generation microprocessor based motor protection relay can fulfill the following protections for any rating motor:

  • Overload protection
  • Locked rotor protection
  • Phase and ground fault protection
  • Unbalanced current protection
  • Load jam
  • Load loss of induction motor etc.

All these are covered accurately with the bare minimum data that needs to be fed into the relay at site. Typical information required for the purpose are:

  • Motor full load current
  • Locked rotor current
  • Locked rotor thermal limit time
  • Motor service factor etc.

They use an element that accounts for the I2r heating effect of both the positive- and negative-sequence current. The element is a thermal model defined by the motor nameplate data entered as settings. The model estimates motor temperature and compares it to thermal limit trip and alarm thresholds. The relay trips to prevent overheating for the abnormal conditions of overload, locked rotor starting, too frequent or prolonged starts, and unbalanced current.

These relays typically include:

  • Thermal overload protection, monitoring all three-phases with thermal replicas for direct and frequency convertor controlled drives
  • Short circuit protection
  • Start-up and running stall protection
  • Phase unbalanced protection
  • Single-phasing protection
  • Earth fault protection
  • Undercurrent protection
  • Digital read-out of set-values, actual measured values and memorized values
  • Self supervision system
  • Outstanding accuracy
  • Optimum philosophy

The present day concept is use of microprocessor based numerical relays for both HV and LV motors (say beyond 50 KW), as the relays come with lot of features which allow them to be interchangeable, ensures site settings and give valuable feedback on the load details whenever a trip occurs or not.

17.1.6 Starting and stalling conditions

As the magnitude and duration of motor starting currents and the magnitude and permissible duration of motor stalling currents are major factors to be considered in the application of overload protection, these will be discussed. It is commonly assumed that the machines started direct on line the magnitude of the starting current decreases linearly as the speed of the machine increases.

This is not true. For normal designs the starting current remains approximately constant at the initial value for 80-90% of the total starting time.

Figure 17.6
Motor Current during Start Conditions

When determining the current and time settings of the overload protection it can be assumed that the motor starting current remains constant and equal to the standstill value of the whole of the starting time.

17.2 Stalling of Motors

Refer to Figures 17.7 and 17.8. Should a motor stall when running or be unable to start because of excessive load, it will draw a current from the supply equivalent to the locked rotor current. It is obviously necessary to avoid damage by disconnecting the machine as quickly as possible if this condition arises.

Figure 17.7
Relay operation times less than stall withstands time: relay gives stall protection
Figure 17.8
Relay Operation time greater than stall with stand time: Relay does not give stall protection

It is not possible to distinguish this condition from a healthy starting condition on current magnitude.

Majority of the loads are such that the starting time of normal induction motors is about or less than 10 seconds, while the allowable stall time to avoid damage to the motor insulation is in excess of 15 seconds.

If a double cage drive is to be protected, it might be that the motor cannot be allowed to be in a stall condition even for its normal start-up time. In this case a speed switch on the motor shaft can be used to give information about whether the motor is beginning to run up or not. This information can be fed to suitable relays which can accelerate their operating time [Refer Figure 17.9 (a) and (b)].

Figure 17.9 (a)
Typical Motor Start
Figure 17.9 (b)
Blocked Rotor Condition

Whether or not additional features are required for the stalling protection depends mainly on the ratio of the normal starting time to the allowable stall time and the accuracy with which the relay can be set to match the stalling time/current curve and still allow a normal start.

17.3 Over Current / Overload

Over current protection for motors is usually required to safeguard the motor against short circuit mainly to take care of phase faults. In order to provide an effective protection, phase fault current shall be greater than starting current. Otherwise the protection will act during normal starts. In such extreme cases, differential protection shall be provided for the motor. An instantaneous, high set, simple protection provides reliable, inexpensive coverage against phase faults. The operation of this instantaneous protection may involve, typically, 70 – 130 milli second at twice the current setting.

IDMT characteristics suiting the motor’s thermal capability curve are realized using the overload units to provide protection against long duration, light and medium overloads. NEC recommends provision of such overload coverage in each phase. However thermal capability curve of a motor represents an approximate average of the safe thermal zone of operation only and cannot be the exact model of the motor. Also the overload protection requirement varies considerably with size and design.

17.3.1 Phase-phase faults

Because of the relatively greater amount of insulation between phase windings, faults between phases seldom occur. As the stator windings are completely enclosed in grounded metal the fault would very quickly involve earth, which would then operate the instantaneous earth fault protection.

Differential protection is sometimes provided on large (2 MW) and important motors to protect against phase-phase faults, but if the motor is connected to an earthed system there does not seem to be any great benefit to be gained if a fast-operating and sensitive earth fault is already provided.

17.3.2 Terminal faults

High set instantaneous overcurrent relays are often provided to protect against phase faults occurring at the motor terminals, such as terminal flashovers. Care must be taken when setting these units to ensure that they do not operate on the initial peak of the motor starting current, which can be 2.5 times the steady state r.m.s. value. The asymmetry in the starting current rapidly decreases, and has generally fallen to its steady state value after one cycle. A typical motor starting current is shown in figure 17.10.

Figure 17.10
Transient over current during first few cycles when starting a motor

17.4 Under-voltage / Over-voltage

As per NEMA MG1 standards, AC induction motors shall operate satisfactorily at rated load, with the voltage varying within + / - 10 % of rated value at rated frequency. With a voltage decrease in this range, the power factor of the AC induction motor increases. In the same way, an increase in voltage results in a decrease of the power factor. The torque developed by the motor, whether of locked rotor or of breakdown will be proportional to the square of the voltage applied.

Average accelerating torque is given as:

[(voltage available at motor bus / rated motor voltage) 2 (rated torque)] - Load torque

Hence, due to the reduced accelerating torque, the motor will have problems in starting and reaching full speeds. Also a running motor may lose speed and draw heavy currents.

Hence under voltage protection is invariably provided for induction motors. Typically, by sensing a bus under voltage condition all the connected motors to that bus are tripped out.

The under voltage setting is normally 75 to 80 %.

Either an increase or a decrease in voltage results in increased heating of the motor at the rated load and hence may accelerate the deterioration of the insulation system, in the long run.

Similarly, over voltage can be detrimental to the insulation system as the temperature rises because of increased slip due to either an under voltage or an over voltage.

17.5 Under-frequency

AC motors operate successfully under running conditions at rated load and at rated voltage with a variation in the frequency up to 5 percent above or below the rated frequency.

Performance within this frequency variation will not normally be as per the standards established for operation at rated frequency.

At a frequency lower than the rated frequency, the speed is decreased. Since the magnetic flux in the machine, which is proportional to the inverse of frequency at a particular voltage increases, locked-rotor torque also increases and power factor decreases.

Also this may result in over magnetization of the core of the motor that, in turn, may result in overheating of the stator due to increased iron losses. If left unchecked, this may cause severe damage to the motor.

Normally, the result being overheating that is protected separately, motor feeders will not be separately provided with this protection. Frequency cannot be different from the source to even the remotest utilization point, unlike voltage that can drop even atrociously. However the impact of this aspect being very serious the protection is provided at the source itself, be it generator or the switchgear incomer of the particular plant.

17.6 Pole slip / Out of step

These aspects are purely applicable to synchronous machines only. During a pole-slip condition, negative currents can be induced into the field which is opposite of the normal positive current flow produced by the excitation system.

Hence, a large negative induced current with no current path will result in a very high positive voltage transient across the power rectifiers. The large voltage transient can cause damage to the solid-state devices and produce severe pitting on the slip rings.

With the application of the crowbar SCR circuit, the voltage sensing circuit will detect the positive induced field voltage and gate on the appropriate SCR to allow the negative current to flow from the field through the discharge resistor. When the crowbar circuit turns on, the rectifier bridge will be inhibited to prevent overload into the crowbar discharge resistor.

The out-of-step conditions (loss of synchronism) of a synchronous machine may occur as a result of pole slipping and hence pole slipping protection also detects loss of synchronism, but with the excitation intact.

Synchronous motors can develop torque only in synchronism. Overloading, beyond motor’s capability, may result in slowing down of the rotor. Once synchronism is lost, the motor will not be able to develop any torque. This is called ‘a motor going out of step’.

Since the rotor of a synchronous motor is applied DC voltage and the rotor doesn’t have any induced voltage, no AC voltage is supposed to be present when the motor is operating synchronously. Hence synchronous motors with brush type excitation can be easily protected against out of step or loss of synchronism by means of AC detection circuits connected to the rotor. Such circuits will detect pullout resulting from excessive shaft load or too-low supply voltage and protect the motor against overheating and the resulting damages.

Both effects may cause severe mechanical and thermal stresses to the machine. Loss of excitation protection is generally used to guard against the consequences of a partial or complete failure of the excitation. An under impedance relay is used to recognize this event.

17.7 Loss of excitation

Synchronous motors can be protected against loss of excitation by a low-set undercurrent relay connected to the field. This relay should have a time delay drop out.

On large synchronous motors an impedance relay is frequently applied that operates on excessive VAR flow into the machine, indicating abnormally low field excitation. If an under voltage unit is part of the relay, its function should be shorted out because loss of motor field may produce little or no voltage drop. Operation of synchronous motors drawing reactive power from the system can result in overheating in parts of the rotor that do not normally carry current. Some loss-of-field relays (device 40) can detect this phenomenon.

17.8 Inadvertent energization

Inadvertertent energization protection is needed for synchronous motors especially to avoid any accidental closing of the breaker when the supply to the motor fails and the motor is coasting down. Due to the stored energy in the drive, especially from the driven side, motor starts acting like a Generator. Under such circumstances, the supply being restored will be out of phase with motor generated voltage and there can be a resultant flashover.

While giving permissive start to a motor, there can be an accidental energization which can cause physical damages to the equipment in spite of all precautions to avoid closing of the breaker of a motor satisfying all the mandatory conditions,.

17.9 Over fluxing

At frequencies lower than the rated frequency, the speed decreases. Since the magnetic flux in the machine, which is proportional to the inverse of frequency at a particular voltage increases, locked-rotor torque also increases and power factor decreases. Also this may result in over magnetization of the core of the motor that in turn may result in overheating of the stator, due to increased iron losses. If left unchecked, further fall in frequency will result in saturation of the magnetic core thereby impairing its torque delivering capability.

This kind of protection must invariably be provided in applications where the frequency of the supply is varied in order to obtain variable speeds. All modern day variable frequency drives have this protection built into the logics and hence they are called as variable voltage variable frequency drives, VVVF drives in short.

By reducing the over fluxing of the motor, and hence the iron losses, the motor runs cooler and more efficiently, the power factor is maintained at the most appropriate value for every condition of load, which, in turn, reduces the apparent reactive power.

This will bring about a significant reduction in the apparent power demand which may reduce the input real power as well. This kind of protection is popularly known as V/Hz protection or “V / f” control.

17.10 Stall protection / acceleration time

Stall condition of a motor is the result of a hard-to-start load causing a blockage of its rotation. This results in the motor drawing heavy current without any scope for reduction on its own. One of the easiest ways to detect such conditions is sensing of the motor’s speed. It can safely be concluded that motor is stalled, if the zero speed (standstill) condition of the motor continues, even after energizing the motor. However, it may not always be feasible to provide such detection and the circuits must depend on the current drawing pattern to discriminate against a normal starting current. The motor manufacturer will give the motor’s withstanding capability. The protection must be strictly in agreement with this. Else the motor will be seriously damaged.

This majority of loads are such that the starting time of normal induction motors is about or less than 10 seconds, while the allowable stall time to avoid damage to the motor insulation is in excess of 15 seconds. It may not always be possible to distinguish this condition from a healthy starting condition on current magnitude, especially using the conventional thermal overload detection models.

A typical stalling protection circuit is able to determine stalling based on the current drawn and the duration of the current flow, instead of depending on the simulation of a thermal model, providing a reliable protection for the motor.

17.10.1 Acceleration Time

Acceleration time for electric motors is directly proportional to total inertia and inversely proportional to the electric motor torque. For electric motors with constant acceleration torque, acceleration time is:

where WK2 = rotational inertia in lb-ft2, (N2 - N1) = the speed difference, and Tx = acceleration torque in lb-ft.

Acceleration torque decreases with the motor’s voltage squared. It decreases with the load torque, which normally increases as a function of the increasing speed, and higher frictional losses and windage losses. Hence it can be summed up as a composite function of several parameters and cannot be a constant throughout its starting period. An approximation method is necessary to find the electric motor’s acceleration time if the acceleration torque is not linear during speed increase. The quickest method is to break up the speed versus torque curves of the electric motor and the driven machine into segments and calculate acceleration time for each segment. Accurate electric motor acceleration times usually result.

17.10.2 Start up supervision

Typical startup supervision includes monitoring of the time taken for the motor to draw the huge inrush current. Out of experience and through the wisdom passed on by the fore-runners, it has been a regular practice to keep the record of the starting details of various, especially critical, motors of higher rating (above 200 kW). Such a typical record would contain the date and time of starting, the supply voltage in all the three lines, starting current range, as it declines over the period of starting, the starting time – right from the breaker closure to the resumption of normal current, breaker operation counter reading etc.

However all such data is being logged by the modern day, intelligent relays and even some of them support additional information. Apart from the regular features they give information about harmonic current, thermal parameters like the equivalent heat generated etc. Based on such data it will be possible to see the time remaining for the thermal overload to act at the present load. Accordingly, the operational personnel can be warned. In case the motor trips on overload, instead of relying on the conventional number of starts, the time required for a safe restart will be made available through the algorithm incorporated in it and based on the data entered by the user & actual data acquired by it.

17.10.3 Unbalanced Supply Voltages

The voltage supplied to a three phase motor can be unbalanced for a variety of reasons: single phase loads, blown fuses in p.f. improvement capacitors etc. In addition, the accidental opening of one phase lead in the supply to the motor can leave the motor running, supplied by two phases only.

It might seem that the degree of voltage unbalance met within a normal installation (except when one phase is open circuited) would not affect the motor to any great extent, but this is not so. It should be remembered that it is not the unbalanced voltage that is important but the relatively much larger negative sequence component of the unbalance current, resulting from the unbalanced voltage.

Loss of one phase represents the most dangerous case of unbalance. It is therefore essential for motors that are protected again short circuit by fuses (limited breaking capacitor of the breaker) to be equipped with fast operating loss of phase protection.

Voltage unbalance is defined as the percentage maximum voltage deviation from average voltage with respect to the average voltage. Higher voltage unbalances will result in reduced efficiency, overheating of the motor calling for derating of the power rating of the motor. This is because, rated performance of polyphase motors assumes a balanced power supply at the motor terminals and hence, unbalanced voltage affects the motor’s current, speed, torque, temperature rise and efficiency. A minor voltage unbalance in voltage significantly increases the losses and reduces the efficiency considerably. For instance, it is noticed that the usage an energy efficient motor that can reduce the losses by 20 % was offset by a voltage unabalance of 3.5 % on the energy front

NEMA Standard MG 1–14.35, recommends the derating of the motor where the voltage unbalance is between 1% and 5% beyond which operation shall not continue.

Basically, unbalanced voltages, single phasing in the extreme case, will give rise to a pulsating flux in the rotor bars. This will result in uneven heating of the rotor bars and hence localized overheating will be taking place. Uneven expansion due to the localized heat of the rotor bars can be detrimental to the rotor’s integrity. This can result in the development of cracks ending up finally as rotor bar failures.

However this kind of protection against unbalanced voltages will safeguard the motor against an unbalance based on the magnitude of the voltages. This can turn out to be a sort-of-overbearing for the motor. The motor may be able to continue in service, satisfactorily, even with an appreciable amount of unbalance - that may not result in too dangerous overheating. To detect whether the unbalance can have a deleterious effect or not, it is required to analyze the three phase voltages both by means of the phase angle as well as magnitude difference, not just magnitude alone. This gives a picture about the quantum of negative sequence currents that are present, which will be contributing to the ultimate additional overheating of the rotor winding.

17.11 Negative sequence currents

Analysis of negative sequence currents (one of the three symmetrical components of any type of current) are particularly of more importance in the case of large rating motors (1000 HP and above). Symmetrical components of three phase currents consist of:

  • Positive-sequence currents: normally present during a typical steady state condition.
  • Negative-sequence currents: present only during unbalance.
  • Zero-sequence currents: present only when earth is also involved in the unbalance.

Negative- and zero-sequence currents are usually only present in substantial levels during unbalanced, faulted conditions.

Figure 17.11
The Positive, Negative and Zero Components

The method of symmetrical components consists of reducing any unbalanced three phase systems of vectors into three balanced systems: the positive, negative and zero sequence components. The positive sequence components consist of three vectors equal in magnitude 120° out of phase, with the same phase sequence or rotation as that of the source of supply. The negative sequence components are three vectors equal in magnitude, displayed by 120° with a phase sequence opposite to the positive sequence. The zero sequence components consist of three vectors equal in magnitude and in a phase.

Larger rating motors are more prone to dangers arising out of negative sequence currents flowing. The presence of negative sequence can be expressed as a percentage with respect to the positive sequence currents.

Based on this value, the motor rating needs to be derated. The derating effect is more pronounced in the case of motors with high starting current to running current ratio. For example a motor with this ratio as 6 (starting current = 6 times the full load current) needs to be derated by 20 % for an unbalance (100 * negative sequence current / positive sequence current) of 5 %. For the same level of unbalance, a motor with this ratio as 4 needs to be derated by less than 10 %.

The reduction in output for the machines having ratios of starting to running current of 4, 6 and 8 respectively is shown in figure 17.12.

Figure 17.12
Maximum continuous output versus voltage unbalance

17.12 Derating Factors

The performance of AC induction motors, or for that sake any equipment, is influenced by various factors like ambient temperature, quality of the incoming power supply etc. these factors need to be specified explicitly while procuring, especially when the operating conditions differ widely from the standard values. For instance, when an induction motor is required to be operated at an ambient temperature exceeding 40 degree C, it must be clearly spelled out at the procurement stage itself.

Once a standard motor is available and needs to be utilized for an application with the operating conditions differing from the originally intended ones, the motor’s rating has to be suitably derated.

The factors that need to be considered in derating a motor’s performance are:

  • Supply Voltage
  • Supply Frequency
  • Ambient Temperature
  • Altitude of the location of installation

AC motors are designed to operate on voltages and frequencies that are well standardized. For example, NEMA standards specify voltage ratings of 380 V, 400 V, 415 V … at 50 Hz. Similarly, for 60 Hz of supply frequency, voltage ratings of 115 V, 200 V, 230 V, 460 V, 575 V are standardized.

A small variation in supply voltage can have a great influence on a motor’s performance. For example, when the voltage is 10% below the rated voltage of the motor, the motor has 20% less starting torque. This reduced voltage may prevent the motor from getting its load started or keeping it running at rated speed. A 10% increase in supply voltage, on the other hand, increases the starting torque by 20%. This increased torque may cause damage during startup. A conveyor, for example, may lurch forward at startup.

A voltage variation will cause similar changes in the motor’s starting amps, full-load amps, and temperature rise. It can be generalized that a 10 % rise in voltage will result in an increase in motor performance of 20 %.

In the same way, an increase in frequency of 5 % results in a corresponding increase in the speed and a 10 % decrease in the motor starting torque. Conversely, a decrease in the supply frequency by 5 % results in a proportionate reduction in speed and a 11 % increase in the starting torque. Hence suitable corrections have to be applied to the standard motors accordingly.

Standard motors are designed to operate below 3300 feet (1000 m). The motors operating at temperatures above 1000 meters have to be derated because of the impaired cooling of the motor due to the light air at higher altitudes. The thin air at higher altitudes will have less cooling effect on the motor as the net heat transfer, due to the reduced air mass, goes down. At an altitude of above 5000 ft, the derating factor becomes 0.94. Roughly for every 1600 feet rise in altitude, the derating factor reduces by 0.04.

17.13 Earth Faults – Core Balance, Residual Stabilising Resistors

Faults that occur within the motor windings are mainly earth faults caused by a breakdown in the winding insulation. This type of fault can be very easily detected by means of an instantaneous relay, usually with a setting of approximately 20% of the motor full load current, connected in the residual circuit of three current transformers.

It is important to note that unbalanced load currents do not cause nuisance earth-fault trips. If there is no leakage to earth, unbalanced load currents add to zero and do not cause an output from a core-balance CT.

Figure 17.13
Earth fault protection

Care must be taken to ensure that the relay does not operate from spill current due to the saturation of one or more current transformers during the initial peak of the starting current; this can be as high as 2.5 times the steady state r.m.s value, and may cause operation, given the fast operating speed of the normal relay. To achieve stability under these conditions, it is usual to increase the minimum operating voltage of the relay by inserting a stabilizing resistor in series with it (refer figure 17.13).

Current sensing is the best method to detect and locate earth faults. However, system capacitance, unbalanced loads, current-sensor limitations, and harmonics affect current measurement and limit the lower level of practical earth-fault detection.

Current flowing to earth has only two paths—it can flow to earth through an earth fault or it can flow to earth through distributed capacitance. Current flowing to earth through distributed capacitance can cause sympathetic tripping during an earth fault and it can cause nuisance tripping during normal operation. If the earth-fault trip level is high enough to eliminate sympathetic tripping, nuisance tripping due to unbalanced and harmonic capacitive current is usually not a problem. Charging current is defined as the current that flows to earth when one phase of an unearthed system is faulted to earth.

When a motor is started across the line, the inrush current can have a DC-offset component that can cause an output from a core-balance current transformer. Such transient characteristics are unpredictable because the switch can close at any point in the electrical cycle. Transient conditions typically last less than 100 ms and nuisance earth-fault trips can be avoided by setting a longer trip delay time or by using a digital filter to reject the dc component. All current transformers, including the window-type core-balance CTs used to detect earth-fault (zero-sequence) current, have practical limitations. A minimum excitation current is required in the primary coil before there can be a proportional output current. Excitation current is a function of burden, CT construction, and size. Sensitive earth-fault detection requires excitation current to be small. A large fault current, such as a phase-to-phase fault or an earth fault on a solidly earthed system, can saturate a current transformer. Saturation occurs when a CT cannot maintain a secondary current waveform proportional to a large primary current. Secondary current characteristics in this case are unpredictable and earth-fault protection may not operate. Stability against external faults is guaranteed thanks to the use of a stabilizing resistor.

To detect high-impedance faults and provide machine-winding protection, the earth-fault current pickup level should be less than 20% of the prospective earth-fault current. The pickup level of all system earth-fault protection devices should be the same, and coordination should be accomplished by varying trip delay times.

17.14 Calculation of protective relay settings

A digital motor protection relays, typically, require the following details to be entered / programmed into the unit (the appropriate calculations / justifications for the settings are indicated in the remarks column). As an example, protective relay (microprocessor based relay) settings for a 700 kW, 3.3 kV, 147A squirrel cage induction motor driving a fan having an acceleration time of 44 seconds is considered and the settings will be as shown in Table 17.2:

Table 17.2
Protective Relay Settings

However, most recent developments have made this new generation, digital (microprocessor based) relays much more intelligent, requiring very few parameters to be set by the user at site. At the same time they provide very fast, reliable response in clearing the faults.

ANSI Device numbers used in these circuits:

12 = Over speed

24 = Over excitation

25 = Synchronization check

27 = Bus/Line under voltage

32 = Reverse power (anti-motoring)

38 = Over temperature (RTD)

39 = Bearing vibration

40 = Loss of excitation

46 = Negative sequence / unbalance (phase current imbalance)

47 = Negative sequence under voltage (phase voltage imbalance)

49 = Bearing over temp (RTD)

50 = Instantaneous over current

51 = Time over current

51V = Time over current -- voltage restrained

55 = Power factor

59 = Bus over voltage

60FL = Voltage transformer fuse failure

67 = Phase/Ground directional current

79 = Auto re-close

81 = Bus over / under frequency

37 = Under current

48 = Incomplete Sequence

49S (26) = Locked Rotor

49/51 = Over load

50 = Short Circuit

50GS/51GS = Ground Fault

51R = Jam (Running)

59 = Over voltage

60V = Voltage unbalance

62 = Timer

66 = Successive

81L/H = Under-and Over frequency

87M = Differential

86M = Lock-out Auxiliary

Addl. Protection for a Synchronous motor:

26F = Ammortisseur Winding Over temperature (Include if field is accessible)

27DC = Under voltage Relay

37 = Undercurrent

50 = Short Circuit

55 = Out of Step Protection/Power Factor

95 = Reluctance Torque Synchronizing and Re-Synchronizing

96 = Auto loading/Unloading Relay

Figure 17.14
Typical protection logics for a Synchronous motor
Figure 17.15
Typical protection logics for an Induction motor

17.15 Example : GE Multilin 239 Motor Protection System

As a sample case, this section discusses the GE Multilin 239 Motor protection system.

The GE Multilin 239 relay is designed to fully protect three phase AC motors against conditions which can cause damage. In addition to motor protection, the relay has features that can protect associated mechanical equipment, give an alarm before damage results from a process malfunction, diagnose problems after a fault and allow verification of correct relay operation during routine maintenance. Using the ModBus serial communications interface, motor starters throughout a plant can be connected to a central control/monitoring system for continuous monitoring and fast fault diagnosis of a complete process.

One relay is required per motor. Since phase current is monitored through current transformers, motors of any line voltage can be protected. The relay is used as a pilot device to cause a contactor or breaker to open under fault conditions; that is, it does not carry the primary motor current. When the over temperature option is ordered, up to 3 RTDs can be monitored. These can all be in the stator or 1 in the stator and 2 in the bearings. Installing a 239 in a motor starter for protection and monitoring of motors will minimize downtime due to process problems.

Overload (15 selectable curves) Status/current/temperature display
Short circuit Fault diagnosis
Locked rotor Trip record
Stall / mechanical jam Memory lockout
Repeated starts (Mod 505) Thermal capacity / load% / RTD analog
Single phase / unbalance output
Ground fault Trip / alarm / auxiliary / service relay outputs
Overtemperature (Thermistor & 3 RTDs) Motor Running Hours
Undercurrent Motor maximum current on last start
Overload warning Simulation mode for field testing
Breaker failure Clear LCD display
  RS485 Modbus communications interface
  AC/DC control power
  Compact size, fits most starters
  Update options and/or MODs in field
  CSA/UL Approved
  Conformal coating for harsh environment


Generator protection

18.1 Introduction

A generator is the heart of an electrical power system, as it converts mechanical energy into its electrical equivalent, which is further distributed at various voltages. It therefore requires a ‘prime mover’ to develop this mechanical power and this can take the form of steam, gas or water turbines or diesel engines.

Steam turbines are used virtually exclusively by the main power utilities, whereas in industry, three main types of prime movers are in use:

  • Steam turbines–normally found where waste steam is available and used for base load or standby
  • Gas turbines–generally used for peak-lopping or mobile applications
  • Diesel engines–most popular as standby plant

Small and medium sized generators are normally connected directly to the distribution system, whilst larger units are connected to the EHV grid via a transformer (see Figure 18.1 and Figure 18.2).

Figure 18.1
Small and medium size generators
Figure 18.2
Larger generating units

It will be appreciated that a modern large generating unit is a complex system, comprised of a number of components:

  • Stator winding with associated main and unit transformers
  • Rotor with its field winding and exciters
  • Turbine with its boiler, condenser, auxiliary fans and pumps

Many different faults can occur in this system, for which diverse protection means are required. These can be grouped into two categories:

Electrical Mechanical
Stator insulation failure Failure of prime mover
Overload Low condenser vacuum
Over voltage Lubrication oil failure
Unbalanced load Loss of boiler firing
Rotor faults Over speeding
Loss of excitation Rotor distortion
Loss of synchronism Excessive vibration

We will look briefly at the electrical side in this chapter.

18.2 Stator grounding and ground faults

The neutral point of the generator stator winding is normally grounded so that it can be protected, and impedance is generally used to limit ground fault current.

The stator insulation failure can lead to ground faults in the system. Severe arcing to the machine core could burn the iron at the point of fault and weld laminations together. In the worst case, it could be necessary to rebuild the core down to the fault necessitating a major strip-down.

Practice, as to the degree of limitation of the ground fault current varies from rated load current to low values such as 5 amps.

Generators connected direct to the distribution network are usually grounded through a resistor. However, the larger generator–transformer unit (which can be regarded as isolated from the EHV transmission system) is normally grounded through the primary winding of a voltage transformer, the secondary winding being loaded with a low ohmic value resistor. Its reflected resistance is very high (proportional to the turns ratio squared) and it prevents high transient over voltages being produced as the result of an arcing ground fault.

When connected directly through impedance, over current relays of both instantaneous and time delayed type are used. A setting of 10% of the maximum ground fault current is considered the safest setting, and is normally enough to avoid spurious operations due to the transient surge currents transmitted through the system capacitance. The time delay relay has a value of 5%.

Ground fault protection can be applied by using a transformer and adopting a relay to measure the grounding transformer secondary current or by connecting a voltage operated relay in parallel with the loading resistor (see Figure 18.3).

Figure 18.3
Ground fault protection using a relay to measure secondary current

The current operated relay should incorporate a third harmonic filter and is normally set for about 5% of the maximum ground fault current. The third harmonic filter is required because of the low current of the grounding system, which may not be much different from the possible third harmonic current under normal conditions. The time delay is essential to avoid trips due to surges (see Figure 18.4).

Figure 18.4
Ground fault protection using a relay in parallel with loading resistor

In the voltage-operated type, a standard induction disc type over voltage relay is used. It is also to be noted that the relay is connected across the secondary winding of the transformer and the relay shall be suitably rated for the higher continuous operating voltage. Further, the relay is to be insensitive for third harmonic current.

Phase-to-phase faults clear of ground are less common. They may occur on the end coils or on adjacent conductors in the same slot. In the latter case, the fault would involve ground in a very short time.

18.3 Overload protection

Generators are very rarely troubled by overload, as the amount of power they can deliver is a function of the prime mover, which is continuously monitored by its governors and regulator.

Where overload protection is provided, it usually takes the form of a thermocouple or thermistor embedded in the stator winding. The rotor winding is checked by measuring the resistance of the field winding.

18.4 Overcurrent protection

It is normal practice to apply IDMTL relays for over current protection, not for thermal protection of the machine but as a ‘back-up’ feature to operate only under fault conditions.

In the case of a single machine feeding an isolated system, this relay could be connected to a single CT in the neutral end in order to cover a winding fault.

With multiple generators in parallel, there is difficulty in arriving at a suitable setting so the relays are then connected to line side CTs.

18.5 Overvoltage protection

Overvoltage can occur as either a high-speed transient or a sustained condition at system frequency.

The former are normally covered by surge arrestors at strategic points on the system or alternatively at the generator terminals depending on the relative capacitance coupling of the generator / transformer, and connections, etc.

Power frequency overvoltages are normally the result of:

  • Defective voltage regulator
  • Manual control error (sudden variation of load)
  • Sudden loss of load due to other circuit tripping

Overvoltage protection is therefore only applied to unattended automatic machines, at say a hydroelectric station. The normal settings adopted are quite high, almost equal to 150% but have instantaneous operation.

18.6 Unbalanced loading

A three-phase balanced load produces a reaction field, which is approximately constant, rotating synchronously with the rotor field system.

Any unbalanced condition can be broken down into positive, negative and zero sequence components.

The positive component behaves similarly to the balanced load. The zero components produce no main armature reaction.

However, the negative component creates a reaction field, which rotates counter to the DC field, and hence produces a flux, which cuts the rotor at twice the rotational velocity. This induces double frequency currents in the field system and rotor body.

The resulting eddy-currents are very large, so severe that excessive heating occurs, quickly heating the brass rotor slot wedges to the softening point where they are susceptible to being extruded under centrifugal force until they stand above the rotor surface, in danger of striking the stator iron.

It is therefore very important that negative phase sequence protection be installed, to protect against unbalanced loading and its consequences.

18.7 Rotor faults

The rotor has a DC supply fed onto its winding which sets up a standing flux. When this flux is rotated by the prime mover, it cuts the stator winding to induce current and voltage therein.

This DC supply from the exciter need not be grounded. If a ground fault occurs, no fault current will flow and the machine can continue to run indefinitely; however, one would be unaware of this condition. Danger then arises if a second ground fault occurs at another point in the winding, thereby shorting out a portion of the winding. This will cause the field current to increase and be diverted, burning out conductors.

In addition, the fluxes become distorted, resulting in unbalanced mechanical forces on the rotor causing violent vibrations, which may damage the bearings and even displace the rotor by an amount, which would cause it to foul the stator.

It is therefore important that rotor ground fault protection be installed. This can be done in a variety of ways.

18.7.1 Potentiometer method

The field winding is connected with a resistance with a centre tap. The tap point is connected to the ground through a sensitive relay R. A ground fault in the field winding produces a voltage across the relay.

The maximum voltage occurs for faults at end of the windings. However, there is a chance that faults at the centre of the winding may go undetected. Hence, one lower tap is provided in the resistance. Though normally, the centre tap is connected, a pushbutton or a bypass switch is used to check for faults at the center of winding. A proper operating procedure should be established to ensure that this changeover is done at least once a day (see Figure 18.5 (a)).

Figure 18.5 (a)

18.7.2 AC injection method

This method requires an auxiliary supply, which is injected to the field circuit through a coupling capacitance. The capacitor prevents the chances of higher DC current passing through the transformer. A ground fault at any part of the winding gives rise to the field current, which is detected by the sensitive relay. Care should be taken to ensure that the bearings are insulated, since there is a constant current flowing to the ground through the capacitance (see Figure 18.5 (b)).

Figure 18.5 (b)
AC injection

18.7.3 DC injection method

This method avoids the capacitance currents by rectifying the injection voltage adopted in the previous method. The auxiliary voltage is used to bias the field voltage to be negative with respect to the ground. A ground fault causes the fault current to flow through the DC power unit, causing the sensitive relay to operate under fault conditions (see Figure 18.5 (c)).

Figure 18.5 (c)
DC injection

18.8 Reverse power

Reverse power protection is applicable when generators run in parallel, and protects against the failure of the prime mover. Should this fail, the generator would run the motor by taking power from the system and could aggravate the failure of the mechanical drive.

18.9 Loss of excitation

If the rotor field system should fail for whatever reason, the generator would then operate as an induction generator, continuing to generate power determined by the load setting of the turbine governor. It would be operating at a slip frequency and although there would be no immediate danger to the set, heating would occur, as the machine would not have been designed to run continuously in such an asynchronous fashion. Some form of field failure detection is thus required, and on the larger machines, this is augmented by an MHO type impedance relay to detect this condition on the primary side.

18.10 Loss of synchronisation

A generator could lose synchronism with the power system because of a severe system fault disturbance, or operation at a high load with a leading power factor. This shock may cause the rotor to oscillate, with consequent variations of current, voltage and power factor. If the angular displacement of the rotor exceeds the stable limit, the rotor will slip a pole pitch.

If the disturbance has passed by the time this pole slip occurs, then the machine may regain synchronism; otherwise it must be isolated from the system.

Alternatively, trip the field switch to run the machine as an asynchronous generator, reduce the field excitation and load, then re-close the field switch to re-synchronize smoothly.

18.11 Field suppression

It is obvious that if a machine develops a fault, the field should be suppressed as quickly as possible, otherwise the generator will continue to feed its own fault and increase the damage. Removing the motive power will not help in view of the large kinetic energy of the machine.

The field cannot be destroyed immediately and the flux energy must be dissipated without causing excessive inductive voltage rise in the field circuit.

For small to medium sized machines, this can be satisfactorily achieved using an automatic air circuit breaker with blow-out contacts. On larger sets, above say 5 MVA, a field discharge resistor is used.

18.12 Industrial generator protection

The various methods discussed above are normally applicable for protection of an industrial generator. The following sketch shows the various protection schemes employed in an industrial environment. Of course, not all protections are adopted for every generator since the cost of the installation decides the economic feasibility of the protection required. Note that the differential relay (though not discussed separately in this chapter) is normally necessary for generators in the range of megawatts (see Figure 18.6).

Figure 18.6
Typical protection scheme for industrial generator

18.13 Numerical relays

The above paragraphs described the use of individual relays for different fault conditions. However, the modern numerical relays combine most of the above functions in a single relay with programming features that make them useful for any capacity generator.

The numerical relays are manufactured by all the leading relay manufacturers. The various protection functions that are available in a typical numerical relay are as below (see Figure 18.7).

  • - Inverse time overcurrent
  • - Voltage restrained phase overcurrent
  • - Negative sequence overcurrent
  • - Ground overcurrent
  • - Phase differential
  • - Ground directional
  • - High-set phase overcurrent
  • - Undervoltage
  • - Overvoltage
  • - Volts/Hertz
  • - Phase reversal
  • - Under frequency
  • - Over frequency
  • - Neutral overvoltage (fundamental)
  • - Neutral undervoltage (3rd harmonic)
  • - Loss of excitation
  • - Distance elements
  • - Low forward power
Figure 18.7
Generator protection relay by GE

The relays can also develop the thermal model for the generators being protected, based on the safe stall time, previous start performances, etc., which is used to prevent the restart attempt of the generator under abnormal conditions or after a few unsuccessful starts/trips.

In addition to the various protection functions, these numerical relays also record generator output figures such as voltage, current, active power, reactive power, power factor, temperature of stator/rotor windings, etc., on a continuous basis. Hence, the numerical relays are increasingly finding applications in modern industries.

Microprocessor based relays are capable of providing additional protection functions within a single hardware platform. The following functions are currently supported in the commercially available protection relays

  • Field ground fault detection ( 64 F)
  • Brush lift-off detection (64B)
  • Out-of-step protection ( 78)
  • Turn-to-turn stator winding fault detection using split phase differential (50DT)
  • Neutral overall turn-to-turn fault detection ( 59 N)

18.13.1 Field ground fault detection

The field circuit of a generator is an ungrounded DC system. In general, a single ground fault will not affect the operations of a generator – but it will establish a ground reference and possibly affect the field insulation. This increases the probability of a second fault during which a portion of the field winding will be short circuited, eventually causing damage to the generator.

A microprocessor based multifunction relay can provide automatic tripping using an injection principle.

Figure 18.8
Field ground protection using an injection voltage signal

As shown in Figure 18.8, a 15 volt squared signal is injected into the field. The return signal waveform is modified due to its field winding capacitance. The injection frequency setting is adjusted (0.1 to 1.0 Hz) to compensate for field winding capacitance. From the input and return voltage signals, the relay calculates the field insulation resistance. The relay setpoints are in ohms typically with a 20 KΩ alarm and 5 KΩ trip or critical alarm.

18.13.2 Brush lift-off detection

The use of the injection method for field ground detection provides a means of detecting how well the brushes of a generator are making contact with the rotor shaft. This is done by analyzing the return voltage signal. Such an analysis can provide an indication that the brushes on a generator are not making good contact with the rotor. Figure 18.9 shows the analysis method. The front of the return voltage signal is rounded due to the field winding capacitance. When the brushes begin to open, they create a higher contact resistance causing the voltage to rise. The level of voltage is measured at a fixed point on the return voltage signal. When the voltage rises above its normal value, an alarm is initiated.

Figure 18.9
Brush lift-off voltage

18.13.3 Out of step generator protection

Though out-of-step relaying protection existed on transmission lines, there were few applications to cover the increasingly common situation where the electric center of a power system disturbance passes right through the generator unit step-up transformer or the generator itself. This variation in impedance can be detected by distance type relays. The best way to visualize and detect out-of-step generator phenomenon is to analyze apparent impedance variations with time as viewed at the terminals of the generator. This apparent impedance locus depends on the type of governor and excitation system of the unit as well as the type of fault which initiated the impedance swing.

18.13.4 Turn-to-Turn stator winding fault detection using split-phase differential

On generators with multi-turn coils and two or more windings per phase, a split-phase relay scheme can be used to detect turn-to-turn faults. This is a particularly popular winding design on hydro generators. In this protection scheme, the currents in each phase of the stator windings are split into two equal groups and the currents of each group compared. A difference in these currents indicates an unbalance caused by a turn-to-turn fault. A definite time overcurrent relay is used for this scheme. The overcurrent pickup is set above any normal unbalance current but below the unbalance caused by a single shorted turn. The time delay is set to prevent operation for transients occurring during external faults caused by unequal CT response. Any expected problem with CT error can be eliminated by the user of a window CT. The elimination of CT errors will permit the use of a more sensitive setting. Split –phase protection will detect phase and some ground faults in the stator winding. However, because of the time delay, it is normally used to supplement high-speed differential protection for high magnitude phase faults.

18.13.5 Neutral overall Turn-to-Turn fault detection (59N)

For generators where the stator winding configuration does not allow the application of split-phase differential, a neutral voltage method can be used to detect turn-to-turn stator winding faults. As shown in Figure 18.10, VT is connected in wye and the primary ground lead is tied to the generator neutral. The secondary is connected in a “broken delta” with an overvoltage relay connected across its open delta to measure 3E0 voltage. By connecting the primary ground lead to the generator neutral, the 59N relay is made insensitive to the stator ground faults. The relay will, however, operate for turn-to-turn faults which increase the 3E0 voltage above low normal levels. Installation requires the cable from the neutral of the VT to generator neutral be insulated for the system line-to-ground voltage and the 59N relay to be turned to the fundamental (60Hz) voltage since some third-harmonic voltages will be present across the broken delta input.

Figure 18.10
Turn-to-Turn stator winding fault protection using neutral overvoltage method

18.14 Parallel operation with grid

In modern industries and continuous process plants, it is customary to have the plant generators (gas/steam turbine or diesel engine driven) operate in parallel with the grid to ensure uninterrupted power to essential loads. The basic protection employed in such systems are reverse power relays, which are used basically to protect the grid from faulty generators operating as motors.

It is also quite common to see these systems provided with an ‘islanding’ feature, which enables the unstable grid to be isolated from the stable generating sets. The protection employed in such cases is under frequency and dv/df , which are basically the effects of grid disturbances.

It is also common that power is exported to the grid from the industrial generators, when power is generated in excess of the demand. The protective systems employed in all such cases should be discussed with supply authorities to ensure that all protective functions as required by local regulations are met.


Cables and Protection

19.1 Introduction

Cable is a general term used to denote a bundle of wires, such as wire ropes. An electrical cable is a bundle of electrical conductors used for carrying electricity. An insulated cable has a covering of an insulating material over the conductor in order to protect persons from direct contact with the electrical conductor, thus reducing the risk of an electric shock. Though the term cable does not automatically imply insulation or even an electrical conductor, in current electro-technical terminology, a cable is taken to mean an insulated current carrying conductor. In this text, the term cable will be solely used to represent such a conductor.

The power produced at generating stations is transmitted and distributed to the users’ factories or houses for their use/consumption. This is made possible by the use of overhead transmission lines or by the use of electric cables, which connect the utility station and the users’ loads. Overhead transmission lines comprise of an open system of conductors made from steel and aluminum or copper wires strung over porcelain or ceramic insulators. Figure 19.1 shows a typical high voltage overhead transmission line system terminating at a substation:

Figure 19.1
Typical view of an overhead transmission line terminating at a substation

Electric cables comprise of copper or aluminum wires with layers of insulating materials over the conductors. Figure 19.2 shows a typical view of a high voltage cable for 33kV application:

Figure 19.2
Typical view of a 33kV, Cross-linked polyethylene cable

Overhead transmission lines cannot be installed at all applications due to reasons attributable to environment, space requirement, safe clearances etc.; likewise, cables cannot be used in all applications for reasons attributable to economic voltage level, distance etc.

Therefore, it has become the practice to use cables for low voltage and medium voltage for power distribution in cities and other crowded habitats; however, overhead lines are used in rural areas for power distribution both in low and medium voltages. Power distribution in large industrial plants invariably use cables for all voltages (the voltage rarely goes beyond 33 kV) since the use of overhead lines would be difficult and cumbersome. Power transmission which is the responsibility of utilities, is invariably done using overhead transmission lines and is usually at high and extra-high voltage. In large cities, cables of high and extra high voltages (up to 220 kV) are also used for the sub-transmission system due to difficulties in installing overhead conductors, as the lines require considerable space for ensuring safe clearances with nearby structures. Over a period, overhead lines would be eliminated in our cities for various reasons (some explained above) and high voltage cables will replace them. Due to restrictions of location, all outdoor substations inside cities will be converted into compact gas insulated indoor substations and most new substations will in future be the indoor type. High voltage cables will play a crucial role in such cases i.e., for interconnections to and from indoor substations.

19.2 Advantages of cables over overhead transmission lines

In general, we can note that high voltage cables have the following advantages over the overhead transmission lines:

  • In crowded metros, overhead transmission lines occupy a large footprint, and apart from looking grotesque, pose safety problems. Requirement of a large area calls for land space as well as clearances around the conductors (referred to often as ‘a power alley’). This is becoming increasingly difficult to provide in today’s crowded metropolitan cities and their satellite townships. In such cases, high voltages cables offer the advantage of installation in cable trenches or underground cable tunnels thereby freeing valuable land space over ground. The cables can also be buried directly in ground preferably routed in the space provided along side the roads called the “berm“. Freeing of land space has helped in the saving of cumbersome land acquisition procedures and associated litigation issues.
  • Ecological restrictions as well as very high real estate costs favor the installation of high voltage cable systems. Sometimes, the objections include visual pollution of an area of natural scenic beauty or a historic site by the incongruous transmission structures. Another problem is the high electromagnetic interference associated with exposed electrical lines.
  • In areas prone to atmospheric lighting discharges, the overhead transmission lines suffer frequent breakdown and cause power outages. High voltage cables are not affected by the above atmospheric discharges, as they are either buried in the ground or routed inside a tunnel or trench.
  • Due to higher surge impedance, high voltage cables offer increased protection from switching surges to various equipment, mainly transformers in installations such as outdoor switchyards.
  • For power supply to small islands, it is only possible to transmit power through underwater high voltage cables, as overhead transmission lines are ruled out in such applications.

19.3 Disadvantages of cables in power transmission

While we saw high voltage cables score over overhead transmission lines in a few situations, they also suffer from a few disadvantages:

  • Location of fault in a high voltage cable system is more difficult compared to an overhead transmission line system.
  • High voltage cable systems are expensive in voltage levels higher than 33kV when compared to overhead transmission line systems either for the purpose of intra-plant distribution or for interplant transmission of power.
  • High voltage cables of the oil filled type call for monitoring and inspection schedules which need to be implemented strictly. In the case of overhead transmission lines, such schedules are less stringent and rectification, if needed, is easier in comparison to the cable systems.
  • Cable joints and terminations are expensive and require factory trained and skilled technicians for their installation. In comparison, jointing and termination in overhead transmission line systems are straightforward and simple.
  • The joints and terminations in the high voltage cable system pose a cause for worry to the maintenance personnel since they are the weakest links in the otherwise robust electrical system. This calls for constant monitoring of the joints and terminations.
  • Testing of high voltage cable systems is a time consuming process compared to testing of overhead transmission line systems.

Therefore, we can conclude that selection of transmission system requires elaborate research and the choice of high voltage cables or overhead systems should be made judiciously.

19.4 Types of cables

We can classify high voltage cables broadly into different types based on the insulation medium used. These are:

  • PVC insulated cables
  • VIR insulated cables
  • Low pressure oil filled cables
  • High pressure oil filled cables
  • Paper insulated cables
  • Polyethylene (PE) insulated cables
  • Cross linked polyethylene (XLPE) cables

Cables can also be classified according to the voltage grades, such as low voltage cables, medium voltage cables, high voltage (HV) cables and extra high voltage (EHV) cables, which in turn is decided by the system voltage where a cable is used. In fact, the type of insulation discussed above is very much dependent on the voltage grade of the cable. The voltage grade based classification can however vary between different countries as no uniform classification is followed internationally. In the forthcoming chapters, we would learn more about the construction and use of these various cables. While MV and HV cables are very common in industrial plant applications, the use of EHV cables is almost restricted to utilities in distribution circuits.

Power cables are also grouped according to the number of cores: single-core, 2-core, 3-core and so on. Multi-core cables are commonly used only up to MV levels. HV and EHV cables are always of the single core type.

19.5 Cable jointing (splicing) accessories

Cable manufacturers produce cables in standard lengths ranging from 300m to 1000m and deliver them to the customers wound on drums. The above lengths depend on the type and unit weight (kg/m) of the cable that is being manufactured. The weight of the cable drums is substantial and a typical drum with 500m of 3cx240 sq. mm of XLPE insulated cable can weigh up to 7500 kg. This introduces a bottleneck in terms of the handling capacity at the cable factory. In addition, large unwieldy drums can pose problems during transportation and installation of the cables at site. Thus, cables need to be supplied in pre-agreed lengths. If the feeder length in any system exceeds the standard lengths, it is necessary to use multiple lengths of cable for that feeder; this is when joints are needed. Cable joints as the name implies, joins the tail end of the first cable and the head end of the second cable. Cable companies themselves, or some other manufacturers who specialize only in joints, offer “jointing kits”. We use these kits whenever we need a joint. Also in the case of cable failure in an existing installation, it would be prudent to remove the damaged portion and replace this section with a new length by jointing to the healthy portions of the cables.

Every user would prefer to install their cables without joints, but due to inevitable reasons (some explained above), cable joints become a necessity. In general, users feel that a cable joint is a weak point in the distribution chain. On the contrary, jointing kit manufacturers vouch that a properly made joint is as good as the original cable. In addition, joints are required when two cables of dissimilar construction are to be jointed. This happens when an expansion takes place in an existing factory. Likewise, “T” joints are required in certain distribution schemes. Another type of joint is the “branch Y” joint which is used in a few applications.

We can group the various types of joints broadly as:

  • Straight through
  • Branch Y joints
  • T joints
  • Transition joints

Depending on the type of insulation of the cable under use, there are further variations in the above types. Also, distinction is sometimes decided in terms of the location where the joints are made, namely, indoor types or outdoor types. We will study the various types of jointing kits in the forthcoming chapters.

Figure 19.3 shows typical variants of cable joints:

Figure 19.3
Various types of cable joints

19.6 Need for termination kits

Cables also need special kits for the purpose of their termination at sending end and at receiving end. Every cable, whether it is low-tension type or high-tension type, needs proper termination so that a cable run can be connected to a piece of equipment, usually a circuit breaker, a transformer, or a motor and so on. There are basic requirements such as cable boot, cable lugs and consumables like insulation tapes and cable glands used for low voltage cables etc. In the case of high voltage cables there are other accessories related to sealing, stress control etc. These are called “termination kits”, which can be either procured from the cable manufacturers or from specialized manufacturers of jointing kits as mentioned above, who also make the termination kits. These aspects will be discussed in detail in the forthcoming chapters. In addition, basic types of termination kits vary with respect to their location: indoor or outdoor.

Proper termination kits with proven test results are of great importance in order to provide faultless terminations. An improperly made termination would result in the heating of the joint and eventual flashover and outage in the systems.

The manuals supplied with the kits give a systematic procedure for going ahead with the preparation and completion of the termination. Besides the manual, some amount of hands-on training is also needed to carry out a sound job. Figure 19.4 shows a typical high voltage cable termination arrangement:

Figure 19.4
Typical HV cable termination

We can group the various types of termination kits broadly as:

  • Indoor termination kits
  • Outdoor termination kits (the arrangement shown in the figure above)
  • End sealing kits

The first two types explained above are for active terminations. The third type, namely, the end sealing kit, is used whenever cable ends are to be left without use for a long time. As with cables, there is also a continuous improvement in the field of cable accessories such as jointing and termination kits. There are new composite type insulator designs, which have greatly reduced weights and provide extra creepage distances. These insulators are of the self-cleaning type with excellent properties in areas of fire resisting capability and UV radiation resisting capability.

Cables need to be jointed and/or terminated by skilled technicians who use standard jointing/termination kits. We will study the various types of termination kits in later chapters.

19.7 Types of Failures

High voltage cable networks represent a major capital asset in electricity companies and industries. Failures of cable systems are disruptive, expensive and hazardous to personnel. They disrupt business processes and increase the overall cost of the system. While some of the failures are not so common, it is invariably possible to identify some shortcomings in design, installation, operation and maintenance practices as being the reasons for such failures. Cable failures may be primarily classified as mechanical failures and electrical failures. Figure 19.5 provides the statistical results of the causes for cable failures in a large utility system having huge cable networks. It can be seen that damages due to non electrical causes and cable joints constitute 95% of the causes of cable failures:

Figure 19.5
Reasons for Cable system failures

19.7.1 Electrical Failures

Failures on account of electrical phenomena come under this classification. These are failures due to:

  • Partial discharge
  • Excessive heating due to overloads
  • Short circuits
  • Lightning surges
  • Insulation failure due to voltage stress
  • Insulation failure due to moisture ingress

19.7.2 Mechanical Failures

Mechanical damages are mostly due to activities or work near underground cables (directly buried type) that inadvertently lead to damaging of cable insulation and/or conductors. Examples for mechanical damages are:

  • Damages inflicted by digging operations
  • Stresses due to passage of heavy vehicles on top of earth beneath which cables are buried
  • Damages due to heavy vibration from adjacent rail tracks
  • Loose connection in joints and terminations
  • Stresses due to insufficient bending radius
  • Insulation damage due to chemical attacks, rodents etc.

19.8 Reasons for Failures

Cable failures can usually be attributed to shortcomings in design, installation, operation and maintenance practices. The reasons for failures can be due to one or more factors and can be generally classified as follows:

19.8.1 Design Errors related to Sizing

Design errors in selection of appropriate size of the cable can lead to very costly and sometimes uncorrectable consequences. Sizing errors could happen by not taking due consideration of the starting currents of huge motors and failure to take into consideration adequate heat dissipation of cables, fault current availability etc. Cable sizes could be wrongly selected based on criteria of the planned loads without taking into consideration load additions or enhancements at a later date, incorrect neutral sizing without adequate consideration of third harmonic currents etc. Such conditions would result in cables carrying excessive currents beyond their rated capacities, leading to excessive heating and consequently their premature failure.

19.8.2 Improper selection of Cable type for the Application

Improper selection of cable core material (Al or Cu), insulation material (paper, PVC or XLPE) can lead to premature failures. As an example, selection of Al cable instead of Cu cable for an application where there is space constraint would result in insufficient heat dissipation of cables, elevated operating temperatures and reduced life. Selection of an unarmored cable, for an application where the cable is prone to mechanical damages, can result in failures.

19.8.3 Installation Mistakes

Selection of the proper cable alone is not an end by itself. Installation of the cable carries as much importance in ensuring its reliability and long life. The following mistakes committed during cable installation can lead to their premature failures:

  • Improper backfill of soil, insufficient depth of laying
  • Lack of adequate mechanical protection such as sand bedding, brick laying etc.
  • Failure to take into consideration proper grouping factors
  • Damages to insulation due to rough handling
  • Failure to prevent moisture ingress through ends of cable before termination
  • Insufficient bending radius in curves

Extreme care should be exercised during installation of the cable to prevent stresses on account of excessive bending. The permanent radius of the bend after installation should be within the limits recommended by the cable manufacturer. The minimum bending radius is the minimum radius to which a cable can be bent while under pulling tension without exceeding the maximum side wall pressure. Bends decrease the insulation system life in several ways and cause premature failure of cables:

  • Insulation portion on the outside of the bend is more prone to tearing, cutting or stretching thin, resulting in deterioration of the insulation and consequent penetration of contaminants like moisture, chemicals, exposure to UV radiation etc.
  • Bending stresses result in deterioration of the insulation through heat cycling and voltage stress
  • Insulation on the outer radius of the bend inherently gets thinner due to stretching and results in reduced insulation properties and deterioration
  • Increased voltage stress and moisture penetration promote faster growth of water trees and electrical trees and cause accelerated deterioration of the cable

Minimum bending radius is stipulated in terms of multiples of the diameter of the cable irrespective of whether the cable is shielded, unshielded, armored or unarmored.

19.8.4 Operating and Service Conditions

Cables can and do fail when subjected to operating and service conditions beyond their capacity and range. Lightning strikes, overloading of cables either due to faults or wrong operation, voltage surges, damages due to digging operations, damages due to rodents are some of the causes under operating and service conditions by which cables can fail. Human error during operation can result in cables carrying currents in excess of their design capacity and can consequently lead to failure.

19.8.5 Ageing

Cable insulation, like any other material, is liable to degradation by the ageing process. Dielectric strength and insulation resistance of the insulation deteriorate over time and on account of the following causes:

  • Dielectric stress due to voltage
  • Thermal degradation
  • Degradation due to radiation exposure
  • Degradation due to exposure to chemicals, solvents etc.
  • Degradation due to mechanical stresses, i.e. Cable bends
  • Water Trees and Electrical Trees

Thermal ageing causes hardening of the insulation which may lead to cracks. Development of cracks leads to the penetration of moisture and other contaminants into the cable, resulting in its premature failure.

19.8.6 Treeing in XLPE

Polymeric materials such as ethylene propylene rubber, polyethylene and cross linked polyethylene are the most common types of cable insulation materials used nowadays. Under electric stress, a series of tiny hollow channels can develop within these insulation materials when exposed to water. The base of the tree is located at the point where the tree originated and its extremities tend to grow in a direction parallel to the direction of the electrical field. Water trees require both moisture and an electric field to grow. A tree originating at the stress relieving layer at the conductor shield of a cable grows radially until the cable fails. Water trees begin to form when a cable is exposed to water and subjected to normal operating voltage over an extended period of time. Tree growth continues in the presence of an electrical field and water until the total insulation wall thickness is bridged; when this occurs, the cable fails.

Almost all polymeric insulation compounds have ‘tree retardant’ additives to slow down the growth of water trees. In addition to additives, the following measures are also taken to prevent water ingress into the cable:

  • Metal sheath
  • Strand blocking material to prevent water flowing along the strands of the conductor

Electrical trees are similar to water trees, but develop in the absence of water when very high electrical stresses are involved. These high electrical stresses can arise due to switching surges or lightning strokes, or from localized stresses attributable to major defects in the cable.

If a new TR-XLPE cable has extensive water treeing, the problem can be attributed to a manufacturing defect. If the cable has strand blocking, water absorbing tape or a hermetically sealed shield and still it develops water trees within a short time, the possible root causes could be a manufacturing problem, mechanical damage or shield corrosion.

19.8.7 Voltage Stress

Electrical stress resulting from a non uniform electrical field inside the cable insulation is one of the major causes for cable failures. The insulation of a cable, particularly those rated for medium voltage and high voltage systems is subjected to large voltage stress across a relatively small thickness of material. The electrical stress is maximum at the surface of the conductor, lowest at the insulation shield and varies logarithmically with the cable geometry. Cables or accessories with partially damaged or missing semicon or metallic shields may experience very high electric stress, resulting in partial discharges and premature failure of the cable.

Similarly, when a cable is jointed with another cable or is terminated on an equipment, the alterations that are made to the cable’s insulation, affect the distribution of stress considerably and unless properly controlled, can result in premature failures.

Continuous application of voltage stress in addition to the normal ageing process, leads to failure of the insulation and the life time T in years is found to be inversely proportional to power of the voltage to an ageing coefficient; it is generally given by the following empirical formula:

T = K / (VN)


V = Electric stress in kV/mm
N = Ageing / endurance coefficient (8 to 12 for AC and 12 to 15 for DC)
K = Constant based on the type of insulation

The distribution of electrical stress across the insulation from the surface of the conductor inside the cable is related to temperature conditions and termination/ joints. Figure 19.6 shows non uniformity of stress distribution at the termination point of the cable:

Figure 19.6
Non uniform voltage stress distribution at cable termination point

Figure 19.7 below shows how the voltage distribution is made uniform, using a stress cone:

Figure 19.7
Stress control using stress cone

A stress cone is a prefabricated cable termination device made from a high permittivity material. Once applied to a cable with an appropriate design, a stress cone provides stress relief. Prefabricated stress cones with geometric-capacitive stress control, were initially developed for medium voltage cables; now they represent the standard solution for sealing ends on all types of polymer-insulated cables and for all voltage levels up to 500 kV.

To install the stress cone, the cable end is prepared and the insulation shield is cut circumferentially at a certain distance from the cable end. After the cable is prepared, the stress cone is slipped over the cable and made to sit over the insulation shield cutback. When installing the stress cone, silicon grease is normally used as a lubricant and as filler for the voids that may be present between the cable and the stress cone. Stress-control sleeves are designed to control the high electrical stress at the end of the cable insulation shielding. When the stress-control sleeve with adequate volume resistivity and dielectric constant is applied to the cable, the reliability of performance of the termination and the joint is increased. Drawbacks of stress cones are:

  • Availability in limited voltage ranges
  • Inventory has to be maintained, thus increasing inventory costs

Temperature and Temperature Gradients

Temperature and temperature gradients in the cable insulation may vary with the load and also due to external factors. The temperature differences between the innermost and outermost parts of the insulation can distort the gradient of electrical stress in the insulation. Under low load conditions, the voltage stress in the insulation is maximum near the surface of the conductor. However, under high load conditions, when the temperature of the insulation that is closer to the conductor is high, the resistivity of insulation near the core is reduced, resulting in the shifting of voltage stress away from the cable core towards the periphery of the insulation. Figure 19.8 shows the relative electric stress with respect to the average stress in a cable under different load conditions:

Figure 19.8
Electrical stress (relative to the average stress) distribution for a 20mm wall cable

It can be seen that the electric stress close to the conductor screen could be quite high when the cable is not carrying load but with full voltage applied to the conductor. It can also be seen that the stress level tends to flatten with increasing load and is almost constant for up to 20 mm distance from the conductor screen surface at or near full load operating conditions.

Basics of Stress control Approach

There are methods such as control tubing, stress cone, use of flexible tapes, etc. that are designed to take care of the geometric shape of the joints and terminations without any voids and air gaps that could lead to stress related failures. These various methods of stress control are covered in the following paragraphs.

Stress control Tubing

Shrink Polymer Systems employ heat shrinkable, high permittivity and low resistivity stress control tubing which is shrunk on to a stress relief tape previously applied over a cable joint. This has the effect of achieving a more uniform distribution of electric field lines and therefore lesser stress on the insulation.

When designing jointing systems, the thickness of the insulation over the bare conductor (i.e., ferrule) should have a safety factor in excess of 15 percent of the original cable. Shrink polymer systems employ a one-piece, combined dual wall (insulation/semi conductive) tube of appropriate diameter to match this insulation at voltages to 12 kV. At 17.5, 24, and 36 kV additional insulation tubes are added to meet these cable specifications. The installer must remember to shrink this material all around the tube to avoid inconsistent wall thicknesses on full recovery.

Stress-Relieving Tapes

This type of tape generally has permittivity values between seven and thirteen (test method IEC 250). The tape possesses high tack, high stretch, and low viscosity void-filling qualities with a permittivity value of minimum nine. Stress-relieving tape must be used in conjunction with heat shrinkable installations. This is applied in a half width overlap with stretch and must also be applied to any indents left by the tooling. Gaps between the end of the primary insulation and a connector must also be filled in. Push-on molded components are also widely used, eliminating the need to fill voids and use of stress tapes. Push-on molded components have several disadvantages. On three-core cables the molded components prove to be very bulky and have no design features to eliminate moisture penetration unless used in conjunction with large diameter shells and resins.

The stress control tape use is an accepted practice with results showing improvements of AC breakdown voltages when compared with the use of normal tape, as shown in figure 19.9:

Figure 19.9
Advantage of stress control sleeve

19.8.8 Workmanship of Joints

The most common failure mode for cable is insulation failure. Insulation failure has many reasons including accessories especially where a joint or termination has been made. Insulation failures in cable joints may be attributed to one or more of the following reasons:

  • Incorrect sealing
  • Improper core clearances
  • Poor workmanship

Failure to restore the electrical and mechanical properties of the joint/termination to those of the original cables (attributable to design of accessory kits or failure to follow manufacturer’s instructions)

Cable accessories, including splices or joints, and terminations or elbows, are some of the most vulnerable parts of an underground cable installation that can easily fail. The most common cause of failure in accessories is generally found to be improper installation. It is difficult to check the quality of the termination immediately after installation, because most of the tests are relative in nature i.e. they are related to some earlier noted values and if found satisfactory, the terminations are considered acceptable. Visual inspections also do not show any major defect even if there is a problem in the joint. Sometimes a poor installation may not result in a failure for many years. For example, the improper termination of the cable’s metallic and semi-conducting shields could cause a failure in the long run.

19.8.9 Vandalism and illegal Activity

Cable failures can also be attributed to vandalism and illegal activities. These however are beyond the scope of this manual.

19.9 Short-circuit protection of underground cables

Underground cables must be protected against excessive overheating caused by fault currents. Excessive heating could damage the cable, requiring lengthy and costly repairs. Faults in pipe-type cables may burn through the steel pipe, if the fault is not cleared quickly enough. In addition, radially directed forces on the pipe during prolonged faults can cause weld seam ruptures. These ruptures could cause additional environmental implications, because thousands of gallons of insulating oil fluid could leak into the ground.

For these reasons, cable protection must be high-speed, and typically requires some form of a communications channel between the two ends of the cable circuit. Because most cable faults involve ground initially, ground-fault sensitivity is of utmost importance. Therefore, high-speed pilot relaying systems are the most common relaying schemes applied for HV cable protection.

The main problem in protecting cable circuits is the high charging current, which may be an appreciable fraction of the load current, especially in long cable circuits. This limits the choice of minimum fault current settings. In addition, cable circuit energization and de-energization creates high transient currents. The frequency and magnitude of these currents depend not only on the capacitance, inductance, and resistance of the circuit being energized, but also the circuit breaker characteristics, namely preinsertion resistors. Similar high transient discharging and charging currents flow in the cable circuit during external fault conditions. The protection systems must be designed to cope with these transient currents and frequencies. Therefore, a current setting of several times the steady-state charging current may be necessary to ensure that the protection system will not misoperate.

Most faults in a cable circuit are permanent, regardless of relay operating speed. Any reclosing is therefore prohibited, since it will only cause additional damage. Because a relay system operation on a cable circuit may be caused by a flashover of terminal or other connected equipment, it is important to know what other equipment is located within the protected zone of the cable.

Typically, the protection systems applied in cable protection are similar to the ones applied in EHV overhead transmission lines. However, we must understand the fundamental differences between the two applications to provide proper protection of underground cables.

The three pilot protection schemes applied for cable protection are: current differential, phase comparison, and directional comparison.

19.9.1 Current Differential Protection

The current differential protection scheme compares the currents from a local terminal with the currents received through a communications channel from the remote terminal to determine whether the fault is inside or outside the underground cable zone of protection. The current differential scheme can be either of the segregated-phase or the composite type system. The segregated-current differential system compares the currents on a per-phase basis. The composite-current differential system compares a local and a remote single-phase signal proportional to the positive-, negative-, and zerosequence current input. The current differential scheme provides instantaneous protection for the entire length of the cable circuit.

The current differential scheme is frequently applied to protect cables because this scheme is less dependent on cable electrical characteristics. The current differential scheme requires a communications channel of wide bandwidth to transmit and receive current information to and from the remote terminal. Its availability, therefore, depends on channel availability. The current differential scheme only requires current inputs and cannot by itself provide backup protection. However, modern numerical relay systems have integrated the current differential relaying scheme as part of a full distance protection relay. It requires special security logic to restrain for external faults during current transformer saturation conditions. The current differential scheme is immune to power swings and current reversal conditions. The relaying settings for current differential schemes are few and easy to compute, however, cable-charging currents and shunt-reactor applications in cable circuits must be considered.

19.9.2 Phase Comparison Protection

Phase comparison relaying schemes compare the phase angle between the local and the remote terminal line currents. Therefore, this scheme requires a communications channel to transmit and receive the necessary information to and from the remote line terminal. Like the current differential relaying system, the phase comparison principle depends on communications channel availability. Phase comparison relaying systems are either of the segregated-phase or the composite type.

Phase-angle comparison is performed on a per-phase basis in the segregated-phase comparison system. All other phase comparison systems use a composite signal proportional to the positive-, negative-, and zero-sequence current input to provide protection for all fault types. In this scheme, the composite signal is passed through a squaring amplifier to obtain a square wave signal that contains phase angle information. The relay compares the local squared signal against the remote squared signals; if the coincidence of the two signals is greater than a certain value, 90° for example, the scheme declares an internal fault condition.

This scheme has been very popular in the past because it has minimal communications channel requirements. Because the current signals contain phase-angle information, this scheme is more secure than the current differential scheme for external fault conditions with CT saturation. Although the sensitivity of the phase comparison relaying system is normally lower than that of the current differential relaying system, all other characteristics are the same.

19.9.3 Directional Comparison Protection

Directional comparison schemes compare the fault direction information from both ends of the cable to determine whether the fault is internal or external to the cable zone of protection. Directional comparison schemes use different types of measuring elements, such as distance, directional zero-sequence, or negative-sequence, at each end of the cable circuit.

Directional comparison schemes require a communications channel for the exchange of directional information between terminals to provide high-speed protection for the entire cable circuit. Its minimum channel requirements have made this scheme, both blocking and unblocking types, very popular in cable protection applications. Loss of the communications channel only disables directional comparison functions, but does not disable directional-protection functions for local and remote backup.

Directional comparison schemes require both voltage and current inputs. Frequently, these schemes use phase-distance and ground-distance elements. It is a good practice to avoid using relay elements in directional comparison schemes that depend on the cable characteristics. Ground distance element settings and measurement depend to a great degree on the cable characteristics and the ground current return path.

Modern numerical relays have directional zero-sequence and negative-sequence elements available for cable protection. Negative-sequence directional elements provide excellent fault resistance coverage. These elements do not need to be desensitized to the effects of charging current.

19.9.4 Distance-Relay Application Considerations

Frequently, protection engineers use phase distance and ground distance elements in directional comparison schemes for cable protection. They also use distance elements for Zone 1 instantaneous tripping, and for backup cable protection using Zone 2 and higher-zone time-delayed tripping. Distance relay element application for cable protection requires a good knowledge of cable electrical parameters and a good understanding of the relay technology and any potential limitations.

Impedance is another difference between the electrical characteristics of underground cables and overhead lines. In general, the power cable impedance is less than the overhead line impedance because the phase conductor spacing in cables is less than the spacing in overhead lines. In some cases, the impedance may be less than the minimum distance relay setting value.

The cable zero-sequence impedance angle is less than the zero-sequence impedance angle for overhead lines. The zerosequence angle compensation requires a large setting range that accommodates all possible cable angles.

The current return path for an underground cable depends upon many factors, as we mentioned earlier: sheath bonding methods, sheath grounding, and any conducting path in parallel with the cable. All of these factors affect the underground cable sequence impedances, especially the zero-sequence impedance of the cable. Therefore, the computed zero-sequence impedance value is questionable. In pipe-type cables, the zerosequence impedance varies as a function of the ground-fault current level.

Most faults in underground single-conductor cables involve ground. It is therefore important to concentrate on the impedances seen by ground distance relays for faults in the underground cable and faults external to the cable zone of protection. Equation 1 gives the compensated ground loop impedance.

Va = line-to-neutral voltage
Ir = residual current
k0 = zero-sequence current compensation factor.

Choosing the correct zero-sequence current compensation factor, k0, produces the correct distance measurement in terms of positive-sequence impedance. Equation 2 gives the proper zero-sequence current compensation factor for overhead transmission lines.

Z0L = zero-sequence impedance of the line
Z1L = positive-sequence impedance of the line.

Note that in overhead transmission lines, Z1L and Z0L are proportional to the distance. However, this is not true for underground cables where the zero-sequence impedance may be nonlinear with respect to distance [9]. The zero-sequence compensation factor, k0, for solid-bonded and cross-bonded cables is not constant for internal cable faults, and it depends on the location of the fault along the cable circuit. Because ground distance relays use a single value of k0, the compensated loop impedance displays a nonlinear behavior.

19.10 Cable protection applications

In this section, we look at some complex cable application examples and offer some recommendations for protecting underground cables, including other considerations, such as reclosing in mixed overhead and underground cable circuits.

19.10.1 Circuit Consisting of Underground Cable Only

For pure cable circuits, which are relatively short in length, the most common form of protection is line current differential. Typically, this example has two line current differential systems, a Main One system and a Main Two system, each with a communications channel connected to separate and independent communications paths. For instance, one may be on a direct buried fiber cable and the second one on a multiplexed fiber, or a digital microwave communications network. Modern current differential relay systems offer complete distance protection schemes, including relay-to-relay communications capability in two different ports for pilot system and other protection and control applications. Therefore, users could choose to provide additional pilot schemes using distance and negative-sequence directional elements in both Main One and Main Two relays. Overreaching time-delayed zones of distance protection, and directional-overcurrent elements, will typically provide backup protection in both Main One and Main Two protection systems.

This application could also have direct transfer tripping for breaker failure conditions on the same digital channels, taking advantage of relay-to-relay communications. Automatic reclosing is not appropriate because the protective section consists of an underground cable only.

19.10.2 Cable Circuits Terminated into a Transformer

Quite often, EHV cable circuits terminate in transformers to provide the load to major metropolitan area. In some applications, the transformers do not have a high-voltage-side circuit breaker, as shown in Fig. 19.10.

Figure 19.10
EHV cable terminated into a transformer

In such applications, the Main One and Main Two cable protection relaying systems could consist of either current differential protection, and/or directional comparison protection systems, using phase-distance and negative-sequence directional elements for sensitive ground-fault protection. Overreaching time-delayed zones of distance protection, and directional- overcurrent elements will provide backup protection in both Main One and Main Two protection systems. Again, digital communications channels can provide the wide bandwidth required for current differential protection system(s) or for the directional comparison system(s).

There are no high-side circuit breakers at the distribution transformer terminal to trip for transformer faults, so direct transfer tripping of the remote terminal in case of transformer faults is necessary. Typically, this requires two transfer trip channels to ensure that one channel is always available in case of required maintenance or communications system outages.

In these types of applications, we can take advantage of digital relay-to-relay communications, and send the direct transfer trip bits for transformer faults to the remote station using the same digital channels that are used for the line current differential or the directional comparison system. We can take advantage of digital relay-to-relay communications, to eliminate all four sets of transmitters and receivers that would have been required for the cable and transformer protection. This reduces installation and maintenance costs, at the same time increasing the reliability of the protection systems.

Likewise, automatic reclosing is not appropriate, because the protective section consists of an underground cable only.

19.10.3 Mixed Overhead and Underground Cable Circuit

Applications of mixed overhead and underground cable circuits are very common. Fig. 19.21 shows a number of circuit arrangements.

Figure 19.11
Mixed overhead and underground circuits

Protection systems for mixed overhead transmission line(s) with underground cable are similar to the protection systems for HV and EHV transmission lines. One important difference from cable circuits is that many users will allow high-speed reclosing if the overhead portion of the line length is much greater than the underground cable. Systems where the cable length is less than 15–25 percent of the total circuit length usually permit autoreclosing.

Another important factor is whether the cable portion is at the beginning of either terminal or whether it is between two overhead line sections. In Fig. 19.11a, the cable is at the beginning of the transmission line and the line length is much longer than the cable section length. In this application, two instantaneous Zone 1 elements are set at the relay near the cable terminal to discriminate between faults in the cable and the overhead line section and to block autoreclosing for cable faults. The first instantaneous Zone 1 element (Z1-1) for the relay near the cable is set at 120–150 percent of the cable positive-sequence impedance. Operation of this zone (Z1-1) trips the local breaker, and sends direct-transfer trip to trip and block high-speed reclosing of the remote terminal. In addition, it blocks high-speed reclosing at the local terminal. The second instantaneous Zone 1 (Z1-2) element of the relay near the cable, is set at the typical Zone 1 reach, which is 80 percent of the total cable plus overhead-line positive-sequence impedance. For faults in this zone (Z1-2) and not in Z1-1, the relay sends a direct-transfer trip to trip and allows high-speed reclosing at the remote end for single-line-to-ground faults. This application also permits high-speed reclosing for single-lineto- ground faults, for the previous condition at the local terminal near the cable.

In Fig. 19.11a, at the terminal farther away from the cable, the distance relay has only one Zone 1 element. The reach of this element is at 80 percent of the overhead line positive-sequence impedance. Faults detected in this zone trip the local breaker, send direct-transfer trip to trip the remote breaker, and allow high-speed reclosing. Faults detected in an overreaching Zone 2 do not permit high-speed reclosing.

If the underground cable is of the pipe-type, reclosing may be prohibited all together unless line current differential relay systems are protecting the cable portion separately, as shown in Fig. 19.11b. In such a case one can positively identify that the fault is on the cable circuit and, via communications, block autoreclosing at the two ends of the line.

When the cable is very short, for instance less than 300 m, and not a pipe-type cable, some users would ignore the cable altogether and allow high speed reclosing because they assume that the majority of the faults will be on the overhead line section. In some cases, it is economical for short cable lengths to be thermally dimensioned for autoreclosing, however, for longer cable lengths autoreclosing may or may not be feasible, depending on the thermal rating of the cable.

Fig. 19.11c shows a three-terminal application in which the cable is protected by a separate line differential system for high-speed detection of cable faults and to block high-speed reclosing at the other two terminals. In Fig. 19.11 we do not show the Main Two protection systems. In all three examples of mixed overhead line with cable applications shown in Fig. 19.21, the protection and reclosing logic is quite complex. However, with modern digital relay communications capability and logic programmability, the task of designing a secure and dependable protection and high-speed reclosing scheme is greatly simplified.

Although the electrical characteristics of high-voltage underground ac transmission cables are significantly different from those of overhead transmission lines, you can adequately protect underground cable circuits, especially with modern protective relays:

  • Use current differential, phase comparison, and directional comparison relaying schemes.
  • Apply directional comparison schemes using distance elements, especially if they are supplemented with negative-sequence directional elements to ensure the required sensitivity for high-resistance faults at contaminated cable potheads.
  • Take special care when making ground distance settings, including proper selection of the zero-sequence
  • current compensation factor, because the zerosequence impedance of the cable is not linearly related to fault distance, and is affected by cable bonding and grounding methods.
  • Apply modern relays that offer integrated line current differential protection, full distance schemes, negative- sequence directional elements, pilot-scheme logic, and relay-to-relay communications. Functional integration in digital relays offers the most in cable protection.
  • Use relay-to-relay communications to create new protection schemes and for combining traditional schemes to reduce costs, increase reliability, and enhance performance of cable protection systems.

19.11 Fault Location

Locating of underground cable faults is an exercise that can be difficult and time consuming. However, many methods are available for the detection of locating cable faults. These methods can be basically categorized into:

  • Electrical test methods
  • Mechanical test methods
  • Visual check methods

19.11.1 Visual Inspection of Exposed Cables

All the investigation tools at ones disposal, including sensory organs, should be used for the detection and analysis of faults. Visual inspection of cables is an in-situ technique for detection of cable abnormalities. Visual inspection is a qualitative assessment of cable condition; it is inexpensive, does not require expensive equipment and is comparatively easy to perform and suitable for cables laid over ground. Many a fault problem gets solved through detection by sensory organs. More subtle signals however, can only be detected by means of special instruments and test equipment.

A keen mind and an observant eye are of great value in the detection of symptoms and evidences in visual inspection. Following are the observations that can be made during visual inspection:

  • Discoloration of cable insulation
  • Development of cracks on the insulation surface
  • Distortion, swelling, shrinkage and dimensional changes
  • Signs of melting, charring, emission of light due to overheating
  • Changes in surface hardness of cable insulation by feel of touch
  • Emission of unusual smell (ozone due to corona, burnt smell due to faults etc.)

For the observations to be successful, the observer should know what to look for and where to look for it. Accurate observation coupled with the gathering of all relevant data can go a long way in the successful identification of the root cause of cable problems. Since human memory can at best be faulty, it is advisable to take photographs of a fault site for further reference and analysis. The main drawback of visual inspection is that the complete cable may not be easily accessible for performing visual inspection. The other drawback is that this method is suitable only for cables laid over ground.

19.11.2 Reports of underground faults by observers in the vicinity

Interviewing of personnel who happened to be close to the fault location during its occurrence can provide vital information and clues as to the location and cause of the fault. These clues can include:

  • Observation of smoke, fire or spark at the fault site
  • Abnormal smell
  • Abnormal noise from the location

19.11.3 Other Tests

Transmitter-Receiver Test

The exact location of a fault can be detected using a Transmitter-receiver type cable fault detector. The exact route of the cable should be known and should be accessible for using this method. The instrument consists of a transmitter and a hand held portable receiver. Figure 19.12 shows the principle of operation of the detector:

Figure 19.12
Locating of Fault using Transmitter-Receiver instrument

The transmitter is connected to the faulty cable at one end after disconnecting the cores as well as the ground at the other end of the cable. The transmitter sends signals along the cable and this signal gets returned back to the transmitter through the fault in the cable. The portable receiver consists of two spike probes as shown, which have to be inserted into the ground above the cable as shown in the figure. The current in the soil spreads out like the spokes of wheel from the fault. The ground spikes provide entry and exit paths for this current and is detected by the receiver. The receiver is dropped into the soil along the cable path every few feet during fault location. As the fault location is approached, the receiver indicates higher and higher readings. When the probes are astride the fault, the instrument produces a null, thereby indicating the fault to be below the probes.

Thumper Test

Locating faults in high voltage cables is different from that of low voltage cables due to the following reasons:

  • Distance between the conductor and earth is more (higher thickness of insulation)
  • Concentric neutral wraps around the outside of the cable

Low voltage cable testing uses the flow of the tester current between the faulted conductor and earth for locating the fault. The low voltage values used in low voltage cable testing would not be enough to arc the longer distance between the conductor and earth in high voltage cables.

The thumper test is a typical test method for locating high voltage cable faults. The principle of the method is to connect a large capacitor between the conductor and the concentric neutral. The capacitor is then charged up to a high voltage, which would result in a discharge and cause an arc between the conductor and the neutral. The arc ionizes the air, causes an explosion (thump) which is monitored during the test. Since this test involves high voltages, there is a possibility that the test itself may cause damage to an otherwise healthy cable.

19.12 Electrical Tests for detection of Cable Faults

Detection of faults in an overhead line system can be comparatively easier when compared with fault detections in underground cable systems owing to non visibility of the fault. Rectification of the fault can also be more cumbersome and more time consuming and expensive than for an overhead line. Several techniques and instruments are available to ease the job of cable fault location.

Different types of cable faults require different techniques for identification of the fault location; therefore, it is first necessary to determine the type of fault in order to select the appropriate technique. A persistent fault to earth is generally easily located using the transmitter-receiver instrument. Open circuit and short circuit faults are best tackled using Time domain reflectometry (TDR) test. A flashing fault that happens only at high voltages requires a high voltage surge generator or ‘thumper’ test.

19.12.1 Loop Tests

Murray Loop Test

Murray loop method makes use of an electric bridge circuit for locating cable faults. Two arms of the bridge consist of resistors and the other two arms are made up of the faulty and healthy cores. The values of the resistances in three arms in the bridge are known and using these, the resistance of the fourth arm is calculated. Using this resistance value and the resistance per unit length of the cable, the distance of the fault can be calculated. However, this method has the following limitations:

  • It is useful only for shunt faults and only if at least one healthy conductor is available
  • The fault resistance should be below 200 ohms
  • The test is not applicable for open circuit faults
  • Only approximate location of the fault can be identified
  • The other end of the cable should also be accessible for fixing a jumper

The principle of this test method is illustrated in the figure 19.13:

Figure 19.13
Murray Loop test

Two arms in the bridge are known resistances Ra and Rb. The third arm of the bridge is made up of the healthy core plus part of the defective core with resistance R1 and the fourth arm made up of the faulty core up to the point of the fault with resistance R2. The relationship between the resistances is given by:

Ra / Rb = R1 / R2

The bridge is then balanced by adjusting the variable resistance ‘Rb’ to obtain a null point in the galvanometer. The ratio ‘R1 / R2’ is obtained. The total resistance ‘R’ (= R1 + R2 ) is then measured using wheat-stone bridge principle by making the total cable loop as an arm of the wheat-stone bridge. Using the above two relationships between ‘R1’ and ‘R2’ and the resistance per unit length of the cable, the distance of the fault from the measuring point can then be calculated.

19.12.2 Electro-Acoustic Detection

Acoustic detection method is a non destructive test method and is used for detecting partial discharges in cables. The method is an important diagnostic tool especially for medium voltage and high voltage cables. The main advantages of acoustic detection test method are:

  • It is immune to electrical interference
  • It can be performed on energized cables without shutting down power

The acoustic signals are detected using high precision, broad bandwidth microphones. The main drawback of this test method is the attenuation of the signals during propagation, needing close proximity to the problem location (app. within 20 mts of the problem location) for detection.

19.12.3 Time Domain Reflectometry

Time Domain Reflectometry (TDR) also called by various names such as ‘Pulse echo method’, ‘Cable radar’ and ‘Pulse reflection method’, is a method used for the detection of short circuits and open circuits in cables. The technique is similar to the radar system used for the detection of flying aircraft. Using the TDR method, it is possible to detect changes in the cable along the measurement of distance at which these changes are located.

The cable is tested by connecting one end of the cable to the TDR instrument. The TDR instrument generates and injects short duration pulses at a high repetition rate into the cable between the phase conductor and the shield (neutral) of the cable. A time domain reflectometry test injects a 20-ns to 500-ns pulse to determine cable profile in terms of discontinuities or joint locations. Changes in the impedance of the cable result in reflection of these pulses back to the instrument which detects and displays the reflected pulses using either a CRT or a LCD display. The reflections are displayed with the elapsed time along the horizontal axis (x-axis) and the amplitude of the reflection along the vertical axis (y-axis). The magnitude of the change in cable impedance is translated to a corresponding change in the amplitude of pulse on the display. Cable shorts result in negative deflection of the display and open circuits result in a positive deflection. Consequently, the end of the cable which is in effect, an open circuit, would result in a positive deflection.

Apart from cable defects, splices and T-connections which result in a change in cable impedance, also result in deflections on the display. Knowing the speed of propagation of the pulse in the cable, it is possible to calculate the cable length to the source which had caused a deflection on the display. TDR method is not suitable for non linear faults. Figures 19.14(a), 19.14(b) and 19.14(c) show the equivalent circuit of the cable and the displays corresponding to a healthy open ended cable, a cable with its end shorted and a cable having a short circuit respectively.

Figure 19.14(a)
Healthy cable open ended
Figure 19.14(b)
Cable with shorted ends
Figure 19.14(c)
Cable with short

19.13 Analysis of Failures

Faults should be diagnosed logically and technically to prevent their recurrence. Superficial resolving of a fault may make it disappear only temporarily and it may only be a question of time before the fault reappears again in a more serious form. The various causes for the fault should be investigated using metering and data recorders and the root cause arrived at.

A prerequisite for detecting the root causes of problems is keen observation. The symptoms and evidences observed during a fault provide valuable clues to the identification of the cause of the problem. The evidences at the fault site should not be disturbed before the site has been inspected thoroughly, since vital evidence can get lost during the disturbance. The situation can be more or less compared with that of a sleuth at the site of crime who gathers evidence. Recording of the various events and their sequences during the fault (relay operation, meter indications, emanation of noise, smell etc.) will be of great assistance and help in the analysis. Evidences (damaged insulation/ conductors) should be collected from the fault site to aid analysis. Error in observing the vital clues may jeopardize the whole course of the investigation process itself.

Identification of the cause is the next critical step that follows observation and collection of evidences. Pinpointing the root cause is important from the point of view of not only solving the particular incident, but also to prevent similar occurrences in other places in the future. Sound technical knowledge, analyzing ability, logical and lateral thinking capability, patience, sound and unbiased judgment are all required for the correct identification of the root cause of the problem. Sometimes, suspicion itself without hard facts at hand may help in looking for clues to confirm the suspicion. Over confidence can be an obstacle in performing a proper analysis.

During the analysis of a fault, all the contributing factors and parameters need to be considered so as not to miss out an important detail. However, the collected and observed facts and data need to be sifted and examined to isolate the pertinent information from irrelevant data. Thorough knowledge of the system coupled with unbiased, logical and systematic thinking is required for analyzing the data. Sometimes, even a seemingly improbable factor could be an important factor for analyzing the fault. Hence, it is imperative that even trivial evidences should not be ignored, as they might contain the clue for resolving the problem.

A cable failure is normally detected as either an open circuit or a short circuit. Open circuits are more common in low voltage cables than at medium or high voltage due to the magnitude of voltage which can survive with minimum clearance to ground. However, in the case of higher voltage systems, conduction continues with arcing in the conduction path, ultimately leading to localized overheating, failure of the insulation at the arcing area and consequently a short circuit.

The three most commonly seen problems in PILC cables are:

  • Partial discharge (in cable itself and in joints)
  • Moisture ingress
  • Thermal aging

If the failure is related to a polymeric cable, checking of the following would be of great assistance:

  • Detailed examination of the conductor including possible metallurgical examination
  • Dissecting the insulation close to the failure
  • Insulation resistance measurements
  • AC breakdown level tests on a long sample near the failure site
  • Chemical tests on the insulation
  • Semicon resistivity at elevated temperature near the failure site
  • Metallurgical tests on the shield or sheath if present
  • Chemical tests on the jacket if present

In any failure analysis it is recommended to take up a close visual examination of the failed part at and near the failure site and also talking to or reading accounts of the failure from the personnel involved. Depending on the circumstances and the observations, some more investigations or tests may be required, or more information may be requested from the cable user. Overheating may indicate a possible root cause of failure of the system. The other possible reasons that should be checked during the analysis are:

  • Backup protection
  • System ampacity
  • Thermal runaway
  • Lack of cooling

Signs of over heating may warrant further chemical or metallurgical tests to determine the maximum temperature reached. It may be necessary to take up further investigation into the system operations to determine the root cause of this type of failure. In case of overheating the possible root causes could be any one of the following, or something else:

  • Erroneous initial ampacity calculations leading to selection of undersized cables
  • Improper backup protection which does not isolate the cable quickly during higher currents
  • Failure of proper backfill leading to unfavorable conditions
  • Adverse environment such as the presence of a closely installed hot pipe

Another possible root cause of failure is the manufacturing defect in cables and accessories, which may be detected by visual examination after some period of service but which may not be visible when the items are new. Visual inspections after some time or after faults, may show voids or inclusions in the insulation or protrusions from the semicon. Voids could be simply bubbles in the insulation, while inclusions are the presence of some foreign matter. Protrusions could be sharp points extending from the semicon into the insulation. Any of these observations indicate a manufacturing defect as the cause of failure. Any or all of these lead to highly localized electrical fields, which may lead to partial discharge at the site or rapid growth of water or electrical trees near the defect. Unfortunately, the defect which may have caused the failure, is mostly destroyed at the time of fault, but generally can be observed in the other phases which can give sufficient evidence of poor manufacturing quality. However, modern cables are produced in highly controlled environments which should not lead to such defects. A cable having strand blocking, water absorbing tape, or a hermetically sealed LC shield, develops extensive water treeing in a short time; the possible root cause could be a manufacturing problem or a mechanical damage or shield corrosion.

Another type of failure is accompanied by signs of burning or arcing on the surface of the semicon. If the burning or arcing becomes extensive, the cable shield can get corroded. The cause is generally found to be the jackets getting damaged by arcing allowing corrosive ground water to enter the cable leading to severe corrosion of the metallic shield. Corrosion is found to be a serious form of shield damage in both copper and lead, even in fully jacketed cables.

Copper shields or neutrals over polymeric cables may suffer mechanical damage during installation, or experience damage from temperature cycling over a period, particularly near cable clamp locations. The lead sheath on PILC cables may be subjected to fracture and creep, resulting in cracks and breaks. Breaks in the metallic shield on polymeric cables may lead to points of high electrical stress, which may lead to local partial discharge and ultimately failure.

To investigate a failure in an accessory, in addition to the usual visual examination and gathering of environmental and operating information, other work specific to accessory failure analysis may include:

  • Comparison of failed accessory with healthy accessories in adjacent phases in terms of visual appearance and the installation practice
  • Contact resistance measurements in connectors
  • Comparing dimensions with assembly drawings of the accessory
  • Signs of poor workmanship, if any
  • Signs of surface tracking, if any
  • Electrically floating metal electrodes, if any

Analysis of various failures in the PILC and XLPE cables and cable termination indicate the combination of various factors shown in the table 19.1:

Table 19.1
Typical causes for cable insulation and accessories failures


Analysis of failures for PILC cables indicate that moisture entry in PILC cable is one of the major factors leading to premature aging and even to failure. There are instruments available to assess the moisture content in the cable using tan delta measurements. Table 19.2 shows the typical values of the dissipation factor and the corresponding average moisture content for PILC cables. If the cable is estimated to be having moisture content of 2% and higher, it may be concluded that cable replacement may be necessary in the near future (assuming that the cable is loaded to its full capacity).

Table 19.2
Moisture analysis in PILC cables


19.14 Documentation

19.14.1 Documentation of Work

Documentation of work carried out on cable installations is an important activity in asset maintenance. It is very important that clear documentations are available on the installed cables and the terminations carried out on them, in order to assess the conditions of the cable, to locate faults or to perform predictive maintenance activities. Documentation of the type of cable is also important since any diagnostic testing must take into account cable design and construction. Preparation of records is vital on account of the following reasons:

  • Records would serve as reference and help in future trouble shooting
  • Others can access the records and utilize them for their use
  • Dissemination of information would enable ease of trouble shooting at other locations
  • Documentation would enable identification of similar potential problem locations and help in taking preventive countermeasures to avoid failures
  • Any mistakes committed during the fault detection would create an awareness to avoid the same pitfall in future trouble shooting practices
  • Data on the fault detection would enable more accurate resource planning in terms of man power, time and funds for future use

Cable condition assessment testing can be broadly divided into five parts:

  • Check on quality of insulation material
  • Checking of Metallic shield or neutral
  • Check on Jacket materials
  • Check on accessories including splices and terminations
  • Local environment and operating conditions

Documentation of the above check results would enable tracking of the condition of the cable and detect any deterioration over time.

Documentation of following on a continuous basis can help in assessing the condition of the installation, which is one of the major causes of failures in termination:

  • Temperature measurements
  • Partial discharges

Operating temperatures can easily be measured on an energized, current carrying accessory using hand-held, infrared detectors. The load current must be recorded during the temperature measurement test to ensure that future readings are compared. Obviously, the higher the current, the higher the temperature. It is also necessary to record the surface temperature of the incoming cable. In general, the surface temperature on a splice or termination should be lower than the surface temperature on the incoming cable. If not, an accessory problem is indicated.

Partial discharges (PD) in accessories can be located using a number of off-line or on-line techniques and many equipment/devices are available to conduct the tests in the field with minimum efforts. Ultrasonic or Radio Frequency detectors are very useful in measuring and locating partial discharges in terminations or accessible splices. Non-contact probes can find only surface discharges, which may indicate contamination at the surface that may lead to a breakdown. A contact sonic probe or RF detector is required to detect internal discharges. Since cables must be energized for PD testing, contact probes should be electrically isolated from the person performing the test for safety reasons.

Some points of the operating environment, which must be documented, are:

  • Cable current loading compared to cable ampacity
  • Ambient temperature
  • Type of backfill around direct buried cables or ducts
  • Moisture or chemicals in contact with the cables and accessories
  • Lightning impulses and other system induced over-voltages
  • Switching operations

19.14.2 Documentation of Failures

Initially, a failure investigation should be directed towards the collection of all relevant background and historical information. This information should include reconstruction of the events leading to the failure, manufacturing data, service records, operating conditions and details of any repairs, maintenance or modifications. Such information can be of great help in understanding the failure mechanism. The important details that are needed for the assessment are:

  • Current loading and duty cycle
  • Fault occurrence data
  • Previous failures
  • A record on the failures should identify:
  • Date of fault
  • Nature of fault
  • Location of fault
  • Tests and investigations carried out
  • Results of such tests and investigations
  • Rectification carried out
  • Test results after rectification

Photographs taken of a major fault, aid in further analysis and can be kept as a record for future reference. Such records would help in minimizing the time needed to ascertain the location of the fault, enabling faster restoration of power supply to the affected area. The records would also assist in ensuring that the same types of faults may not repeat at the same locations. Additionally, a clear documentation of past failures and/or case studies will definitely help in narrowing down the search in the case of new faults. Testing agencies, utility and distribution companies would especially benefit to a great extent through access to data on different types of faults and the solutions adopted.






Management of protection

20.1 Management of protection

A protective system is considered 100% perfect if the number of circuit breakers opened under a fault is as per the design configuration. However, there are occasions when a few protective relays incorrectly operate or fail to operate. There are many possible reasons but the principal reasons could be:

  • Internal faults in the relays
  • Defects in the wiring to the relays
  • Wrong and poorly coordinated settings
  • Unforeseen faults at the design stage
  • Mechanical failures

Protection systems must be kept 100% operational at all times as one never knows when or where faults are likely to occur. The systems must therefore be maintained and managed properly to ensure safe and efficient operation of the power network.

Although the relays are tested prior to commissioning a system, it is most likely that the relays are not operating due to the soundness of the system. However, it cannot be assumed that the relay did not operate because of the system’s condition. Hence, it is vital that the relays be periodically checked and tested. It is also important that records be kept on the tests conducted and the details of results for future reference.

The functions required for good maintenance are listed on the following schedule A and it is important that good records are kept of the system parameters, wiring schematics, relay settings and calculations, CT magnetization curves, and so on.

Some suggested formats of test sheets are attached to give an idea of the sort of information that should be kept on file.

20.2 Schedule A

Schedule A is nothing but the basic functions that are considered essential to ensure that the relays are kept in good form during their life. The tests will indicate any internal parts that are to be corrected or replaced. The records will also indicate the frequency of failures expected in typical relays and the replacements that are needed at regular intervals. Such frequent replacement parts can be kept as spares so that the relays can be put back into perfect condition immediately upon noticing the defects.
Table 20.1 generally outlines this schedule.

Table 20.1
Schedule A
Functions of maintenance

Routine inspection and testing

Annual trip testing (random)
Full scheme test every 4th year.

Incorrect operations

Spares and repairs

Performance assessment




Protection management also involves addressing some of the following issues listed in schedule B (see Table 20.2).

20.3 Schedule B

Table 20.2
Schedule B




Skilled technical staff


Access for work

Technology has been changing at a rapid rate in recent times and it is important that staff are trained to be skilled in their area and are kept up to date. Good forward planning is essential to obtain access to the plant for maintenance.

If the budget can’t carry permanent staff, then bring in specialist private companies to do the annual checks.

Above all, make sure that the relays are:

  • Applied correctly for job
  • Commissioned properly
  • Set correctly
  • Maintained in good condition and working order

20.4 Test sheets

A typical test sheet standard format is as seen below and the format can be redesigned based on the relay type and the tests needed.

A typical test format for a motor protection relay with various protective functions could be as below.

When a system is put into service, it is necessary that proper records be available on the various tests to be conducted. Above all, a checklist is mandatory to ensure that all basic tests are carried out before putting the system into use. The following table is a typical commissioning checklist, which should be planned well in advance of commissioning any electrical system, whether simple or complex.

Primary and secondary injection tests are the most common tests applicable for voltage and current sensing relays, whose functions depend on the correct sensing characteristics. The following table shows a typical test sheet for such a purpose.

A secondary injection test is used when there is no possibility of applying the primary voltage or passing the primary current to the voltage and current transformers connected to a relay. For example, a 110 V supply and a 5 amp current source would be able to complete most of the functional tests of typical relays.

Appendix A

The Protection of Railway Traction Circuits


The original electrified railway trains operated on DC at voltages from about 500 to 3000 volts. Power was fed to the traction motors via either a special conductor rail or overhead catenaries and returned via the train track

For city and suburban services, DC is still the most widely used but, for main line traction, AC electrification has become the norm. Early schemes used low frequency – 16imageor 25 Hz. Modern systems, notably those in Britain, France and Japan, utilise single-phase 25kV 50 Hz mains frequency.

Classical Schemes

In all systems, current returning via the grounded rails caused interference with telecommunication circuits. Figure 1 shows how booster transformers are used to force the traction return current to flow in an aerially mounted conductor thus considerably reducing electromagnetic interference.

Figure 1
25 kV Traction with Booster Transformers

A step-down transformer, which is connected between phases of the electricity grid, provides the 25KV traction supply. The circuit flows via the overhead catenaries to the driving motors and returns through the rails and then the return conductor. The rails are bonded to ground at regular intervals and therefore at nominal ground potential. In the event of a fault, a single pole circuit breaker is operated to isolate the supply.

The protection philosophy of AC traction circuits is fundamentally different from normal U\utility transmission and distribution circuits. In T and D, security and continuity of supply is paramount and feeders and transformers are often duplicated to achieve this aim. In traction, one cannot provide duplicate catenaries to feed a single locomotive and, in addition, broken overhead conductors represent a greater hazard due to the proximity of railway staff and passengers. Furthermore, traction motor faults can cause a fire with serious consequences to passengers especially in tunnels. For these reasons, traction protection ranks operating speed and dependability above stability.

Especially as Control Centres are manned, an occasional unwanted trip can easily be rectified by manually reclosing the relevant circuit breaker, even if some trains are delayed while safety checks are carried out. Failure to trip for a fault condition is much more serious.

The track supply transformers are typically 10 to 25 MVA, with a 10% impedance, so that fault currents are low compared with T & D systems. Fault currents down the track are further limited by catenary and return conductor impedances. Typical loop impedances are about 1 ohm per mile. Also, unequal catenary impedances must be taken into account, such as occur on a 4-track railway where the centre tracks have a higher impedance than the outer tracks due to mutual coupling effects. Minimum fault currents are about twice the value of maximum load currents, so overcurrent protection would seem to be sufficient. In fact, time delayed overcurrent protection is used for back-up protection, but the primary protection is usually distance protection. Figure 2 shows a typical 2-track railway traction system.

Figure 2
Classic 25 kV Feeder Diagram

The infeed to the tracks in the “northbound” direction comes from transformer T1 at FS (feeder station). Catenaries A & B above the northbound and southbound tracks are energised via paralleling (sub-sectioning) substations SS and SS2. These parallel paths reduce the catenary impedance and hence the volt drop to the locomotive pantograph. This configuration allows a faulty section to be isolated whilst maintaining supply to the other healthy sections. The protection system must ensure that only the two circuit breakers associated with a faulty section are tripped. To achieve this, the protection must be directional. Distance protection is not only directional, but can also discriminate between high load currents and back-fed fault currents of lower values.

High speed trains have a much higher traction power demand, not only because of higher windage losses due to air friction, but also due to quicker acceleration requirements. The higher currents tend to give higher voltage drops, necessitating more power input stations and booster transformers. This results in significant cost increases for such electrification schemes and different techniques, using autotransformers, are used for modern railways.

Autotransformer Schemes

Autotransformer schemes utilise a centre-tapped 50 kV feeding transformer with the outputs ( +25 kV & – 25 kV) connected to the catenary and a parallel feeder conductor respectively. Autotransformers are located along the tracks at about 5 Km intervals to ensure equal division between these two conductors. The centre taps of the feeding transformers and autotransformers are connected to the rail track. Figure 3 illustrates a typical scheme.

Figure 3
Autotransformer Scheme

These schemes result in lower distribution losses, higher power ratings and lower maintenance costs than classic booster transformer designs Note, however, that 2-pole switchgear is needed.

The current distribution achieved is shown in Figure 4 and again, the rail track currents are negligible, except for the section of track where the locomotive is. On this section, only half the load current will flow in the rails.

Figure 4
Current Distribution

Autotransformer scheme protection philosophy

Figure 5 illustrates that the vector addition of the feeder and catenary currents between the feeder transformer and the locomotive is equal to the traction current.

Figure 5
Quadrilateral Distance Relay Impedance Characteristic

Beyond the locomotive, the vector sum is zero. The same is true of fault current under fault conditions. This resultant current, derived from CTs, and usually summated in the relay, is used as the current input to a distance relay, while the catenary to rail and feeder to rail potentials are used as the voltage input. As the autotransformers have a low percentage reactance, typically 1% on a 10 MVA base, the feeder and catenary volt drops are similar. However, in the event of a fault, the fault current flows in both the catenary and feeder and the relationship between the measured impedance and the distance to the fault is non-linear. Distance relays are set to operate for faults up to the mid-point substation, but these relays can over or under reach and may trip for a fault in the next section. Operation of a distance relay is arranged to trip all feeder station breakers and thus cut supplies to all tracks. Autoreclosing is always applied to restore supplies to all but the faulty section. This temporary interruption of supply to a moving train has minimal effect due to the train’s inertia

Paralleling between tracks is usually removed before autoreclosing to avoid unnecessary re- tripping of healthy catenary sections. This is achieved by opening all the associated motorised isolators during the autoreclose dead time. Following reclosure, the tracks will be radially fed and a persistent fault will cause only the relevant track circuit breaker to trip. Under these conditions, cross tripping of parallel track circuit breakers is prevented.

With radially fed tracks, multiple shot autoreclosing is often provided. This feature promotes the dislodging of fault debris, which cause semi-permanent faults. Just prior to the ultimate reclosure, the zone 1 characteristic is given an increased reach (often by using an alternative setting group in a numerical relay) to respond to a higher catenary fault loop impedance.

Back-up Protection

To ensure good contact between pantograph and catenary, the height of the catenary above the track must be constant. The system is designed for full load rating at maximum ambient temperature. Overcurrent conditions, due to peak hour timetables, or trains simultaneously starting or accelerating will result in the catenary overheating. The inherent thermal capacity of the conductors will accommodate this for a limited time, but, if sustained, the catenary will overheat and cause loss of alignment with respect to the track. Tension in the catenary is usually maintained by the provision of balance weights suspended at both ends of the contact wire. If the catenary stretches due to overheating, the balance weights may touch the ground and the tension will be lost. To guard against the possibility of this occurring, catenary thermal protection is always provided.

This protection device makes use of a thermal model set to reproduce both the heating and cooling chacteristics of the catenary. The thermal model is energised by catenary current and has two set points – a lower alarm setting and a higher trip setting. Thermal relays are based on integrating the square of the measured current with time but, to determine the actual line temperature, the ambient temperature must be taken into account. This can either be assumed or measured by installing a temperature probe mounted external to the substation. However, the catenary often passes through tunnels and cuttings with significant changes in ambient temperatures.

Therefore the probe should be mounted in a position that most accurately measures the average temperature of the majority of the protected line section.

As it is virtually impossible to position the probe that accurately measures the exact ambient temperature, and, in addition, the temperature detectors as well as the current transformers have inherent errors, the actual temperature as computed by the relay may be 4 degrees less than the actual temperature. Many relays compensate for this possible error to ensure that a trip will not occur too late to prevent damage.

Overcurrent protection is normally provided to give back up to the primary systems described above. Two types are used: -

1) Definite time overcurent protection, which is energised continuously and has time settings longer than the distance protection. This protection will only operate if the distance protection fails.

2) Back-up overcurrent protection, which is connected in service only when the distance protection is switched out. As an example, a monitor would detect loss of VT supply to a distance relay and this protection would be automatically disabled. Under these circumstances, the back up over current relays would be automatically connected to provide continuous catenary protection.

Feeder Substation Protection

Traction feeder substations comprise incoming feeders, switchgear, transformers and busbars as well as the traction feeders described. These other plant items are protected in the conventional way as described in the other chapters of this manual.

Distance Relay Setting

The zone settings are given by the formula: -

L1 X C/V where L1 = required Zone reach in primary ohms

    C = protection current transformer ratio

   V = protection voltage transformer ratio.

Typical relay characteristics are shown in the polar diagram Figure 6

Figure 6
Typical Autotransformer-fed Layout

Solid faults on the catenary will, depending on the distance from the relaying point, lie along the dotted line in this figure. The relay operating angle is set to be the same as this catenary characteristic angle, usually 70 to 75º. Zone 1 and Zone 2 are directional, whilst Zone 3 has a backward reach encompassing the origin, to provide back-up protection. The resistance and reactance reach of each zone must be optimised to give maximum fault coverage without tripping for load current.

The Zone 1 distance element is set to cover 85% of measured or calculated impedance up to the mid-point substation. This will ensure that, under maximum over-reach conditions, the relay reach will not extend into the next section. To cover all faults, the Zone 2 distance element is set to cover at least 115% of the section impedance, This element is set to operate after a time delay of about 160 mSec. If the locomotives have regenerative braking, a 20% additional reach margin would be applied.

With these settings, complete protection of the catenary from the Feeder Substation to the Mid-point Substation would be provided.

The Zone 3 distance element is applied to provide back-up protection for faults beyond the mid-point substation and also to cover instances when autotransformers are switched out of service giving a higher than normal impedance. The Zone 3 time lag is typically set to 500 mSec.

Appendix B

Typical Cable Data Sheets

Table B.1
Standard Cable sizes equivalence

Table B.2
Electrical and physical properties of 3 and 4 core PVC insulated PVC bedded SWA PVC sheathed 600/1000 V cables


Practical exercises on relay coordination

The exercises in this appendix have the objective of hands-on learning of protective relay coordination principles discussed in the course. There may be no unique solution for the problems discussed here. Also, the instructors and participants can generate their own variants of these problems for better familiarity with the topic. It is assumed that all participants are familiar with the use of MS-Excel.

A) Spreadsheet based relay coordination


  • This set of problems use a spreadsheet tool for relay coordination (Excel Coordination Demo.XLS). Please copy this Read-Only file and save it in a different name for working. Read through the ‘notes on use’ section carefully.
  • The sheet already contains default data. Substitute the data with the details given in the problems below.
  • All data is in terms of a single system voltage. Relay characteristics are based on IEC 60255 definitions for Standard Inverse (SI), Very Inverse (VI) and Extremely Inverse (EI) operating curves.
  • Instantaneous elements will be assigned a pickup time value of 0.01 sec.
  • Assume a maximum TMS (Time multiplier setting) range of 0.1 to 1.2 and PSM (Plug setting multiplier) range of 0.8 to 3 pu. Increments are possible in steps of 0.01 pu.
  • The reset ratio of all relays to be assumed as 95% (PSM setting should not be lower than load current/Reset ratio).
  • Save the answers to each problem in separate worksheets and continue with the next problem.


A circuit feeding to a motor of full load current (FLC) 80 amperes. The motor is started direct on line and draws a starting current of 600% FLC. Starting time is 4 seconds.

The feeder is protected against short-circuits by a CT and relay. CT ratio is 100/1 and the relay is of IDMT type with an instantaneous element. The operating curve applicable is ‘Extremely Inverse (EI). Instantaneous element setting can be set in the range of 2.0 to 12.0 pu of relay current. Work out the best possible settings assuming a minimum grading interval of 2 seconds with motor starting curve at starting current value.


Review the coordination between the relay mentioned in problem-1 with an upstream relay at the incomer.

The details of the upstream relay are as follows:

CT Primary current is 800 amps.

Load current is 600 amps

Current value for coordination is 5000 amps (Maximum possible fault current value)

Grading interval is 0.40 sec.

Relay characteristic to be used is EI.

Work out suitable PSM and TMS values to be set for this relay.


Repeat the above problem for:

a. Relay curve of VI for Incomer only.

b. Relay curve of SI for Incomer only.


Review the coordination between the following relays operating in tandem. Assume SI characteristics for all relays. There is no DMT element in any of these relays. Grading interval desired is 0.3 sec (minimum)

Relay A: Feeder relay

Relay B: Incoming feeder

Relay C: Feeder at main substation

For relay A:

Maximum load: 400 Amps

CT Primary: 500 Amps

Fault current for coordination with B is 9 kA (Maximum possible fault current value)

For relay B:

Maximum load: 1200 Amps

CT Primary: 1250 Amps

Fault current for coordination with C is 15 kA (Maximum possible fault current value)

For relay C:

Maximum load: 2450 Amps

CT Primary: 2500Amps


In the above example, introduce a DMT element in each relay with current setting of 2.0 pu of CT primary current. Relay A will have a time setting of 0.01 sec (instantaneous) and the other relays will be graded based on this value such that, the coordination requirement at the current values specified in the previous problem (9 kA for relay A and 15 kA for relay B) are satisfied.

B) Spreadsheet based fuse and relay coordination


  • The next set of problems use a spreadsheet tool for fuse-to-relay coordination (Excel Fuse Demo.XLS). Please copy this Read-Only file and save it in a different name for working. Read through the ‘notes on use’ section carefully.
  • The sheet already contains default data. Substitute the data with the details given in the problems below.
  • All data is in terms of a single system voltage. Relay characteristics are based on IEC 60255 definitions for Standard Inverse (SI), Very Inverse (VI) and Extremely Inverse (EI) operating curves. Fuse characteristics represent typical values.
  • Fuse characteristics are to be started from twice the rated current (200%) of fuse. Below this value, it is assumed that the fuse will not operate.
  • Instantaneous elements, where used, will be assigned a pickup time value of 0.01 sec.
  • Assume a maximum TMS (Time multiplier setting) range of 0.1 to 1.2 and PSM (Plug setting multiplier) range of 0.8 to 3 pu for relays. Increments are possible in steps of 0.01 pu.
  • The reset ratio of all relays to be assumed as 95% (PSM setting should not be lower than load current/Reset ratio).
  • Save the answers to each problem in separate worksheets and continue with the next problem.


This problem involves a medium voltage circuit feeding to a motor of full load current (FLC) 80 amperes. The motor is started direct on line and draws a starting current of 500% FLC. Starting time is 6 seconds. Motor is switched by a circuit breaker feeder in a switchboard protected by a CT and relay A and a cable runs for nearly 500m to the motor local panel situated in another building. The supply to the switchboard is from an upstream substation circuit breaker feeder with a rated current of 700 amps. and is protected by relay B.

The local panel near the motor has an isolator with a fuse. Expected short circuit level (Max.) is 3 kA beyond the panel.

For any short circuit fault in the motor or motor cable, the fuses should operate.

The fuse operating time for motor starting current should be at least 3 seconds more than the starting time.

The backup should be provided by relay A. Time coordination should be checked at 3000 amps and the grading interval should be at least:

     0.14* t + 0.15

Where t is the fuse operating time in seconds.

Relay B should be graded with relay A with a grading margin of 0.3 second at 10000A fault current which is the maximum expected short circuit level that can be encountered by B.

Coordination between a fuse and a relay is easier to achieve with relay of EI type characteristics.


Repeat the above problem with an instantaneous element in A to operate at 6000 amps. Coordination with relay B to be done at this current with the same grading margin as given earlier. Check whether the coordination holds good at the maximum expected short circuit level of 10 kA.


Repeat the above problem with a DMT element in B to operate at 9600 amps. Coordination with relay A to be brought back to the same grading margin of 0.3 second at the expected short circuit level of 10 kA. Find the grading margin at 6kA, 7kA, 8, kA and 9 kA using the calculated values.

C) Relay coordination using Demo Application ECOORD


  • Instructors may please use the setup file ECDSETUP.exe and install the demo application
  • Other files with CRV and CRW extensions being sent with the above EXE file may be copied to the directory C:\Elite\Ecoordw\Projects (which is the application default directory for data)
  • Data pertaining to each problem is stored in Project files with names: IDC-Problem 9.crw, IDC-Problem 10.crw etc. Please choose the appropriate Project for each problem.
  • Click on the icon C (view coordination curve) to view the details and make modifications.
  • In most cases, numerical values can be entered in the text boxes even though a drop down list box is provided. Thus it is possible to enter intermediate values in addition to the values displayed in the menu. The problems in this section of the exercise are to be solved using this method of data entry.


The equipment to be protected is IDC-Cable with a size of 10380 C. Mils (Size 10). The protective device is AJD 30 non adjustable CB. Work out the following cases:

  1. Find out the circuit breaker trip rating (maximum possible value) up to which the cable is protected at all current values.
  2. Repeat the exercise after changing the damage temperature to 250 Degrees (from the default 150 Deg).


The device to be protected is a motor (IDC-M1). The protection device is FA-30 non-adjustable circuit breaker. Find the following:

  1. The minimum trip rating of the circuit breaker required to withstand direct-online (full-voltage) starting of the motor at the given starting parameters.
  2. Repeat the exercise for a starting duration of 20 seconds and find the minimum trip rating required.
  3. Find the trip rating keeping the above data (as in 2) but changing the starting method to Wye-Delta option.


The device to be protected is a motor (IDC-M1). The protection device is A2D-60 fuse. Find the following:

  1. The minimum rating of the fuse required to withstand direct-online (full-voltage) starting of the motor at the given starting parameters. The grading time between motor starting and fuse blow-out may be taken as 5 seconds.
  2. Repeat the exercise for a starting duration of 20 seconds and find the minimum fuse rating required.
  3. Find the required fuse rating keeping the above data (as in 2) but changing the starting method to Wye-Delta option.


Coordination is to be achieved between a Versatrip RMS9 circuit breaker rated at 1 ampere and a fuse of A2D 30 type. For the given settings of the circuit breaker, select the minimum rating of fuse which will act as a back up to the circuit breaker for all values but will trip instantaneously for currents above20 amperes.


SIPROTEC4 7SA6 Distance protection relay

This section discusses the SIEMENS SIPROTEC 4 7SA6 distance protection relay, its functions, installation procedures, applications and maintenance issues. The SIPROTEC 4 units are numerical relays capable of providing control and monitoring functions.

D.1 Application

The distance protection relay 7SA6 is non-switched incorporating all the additional functions for protection of overhead lines and cables at all voltage levels from 5 to 765 kV. All methods of neutral point connection (resonant earthing, isolated, solid or low-resistance earthing) are reliably dealt with. The unit can issue single or three-pole TRIP commands as well as CLOSE commands. Consequently both single-pole, three-pole and multiple auto-reclosure is possible. Teleprotection functions as well as earth-fault protection and sensitive earth-fault detection are included. Power swings are detected reliably and non-selective tripping is prevented. The unit operates reliably and selectively even under the most difficult network conditions.

Figure D.1 Front View of 7AS61
Figure D.2 Front View of 7AS64

D.2 Protection functions

Distance protection (ANSI 21, 21N)

The main function of the 7SA6 is a non-switched distance protection. By parallel calculation and monitoring of all six impedance loops a high degree of sensitivity and selectivity is achieved for all types of fault. The shortest tripping time is less than one cycle. All methods of neutral-point connection (resonant earthing, isolated, solid or low-resistance earthing) are reliably dealt with. Single-pole and three-pole tripping is possible. The following four pickup methods can be employed alternatively:

  • Overcurrent pickup I>>
  • Voltage-dependent overcurrent pickup V/I
  • Voltage-dependent and phase angle-dependent overcurrent pickup V/I
  • Impedance pickup Z<

Load zone: The pickup mode with quadrilateral impedance pickup (Z<) is fitted with a variable load zone. In order to guarantee a reliable discrimination between load operation and short-circuit – especially on long high loaded lines – the relay is equipped with a selectable load encroachment characteristic. Impedances within this load encroachment characteristic will prevent the distance zones from unwanted tripping.

Absolute phase-selectivity: The 7SA6 distance protection incorporates a well proven highly sophisticated phase selection algorithm. The pickup of unfaulted phases is reliably eliminated. This phase selection algorithm achieves singlepole tripping and correct distance measurement in a wide application range. Interference to distance measurement caused by parallel lines can be compensated for by taking the earth current of the parallel system into account. This parallel line compensation can be taken into account both for distance measurement and for fault locating.

6 distance zones: Five independent distance zones and one separately overreach zone are available. Each distance zone has dedicated time stages, partially separate for single-phase and threephase faults. Earth faults are detected by monitoring the earth current 3I0 and the zero sequence voltage 3V0. The quadrilateral tripping characteristic allows use of separate settings for the X and the R directions. Different R settings can be employed for earth and phase faults. This characteristic offers advantages in the case of faults with fault resistance. All the distance protection zones can be set to forwards, reverse or non-directional.

Measuring voltage monitoring: Tripping of the distance protection is blocked automatically in the event of failure of the measuring voltage, thus preventing spurious tripping.

Power swing detection (ANSI 68, 68T) Dynamic transient reactions, for instance short-circuits, load fluctuations, auto-reclosures or switching operations can cause power swings in the transmission network. During power swings, large currents along with small voltages can cause unwanted tripping of distance protection relays. To avoid uncontrolled tripping of the distance protection and to achieve controlled tripping in the event of loss of synchronism, the 7SA6 relay is equipped with an efficient power swing detection function. Power swings can be detected under symmetrical load conditions as well as during single-pole auto-reclosures.
Tele (pilot) protection for distance protection (ANSI 85-21)

A teleprotection function is available for fast clearance of faults up to 100 % of the line length. The following operating modes may be selected:

  • POTT
  • Directional comparison pickup
  • Unblocking
  • PUTT acceleration with pickup
  • PUTT acceleration with Z1B
  • Blocking
  • Pilot-wire comparison
  • Reverse interlocking
  • DUTT, direct underreaching zone transfer trip (together with direct transfer Trip function).

The carrier send and receive signals are available as binary inputs and outputs and can be freely assigned to each physical relay input or output. At least one channel is required for each direction.

Direct transfer tripping Under certain conditions on the power system it is necessary to execute remote tripping of the circuit-breaker. The 7SA6 relay is equipped with phase-selective intertripping signal inputs and outputs.
Weak-infeed protection: echo and/or trip (ANSI 27 WI) To prevent delayed tripping of permissive schemes during weak or zero infeed situations, an echo function is provided. If no fault detector is picked up at the weakinfeed end of the line, the signal received here is returned as echo to allow accelerated tripping at the strong infeed end of the line. It is also possible to initiate phase-selective tripping at the weak-infeed end. A phaseselective single-pole or three-pole trip is issued if a permissive trip signal (POTT or Unblocking) is received and if the phaseearth voltage drops correspondingly.
Overvoltage protection, undervoltage protection (ANSI 59, 27)

A voltage rise can occur on long lines that are operating at no-load or are only lightly loaded. The following measuring elements are available in 7SA6:

  • Phase-to-earth overvoltage
  • Phase-to-phase overvoltage
  • Zero-sequence overvoltage
  • Negative-sequence overvoltage

The zero-sequence voltage can be connected to the 4th voltage input or be derived from the phase voltages.

The 7SA6 is also fitted with three two-stage undervoltage measuring elements:

  • Phase-to-earth undervoltage
  • Phase-to-phase undervoltage
  • Positive-sequence undervoltage

The undervoltage measuring elements can be blocked by means of a minimum current criterion and by means of binary inputs.

Directional earth-fault protection for high-resistance faults (ANSI 50N, 51N, 67N) In earthed network it may happen that the distance protection´s sensitivity is not sufficient to detect high-resistance earth faults. The 7SA6 protection relay offers therefore protection functions for faults of this nature. The earth-fault protection can be used with three definite-time stages and one inverse- time stage (IDMT). Inverse-time characteristics according to IEC 60255-3 and ANSI/IEEE are provided. A 4th definite-time stage can be applied instead of the 1st inverse-time stage. An additional logarithmic inverse-time characteristic is also available. The direction decision is determined by the earth current and the zero-sequence voltage or by the negative-sequence components V2 and I2. In addition or as an alternative, the direction can be determined with the earth current of an earthed power transformer and the zero-sequence voltage. Dual polarization applications can therefore be fulfilled. Each overcurrent stage can be set in forward or reverse direction or in both directions (non-directional).
The function is equipped with special digital filter algorithms, providing the elimination of higher harmonics. This feature is particularly important for small zero-sequence fault currents which usually have a high content of 3rd and 5th harmonic. Inrush stabilization and instantaneous switch-onto-fault tripping can be activated separately for each stage as well.
Tele (pilot) protection for directional earth-fault protection (ANSI 85-67N) The directional earth-fault protection can be combined with the available signaling methods:
  • Directional comparison

The transient blocking function (current reversal guard) is also provided in order to suppress interference signals during tripping of parallel lines.

The pilot functions for distance protection and for earth-fault protection can use the same signalling channel or two separate and redundant channels.

Backup vercurrent protection (ANSI 50, 50N, 51, 51N) The 7SA6 provides a backup overcurrent protection. Two definite-time stages and one inverse-time stage (IDMTL) are available, separately for phase currents and for the earth current. Two operating modes are selectable. The function can run in parallel to the distance protection or only during failure of the voltage in the VT secondary circuit (emergency operation). The secondary voltage failure can be detected by the integrated fuse failure monitor or via a binary input from a VT miniature circuit-breaker (VT m.c.b. trip). Inverse-time characteristics according to IEC 60255-3 and ANSI/IEEE are provided.
Instantaneous high-speed switch-onto-fault overcurrent protection (ANSI 50HS) Instantaneous tripping is required when energizing a faulty line. In the event of large fault currents, the high-speed switch-onto fault overcurrent stage can initiate very fast three-pole tripping. With smaller fault currents, instantaneous tripping after switch-onto-fault is also possible with the overreach distance zone Z1B or with pickup. The switch-onto-fault initiation can be detected via the binary input “manual close” or automatically via measurement.
Earth-fault detection in systems with a star-point that is not effectively earthed In systems with an isolated or resonant earthed (grounded) starpoint single-phase earth faults can be detected. The following functions are integrated for this purpose:
  • Detection of an earth fault by monitoring of the displacement voltage
  • Determination of the faulted phase by measurement of the phase-to-earth voltage
  • Determination of the earth-fault direction by highly accurate measurement of the active and reactive power components in the residual earth fault current.
  • Alarm or trip output can be selected in the event of an earth-fault in the forward direction.
  • Operation measurement of the active and reactive component in the residual earth current during an earth-fault.

Earth-fault direction detection can also be effected on the basis of the transient earth-fault principle by interfacing with the additional unit 7SN60. Procedures for logging, time stamping and event recording for the network control system are standardized by the 7SA6.

Breaker failure protection (ANSI 50BF) The 7SA6 relay incorporates a two-stage circuit- breaker failure protection to detect failures of tripping command execution, for example, due to a defective circuit-breaker. The current detection logic is phase-selective and can therefore also be used in single- pole tripping schemes. If the fault current is not interrupted after a settable time delay has expired, a retrip command or a busbar trip command is generated. The breaker failure protection can be initiated by all integrated protection functions, as well as by external devices via binary input signals.
STUB bus overcurrent protection (ANSI 50(N)-STUB) The STUB bus overcurrent protection is a separate definite-time overcurrent stage. It can be activated via a binary input signalling that the open line isolator (disconnector) is open. Separate settings are available for phase and earth faults.
Auto-recIosure (ANSI 79) The 7SA6 relay is equipped with an autoreclosure function (AR). The function includes several operating modes:
  • 3-pole auto-reclosure for all types of faults; different dead times are available depending on the type of fault
  • 1-pole auto-reclosure for 1-phase faults, no reclosing for multi-phase faults
  • 1-pole auto-reclosure for 1-phase faults and for 2-phase faults without earth, no reclosing for multi-phase faults
  • 1-pole auto-reclosure for 1-phase and 3-pole auto-reclosure for multi-phase faults
  • 1-pole auto-reclosure for 1-phase faults and 2-phase faults without earth and 3-pole auto-reclosure for multi-phase faults
  • Multiple-shot auto-reclosure
  • Interaction with an external device for auto-reclosure via binary inputs and outputs
  • Control of the internal AR function by external protection
  • Interaction with the internal or an external synchro-check
  • Monitoring of the circuit-breaker auxiliary contacts

In addition to the above-mentioned operating modes, several other operating principles can be employed by means of the integrated programmable logic (CFC). Integration of auto-reclosure in the feeder protection allows evaluation of the line-side voltages. A number of voltage-dependent supplementary functions are thus available:

  • DLC – By means of dead-line check, reclosure is effected only when the line is deenergized (prevention of asynchronous breaker closure).
  • ADT – The adaptive dead time is employed only if auto-reclosure at the remote station was successful (reduction of stress on equipment).
  • RDT – Reduced dead time is employed in conjunction with auto-reclosure where no teleprotection method is employed: When faults within the zone extension but external to the protected line are switched off for rapid auto-reclosure (RAR), the RDT function decides the need for reducing the dead time. This is done on the basis of measurement of the return voltage from the remote station which has not tripped.
Synchronism check (ANSI 25) Where two network sections are switched in by control command or following a 3-pole auto-reclosure, it must be ensured that both network sections are mutually synchronous. For this purpose a synchro-check function is provided. After verification of the network synchronism the function releases the CLOSE command. Alternatively, reclosing can be enabled for different criteria, e.g. checking that the busbar or line is not carrying a voltage (dead line or dead bus).
Fuse failure monitoring and other supervision functions

The 7SA6 relay provides comprehensive supervision functions covering both hardware and software. Furthermore, the measured values are continuously checked for plausibility. Thus the current and voltage transformers are also included in this supervision system. If any measured voltage is not present due to short-circuit or open circuit in the voltage transformer secondary circuit the distance protection would respond with an unwanted trip due to this loss of voltage. This secondary voltage interruption can be detected by means of the integrated fuse failure monitor. Immediate blocking of distance protection and switching to the backup-emergency overcurrent protection is provided for all types of secondary voltage failures. Additional measurement supervision functions are

  • Symmetry of voltages and currents
  • Broken-conductor supervision
  • Summation of currents and voltages
  • Phase-sequence supervision.
Trip circuit supervision (ANSI 74TC) One or two binary inputs for each circuit breaker pole can be used for monitoring the circuit-breaker trip coils including the connecting cables. An alarm signal is issued whenever the circuit is interrupted.
Lockout (ANSI 86) Under certain operating conditions it is advisable to block CLOSE commands after a TRIP command of the relay has been issued.
Only a manual “RESET” command unblocks the CLOSE command. The 7SA6 is equipped with such an interlocking logic.
Thermal overload protection (ANSI 49) For thermal protection of cables and transformers an overload protection with an early-warning stage is provided. The thermal replica can be generated with the maximum or mean value of the respective overtemperatures in the three phases, or with the overtemperature corresponding to the maximum phase current. The tripping time characteristics are exponential functions according to IEC 60255-8 and they take account of heat loss due to the load current and the accompanying drop in temperature of the cooling medium. The previous load is therefore taken into account in the tripping time with overload. A settable alarm stage can output a current or temperature-dependent indication before the tripping point is reached.
BCD-coded output of fault location The fault location calculated by the unit can be output for remote indication in BCD code. The output of the fault location is made in percent of the set line length with 3 decimal digits.
Analog output 0 to 20mA Some measured values can be output as analog values (0 to 20 mA). On a plug-in module two analog channels are made available. Up to two plug-in modules can be installed in the 7SA6. As an option, 2, 4 or no analog channels are available.

D.3. Communication

7SA6 provides the following functionality with respect to data transfer.

  • Every data item is time-stamped at the source, i.e. where it originates.
  • Already during the process of communication, information is assigned to the cause thereof (e.g. assignment of the indication “circuit-breaker TRIP” to the corresponding command).
  • The communication system automatically handles the transfer of large data blocks (e.g. fault recordings or parameter data files). The user has access to these features without any additional programming effort.
  • For the safe execution of a control command the corresponding data telegram is initially acknowledged by the unit which will execute the command. After the release and execution of the command a feedback signal is generated. At every stage of the control command execution particular conditions are checked. If these are not satisfied, command execution maybe terminated in a controlled manner.

D.3.1 Physical connection

RS 485 bus
With this data transmission via copper conductors, electromagnetic fault influences are largely eliminated by the use of twisted-pair conductors. Upon failure of a unit, the remaining system continues to operate without any problem.

Fiber-optic double ring circuit
The fiber-optic double ring circuit is immune to electromagnetic interference. Upon failure of a section between two units, the communication system continues to operate without disturbance. It is usually impossible to communicate with a unit that has failed. Should a unit fail, there is no effect on the communication with the rest of the system.

D.3.2 Communication Protocols

IEC 60870-5-103
IEC 60870-5-103 is an internationally standardized protocol for efficient communication with protection relays. IEC 60870-5-103 is supported by a number of protection device manufacturers and is used world-wide. Supplements for the control function are defined in the manufacturer- specific part of this standard.

PROFIBUS-FMS is an internationally standardized communication protocol (EN 50170). Connection to a SIMATIC programmable controller is made on the basis of the data obtained (e.g. fault recording, fault data, measured values and control functionality) via the SICAM energy automation system.

PROFIBUS-DP is an industrial communications standard and is supported by a number of PLC and protection device manufacturers.

DNP 3.0
DNP 3.0 (Distributed Network Protocol, Version 3) is an internationally recognized protection and bay unit communication protocol. SIPROTEC 4 units are Level 1 and Level 2 compatible.

An Ethernet application-specific profile for energy automation applications is currently under preparation.


SIPROTEC4 7SJ64 Feeder Management Relay

This section discusses the SIEMENS SIPROTEC 4 7SJ64 multifunction protection relay, its functions, installation procedures, applications and maintenance issues. The SIPROTEC 4 units are numerical relays capable of providing control and monitoring functions.

E.1 Application

The SIPROTEC 4 7SJ64 can be used as a protective control and monitoring relay for distribution feeders and transmission lines of any voltage in networks that are earthed (grounded), low-resistance earthed, unearthed, or of a compensated neutral point structure. The relay is suited for networks that are radial or looped, and for lines with single or multi-terminal feeds. The SIPROTEC 4 7SJ64 is equipped with a synchronization function which provides the operation modes ‘synchronization check’ (classical) and ‘synchronous/asynchronous switching’ (which takes the CB mechanical delay into consideration). Motor protection comprises undercurrent monitoring, starting time supervision, restart inhibit, locked rotor.

Figure D.1
Front View of 7SJ64

E.2 Protection functions

Non-directional overcurrent protection (50, 50N, 51, 51N) is the basis of the device. There are two definite time overcurrent protective elements and one inverse time overcurrent protective element for phase and ground current. For inverse time overcurrent protective elements, several characteristics of different standards are provided. Alternatively, user-defined characteristics can be programmed.

Depending on the version of the device(62/63/64), the non-directional overcurrent protection can be supplemented with directional overcurrent protection (67, 67N), breaker failure protection (50BF), and sensitive ground fault detection for high-resistance ground faults. The highly sensitive ground fault detection can be directional or non-directional.

In addition to the fault protection functions already mentioned, other protective functions are available. These additional functions include frequency protection (81O/U), overvoltage protection (59) and undervoltage protection (27), negative sequence protection (46) and overload protection (49) with start inhibit for motors (66/68) and motor starting protection (48), as well as automatic reclosing (79) which allows different reclosing cycles on overhead lines. The automatic reclosing system may also be connected externally. To ensure quick detection of the fault, the device is equipped with a fault locator.

External detectors account for ambient temperatures or coolant temperatures (by means of an external RTD-box). Before reclosing after three-pole tripping 7SJ64 can verify the validity of the reclosure by voltage check and/or synchronous check. The synchronization function can also be controlled externally.

Figure E.2
7SJ64 Protection functions
Time-overcurrent protection (ANSI 50, 50N, 51, 51N) This function is based on the phase-selective measurement of the three phase currents and the earth current (four transformers). Two definite-time overcurrent protection elements (DMT) exist both for the phases and for the earth. The current threshold and the delay time can be set in a wide range. In addition, inverse-time overcurrent protection characteristics (IDMTL) can be activated. With the “flexible protection functions”, further definite-time overcurrent stages can be implemented in the 7SJ64 unit.

Reset characteristics : For easier time coordination with electromechanical relays, reset characteristics according to ANSI C37.112 and IEC 60255-3 / BS 142 standards are applied. When using the reset characteristic (disk emulation), a reset process is initiated after the fault current has disappeared. This reset process corresponds to the reverse movement of the Ferraris disk of an electromechanical relay (thus: disk emulation).

Inrush restraint : The relay features second harmonic restraint. If the second harmonic is detected during transformer energization, pickup of non-directional and directional normal elements are blocked.

Cold load pickup/dynamic setting change : For directional and nondirectional timeovercurrent protection functions the initiation thresholds and tripping times can be switched via binary inputs or by time control.

Directional time-overcurrent protection (ANSI 67, 67N)

Directional phase and earth protection are separate functions. They operate in parallel to the non-directional overcurrent elements. Their pickup values and delay times can be set separately. Definite-time and inverse-time characteristic is offered. The tripping characteristic can be rotated about ± 180 degrees. By means of voltage memory, directionality can be determined reliably even for close-in (local) faults. If the switching device closes onto a fault and the voltage is too low to determine direction, directionality (directional decision) is made with voltage from the voltage memory. If no voltage exists in the memory, tripping occurs according to the coordination schedule. For earth protection, users can choose whether the direction is to be determined via zero-sequence system or negative-sequence system quantities (selectable). Using negative-sequence variables can be advantageous in cases where the zero voltage tends to be very low due to unfavorable zero-sequence impedances.

Directional comparison protection (cross-coupling)
It is used for selective protection of sections fed from two sources with instantaneous tripping, i.e. without the disadvantage of time coordination. The directional comparison protection is suitable if the distances between the protection stations are not significant and pilot wires are available for signal transmission. In addition to the directional comparison protection, the directional coordinated time-overcurrent protection is used for complete selective backup protection. If operated in a closed-circuit connection, an interruption of the transmission line is detected.

(Sensitive) directional earth-fault detection (ANSI 64, 67Ns/67N) For isolated-neutral and compensated networks, the direction of power flow in the zero sequence is calculated from the zero-sequence current I0 and zero-sequence voltage V0. For networks with an isolated neutral, the reactive current component is evaluated; for compensated networks, the active current component or residual resistive current is evaluated.
(Sensitive) earth-fault detection (ANSI 50Ns, 51Ns/50N, 51N) For high-resistance earthed networks, a sensitive input transformer is connected to a phase-balance neutral current transformer (also called core-balance CT). The function can also be operated in the insensitive mode, as an additional shortcircuit protection.
Intermittent earth-fault protection Intermittent (re-striking) faults occur due to insulation weaknesses in cables or as a result of water penetrating cable joints. Such faults either simply cease at some stage or develop into lasting short-circuits. During intermittent activity, however, star-point resistors in networks that are impedance-earthed may undergo thermal overloading. The normal earth-fault protection cannot reliably detect and interrupt the current pulses, some of which can be very brief. The selectivity required with intermittent earth faults is achieved by summating the duration of the individual pulses and by triggering when a (settable) summed time is reached. The response threshold IIE> evaluates the r.m.s. value, referred to one systems period.
Phase-balance current protection (ANSI 46) (Negative-sequence protection) In line protection, the two-element phase balance current/negative-sequence protection permits detection on the high side of high-resistance phase-to-phase faults and phase-to-earth faults that are on the low side of a transformer. This provides backup protection for high-resistance faults beyond the transformer.
Breaker failure protection (ANSI 50BF) If a faulted portion of the electrical circuit is not disconnected upon issuance of a trip command, another command can be initiated using the breaker failure protection which operates the circuit-breaker, e.g. of an upstream (higher-level) protection relay. Breaker failure is detected if, after a trip command, current is still flowing in the faulted circuit. As an option, it is possible tomake use of the circuit-breaker position indication.
Auto-reclosures (ANSI 79) Multiple reclosures can be defined by the user and lockout will occur if a fault is present after the last reclosure. The following functions are possible:
  • 3-pole ARC for all types of faults
  • Separate settings for phase and earth faults
  • Multiple ARC, one rapid auto-reclosure (RAR) and up to nine delayed auto-reclosures (DAR)
  • Starting of the ARC depends on the trip command selection (e.g. 46, 50, 51, 67)
  • Blocking option of the ARC via binary inputs
  • ARC can be initiated externally or via CFC
  • The directional and non-directional elements can either be blocked or operated non-delayed depending on the auto-reclosure cycle
  • Dynamic setting change of the directional and non-directional elements can be activated depending on the ready AR
  • The AR CLOSE command can be given synchronous by use of the synchronization function.
Synchronization (ANSI 25) In case of switching ON the circuit-breaker, the units can check whether the two subnetworks are synchronized (classic synchro- check). Furthermore, the synchronizing function may operate in the “Synchronous/ asynchronous switching” mode. The unit then distinguishes between synchronous and asynchronous networks: In synchronous networks, frequency differences between the two subnetworks are almost non-existant. In this case, the circuit breaker operating time does not need to be considered. Under asynchronous condition, however, this difference is markedly larger and the time window for switching is shorter. In this case, it is recommended to consider the operating time of the circuit-breaker. The command is automatically pre-dated by the duration of the operating time of the circuit breaker, thus ensuring that the contacts of the CB close at exactly the right time. Up to 4 sets of parameters for the synchronizing function can be stored in the unit. This is an important feature when several circuit- breakers with different operating times are to be operated by one single relay.
Thermal overload protection (ANSI 49) For protecting cables and transformers, an overload protection with an integrated pre-warning element for temperature and current can be applied. The temperature is calculated using a thermal homogeneous body model (according to IEC 60255-8), which takes account both of the energy entering the equipment and the energy losses. The calculated temperature is constantly adjusted accordingly. Thus, account is taken of the previous load and the load fluctuations. For thermal protection of motors (especially the stator), a further time constant can be set so that the thermal ratios can be detected correctly while the motor is rotating and when it is stopped. The ambient temperature or the temperature of the coolant can be detected serially via an external temperature monitoring box (resistance-temperature detector box, also called RTD-box). The thermal replica of the overload function is automatically adapted to the ambient conditions. If there is no RTD-box it is assumed that the ambient temperatures are constant.

E.3. Communication

A 9-pole DSUB socket at the front panel is used for local communication with a personal computer. By means of the SIPROTEC® operating software DIGSI ®, all operation and evaluation tasks can be executed via this user interface, such as specifying and modifying configuration parameters and settings, configuring user-specific logic functions, retrieving operational messages and measured values, inquiring device conditions and measured values, issuing control commands.

Depending on the model, additional interfaces are located on the rear side of the device. They serve to establish an extensive communication with other digital operating, control and memory components:

  • The service interface can be operated via electrical data lines or fiber optics and also allows communication via modem. For this reason, remote operation is possible via personal computer and the DIGSI® operating software, e.g. to operate several devices via a central PC.
  • The additional port on 7SJ64 is designed exclusively for connection of a RTD-Box (resistance temperature detector) for entering external temperatures. It can also be operated via data lines or fibre optic cables.
  • The system interface ensures the central communication between the device and the substation controller. It can also be operated via data lines or fibre optic cables. For the data transfer Standard Protocols according IEC 60870 870-5-103 are available via the system port.
  • The EN-100-module allows the devices to be integrated in 100-Mbit-Ethernet communication networks in control and automation systems using protocols according to IEC61850. Besides control system integration, this interface enables DIGSI-communication and inter-relay communication via GOOSE.
  • Alternatively, a field bus coupling with PROFIBUS FMS is available for SIPROTEC® 4. The PROFIBUS FMS according to DIN 19245 is an open communication standard that has particularly wide acceptance in process control and automation engineering, with especially high performance. A profile has been defined for the PROFIBUS communication that covers all of the information types required for protective and process control engineering. The integration of the devices into the power automation system SICAM® can also take place with this profile.
  • Besides the field-bus connection with PROFIBUS FMS, further couplings are possible with PROFIBUS DP and the protocols DNP3.0 and MODBUS. These protocols do not support all possibilities which are offered by PROFIBUS FMS.

E.3.1 Physical connection

RS 485 bus
With this data transmission via copper conductors, electromagnetic fault influences are largely eliminated by the use of twisted-pair conductors. Upon failure of a unit, the remaining system continues to operate without any problem.

Fiber-optic double ring circuit
The fiber-optic double ring circuit is immune to electromagnetic interference. Upon failure of a section between two units, the communication system continues to operate without disturbance. It is usually impossible to communicate with a unit that has failed. Should a unit fail, there is no effect on the communication with the rest of the system.

E.3.2 Communication Protocols

IEC 61850 protocol
By means of this protocol, information can also be exchanged directly between bay units so as to set up simple masterless systems for bay and system interlocking. Access to the units via the Ethernet bus will also be possible with DIGSI. It will also be possible to retrieve operating and fault messages and fault recordings via a browser. This Web monitor will also provide few items of unit-specific information in browser windows.

IEC 60870-5-103
IEC 60870-5-103 is an internationally standardized protocol for efficient communication with protection relays. IEC 60870-5-103 is supported by a number of protection device manufacturers and is used world-wide. Supplements for the control function are defined in the manufacturer- specific part of this standard.

PROFIBUS-FMS is an internationally standardized communication protocol (EN 50170). Connection to a SIMATIC programmable controller is made on the basis of the data obtained (e.g. fault recording, fault data, measured values and control functionality) via the SICAM energy automation system.

PROFIBUS-DP is an industrial communications standard and is supported by a number of PLC and protection device manufacturers.

DNP 3.0
DNP 3.0 (Distributed Network Protocol, Version 3) is an internationally recognized protection and bay unit communication protocol. SIPROTEC 4 units are Level 1 and Level 2 compatible.

An Ethernet application-specific profile for energy automation applications is currently under preparation.

E.3.3 System solution for protection and station control

Together with the SICAM power automation system, SIPROTEC 4 can be used with PROFIBUS-FMS. Over the low-cost electrical RS485 bus, or interference-free via the optical double ring, the units exchange information with the control system.

Units featuring IEC 60870-5-103 interfaces can be connected to SICAM in parallel via the RS485 bus or radially by fiber-optic link. Through this interface, the system is open for the connection of units of other manufacturers.

For IEC 61850, an interoperable system solution is offered with SICAM PAS. Via the 100 Mbits/s Ethernet bus, the units are linked with PAS electrically or optically to the station PC. The interface is standardized, thus also enabling direct connection of units of other manufacturers to the Ethernet bus. With IEC 61850, however, the units can also be used in other manufacturers’ systems


SIPROTEC4 7SD61 Line Differential Relay

This section discusses the SIEMENS SIPROTEC 4 7SD61 Line differential relay, its functions, installation procedures, applications and maintenance issues. The SIPROTEC 4 units are numerical relays capable of providing control and monitoring functions.

F.1 Application

The 7SD610 relay is a differential protection relay suitable for all types of applications and incorporating all those functions required for differential protection of lines, cables and transformers.

It is designed to provide protection for all voltage levels and types of networks; two line ends may lie within the protection zone. The relay features very high-speed and phase-selective short-circuit measurement. The unit is thus suitable for single and three-phase fault clearance. The necessary restraint current for secure operation is calculated from the current transformer data by the differential protection unit itself. Digital data communication for differential current measurement is effected via fiberoptic cables or digital communication and pilot wires, so that the line ends can be quite far apart. Thanks to special product characteristics, the relay is particularly suitable for use in conjunction with digital communication networks. The units measure the delay time in the communication network and adaptively match their measurements accordingly. The units can be operated through pilot wires or twisted telephone pairs at typical distances of 15 km by means of special converters. The serial communication interfaces for data transmission between the ends are replaceable by virtue of plug-in modules and can easily be adapted to multi-mode and mono-mode fiber-optic cables and to leased lines or switched lines within the communication networks. Extremely fast, selective and sensitive protection of two-end lines can now be provided by means of these relays.

Figure F.1
Front View of 7SD61

LEDs and an LC display provide information on the function of the device and indicate events, states and measured values. Integrated control and numeric keys in conjunction with the LCD facilitate local interaction with the local device. All information of the device can be accessed using the integrated control and numeric keys. This information includes protective and control settings, operating and fault indications, and measured values; setting parameters can be changed

F.2 Protection functions

Figure F.1
7SD61 Protection functions
Differential protection (ANSI 87L, 87T)

The differential protection function has the following features:

  • Measurements are performed separately for each phase; thus the trip sensitivity is independent of the fault type.
  • An adaptive measurement method with high sensitivity for differential fault currents below the rated current offers the detection of highly resistive faults. This trip element uses special filters, which offer high security even with high level DC components in the short-circuit current. The trip time of this stage is about 35 ms, the pickup value is about 10% of the rated current.
  • A high-set differential trip stage which clears differential fault currents higher than the rated current within 15 ms offers fast tripping time and high-speed fault clearance time. A high-speed charging comparison method is employed for this function.
  • When a long line or cable is switched on at one end, transient peaks of the charge current load the line. To avoid a higher setting of the sensitive differential trip stage, this setpoint may be increased for a settable time. Under normal operating conditions, the relay is switched automatically to the sensitive setting.
  • A new feature of the unit is parameterization of the current transformer data. The unit automatically calculates the necessary restraint current by means of the previously entered current transformer error. The unit thus adaptively matches the working point on the tripping characteristic so that it is no longer necessary for the user to enter characteristic settings.
  • Different current-transformer ratios may be employed at the ends of the line. A mismatch of 1:8 is permissible. The tripping values of the unit are referred to a rated operating current previously entered by the user.
  • Differential protection tripping can be combined with overcurrent pickup. In this case, pickup of the protection relay is initiated only on simultaneous presence of differential current and overcurrent.
  • Easy to set tripping characteristic. Because the relay calculates its restraint current, only the setpoint _Diff> and _Diff>> must be set.
  • Single-phase short-circuits within the protection zone can be cleared using a time delay, whereas multi-phase faults are cleared instantaneously. Because of this function, the unit is optimally suited for applications in inductively compensated networks, where differential current can occur as a result of charge transfer phenomena on occurrence of a single-phase earth fault within the protection zone, thus resulting in undesired tripping by the differential protection relay. Undesired tripping of the differential protection can be suppressed by making use of the provision for introduction of a time delay on occurrence of single-phase faults
  • With transformers or compensation coils in the protection zone, the sensitive response threshold IDiff> can be blocked by an inrush detection function. Like in transformer differential protection, it works with the second harmonic of the measured current compared with the fundamental component. Blocking is cancelled when an adjustable threshold value of the short-circuit current is reached, so that very high current faults are switched off instantaneously.
Thermal overload protection (ANSI 49) A built-in overload protection with a current and thermal alarm stage is provided for thermal protection of cables and transformers. The trip time characteristics are exponential functions according to IEC 60255-8. The preload is considered in the trip times for overloads. An adjustable alarm stage can initiate an alarm before tripping is initiated.
Overcurrent protection (ANSI 50, 50N, 51, 51N)

The 7SD610 provides a three-stage overcurrent protection. Two definitetime stages and one inverse-time stage (IDMT) are available, separately for phase currents and for the earth current. Two operating modes are selectable. The function can run in parallel to the differential protection or only for backup during interruption of the protection communication. Two stages e.g. can run in backup mode, whereas the third stage is configured for emergency operation. The following ANSI/IEC inverse-time characteristics are available:

  • Inverse
  • Short inverse
  • Long inverse
  • Moderately inverse
  • Very inverse
  • Extremely inverse
  • Definite inverse
Instantaneous high-speed switch-onto-fault overcurrent protection (ANSI 50HS) Instantaneous tripping is possible when energizing a faulty line. On large fault currents, the high-speed switch-onto-fault overcurrent stage can initiate very fast three-pole tripping. Circuit-breaker closure onto a faulty line is also possible provided that the circuitbreaker auxiliary contacts of the remote end are connected and monitored. If an overcurrent arises on closing of the circuit- breaker at one end of a line (while the other end is energized) the measured current can only be due to a short-circuit. In this case, the energizing line end is tripped instantaneously. In the case of circuit-breaker closure, the auto-reclosure is blocked at both ends of the line to prevent a further unsuccessful closure onto a short-circuit. If circuit-breaker intertripping to the remote end is activated, intertripping is also blocked.
Auto-reclosure (ANSI 79) (optional)

The 7SD610 relay is equipped with an auto-reclosure function (option). For 1-phase or for multi-phase faults, different dead times can be set. The function includes several operating modes:

  • 3-pole auto-reclosure (AR) for all types of faults.
  • 1-pole auto-reclosure for 1-phase faults, no AR for multi-phase faults.
  • 1-pole AR for 1-phase faults and for 2-phase faults without earth connection.
  • 1-pole AR for 1-phase and 3-pole AR for multi-phase faults.
  • Multiple-shot AR. Up to 8 ARs are possible.
  • Interaction with an external protection relay for AR via binary inputs and binary outputs.
  • Adaptive auto-reclosure: Both breakers open after the fault in the protection zone has been detected. The breaker is switched on by only one relay. If the fault has disappeared,
  • the other line end is switched on via communication links. If not, the line end makes a final trip.
  • Interrogation of synchro-check protection before auto-reclosure occurs. This issues the release signal for auto-reclosure to the unit via a binary input.
  • Monitoring of the circuit-breaker auxiliary contacts and c.b.-ready status.
  • Voltage check for discrimination between successful and non-successful reclose attempts.
Breaker failure protection (ANSI 50BF) The 7SD610 relay incorporates a two-stage breaker failure protection to detect the failure of tripping command execution, for example, due to a defective circuit-breaker. The current detection logic is phasesegregated and can therefore also be used in single-pole tripping schemes. If the fault current is not interrupted after a settable time delay has expired, a retrip command or a busbar trip command is generated. The breaker failure protection can be initiated by all integrated protection functions as well as by external devices via binary input signals.
High-speed current monitoring and other monitoring functions Numerous monitoring functions for hardware and software are implemented in the 7SD610 unit. The measuring circuits, analog- to-digital conversion and the supply voltages, memory and software execution (watch-dog function) are monitored. An open circuit between the CTs and relay inputs under load may lead to tripping of a differential relay if the load current exceeds the differential setpoint. The 7SD610 provides fast bus wire supervision which immediately blocks all line ends if an open circuit is measured by a local relay. This avoids maloperation due to open circuit. Only the phase where the open circuit is detected is blocked. The other phases remain under differential operation.
Additional measurement supervision functions are:
  • Symmetry of voltages and currents
  • Summation of phase currents and comparison with the measured current at measuring input for the I4-earth current transformer. If a significant difference is detected, the differential protection is blocked immediately, because this difference can only originate in a hardware fault of the unit’s analog part.
  • Phase-sequence supervision.
Trip circuit supervision (ANSI 74TC) One or two binary inputs for each circuit- breaker pole can be used for monitoring the circuit-breaker trip coils including the connecting cables. An alarm signal is issued whenever the circuit is interrupted. For each trip circuit, 1 or 2 binary inputs can be used.
Lockout (ANSI 86) All binary outputs can be stored like LEDs and reset using the LED reset key. The lockout state is also stored in the event of supply voltage failure. Reclosure can only be issued after the lockout state has been reset.

F.3. Communication

As an option, the 7SD610 provides one protection data interface for two line end applications. In addition to the differential protection function, other protection functions can use this interface to increase selectivity and sensitivity as well as covering advanced applications.

  • Interclose command transfer with the auto-reclosure “Adaptive dead time” (ADT) mode
  • 28 remote signals for fast transfer of binary signals
  • Flexible utilization of the communication channels by means of the programmable CFC logic.

The protection data interface has different options to cover new and existing communication infrastructures

  • FO51), OMA12) module: 820 nm fiber-optical interface with clock recovery/ST connectors for direct connection with multi-mode FO cable up to
  • 1.5 km for the connection to a communication converter.
  • FO61), OMA22) module: 820 nm fiber-optical interface/ST connectors for direct connection up to 3.5 km with multi-mode FO cable.

New fiber-optic interfaces, series FO1x

  • FO171): For direct connection up to 24 km3), 1300 nm, for mono-mode fiber 9/125 μm, LC-Duplex connector
  • FO181): For direct connection up to 60 km3) 1300 nm, for mono-mode fiber 9/125 μm, LC-Duplex connector
  • FO191): For direct connection up to 100 km3) 1550 nm, for mono-mode fiber 9/125 μm, LC-Duplex connector

The link to a multiplexed communication network is made by separate communication converters (7XV5662). These have a fiber- optic interface with 820 nm and ST connectors to the protection relay. The link to the communication network is optionally an electrical X21 or a G703.1 interface.

For operation via copper wire communication (pilot wires or twisted telephone pair), a modern communication converter for copper cables is available. This operates with both the two-wire and three-wire copper connections which were used by conventional differential protection systems before. The communication converter for copper cables is designed for 5 kV insulation voltage. An additional 20 kV isolation transformer can extend the field of applications of this technique into ranges with higher insulation voltage requirements. The connection via FO cable to the relay is interference free. With SIPROTEC 4 and the communication converter for copper cables, a digital follow-up technique is available for two-wire or three-wire protection systems (typical 15 km) and all three-wire protection systems using existing copper communication links.

F.3.1 Communication Interfaces connection

Connection Front side, non-isolated, RS232,
9-pin D-subminiature female connector for connection of a PC
Operation With DIGSI
Transmission speed Min. 4800 Baud; max. 115200 Baud;
Factory Setting: 38400 Baud; Parity: 8E1
Transmission distance 15 m / 50 feet

System Interface

Some of the interface details mentioned here is optional depending on the device model and ordered components:

RS232 Connection for flush mounting housing Rear panel, slot “B”, 9-pole D-subminiature female connector
  For Panel Surface-Mounted Case in console housing at case bottom
9-pole D-subminiature female connector
  Transmission speed Min. 4800 Baud; max. 38400 Baud
Factory setting 19200 Baud
  Maximum Distance of Transmission Max. 15
RS485 Connection for flush mounting housing Rear panel, slot “B”, 9-pole D-subminiature female connector
  For Panel Surface-Mounted Case in console housing at case bottom
9-pole D-subminiature female connector
  Transmission speed Min. 4800 Baud; max. 38400 Baud
Factory setting 19200 Baud
  Bridgeable distance Max. 1Km
Fibre optic cable (FO) FOC connector type ST connector
  Connection for flush mounting housing Rear panel, mounting location “B”
  For Panel Surface-Mounted Case in console housing at case bottom
  Permissible path attenuation Max. 8 dB, with glass fibre 62.5/125 μm
  Maximum Distance of Transmission Max. 1.5 km
  Character Idle State Selectable, factory setting “Light off”
Profibus DP RS485 Connection for flush mounting housing Rear panel, slot “B”,
9-pole D-subminiature female connector
  For Panel Surface-Mounted Case in console housing at case bottom
9-pole D-subminiature female connector
  Transmission speed up to 12 MBd
  Maximum Distance of Transmission

1,000 m (1640 ft.) at ≤ 93.75 kBd

500 m (1640 ft.) at ≤ 187.5 kBd

200 m (328 ft.) at ≤ 1.5 MBaud

100 m (328 ft.) at ≤ 12 MBaud

DNP3.0 / MODBUS / RS485 Connection for flush mounting housing Rear panel, mounting location “B”
  For Panel Surface-Mounted Case in console housing
  Transmission speed Up to 19200 Baud
  Permissible path attenuation Max. 8 dB, with glass fibre 62.5/125 μm
  Maximum Distance of Transmission Max. 1 km
Ethernet electrical (EN 100) for
IEC 61850 and DIGSI
Connection for flush-mounted housing Rear panel, mounting location “B”
2 x RJ45 female connector
100BaseT according to IEEE802.3
  Connection for surface mounting housing In console housing on bottom
  Transmission speed 100 Mbits/s
  Bridgeable distance 20 m

F.3.2 Communication Protocols

IEC 60870-5-103

IEC 60870-5-103 is an internationally standardized protocol for efficient communication with protection relays. IEC 60870-5-103 is supported by a number of protection device manufacturers and is used world-wide. Supplements for the control function are defined in the manufacturer- specific part of this standard.


PROFIBUS-FMS is an internationally standardized communication protocol (EN 50170). Connection to a SIMATIC programmable controller is made on the basis of the data obtained (e.g. fault recording, fault data, measured values and control functionality) via the SICAM energy automation system.


PROFIBUS-DP is an industrial communications standard and is supported by a number of PLC and protection device manufacturers.

DNP 3.0

DNP 3.0 (Distributed Network Protocol, Version 3) is an internationally recognized protection and bay unit communication protocol. SIPROTEC 4 units are Level 1 and Level 2 compatible.


An Ethernet application-specific profile for energy automation applications is currently under preparation.


SIPROTEC4 7SS60 Feeder Management Relay

This section discusses the SIEMENS SIPROTEC 4 7SS60 Busbar protection relay, its functions, installation procedures, applications and maintenance issues. The SIPROTEC 4 units are numerical relays capable of providing control and monitoring functions.

G.1 Application

The 7SS60 system is an easily settable numerical differential current protection for busbars. It is suitable for all voltage levels and can be adapted to a large variety of busbar configurations.

The components are designed for

  • single busbars, (with and without sectionalizing isolators)
  • 1½-breaker configurations and
  • double busbars with sectionalizing isolators, longitudinal couplers and transversal couplers

The use of matching transformers allows phase-selective measurement. Single-phase measurement can be achieved by using summation current transformers. The 7SS60 is designed to be the successor of the 7SS1 static busbar protection. The existing summation current or matching transformers can be reused for this protection system.

Figure G.1
Front View of 7SS601

The 7SS60 busbar protection has the following features:

  • Busbar protection operating on the differential current principle; one measuring system per busbar section or, depending on the configuration, per phase and zone; optionally one additional measuring system for the check zone (isolator-independent measuring system)
Figure G.2
Basic connection scheme of 7SS60
  • Full galvanic and interference-immune isolation between the internal processing circuits and the measuring, control and supply circuits of the system by screened measuring transducers, binary input and output modules and dc voltage converters
  • Fully digital measured value processing and protection functions, from the sampling and digitizing of the measured values to the TRIP decisions for the circuit breakers
  • High degree of security against overfunction, and detection of external faults even with unfavourable transformer configuration
  • Differential current supervision of transformer circuits, with blocking option for TRIP command
  • Blocking of TRIP command possible by fast binary input
  • Low demands on current transformers
  • Numerical system with powerful 16-bit microprocessor system
  • Easy menu-guided operation via integrated keypad and display panel or by connected PC using DIGSI
  • Storage of fault annunciations and of instantaneous values for fault recording
  • Continuous monitoring of the hardware and software of the 7SS601 measuring system, as well as of the primary current transformers and their supply conductors
  • Integrated commissioning aids

G.2 Protection functions

G.2.1 Measurement Method

The measurement method by which the 7SS60 numerical busbar protection detects a short-circuit in the protected zone relies on Kirchhoff’s current law. This law states that the vectorial sum of all currents flowing into a closed area must be zero.

Figure G.3
Busbar with n feeders

Assuming that the currents J1, J2, J3 to Jn flow in the feeders connected to the busbar, the following equation applies in the fault-free condition (the currents flowing towards the busbar are defined as positive, and the currents flowing away from the busbar as negative):

J1 + J2 + J3 ... + Jn = 0

If this equation is not fulfilled, there must be some other – impermissible – path through which a current flows. This means that there is a fault in the busbar region.

The above considerations apply strictly to the primary-side conditions in a high-voltage switching station. Protection systems, however, cannot carry out direct measurements of currents in high-voltage systems. Protection equipment measurement systems, performing the current comparisons, are connected through current transformers. The secondary windings provide the currents scaled down according to the transformation ratio while retaining the same phase relation. Furthermore, the current transformers, due to the isolation of their secondary circuits from the high-voltage system and by appropriate earthing measures, can keep dangerous high voltages away from the protection system.

The characteristics of the current transformers are an important factor for the correct operation of the protection. Their physical locations mark the limits of the protection zone covered by the protection system.

The measuring circuit of the 7SS60 busbar protection system is characterized by the following features:

Basic principle Monitoring the sum of the currents as the tripping quantity
Measures taken to guard against the disturbing influences due to current transformer saturation Restraint
Measures taken to obtain very short operating times Separate evaluation of the current transformer currents during the first milliseconds after the occurrence of a fault (anticipating the current transformer saturation)

G.2.2 BusBar protection

The busbar protection function generates the TRIP command that is then multiplied by means of peripheral modules to enable the output to all tripping circuit breakers. It makes the r.m.s. values of the differential current Id and of the restraint current IR available for display, stores events in the form of operational annunciations, fault annunciations or spontaneous annunciations and outputs these via LED indicators or signal relays. Measured values and annunciations are furthermore made available at the RS485 interface for operation by PC using the DIGSI communication software.

Figure G.4
Characteristic of busbar protection system

The 7SS601 measuring system processes the externally formed sums of the differential current Id and of the restraint current IR. By means of these two measured values, the protection function recognizes the presence of a fault in its associated protection zone. Figure G.3 shows the trip characteristic of the protection. The characteristic is divided into a horizontal portion and a portion with a steadily rising slope. Only value pairs of a differential and a restraint current that are both above the characteristic constitute busbar faults that lead to a TRIP command.

Pickup characteristic of the differential protection
The characteristic can be set in the parameters for Id > (pickup value) and for the k factor which considers the linear and non-linear current transformer errors. Differential currents above the set characteristic lead to tripping.

Current transformer monitoring
An independent sensitive differential current monitoring with its parameter Id thr detects faults (short-circuits, open circuit) of current transformers and their wiring even with load currents. The affected measuring system is blocked and an alarm is given. By this, the stability of the busbar protection is ensured in case of external faults.

Trip command lockout (with manual reset)
Following a trip of the differential protection, the TRIP command can be kept (sealed-in). The circuit-breakers are not reclosed until the operator has obtained information on the fault; the command must be manually reset by pressing a key or by a binary input. The logical state of the TRIP command is buffered against a loss of the auxiliary power supply, so that it is still present on restoration of the auxiliary voltage supply.

G.3. Communication

The device is equipped with an RS485 interface. The interface has bus capability and allows a maximum of 32 units to be connected via a serial two-wire interface. A PC can be connected to the interface via an RS232_RS485 converter, so that configuration, setting and evaluation can be performed comfortably via the PC using the DIGSI operating program. The PC can also be used to read out the fault record that is generated by the device when a fault occurs.

With RS485_820 nm optical converters, which are available as accessories (7XV5650, 7XV5651), an interference-free, isolated connection to a control center or a DIGSI-based remote control unit is possible; this allows to design low-cost stations concepts that permit e.g. remote diagnosis.


SIPROTEC4 7UT6 Transformer Differential Relay

This section discusses the SIEMENS SIPROTEC 4 7UT6 transformer differential relay, its functions, installation procedures, applications and maintenance issues. The SIPROTEC 4 units are numerical relays capable of providing control and monitoring functions.

H.1 Application

The SIPROTEC 7UT6 differential protection relays are used for fast and selective fault clearing of short-circuits in transformers of all voltage levels and also in rotating electric machines like motors and generators, for short lines and busbars. The protection relay can be parameterized for use with three-phase and single-phase transformers. The numerical protection relays 7UT6 are primarily applied as differential protection on

  • transformers
    • 7UT612: 2 windings
    • 7UT613/633: 2 up to 3 windings
    • 7UT635: 2 up to 5 windings,
  • generators
  • motors
  • short line sections
  • small busbars
  • parallel and series reactors.
Figure H.1
7UT series relays

In addition to the differential function, a backup overcurrent protection for 1 winding/ star point is integrated in the relay. Optionally, a low or high-impedance restricted earth-fault protection, a negative sequence protection and a breaker failure protection can be used. 7UT613 and 7UT633 feature 4 voltage inputs. With this option an overvoltage and undervoltage protection is available as well as frequency protection, reverse / forward power protection, fuse failure monitor and overexcitation protection.

7UT613 and 7UT63x only feature full coverage of applications without external relays by the option of multiple protection functions e.g. overcurrent protection is available for each winding or measurement location of a transformer. Other functions are available twice: earth-fault differential protection, breaker failure protection and overload protection. Furthermore, up to 12 user-defined (flexible) protection functions may be activated by the customer with the choice of measured voltages, currents, power and frequency as input variables.

Figure H.2
Function diagram of 7UT6

H.2 Protection functions

Differential protection for transformers (ANSI 87T) When the 7UT6 is employed as fast and selective short-circuit protection for transformers the following properties apply:
Figure H.3
SIPROTEC 7UT6 tripping characteristic
  • Tripping characteristic according to Fig. 8/4 with normal sensitive IDIFF> and high-set trip stage IDIFF>>
  • Vector group and ratio adaptation
  • Depending on the treatment of the transformer neutral point, zero-sequence current conditioning can be set with or without consideration of the neutral current. With the 7UT6, the star-point current at the star-point CT can be measured and considered in the vector group treatment, which increases sensitivity by one third for single-phase faults.
  • Fast clearance of heavy internal transformer faults with high-set differential element IDIFF>>.
  • Restrain of inrush current with 2nd harmonic. Cross-block function that can be limited in time or switched off.
  • Restrain against overfluxing with a choice of 3rd or 5th harmonic stabilization is only active up to a settable value for the fundamental component of the differential current.
  • Additional restrain for an external fault with current transformer saturation
Overcurrent-time protection (ANSI 50, 50N, 51, 51N) Backup protection on the transformer is achieved with a two-stage overcurrent protection for the phase currents and 3I0 for the calculated neutral current. This function may be configured for one of the sides or measurement locations of the protected object. The high-set stage is implemented as a definite-time stage, whereas the normal stage may have a definite-time or inverse- time characteristic. Optionally, IEC or ANSI characteristics may be selected for the inverse stage. The overcurrent protection 3I0 uses the calculated zero-sequence current of the configured side or measurement location.
Overcurrent-time protection for earth (ANSI 50/51G) The 7UT6 feature a separate 2-stage overcurrent-time protection for the earth. As an option, an inverse-time characteristic according to IEC or ANSI is available. In this way, it is possible to protect e.g. a resistor in the transformer star point against thermal overload, in the event of a single-phase short-circuit not being cleared within the time permitted by the thermal rating.
Phase-balance current protection (ANSI 46) (Negative-sequence protection) A negative-sequence protection may be defined for one of the sides or measurement locations. This provides sensitive overcurrent protection in the event of asymmetrical faults in the transformer. The set pickup threshold may be smaller than the rated current.
Overexcitation protection Volt / Hertz (ANSI 24) (7UT613/633 only) The overexcitation protection serves for detection of an unpermissible high induction (proportional to V/f) in generators or transformers, which leads to a thermal overloading. This may occur when starting up, shutting down under full load, with weak systems or under isolated operation. The inverse characteristic can be set via seven points derived from the manufacturer data.
Thermal monitoring of transformers

Overload protection based on a simple thermal model, and using only the measured current for evaluation, has been integrated in differential protection systems for a number of years. The ability of the 7UT6 to monitor the thermal condition can be improved by serial connection of a temperature monitoring box (also called thermo-box or RTDbox). The temperature of up to 12 measuring points (connection of 2 boxes) can be registered. The type of sensor (Pt100, Ni100, Ni120) can be selected individually for each measuring point. Two alarm stages are derived for each measuring point when the corresponding set threshold is exceeded.

Alternatively to the conventional overload protection, the relay can also provide a hotspot calculation according to IEC 60345. The hot-spot calculation is carried out separately for each leg of the transformer and takes the different cooling modes of the transformer into consideration.

The oil temperature must be registered via the thermo-box for the implementation of this function. An alarm warning stage and final alarm stage is issued when the maximum hot-spot temperature of the three legs exceeds the threshold value. For each transformer leg a relative rate of ageing, based on the ageing at 98 °C is indicated as a measured value. This value can be used to determine the thermal condition and the current thermal reserve of each transformer leg. Based on this rate of ageing, a remaining thermal reserve is indicated in % for the hottest spot before the alarm warning and final alarm stage is reached.

H.3. Communication

H.3.1 Physical connection

Local PC interface

The PC interface accessible from the front of the unit permits quick access to all parameters and fault event data. Of particular advantage is the use of the DIGSI 4 operating program during commissioning.

RS 485 bus

With this data transmission via copper conductors, electromagnetic fault influences are largely eliminated by the use of twisted-pair conductors. Upon failure of a unit, the remaining system continues to operate without any problem.

Fiber-optic double ring circuit

The fiber-optic double ring circuit is immune to electromagnetic interference. Upon failure of a section between two units, the communication system continues to operate without disturbance. It is usually impossible to communicate with a unit that has failed. Should a unit fail, there is no effect on the communication with the rest of the system.

H.3.2 Communication Protocols

IEC 61850 Ethernet

The Ethernet-based IEC 61850 protocol is the worldwide standard for protection and control systems used by power supply corporations. By means of this protocol, information can be exchanged directly between bay units so as to set up simple masterless systems for bay and system interlocking. Access to the units via the Ethernet bus is also possible with DIGSI.

IEC 60870-5-103

IEC 60870-5-103 is an internationally standardized protocol for efficient communication with protection relays. IEC 60870-5-103 is supported by a number of protection device manufacturers and is used world-wide. Supplements for the control function are defined in the manufacturer- specific part of this standard.


PROFIBUS-FMS is an internationally standardized communication protocol (EN 50170). Connection to a SIMATIC programmable controller is made on the basis of the data obtained (e.g. fault recording, fault data, measured values and control functionality) via the SICAM energy automation system.


PROFIBUS-DP is an industrial communications standard and is supported by a number of PLC and protection device manufacturers.


MODBUS RTU is an industry-recognized standard for communications and is supported by a number of PLC and protection device manufacturers.

DNP 3.0

DNP 3.0 (Distributed Network Protocol, Version 3) is an internationally recognized protection and bay unit communication protocol. SIPROTEC 4 units are Level 1 and Level 2 compatible.

H3.3 System Solution for protection and station control

Figure H.4
System solution for protection and control

Together with the SICAM power automation system, SIPROTEC 4 can be used with PROFIBUS-FMS. Over the low-cost electrical RS485 bus, or interference-free via the optical double ring, the units exchange information with the control system. Units featuring IEC 60870-5-103 interfaces can be connected to SICAM in parallel via the RS485 bus or radially by fiber-optic link. Through this interface, the system is open for the connection of units of other manufacturers (see Fig. 8/12). Because of the standardized interfaces, SIPROTEC units can also be integrated into systems of other manufacturers or in SIMATIC. Electrical RS485 or optical interfaces are available. The optimum physical data transfer medium can be chosen thanks to opto-electrical converters. Thus, the RS485 bus allows low-cost wiring in the cubicles and an interference-free optical connection to the master can be established.


Arc Sensors

This section discusses an Electric Arc, its characteristics and precautions. Further, we will discuss sensors that help identify quickly and take control action to avoid the arc causing serious damage.

I.1 Introduction

An electric arc short-circuit is an infrequent switchgear fault where an explosion-like heat and pressure-effect may cause large material damage and jeopardize the job safety of the operation staff. The goal of the arc protection is to detect the arc and minimize its burning time thus protecting people and property. The burning time is usually minimized by cutting off the current path feeding the arc. Generally arc protection is implemented using a separate arc protection system. In this system arc detectors are connected to specialized arc protection units. New type of line protection relays include sensor inputs and the arc sensors can be directly connected to them. In this way arc protection can easily be integrated as part of the total protection concept with minimal additional cost.

An overcurrent relay with integrated arc sensor inputs can be used to build short-circuit and arc protection of one feeder in a switchgear. The relay will selectively trip the breaker of the feeder in case of arc fault is detected in the feeder cubicle. The information about the activation of the sensor can additionally be wired to the incoming feeder’s overcurrent relay or arc protection unit. The incoming feeder can thus be tripped if there is an arc detected anywhere inside the switchgear.

Figure I.1
Arc Flash characteristics

Figure I.1 is a model of an arc fault and the physical consequences that can occur. The unique aspect of an arcing fault is that the fault current flows through the air between conductors or a conductor(s) and a grounded part. The arc has an associated arc voltage because there is arc impedance. The product of the fault current and arc voltage concentrated at one point, results in tremendous energy released in several forms.

I.2 Features of an Electric Arc

An electric arc is formed if current flows from one electrode to another via a channel of ionized gas. An electrical arc which causes a short-circuit is the worst possible fault that can happen in a power distribution system.

I.2.1 High Temperature

The electric arc is formed when current flows through isolation material – like air or gas – with no galvanic contact. The air becomes conductive when its temperature rises to about 3000°C. To make the air this hot and to start an arc some kind of ignition is required. This may be e.g. a thin wire which burns away when current flows through it. The temperature of a burning arc is depending on the fault current, arc voltage and cooling conditions. In shortcircuit situations the temperature in the centre of the arc may be up to 10.000 …20.000 K. In the contact points the temperature is smaller, about 3000...4500 K.

I.2.2 Ionisation

In high temperature air and other gas molecules are broken to atoms and further to ions and electrons. This causes the gas to conduct electricity.

I.2.3 Light and other radiation

Part of the arc energy flows to the environment as infrared, ultraviolet and visible light radiation. Also radiation in the radio frequencies is generated. The radiation is transmitted by the arc itself and the materials heated up by the arc. At the brightest the light will be between 100..200 ms after the ignition of the arc until smoke and metal steam will reduce the sight. Some measurements have indicated 9000 lux brightness from 6..7 meters. The total radiation may be 1....10 W/cm2 at a distance of 1,5 meters. This is rather high value compared e.g. to the radiation from the sun on the surface of the earth, which is about 0,1 W/ cm2.

I.2.4 Movement of the arc

The thermal force tries to lift the centre of the arc upwards, because the air in the centre is warmer. The lifting of the hot air upwards causes air to move, this convection force further pushes the centre of the arc upwards. These forces make the electric arc to bend to its characteristic arc form. The current flowing due to the short circuit creates elctrodynamic force which makes the arc to move to the direction of the energy flow in the circuit. In switchgears the arc moves to the end of the conducting bars or close to through-holes.

I.2.5 Voltage and resistance

In medium voltage switchgear the arc voltage is about 500...1000 V. In low voltage circuits the arc voltage is about 300 V. The resistance of the arc is usually less than 0,1 Ω. In short-circuit calculations this resistance can often be neglected.

I.3 Where do arc flash hazards occur?

A hazardous arc flash can occur in any electrical device, regardless of voltage, in which the energy is high enough to sustain an arc. Potential places where this can happen include:

  • Panel boards and switchboards
  • Motor control centers
  • Metal clad switch gear
  • Transformers
  • Motor starters and drive cabinets
  • Fused disconnects
  • Any place that can have equipment failure

I.4 Dangers of Arc Flash

Injury to staff : The explosion creates pressure waves that can damage a person’s hearing, a high-intensity flash that can damage their eyesight and a superheated ball of gas that can severely burn a worker’s body and melt metal.

Damage to equipment: The burning effect of arc will be on the electrodes, cubicle doors, walls and on the busbar. There will be burning gases and hot particles exploding out to the environment. The arc will melt and evaporate electrode material. Part of melting material is splashed around and part of it will be mixed with the air. The electrodes will suffer most in those spots where the arc will stay for a longer time. The burning effect may cut busbars and wires, holes may be burned to doors, walls or ceilings and equipment may be destroyed. In addition to the burning effect of the arc itself the arc may set up fires in the materials of the building or in the cables.

I.5 Reasons for arc short-circuits

The most common reasons to arc short-circuits can be classified into two main groups

  1. human and operational errors and
  2. technical reasons.

Typical human and operational errors are

  • work in a wrong cubicle
  • operation of a wrong isolator
  • forgetting to ground the working area
  • forgetting to test the presence of voltage in the working area

Technical reasons to arc short-circuits:

  • faults in equipment and false operation of equipment
  • ageing of insulation and mechanical wear
  • overvoltage
  • overheating
  • moisture, dirt
  • equipment wear
  • corrosion
  • foreign objects (e.g. tools) in the switchgear
  • small animals
  • installation errors
  • bad wire and busbar connections

I.6 Arc Sensors

The goal of the arc protection is to protect property and people in case of an electric arc fault by limiting the arc burning time. To do this the arc protection must first detect an arc and then cut the flow of current. The flow of arc current is usually cut by opening a circuit breaker.

An arc flash fault typically results in an enormous and nearly instantaneous increase in light intensity in the vicinity of the fault. Light intensity levels often rise to several thousand times normal ambient lighting levels. For this reason most, if not all, arc flash detecting relays rely on optical sensor(s) to detect this rapid increase in light intensity. For security reasons, the optical sensing logic is typically further supervised by instantaneous overcurrent elements (ANSI device 50) operating as a fault detector. Arc flash detection relays are capable of issuing a trip signal in as little as 2.5 ms after initiation of the arcing fault.

Arc flash relaying compliments existing conventional relaying. The arc flash detection relay requires a rapid increase in light intensity to operate and is designed with the single purpose of detecting very dangerous explosive-like conditions resulting from an arc flash fault. It operates independently and does not need to be coordinated with existing relaying schemes.

Once the arc flash fault has been detected, there are at least two design options. One option involves directly tripping the upstream bus breaker(s). Since the arc flash detection time is so short, overall clearing time is essentially reduced to the operating time of the upstream breaker. A second option involves creating an intentional three-phase bus fault by energizing a high speed grounding switch. This approach shunts the arcing energy through the high speed grounding switch and both faults are then cleared by conventional upstream bus protection. Because the grounding switch typically closes faster than the upstream breaker opens, this approach will result in lower incident energy levels than the first approach. However, it also introduces a second three-phase bolted fault on the system and it requires that a separate high speed grounding switch be installed and operational. Assuming there is space available for the addition of the grounding switch, there is a significantly higher cost of implementation involved compared to the first approach, and so may not be a practical alternative, especially for existing switchgear lineups.

I.6.1 The fiber optic solution

A new and novel approach to arc flash detection uses the optical fiber itself as the arc flash sensor. The optical fiber can be up to 60 meters (about 200 ft) long. It uses a plastic fiber with a glass core and is routed throughout all high voltage compartments where an arc could potentially occur. A typical fiber routing in two-high switchgear construction is shown in Figure I.2. Single-high construction is handled in a similar manner.

Figure I.2
Looped fiber optic solution

Unlike communication fibers, this optical sensor fiber has no cladding to prevent ambient light from entering the fiber. In fact, the system depends on external light to operate. The fiber is a plastic outer sheath with a glass core making it suitable for harsh environments. The minimum bending radius is about 2 inches. Wherever the fiber is exposed to an arc flash, the flash will be captured and the rapid increase in received light intensity will be detected by the relay. No galvanic wires or conventional photocells need to be installed in the high voltage compartments. If looped, the continuity and integrity of the fiber sensor can be continuously monitored by the system. This is done by periodically sending a test pulse through the fiber loop. If this test pulse is not received at regular intervals, the Internal Relay Failure (IRF) alarm activates.

The relay’s sensitivity to light may be adjusted manually or controlled automatically. When set to automatic mode, it continually adjusts its threshold sensitivity to the relatively slow-changing background lighting levels that might result from opening a compartment door. Manual light intensity level settings may be more appropriate where some normal low-level arcing might take place such as in older air-magnetic switchgear.

The optical arc flash system may be supervised by single-phase fault detectors (ANSI device 50). Fault detector supervision is selectable but recommended by the manufacturer for most applications. It provides additional security at a cost of only about 2 ms in operating time. If both optical and electrical systems indicate an arc-flash fault, the relay issues a trip signal.

I.6.2 Partial discharge detection

Damaged insulation can lead to partial discharges (PD’s) which bridge only part of the insulation clearance. To begin with, these PD’s are not dangerous, but over time they cause ever greater damage to the insulation and their intensity and frequency both increase. If these occurrences are not detected in good time and the cause eliminated, the progressive PD’s will inevitably lead to a disruptive discharge, causing a complete failure of the operating equipment. Partial discharges can in the end damage the isolators so that an arc short-circuit will follow. Partial discharges may be detected by using search coils for detecting high-frequency electrical fields produced by partial discharges. Detection of partial discharge is an early warning of an arc and an alarm from detected partial discharge is usually given.

I.6.3 Ultrasonic sensors

The object of electric condition monitoring is to detect arcing, tracking, and corona before flashover occurs or before they produce an arc flash when the cabinet is opened. Because these phenomena are characterized by airborne and structure-borne ultrasonic emissions, they can be detected by ultrasonic sensors. The instruments have a sensing range of 20-100 kHz, and use heterodyning to translate ultrasonic emissions into the audible range. They are portable, and provide information via headphones for the audio signal and on a meter that displays intensity readings, usually as decibels. They usually contain two sensing heads incorporating piezoelectric transducers – a scanning module for airborne sounds and a contact probe/waveguide for structure-borne signals.

Figure I.3
Ultrasonic sensor

Typically an operator will scan around the door seams and air vents of enclosed electrical cabinets with the scanning module while lis- tening through headphones and observing the display panel. Arcing, tracking, and corona all have distinct sound qualities that can be detected. If there are no air paths, the inspector will use the waveguide to probe around the cabinet wall. To compensate for a possible change in wave characteristics as the ultrasound moves from airborne to structure borne, the operator will change the frequency from 40 kHz (effective for airborne scans) to 25 kHz. Should there be a need to further analyze these patterns, the sounds can be recorded and played back on spectral analysis software. Voltage will play a role in the diagnosis since corona will occur only at 1000 V and higher.


Integral Digital Protection Devices in LV Circuit Breakers

In this appendix, we will take a brief look at protective devices mounted within LV circuit breakers for overload, short circuit and ground (earth) fault protection. Emphasis will be on the modern generation of digital protective devices with communication capability.

J.1 Introduction

One of the main functions of a circuit breaker is to interrupt fault currents. This can be done using external protective devices, referred to as protective relays for sensing a fault (usually over load, ground fault or a short circuit) and give a command to the circuit breaker to open. By and large, this is the method adopted for all MV and HV circuit breakers. Such an approach also necessitates an external power source for auxiliary power for operation of the protective relays and trip coil of the circuit breaker, usually provided through an elaborate DC supply system consisting of storage batteries and their associated charging equipment. However, in low voltage systems such extensive arrangements are expensive to provide and difficult to maintain. Therefore the common practice is to integrate circuit protective devices within the circuit breaker itself and design the protective devices and the trip coil to operate using the energy of the fault itself.

Traditionally LV circuit breakers had used electrical-magnetic devices (sometimes called ‘release’) for sensing faults and these devices operated the breaker tripping mechanism by direct mechanical linkage. These devices were in the form of a bimetal-based thermal elements for obtaining Inverse Definite Minimum Time (IDMT) characteristic for overload trip and a electromagnetic short circuit trip actuated by the magnetic field created by the flow of short circuit current through a few turns (or sometimes just a single turn) of a coil. In other designs, the overload feature was obtained using a hydraulic device to provide IDMT characteristic instead of a bi-metal element. Where there is a need to obtain ground fault protection, the same had to be done using an externally mounted protective relay. Energy for tripping in such case will usually call for a stored-energy source. If this is not acceptable, an alternative was to use series trip relay schemes. Such a scheme is possible only if the ground fault current is reasonably high (around 20% of the feeder CT rating or more).

Use of thermal-magnetic and hydraulic-magnetic devices however had several drawbacks. The difficulty of testing short-circuit trip (which calls for a primary injection test) was a major issue. Another was the difficulty of obtaining time-delayed short circuit operation, often required for the purpose of coordinating the tripping of an air-circuit breaker with other downstream breakers. In some cases, a combination of IDMT, Definite time delay (DMT) and instantaneous tripping was expected for better protection. Ground fault tripping was another problem as an additional relay requires more panel space and elaborate auxiliary power supply arrangements. All these called for an improved protection device and led to the development of static schemes for integrated tripping function. Initially, such devices used discrete components and analog processing of the CT signals to obtain a tripping characteristic, which is a combination of IDMT, DMT, and instantaneous tripping characteristic. Digital design using microprocessors or other custom-built digital components was the next natural evolution. All the current designs of circuit breakers deploy such devices. We will briefly review the typical design and features of a digital tripping device in this appendix.

J.2 Overview of a typical digital protective device

The scheme of a typical digital protective device is shown in Figure J.1.

Figure J.1Schematic of a digital protective device (Courtesy: Siemens Energy and Automation Inc.)

A typical digital protective device uses in-built current sensors which are special purpose CTs with a low secondary rated output current of say 0.5 amps and are encapsulated for thermal and mechanical protection. They are also used for the purpose of providing operative power to the protection device and then to the trip coil of the breaker. (Most protective devices require at least 20% of the rated feeder current in order to function). The current signals from the sensors are converted to digital voltages by a resistor network and analog to digital converters (A/Ds) in the trip unit. The digital voltages are stored in temporary memory and are used by the microprocessors in detecting and processing overcurrent conditions and in metering. The circuit breakers with digital trip devices use specially designed tripping mechanism to enable tripping with minimal mechanical effort, at the same time avoiding the possibility of any mal-operation due to the vibrations caused during breaker operation. Rating plugs are provided for correlating the device settings (which are usually in terms of per unit value) with the actual trip current values.

While CTs take care of over load/overcurrent and ground fault protection, other special protection features may need built-in potential transformers. These are provided in the form of PT modules, which are encapsulated in polymeric material to protect the transformer windings and withstand mechanical vibration when mounted directly on the circuit breaker. An external power supply may also be necessary in certain cases and will be provided from the breaker panel.

J.3 Main features of digital protective devices

Several features unobtainable with older direct acting protective devices are now possible with digital protection. These are as follows:

  • Compact size permitting the same basic device for an entire range of circuit breaker ratings
  • Widely adjustable characteristics with combinations of long time (thermal overload), short time (back up short circuits) and instantaneous (short circuit protection)
  • Built-in ground fault protection by default
  • Switching memory for obtaining exact thermal behavior of protected equipment
  • Other protections such as over/under voltage, over/under frequency and reverse power
  • True RMS current sensing for proper operation in circuits with high harmonic-producing loads
  • Panel indication of load current and cause of tripping
  • Remote alarms and commands
  • Communication capabilities for power management

We will describe each of these features in detail here.

J.3.1 Compact sizes

Sizes of digital protective devices are required to be compact for the same basic device to be used from the smallest to the largest ratings. Separate devices are available for use with Moulded Case circuit breakers (MCCB) and with air circuit breakers (ACB). It is the current practice in LV systems to use MCCBs for outgoing feeders with the incoming feeder connected to an ACB. This is done so that the more robust ACB can be used as a back up device. Also MCCBs do not have the capacity for withstanding sustained short circuit currents whereas ACBs have this capability. The protection device of a typical ACB is shown below in Figure J.2 and that of an MCCB in Figure J.3.

Figure J.2
Digital protective device for an ACB family (Courtesy: Siemens Energy and Automation Inc.)
Figure J.3
Digital protective device for an MCCB family (Courtesy: Siemens Energy and Automation Inc.)

J.3.2 Adjustable characteristics

The digital protection devices combine IDMT (Long time delay), DMT (Short time delay) and instantaneous (high-set) and characteristics and the current and time settings of these protections are independently adjustable over a wide range as can be seen in the figures above. Long delay and short delay protection also have a selectable I2t feature. Most of these devices also provide for ground fault protection (optional in some cases), which can also be selected to be of fixed time or I2t based. In the former case, the tripping will be initiated when the fault current exceeds a set value and the tripping will be done with a set delay (as in the figures below). In the latter case, a portion of the curve will exhibit an inverse time characteristic determined by the I2t value (based on a specific current value, usually in multiples of the rating plug of the device and the set time value). Typical characteristic curves (MCCB) can be seen in Figure J.4. Figure J.5 illustrates ground fault setting options. The ground fault current may be obtained by internal summation of the built-in line CTs (and where applicable, the neutral CT as well) or by sensing the ground circuit return current. In the former case, the current sensors of the device are used for the computation whereas in the latter case, an input from the external CT in the ground return path at the source (transformer secondary) is necessary. The tripping device provides the facility of selecting between these two modes of current sensing.

Figure J.4
Tripping characteristics of a digital protective device of an MCCB family showing overcurrent and ground fault curves separately (Courtesy: Siemens Energy and Automation Inc.)
Figure J.5 (a)
Ground fault delay with fixed time setting
Figure J.5 (b)
Time setting with I2.t type delay

J.3.3 Switching memory

When a feeder is tripped on overload, the conductors take time to cool down. So, when a breaker is closed once again after an overload trip, the available thermal withstand capacity of the protected equipment is actually lower. This is particularly true of rotating machinery like motors. Normally, current based protection overlooks this probability (though overload devices with thermal elements exhibit this feature by virtue of the cooling time delay of the thermal elements. This is addressed in digital protection devices using a feature called ‘thermal memory’. This feature can be turned on or off depending on the requirements of the equipment being protected. Figure J.6 below shows the operation of this feature. It should be noted that this applies only to the long time-delay part of the protection (meant for overload).

Long time-delay characteristics of a digital protective device with thermal memory activated (Courtesy: Siemens Energy and Automation Inc.)

J.3.4 Extended protection

While the protections discussed above will be adequate for most cases, others may call for extra functionalities. These include:

  • Current unbalance
  • Voltage Unbalance
  • Over voltage
  • Under voltage
  • Reverse Power
  • Over frequency
  • Under frequency

Current unbalance may be required in the case of motor feeders as protection against single phasing. Current and voltage unbalance as well as reverse power and frequency protection will be necessary in the case of systems with local generation running in parallel with the utility. Under voltage protection is useful in the case of breakers used for switching a motor in order to prevent its self-restart after a brief power failure.

J.3.5 True RMS current sensing

Most protective devices do not perform correctly when a heavy harmonic producing load is involved. Especially, devices based on peak current sensing will be liable to trip incorrectly due to the distorted waveform in a harmonic situation. This is particularly important with long time delay protection (overload). The digital protective devices described here are based on current sampling and thus accurately reconstruct the current waveform (naturally with an appropriately high sampling frequency). They are thus able to calculate the RMS (heating) value of the current and can handle a high degree of harmonic content in the load current.

J.3.6 Panel indication

Digital tripping devices are usually provided with LCD displays to indicate the load current when the circuit is on. If the device operates due to an abnormality, it also displays the reason of trip in the front panel (in some of the designs this is done using LED lamps). Power for this display is obtained from stored energy capacitor charged by the supply voltage, thus avoiding the use of a battery cell. Other advanced features include individual line current selection for display, percentage of feeder rating, alarm generation at load currents above a set % of the rated load etc.

J.3.7 Remote trip alarm and remote commands

Tripping of the circuit breaker due to operation of protection, exceeding of a selected set point (of any of the measured parameters) and failure of relay (indicated by the self-check scheme) can all generate remote alarms. Some of the protective devices can also accept closing and tripping commands from a remote control panel and communicate breaker status (ON-OFF) with this remote panel. Connections to all such external circuits are through opto-isolated signals.

J.3.8 Communication capabilities for power management

Another feature of the digital protective devices is their ability to capture and store circuit parameters (analog values), events (digital values) with time stamp and communicate these data to a remote power management scheme. Separate communication processors will have to be added to the basic device to provide this capability. External dc control power is however required for powering the communications microprocessor. This allows communication with the trip unit during all load current conditions, even with the circuit breaker switched off. Internal isolation prevents wiring faults from damaging the trip unit’s protective circuits. A log is maintained using internal memory to record trips and other events. The trip details are stored in non-volatile type EEPROM memory which requires no batteries and is unaffected by loss of control power. Events are stored in the active memory, which requires control power to maintain data. The actual number of events that may be recorded depends on memory required for each type of event. Events include circuit breaker position or change, alarm set point activation and release etc. The most recent events are retained. Some of the devices provide for remote settings and display of set values but these are protected for security using password protection.

Different methods of communication are provided including communicating to the local display unit mounted in the breaker (or its panel) and to external management systems. However, the communication protocols and the management devices themselves are usually proprietary in nature, thus limiting their integration capabilities between diverse manufacturers.

J.4 Testing

As we discussed in the beginning of this appendix, one of the main drawbacks of the earlier generation of protective devices was their inability to be tested in any manner except by primary injection, often impossible due to the large magnitude of current which such a test calls for. In contrast, the digital trip devices provide a possibility of testing by secondary injection. With comparatively inexpensive and readily available equipment, it is possible to demonstrate that the tripping system will open the breaker and verify that the device conforms to the published time-current curves. However, field-testing cannot be expected to be as accurate as factory calibration. Therefore slight discrepancies between field tests and factory calibration can be regarded as normal. Failure of the device to trip or inconsistent behaviour with large variations from the standard tripping characteristics will require investigation.

It is usual for manufacturers to provide the test set and interface cables between the breaker and the test set. Testing is to be carried out strictly as per manufacturer’s guidelines using the equipment provided by them as otherwise there is a risk of destruction of the sensitive components used in the digital protective devices.

J.5 Summary

Traditionally LV circuit breakers had used electrical-magnetic devices for sensing faults. To overcome some of the limitations of these devices, development of static protective devices was attempted by various manufacturers. Initially, such devices used analog elements for processing the CT signals and obtain a tripping characteristic, which is a combination of IDMT, DMT, and instantaneous tripping characteristic. Digital design using microprocessors or other custom-built circuits was the next natural evolution. All the current designs of circuit breakers deploy such devices. Several features unobtainable with older direct acting protective devices are now possible with digital protection. In this appendix we had an overview of these features in a typical LV circuit breaker. One of the main features that distinguishes these devices from the older devices is their communication ability which makes their integration with a power management system possible. However, the protocols and the management devices themselves are usually proprietary in nature, thus limiting their integration between equipment of diverse manufacturers.

J.6 Acknowledgement

Details and diagrams of digital protection devices and their features discussed in this appendix are derived from published literature of Siemens Energy & Automation, Inc. Raleigh, NC for their product lines STATIC TRIP III and STD Frame Molded Case Circuit Breaker with microprocessor-controlled Electronic Trip unit.

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